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215-044
1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: 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 10,200 feet See Schematic feet true vertical 9,697 feet N/A feet Effective Depth measured 4,795 feet 5,019 feet true vertical 4,644 feet 4,853 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L-80 8,773' MD 8,364'' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 5,019' MD 4,853' TVD N/A; 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:Belugla/Upper Tyonek Gas Pool 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: Stefan Reed, Operations Engineer 325-153 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 measured true vertical Packer Representative Daily Average Production or Injection Data 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 136' 8,012' 1,524' Collapse 2,470psi Casing Structural 7,651'8,012' 136'Conductor Surface Intermediate Production Liner 10,184'9,682'10,184' measured TVD 7-5/8" 5" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-044 50-133-20650-00-00 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 6 Kenai Beluga Unit (KBU) 22-06Y Plugs Junk measured Length Burst 16" 10-3/4" 136' stefan.reed@hilcorp.com 206-518-0400 4,790psi 10,500psi 5,210psi 6,890psi 10,140psi 1,524'1,506' Casing Pressure Tubing Pressure 0 1452700 0 00 200 p k ft t Fra O s 6. A G L PG , 2 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 3:02 pm, Jun 06, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.06.06 14:44:30 - 08'00' Noel Nocas (4361) BJM 9/23/25 DSR=6/18/25 RBDMS JSB 061325 Page 1/1 Well Name: KEU KBU 22-06Y Report Printed: 6/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Wellbore API/UWI:50-133-20650-00-00 Field Name:Kenai Gas Field State/Province:ALASKA Permit to Drill (PTD) #:215-044 Sundry #:325-153 Rig Name/No: Jobs Actual Start Date:2/26/2025 End Date: Report Number 1 Report Start Date 4/22/2025 Report End Date 4/23/2025 Last 24hr Summary PTW/PJSM, MIRU YJ E-line and Scorpion N2. PT EL PCE 250/2,500 psi. Run GPT to 4,886' - no fluid level. Set CIBP @ 4,855' and dump bail 25 gal (34') cement. PT N2 iron to 250/4,000 psi. Pressure up on well to 3,250 psi with 104.3 mscf N2 for 72 hr MIT-T. RDMO YJ E-line and Scorpion N2. Hook up crystal gauge to tubing and IA to record pressures. Report Number 2 Report Start Date 4/23/2025 Report End Date 4/24/2025 Last 24hr Summary At 5:30am, SITP 2,224 psi, IA 120 psi. Will troubleshoot leak. Report Number 3 Report Start Date 4/28/2025 Report End Date 4/29/2025 Last 24hr Summary PTW/PJSM. MIRU Yellow Jacket E-line. PT 250/2,500 psi. GIH with drive-down bailer and tag at 4,849.5'. Dump bail 10 gal cement on top of plug. SDFN. Report Number 4 Report Start Date 4/29/2025 Report End Date 4/30/2025 Last 24hr Summary PTW/PJSM. SITP 610 psi, IA 139 psi. Run drive-down bailer and tag at 4,845.5'. Set CIBP @ 4,820' and dump bail 25 gal (34') cement. RDMO YJ E-line. SITP 478 psi, IA 138 psi. Report Number 5 Report Start Date 5/1/2025 Report End Date 5/2/2025 Last 24hr Summary PTW, JSA with Fox N2. MIRU N2 pump and 1502 iron. Cool down N2. PT lines 250/4500 psi. Starting pressures: WHP 1850 psi IA 124 psi, OA 0 psi. OPen well. Online with N2. Target pressure 3100 psi. Shut down at 3100 psi and monitor well pressures. Start 72 hr MIT at 10:32 AM on 5/1/2025 with tubing pressure 3136 psi, IA pressure 166 psi and OA 0 psi. RDMO Fox N2. Report Number 6 Report Start Date 5/6/2025 Report End Date 5/7/2025 Last 24hr Summary Witness MIT and tag cement top with AOGCC. MIT observed for 30 minutes with AOGCC inspector BOB Noble. Final T/I/O = 3121/142/28 psi. GOod test. E- line PT lubricator 250/3000 psi. RIH and TAG TOC. FOund only 16' out of 30' of cemet ontop of CIBP. TOC 4801'. Call out Dump bailer and cement kit. Resubmitt 24 hr test witness notification to AOGCC. RIH with 3.5" dump bailer and lightliy tag 4800'. Pick up off cement and fire dump bailer dropping 15 gallons of cement. POOH and lay down E-line. Allow 12 hrs for cement to dry. Report Number 7 Report Start Date 5/7/2025 Report End Date 5/8/2025 Last 24hr Summary Tag top of cement at 4795' with AOGCC Bob Noble. Perforate sterling pool 6 zone with 3 3/8 x 20' guns. From 4594'-4694' (100'). Report Number 8 Report Start Date 5/8/2025 Report End Date 5/9/2025 Last 24hr Summary MIT-IA post production to 1747psi starting pressure. Lost 20psi over 30 minute test. Ending Pressure 1727psi. PASSED. Set CIBP @ 4,855' and dump bail 25 gal (34') cement Dump bail 10 gal cement on top of plug Sy Tag top of cement at 4795' with AOGCC Bob Noble. Perforate sterling pool 6 zone with 3 3/8 x 20' guns. From 4594'-4694' Run drive-down bailer and tag at 4,845.5'. Set CIBP @ 4,820' and dump bail 25 gal (34') cement Page 1 of 2 Updated by DMA 05-30-25 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PBTD = 8,724’ MD / 8,319’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No.Depth ID OD Item 1 18’4.276”11.00”Tubing Hanger 2 4,820’CIBP w/25’ of cmt TOC 4,795’ (4/29/25) 3 4,855’CIBP w/ ~10’ cement(4/22/25) 4 5,019’4.276”6.875”10 ft Swell Packer (Water Swell) 5 5,215’5”CIBP 6 5,259’5” CIBP 7 6,450’2.441”CIBP w/ 20’ of cement 8 7,510’2.441”CIBP (12/7/23) 9 7,635’2.441”CIBP w/ 10’ of cmt (12/5/23) 10 8,510’2.441”CIBP w/ 10ft of cement (11/17/23) 11 8,768’4.276”Milled & push CIBP 12 8,990’-4.276”CIBP w/ 25ft of cement (8/20/22) 13 10,065’-3.710”Cement Retainer RA Tag Depths 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8"244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5”132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8”45 bbls of 15.3#. TOC 6,030’ based on CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00”Surf 136' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 1,524’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 8,012’ TUBING 5"Production 18 L-80 DWC/C-HT 4.276”Surf 10,184’ 2-7/8”Production 6.5 L-80 8RD EUE 2.441”5,905’8,773’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 4 CBL TOC 5,008’ 12 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Date Size Status Top Pool 6, 4,591’ MD & 4,453’ TVD P6 4,594’4,694’4,456’4,549’5/7/25 3-3/8”Open Top Beluga/Upper Tyonek Pool, 4,845’ MD & 4,691’ TVD UB 4,868’4,883’4,712’4,762’1/28/25 2-3/4”Isolated UB 5 5,201’5,211’5,023’5,032’1/28/25 2-3/4”Isolated UB 5A Upper 5,217’5,222’5,037’5,042’1/26/25 2-3/4”Isolated UB 5A Lower 5,230’5,244’5,050’5,063’1/26/25 2-3/4”Isolated UB 5B 5,264’5,283’5,082’5,099’1/25/25 2-3/4”Isolated LB 1B 6,461’6,473’6,201’6,212’12/30/23 2”Isolated LB 1C 6,520’6,526’6,257’6,262’12/30/23 2”Isolated LB 2B 6,792’6,812’6,511’6,530’12/30/23 2”Isolated LB 2E 6,962’6,974’6,670’6,682’12/30/23 2”Isolated LB 3 6,998’7,006’6,704’6,712’12/30/23 2”Isolated LB 3B Upr 7,069’7,075’6,770’6,776’12/30/23 2”Isolated LB 3B Mid 7,083’7,091’6,783’6,791’12/29/23 2”Isolated LB 4A Upr 7,218’7,224’6,910’6,915’12/29/23 2”Isolated LB 4A 7,231’7,251’6,922’6,940’12/8/23 2”Isolated PERFORATION DETAIL continued on following page LB 1 - L4B L TY 72_8 Fish: Milled CIBP to 8768’ (10/2/23) with Rig 401 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 13 LB 4C L- 5A L CBL TOC 6,030’ 8 9 11 10 7 CBL TOC ~4382’ Tubing cut @ 5905’ Milled 5” CIBP pushed to 5444’ 5&6 P6 2 3 Page 2 of 2 Updated by DMA 05-30-25 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 4B L 7,275’ 7,293’ 6,963’ 6,980’ 12/8/23 2” Isolated LB 4B L 7,275’ 7,285’ 6,963’ 6,372’ 1/18/24 2.125” Isolated LB 4B L 7,285’ 7,293’ 6,372’ 6,980’ 1/17/24 2.125” Isolated LB 4C L 7,341’ 7,355’ 7,025’ 7,038’ 12/7/23 2” Isolated LB 5A Up 7,420’ 7,426’ 7,098’ 7,104’ 12/7/23 2” Isolated LB 5A Mid 7,434’ 7,442’ 7,111’ 7,119’ 12/8/23 2” Isolated LB 5A L 7,447’ 7,460’ 7,123’ 7,136’ 12/7/23 2” Isolated LB5AL 7,449’ 7,459’ 7,125’ 7,135’ 1/17/24 2.125” Isolated LB 5C 7,522’ 7,552’ 7,193’ 7,221’ 12/6/23 2” Isolated LB 6A 7,584’ 7,590’ 7,251’ 7,257’ 12/6/23 2” Isolated TY 72 8 7,645’ 7,685’ 7,336’ 7,345’ 11/18/23 2” Isolated UT-1B 7,825’ 7,840’ 7,476’ 7,490’ 11/17/23 2” Isolated UT 4D (coal) 8,552’ 8,578’ 8,157’ 8,181’ 11/6/23 2-1/8” Strip Isolated UT 4E (coal) 8,674’ 8,690' 8,272’ 8,287’ 11/3/23 2-1/8” Strip Isolated LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075' 6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091' 6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224' 6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251' 6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293' 6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341' 7,355' 7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420' 7,426' 7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434' 7,442' 7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460' 7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section: 6 Township: 4N Range: 11W Meridian: Seward Drilling Rig: N/A Rig Elevation: N/A Total Depth: 10,200 ft MD Lease No.: FEEA028142 Operator Rep: Suspend: P&A: X Conductor: 16" O.D. Shoe@ 136 Feet Csg Cut@ Feet Surface: 10 3/4" O.D. Shoe@ 1524 Feet Csg Cut@ Feet Intermediate: 7 5/8" O.D. Shoe@ 8012 Feet Csg Cut@ Feet Production: 5" O.D. Shoe@ 10184 Feet Csg Cut@ Feet Liner: O.D. Shoe@ Feet Csg Cut@ Feet Tubing: 2 7/8" O.D. Tail@ 8773 Feet Tbg Cut@ 5905 Feet Type Plug Founded on Depth (Btm) Depth (Top) MW Above Verified Fullbore Bridge plug 4820 ft 4801 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing 3121 3121 3121 IA 141 142 141 OA 28 28 28 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Cole Bartlewski Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Converting well to gas storage completion. Bridge plug/cement plug in 5" casing to isolate the Upper Beluga prior to perforating the Kenai Sterling Gas Pool 6. The MITT is the last 30 min of a 70+ hour N2 test. Tagging cement was done with eline. Top of cement was found to be 6 feet low. May 6, 2025 Bob Noble Well Bore Plug & Abandonment KBU 22-06Y Hilcorp Alaska, LLC PTD 2150440; Sundry 325-153 none Test Data: P Casing Removal: rev. 3-24-2022 2025-0506_Plug_Verification_KBU_22-06Y_bn 9 9 9 9 9 9 9 99 9 9 9 9 99 9 9 9 999 9 9 9 9 9 9 9 p gpg pg g MITT is the last 30 min of a 70+ hour N2 test g Top ofg cement was found to be 6 feet low. James B. Regg Digitally signed by James B. Regg Date: 2025.05.15 11:51:31 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 5/29/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250529 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 5/10/2025 AK E-LINE GPT/CIBP/Perf HVB 13A 50231200320100 224160 3/16/2025 YELLOWJACKET SCBL IRU 241-01 50283201840000 221076 5/7/2025 AK E-LINE Plug/Perf KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf KBU 24-06RD 50133204990100 206013 4/8/2025 YELLOWJACKET GPT-PLUG MPI 1-61 50029225200000 194142 5/10/2025 AK E-LINE Perf MPU E-42 50029236350000 219082 5/3/2025 AK E-LINE Patch MPU S-55 50029238130000 225006 5/13/2025 AK E-LINE CBL OP16-03 50029234420000 211017 4/25/2025 READ LeakDetect PAXTON 13 50133207330000 225021 4/29/2025 YELLOWJACKET SCBL PBU 01-12B 50029202690200 223090 4/8/2025 HALLIBURTON RBT PBU D-08B 50029203720200 225007 3/22/2025 BAKER MRPM PBU H-17B (REVISION)50029208620100 197152 4/10/2025 HALLIBURTON RBT-COILFLAG PBU J-25B 50029217410200 224134 3/10/2025 BAKER MRPM PBU K-19C (REVISION)50029225310300 224004 3/27/2025 BAKER MRPM PBU K-19C 50029225310300 224004 3/27/2025 HALLIBURTON RBT SRU 241-33B 50133206960000 221053 3/12/2025 YELLOWJACKET PERF Revision Explanation: Both wells had wrong side stack well name and API#/PTD on previous upload H-17b was marked as H-17A and K-19C was marked as K-19B. Well name now reflets correct sidetrack and has correct SPI# and PTD. T40489 T40490 T40491 T40492 T40492 T40493 T40494 T40495 T40496 T40497 T40498 T40499 T40500 T40501 T40502 T40503 T40503 T40504 KBU 22-06Y 50133206500000 215044 5/6/2025 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 5/7/2025 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.05.29 14:33:01 -08'00' From:McLellan, Bryan J (OGC) To:Stefan Reed Cc:Donna Ambruz; Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Date:Wednesday, May 7, 2025 11:03:00 AM Attachments:image003.png Stefan, As discussed, 25’ of cement is sufficient to proceed with perforating. Regards 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: Wednesday, May 7, 2025 10:58 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Regg, James B (OGC) <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Bryan, We tagged TOC @ 4795’, the plug was set at 4820’, confirming we have the required 25’ of cement. We are going to continue with the perforations per sundry. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, May 6, 2025 1:56 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; jim.regg <jim.regg@alaska.gov> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Stefan, Approved. 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: Tuesday, May 6, 2025 12:51 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Bryan, As discussed, our PT on 22-06Y passed but the cement top was not sufficient. Plan is to dump additional cement and perform another witnessed tag tomorrow. We will not re-pressure test the plug. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, April 29, 2025 11:49 AM To: Stefan Reed <Stefan.Reed@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Sounds good. Approved. 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: Tuesday, April 29, 2025 10:10 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Bryan, We tagged TOC @ 4845.5’, calculated TOC was 4836’. We are going to move forward with setting another plug and dump bailing cement. Planned set depth for CIBP is ~4820’ MD and we will dump bail an additional 30’ of cement. Regards, Stefan Reed 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. Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Monday, April 28, 2025 4:52 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Stefan, Hilcorp has approval to proceed with this plan. 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: Monday, April 28, 2025 3:20 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Bryan, After setting a plug @ 4855’ and dumping ~30’ of cement we attempt to PT the plug which failed. We tagged the plug today and only have ~5’ of cement above the plug. Plan forward is to dump bail 10 gals of cement (~13’) today, 28-Apr-25. Tomorrow (29-Apr-2025) we will tag TOC, if cement top is sufficient, we will dump bail an additional ~15gal (~20’) and reattempt the pressure test. If TOC is insufficient plan is to set a new CIBP @ ~4810’ and dump bail 30’ of cement on top. I’ll will let you know our results of the tag tomorrow. 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 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 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. 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 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 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. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that 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 theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. From:McLellan, Bryan J (OGC) To:Stefan Reed Cc:Donna Ambruz; Regg, James B (OGC) Subject:RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Date:Tuesday, May 6, 2025 1:55:00 PM Attachments:image003.png Stefan, Approved. 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: Tuesday, May 6, 2025 12:51 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Bryan, As discussed, our PT on 22-06Y passed but the cement top was not sufficient. Plan is to dump additional cement and perform another witnessed tag tomorrow. We will not re-pressure test the plug. Regards, Stefan Reed Operations Engineer Kenai Asset Team Cell: 206-518-0400 Hilcorp Alaska, LLC CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, April 29, 2025 11:49 AM To: Stefan Reed <Stefan.Reed@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Sounds good. Approved. 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: Tuesday, April 29, 2025 10:10 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Bryan, We tagged TOC @ 4845.5’, calculated TOC was 4836’. We are going to move forward with setting another plug and dump bailing cement. Planned set depth for CIBP is ~4820’ MD and we will dump bail an additional 30’ of cement. 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: Monday, April 28, 2025 4:52 PM To: Stefan Reed <Stefan.Reed@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Stefan, Hilcorp has approval to proceed with this plan. 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: Monday, April 28, 2025 3:20 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Bryan, After setting a plug @ 4855’ and dumping ~30’ of cement we attempt to PT the plug which failed. We tagged the plug today and only have ~5’ of cement above the plug. Plan forward is to dump bail 10 gals of cement (~13’) today, 28-Apr-25. Tomorrow (29-Apr-2025) we will tag TOC, if cement top is sufficient, we will dump bail an additional ~15gal (~20’) and reattempt the pressure test. If TOC is insufficient plan is to set a new CIBP @ ~4810’ and dump bail 30’ of cement on top. I’ll will let you know our results of the tag tomorrow. 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, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Stefan Reed Cc:Donna Ambruz Subject:RE: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Date:Monday, April 28, 2025 4:51:00 PM Attachments:image003.png Stefan, Hilcorp has approval to proceed with this plan. 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: Monday, April 28, 2025 3:20 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: KBU 22-06Y (PTD# 215-044) Pool Isolation Plug Bryan, After setting a plug @ 4855’ and dumping ~30’ of cement we attempt to PT the plug which failed. We tagged the plug today and only have ~5’ of cement above the plug. Plan forward is to dump bail 10 gals of cement (~13’) today, 28-Apr-25. Tomorrow (29-Apr-2025) we will tag TOC, if cement top is sufficient, we will dump bail an additional ~15gal (~20’) and reattempt the pressure test. If TOC is insufficient plan is to set a new CIBP @ ~4810’ and dump bail 30’ of cement on top. I’ll will let you know our results of the tag tomorrow. 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 responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 4/02/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250402 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 19RD 50133205790100 219188 3/20/2025 YELLOWJACKET GPT-PERF BCU 19RD 50133205790100 219188 3/16/2025 YELLOWJACKET PLUG BRU 212-26 50283201820000 220058 3/21/2025 AK E-LINE Perf BRU 212-26 50283201820000 220058 3/15/2025 AK E-LINE Perf CLU 7 50133205310000 203191 1/22/2025 YELLOWJACKET PLUG IRU 11-06 50283201300000 208184 3/20/2025 AK E-LINE Perf KALOTSA 10 50133207320000 224147 3/1/2025 YELLOWJACKET GPT-PLUG-PERF KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF KU 13-06A 50133207160000 223112 3/18/2025 AK E-LINE CIBP MPE-20A 50029225610100 204054 3/13/2025 READ CaliperSurvey MPI 1-39A 50029218270100 206187 3/4/2025 YELLOWJACKET PERF MPU C-01 50029206630000 181143 1/30/2025 YELLOWJACKET PERF MPU K-17 50029226470000 196028 2/7/2025 AK E-LINE Caliper MPU S-53 50029238110000 224159 3/7/2025 YELLOWJACKET SCBL MRU A-15RD2 50733201050200 202019 3/10/2025 AK E-LINE TubingCut PBU 18-27E 50029223210500 212131 3/15/2025 YELLOWJACKET RCT PBU B-30A 50029215420100 201105 3/7/2025 READ CaliperSurvey PBU S-10A 50029207650100 191123 11/18/2024 YELLOWJACKET CBL-TEMP PBU W-220A 50029234320100 224161 2/22/2025 YELLOWJACKET SCBL Revision explanation: Fixed API# on log and .las files Please include current contact information if different from above. T40256 T40256 T40257 T40257 T40258 T40259 T40260 T40261 T40262 T40263 T40264 T40265 T40266 T40267 T40268 T40269 T40270 T40271 T40272 KBU 22-06Y 50133206500000 215044 1/25/2025 YELLOWJACKET GPT-PLUG-PERF Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.04.02 12:55:27 -08'00' 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: 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): 10,200'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 10,500psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Swell Pkr; N/A 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: Stefan Reed, Operations Engineer Contact Email:stefan.reed@hilcorp.com Contact Phone: 206-518-0400 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 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: 5,019' MD / 4,853' TVD; N/A, N/A Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Noel Nocas, Operations Manager 907-564-5278 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 FEEA028142 215-044 50-133-20650-00-00 Hilcorp Alaska, LLC Proposed Pools: L-80 TVD Burst 8,773 10,140psi 1,506' 6,890 psi 5,210 psi1,524' MD 10-3/4" March 26, 2025 2-7/8" 10,184' 1,555 psi 10,184' 136' 7,651' 136' 1,524' Size 136' 7-5/8"8,012' 5,215'5,036' Perforation Depth MD (ft): 8,012' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 22-06YCO 510C Sterling Pool 6 9,682'5" Kenai Beluga-Up Tyonek Gas, Tyonek Gas 16" See Attached Schematic See schematic Length See Attached Schematic 9,697' m n P t r: N 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 2:30 pm, Mar 19, 2025 325-153 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.03.19 13:41:48 - 08'00' Noel Nocas (4361) Provide AOGCC 24 hrs notice to witness isolation plug tag and PT w/ N2 in final 24 hrs of test.10-404 DSR-3/28/25BJM 4/3/25 Gas storage production only. Gas storage injection prohibited without additional AOGCC approval. Perform MITIA to 1500 psi after put on production, but within 30 days after first production. SFD 3/21/2025 X Sterling Pool 6 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.04.04 09:47:39 -08'00'04/04/25 RBDMS JSB 040825 Pool 6 Perfs Rev. 1 Well: KBU 22-06Y Date: 4-Feb-25 Well Name: KBU 22-06Y API Number: 50-133-20650-00 Current Status: SI Gas well Permit to Drill Number: 215-044 First Call Engineer: Stefan Reed (206) 518-0400 Second Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Maximum Expected BHP: 2026 psi @ 4712’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure: 1555 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient: 0.624 psi/ft using 12.0 ppg EMW FIT at the surface casing shoe 4/12/15 Shallowest Potential Perf TVD: MPSP/(0.624-0.1) = 1555 psi / 0.524 = 2968‘ TVD Top of Pools per CO 510C: Beluga/Upper Tyonek Pool: 4845’ MD, 4691' TVD Brief Well Summary KBU 22-06Y was drilled and completed in the Tyonek D Sands in 2015 by Hilcorp. It was perf’d and produced in the D3A and in 2016 the D2 was added. At its peak, it was producing at rates around 6600 mcfd. In mid-2021, Tyonek and Upper Beluga/Tyonek Pools were commingled when the Ty 72_8 and the UT 1B were added with subpar results. The Tyonek Gas Pool was isolated in August of 2022 with a plug set at 8,990’. Rate was stable until additional lower Beluga perfs were added and killed the well. A workover was conducted in 2023 to cement in a 2-7/8” tubing string and try to return original production, with being more selective with perforations, but the well never sustained any stable flow. In January 2025 the lower perforations were isolated and the 2-7/8” tubing was cut and pulled to expose the 5” casing string. Perforations were added in the upper beluga but would not sustain flow. The purpose of this project is to isolate the UB perforations and perforate the pool 6 sands to convert the well to a gas storage producer. Well Status: SI gas producer Notes Regarding Wellbore Condition x CIBP @ 5,215’ w/ open perfs 4,868’-4,883’ and 5,201’-5,211’ Pool Tops: x Sterling Pool 6 – 4591’ MD/4453’ TVD x Beluga/Upper Tyonek – 4845’ MD/4691’ TVD Eline Procedure 1. MIRU E-line 2. PT lubricator to 250/2500 psi 3. Log GPT to CIBP @ 5215’ to confirm fluid level. Push fluid away as necessary. 4. RIH and set 5” CIBP @ ~4860’ 5. Dump bail 30’ cement (~25gals) 6. 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 72- hrs. Beluga/Upper Tyonek Pool: 4845’ MD Cement bond in 5" x 7-5/8" annulus is questionable above perf interval and must be tested with an MITIA after the well comes on-line, but within 30 days of first production. The cement in the annulus acts as a production packer. The TOC outside the 7-5/8" liner is well above the planned perf depth and will provide isolation. -bjm Test pressure must be maintained > 2500 psi throughout test. -bjm CO 510C Sterling Pool 6 – 4591’ MD/ Gas Storage Pool: Recommend checking bond quality on Sector Bond Log recorded Jan. 11, 2025. SFD Beluga/Upper Tyonek – 4845’ MD/ perforate the pool 6 sands to convert the well to a gas storage producer Pool 6 Perfs Rev. 1 Well: KBU 22-06Y Date: 4-Feb-25 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 a minimum 24hr notice to AOGCC for witness tag and test. 7. PU 3-3/8” or similar perf guns and perforate proposed intervals: 8. Make a correlation pass and send log in to operations engineer, reservoir engineer and geologist. a. Record initial and 5/10/15 minute tubing pressures after firing. b. Reperforate any zones per RE/GEO. c. Above perfs will be shot in the Kenai Sterling Gas Pool 6 governed by CO 510C 9. RD E-Line unit and turn well over to operations for conversion to storage well. Attachments: 1. Current Schematic 2. Proposed Schematic Sands Top MD Btm MD Top TVD Btm TVD FT Sterling P6 ±4,594’ ±4,694 ±4,456’ ±4,549’ ±100’ Perform MITIA to 1500 psi with liquid after POP, but within 30 days of flowing the well. -bjm Page 1 of 2 Updated by SAR 02-13-25 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PBTD = 8,724’ MD / 8,319’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No.Depth ID OD Item 1 18’4.276”11.00”Tubing Hanger 2 5,019’4.276”6.875”10 ft Swell Packer (Water Swell) 3 5,215’5”CIBP 4 5,259’5” CIBP 5 6,450’2.441”CIBP w/ 20’ of cement 6 7,510’2.441”CIBP (12/7/23) 7 7,635’2.441”CIBP w/ 10’ of cmt (12/5/23) 8 8,510’2.441”CIBP w/ 10ft of cement (11/17/23) 9 8,768’4.276”Milled & push CIBP 10 8,990’-4.276”CIBP w/ 25ft of cement (8/20/22) 11 10,065’-3.710”Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8"244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5”132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8”45 bbls of 15.3#. TOC 6,030’ based on CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00”Surf 136' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 1,524’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 8,012’ TUBING 5"Production 18 L-80 DWC/C-HT 4.276”Surf 10,184’ 2-7/8”Production 6.5 L-80 8RD EUE 2.441”5,905’8,773’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBL TOC 5,008’ 10 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Date Size Status Top Beluga/Upper Tyonek Pool, 4845’ MD & 4691’ TVD UB 4,868’4,883’4,712’4,762’1/28/25 2-3/4”Open UB 5 5,201’5,211’5,023’5,032’1/28/25 2-3/4”Open UB 5A Upper 5,217’5,222’5,037’5,042’1/26/25 2-3/4”Isolated UB 5A Lower 5,230’5,244’5,050’5,063’1/26/25 2-3/4”Isolated UB 5B 5,264’5,283’5,082’5,099’1/25/25 2-3/4”Isolated LB 1B 6,461’6,473’6,201’6,212’12/30/23 2”Isolated LB 1C 6,520’6,526’6,257’6,262’12/30/23 2”Isolated LB 2B 6,792’6,812’6,511’6,530’12/30/23 2”Isolated LB 2E 6,962’6,974’6,670’6,682’12/30/23 2”Isolated LB 3 6,998’7,006’6,704’6,712’12/30/23 2”Isolated LB 3B Upr 7,069’7,075’6,770’6,776’12/30/23 2”Isolated LB 3B Mid 7,083’7,091’6,783’6,791’12/29/23 2”Isolated LB 4A Upr 7,218’7,224’6,910’6,915’12/29/23 2”Isolated LB 4A 7,231’7,251’6,922’6,940’12/8/23 2”Isolated PERFORATION DETAIL continued on following page LB 1 - L4B L TY 72_8 Fish: Milled CIBP to 8768’ (10/2/23) with Rig 401 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 11 LB 4C L- 5A L CBL TOC 6,030’ 6 7 9 8 5 CBL TOC ~4382’ Tubing cut @ 5905’ Milled 5” CIBP pushed to 5444’ 3&4 Page 2 of 2 Updated by SAR 02-13-25 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 4B L 7,275’ 7,293’ 6,963’ 6,980’ 12/8/23 2” Isolated LB 4B L 7,275’ 7,285’ 6,963’ 6,372’ 1/18/24 2.125” Isolated LB 4B L 7,285’ 7,293’ 6,372’ 6,980’ 1/17/24 2.125” Isolated LB 4C L 7,341’ 7,355’ 7,025’ 7,038’ 12/7/23 2” Isolated LB 5A Up 7,420’ 7,426’ 7,098’ 7,104’ 12/7/23 2” Isolated LB 5A Mid 7,434’ 7,442’ 7,111’ 7,119’ 12/8/23 2” Isolated LB 5A L 7,447’ 7,460’ 7,123’ 7,136’ 12/7/23 2” Isolated LB5AL 7,449’ 7,459’ 7,125’ 7,135’ 1/17/24 2.125” Isolated LB 5C 7,522’ 7,552’ 7,193’ 7,221’ 12/6/23 2” Isolated LB 6A 7,584’ 7,590’ 7,251’ 7,257’ 12/6/23 2” Isolated TY 72 8 7,645’ 7,685’ 7,336’ 7,345’ 11/18/23 2” Isolated UT-1B 7,825’ 7,840’ 7,476’ 7,490’ 11/17/23 2” Isolated UT 4D (coal) 8,552’ 8,578’ 8,157’ 8,181’ 11/6/23 2-1/8” Strip Isolated UT 4E (coal) 8,674’ 8,690' 8,272’ 8,287’ 11/3/23 2-1/8” Strip Isolated LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075' 6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091' 6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224' 6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251' 6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293' 6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341' 7,355' 7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420' 7,426' 7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434' 7,442' 7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460' 7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated Page 1 of 2 Updated by SAR 02-13-25 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 PROPOSED PBTD = 8,724’ MD / 8,319’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No.Depth ID OD Item 1 18’4.276”11.00”Tubing Hanger 4860’CIBP w/ 30’ of cmt 2 5,019’4.276”6.875”10 ft Swell Packer (Water Swell) 3 5,215’5”CIBP 4 5,259’5” CIBP 5 6,450’2.441”CIBP w/ 20’ of cement 6 7,510’2.441”CIBP (12/7/23) 7 7,635’2.441”CIBP w/ 10’ of cmt (12/5/23) 8 8,510’2.441”CIBP w/ 10ft of cement (11/17/23) 9 8,768’4.276”Milled & push CIBP 10 8,990’-4.276”CIBP w/ 25ft of cement (8/20/22) 11 10,065’-3.710”Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8"244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5”132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8”45 bbls of 15.3#. TOC 6,030’ based on CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00”Surf 136' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 1,524’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 8,012’ TUBING 5"Production 18 L-80 DWC/C-HT 4.276”Surf 10,184’ 2-7/8”Production 6.5 L-80 8RD EUE 2.441”5,905’8,773’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBL TOC 5,008’ 10 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Date Size Status Top Pool 6, 4591’ MD & 4453’ TVD P6 4,594’4,694’4,456’4,549’TBD 3-3/8”Proposed Top Beluga/Upper Tyonek Pool, 4845’ MD & 4691’ TVD UB 4,868’4,883’4,712’4,762’1/28/25 2-3/4”Isolated UB 5 5,201’5,211’5,023’5,032’1/28/25 2-3/4”Isolated UB 5A Upper 5,217’5,222’5,037’5,042’1/26/25 2-3/4”Isolated UB 5A Lower 5,230’5,244’5,050’5,063’1/26/25 2-3/4”Isolated UB 5B 5,264’5,283’5,082’5,099’1/25/25 2-3/4”Isolated LB 1B 6,461’6,473’6,201’6,212’12/30/23 2”Isolated LB 1C 6,520’6,526’6,257’6,262’12/30/23 2”Isolated LB 2B 6,792’6,812’6,511’6,530’12/30/23 2”Isolated LB 2E 6,962’6,974’6,670’6,682’12/30/23 2”Isolated LB 3 6,998’7,006’6,704’6,712’12/30/23 2”Isolated LB 3B Upr 7,069’7,075’6,770’6,776’12/30/23 2”Isolated LB 3B Mid 7,083’7,091’6,783’6,791’12/29/23 2”Isolated LB 4A Upr 7,218’7,224’6,910’6,915’12/29/23 2”Isolated LB 4A 7,231’7,251’6,922’6,940’12/8/23 2”Isolated PERFORATION DETAIL continued on following page LB 1 - L4B L TY 72_8 Fish: Milled CIBP to 8768’ (10/2/23) with Rig 401 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 11 LB 4C L- 5A L CBL TOC 6,030’ 6 7 9 8 5 CBL TOC ~4382’ Tubing cut @ 5905’ Milled 5” CIBP pushed to 5444’ 3&4 Note: Proposed perfs are below 7-5/8" TOC. -bjm Page 2 of 2 Updated by SAR 02-13-25 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 PROPOSED PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 4B L 7,275’ 7,293’ 6,963’ 6,980’ 12/8/23 2” Isolated LB 4B L 7,275’ 7,285’ 6,963’ 6,372’ 1/18/24 2.125” Isolated LB 4B L 7,285’ 7,293’ 6,372’ 6,980’ 1/17/24 2.125” Isolated LB 4C L 7,341’ 7,355’ 7,025’ 7,038’ 12/7/23 2” Isolated LB 5A Up 7,420’ 7,426’ 7,098’ 7,104’ 12/7/23 2” Isolated LB 5A Mid 7,434’ 7,442’ 7,111’ 7,119’ 12/8/23 2” Isolated LB 5A L 7,447’ 7,460’ 7,123’ 7,136’ 12/7/23 2” Isolated LB5AL 7,449’ 7,459’ 7,125’ 7,135’ 1/17/24 2.125” Isolated LB 5C 7,522’ 7,552’ 7,193’ 7,221’ 12/6/23 2” Isolated LB 6A 7,584’ 7,590’ 7,251’ 7,257’ 12/6/23 2” Isolated TY 72 8 7,645’ 7,685’ 7,336’ 7,345’ 11/18/23 2” Isolated UT-1B 7,825’ 7,840’ 7,476’ 7,490’ 11/17/23 2” Isolated UT 4D (coal) 8,552’ 8,578’ 8,157’ 8,181’ 11/6/23 2-1/8” Strip Isolated UT 4E (coal) 8,674’ 8,690' 8,272’ 8,287’ 11/3/23 2-1/8” Strip Isolated LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075' 6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091' 6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224' 6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251' 6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293' 6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341' 7,355' 7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420' 7,426' 7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434' 7,442' 7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460' 7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz; Stefan Reed Subject:RE: KBU 22-06Y (PTD# 215-044) Sundry # 324-687 changes Date:Sunday, January 12, 2025 3:16:00 PM Chad, Hilcorp has approval for the revised plan with the following condition: 1. Perform MITIA to 1800 psi on 5” x 7-5/8” annulus after the well has been put on-line, but within 30 days of post-perf production. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Sunday, January 12, 2025 8:32 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Stefan Reed <Stefan.Reed@hilcorp.com> Subject: KBU 22-06Y (PTD# 215-044) Sundry # 324-687 changes Bryan, As we briefly discussed yesterday we are making some changes to the workover on KBU 22- 06Y (PTD# 215-044). We got to step 13 and were unable to establish any circulation. We actually punched 2 more times shallower than proposed and still unable to get circ. We ran a new bond log (attached and found there is cement between the 5” and 7-5/8” casing up to 4382’. While this cement top isn’t as high as we proposed in the program, it definitely provides isolation for the proposed perfs and cement at the top of the current pool at 4845’ and the next pool at 4591’. Because of this, we are skipping steps 15-21, and steps 29-31, because they have already been accomplished. Please let me know if you have any questions or need additional information on this. Regards Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI BELUGA UNIT 22-06Y JBR 03/13/2025 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:1 Had 1 Fail on manual Choke had a bad seat and replaced passed. Accumulator bottles avg precharge 1250 psi. everything else went well. Test Results TEST DATA Rig Rep:Buddy MarshallOperator:Hilcorp Alaska, LLC Operator Rep:Cole Bartalewski Rig Owner/Rig No.:Fox 10 PTD#:2150440 DATE:1/19/2025 Type Operation:WRKOV Annular: Type Test:INIT Valves: 250/3500 Rams: 250/3500 Test Pressures:Inspection No:bopKPS250119224134 Inspector Kam StJohn Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 3 MASP: 1682 Sundry No: 324-687 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 0 NA Inside BOP 0 NA FSV Misc 0 NA 5 PNo. Valves 2 FPManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 1 2"P Annular Preventer 0 NA #1 Rams 1 Blind/Shears P #2 Rams 1 2" Pipe/Slips P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 2 2" Plug P HCR Valves 0 NA Kill Line Valves 2 2" Plug P Check Valve 0 NA BOP Misc 0 NA System Pressure P2900 Pressure After Closure P2200 200 PSI Attained P2 Full Pressure Attained P10 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)NA0 ACC Misc NA0 NA NATrip Tank NA NAPit Level Indicators NA NAFlow Indicator NA NAMeth Gas Detector NA NAH2S Gas Detector NA NAMS Misc Inside Reel Valves 1 P Annular Preventer NA0 #1 Rams P23 #2 Rams P23 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke NA0 HCR Kill NA0 9 9 9 999 9 9 9 9 Fail on manual Choke Manual Chokes FP 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2, Cmt Sqz 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 10,200 feet See Schematic feet true vertical 9,697 feet N/A feet Effective Depth measured 5,215 feet 5,019 feet true vertical 5,036 feet 4,853 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L-80 8,773' MD 8,364'' TVD Packers and SSSV (type, measured and true vertical depth)Swell Pkr; N/A 5,019' MD 4,853' TVD N/A; 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:Belugla/Upper Tyonek Gas Pool 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: Stefan Reed, Operations Engineer 324-687 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 measured true vertical Packer Representative Daily Average Production or Injection Data 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 136' 0 950 0 8490 62 Production Liner 8,012' 1,524' 10,184' measured TVD 7-5/8" 5" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-044 50-133-20650-00-00 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: FEDA 028142 Kenai Gas Field - Beluga/Up Tyonek Gas, Tyonek Gas Kenai Beluga Unit (KBU) 22-06Y Plugs Junk measured Length Burst Collapse 2,470psi Casing Structural 7,651' 9,682' 8,012' 10,184' 136'Conductor Surface Intermediate 16" 10-3/4" 136' stefan.reed@hilcorp.com 206-518-0400 4,790psi 10,500psi 5,210psi 6,890psi 10,140psi 1,524'1,506' Casing Pressure Tubing Pressure 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 Gavin Gluyas at 7:56 am, Feb 27, 2025 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2025.02.26 15:47:28 - 09'00' Noel Nocas (4361) DSR-2/28/25 BJM 4/28/25 X DSR-2/28/25 RBDMS JSB 030325 DSR-2/28/25 Page 1/2 Well Name: KEU KBU 22-06Y Report Printed: 2/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Jobs Actual Start Date:12/20/2024 End Date: Report Number 1 Report Start Date 1/4/2025 Report End Date 1/5/2025 Last 24hr Summary PTW/PJSM, MIRU YJ Eline, PT 250/2000, Ran CCL, 2.25" junk basket to 6565' no tag, Set 2.10" CIBP @ 6450', Dumped 5 gals. cement on CIBP. Est TOC @ 6430', YJ LDFN, MIRU Fox pumping, loaded tbg with 16.6 bbls FW. Report Number 2 Report Start Date 1/5/2025 Report End Date 1/6/2025 Last 24hr Summary PTW/PJSM, Cut tbg @ 5905', Unable to pass cut after. Pumping down the tbg, took 3bbls of methenol to pressure up tbg & IA to 1500 for a PT (pass)Circ .5bbls through cut, swap to IA & pump ~1bbl methenol to freeze protect. Report Number 3 Report Start Date 1/9/2025 Report End Date 1/10/2025 Last 24hr Summary MIRU 401 on KBU 22-06Y. Report Number 4 Report Start Date 1/10/2025 Report End Date 1/11/2025 Last 24hr Summary Install BPV, N/D production tree, N/U BOPE, R/U Floor & install tarps,Test BOPE, RD test equip, pull test plug and BPV, fill well and monitor hole 10 min no flow, install LJ, BOLDS, Pull hanger to rig floor PUW=38K, POOH Racking back 5321' of 2-7/8, LD 17 jts, RU E-line. Report Number 5 Report Start Date 1/11/2025 Report End Date 1/12/2025 Last 24hr Summary RU Yellow Jacket E-line. RIH with 5’’ Composite plug and set at 5000’. POOH MU 2’ casing punch. RIH to 4970’. Pressure up well to 325psi punch hole and attempt to circ well with no luck. Punched the 5''csg two more times at 4810’ and 4845’ with no luck circ through the annulus. Discussed with the OE and pressured up well to 4000psi and held for 10min with no leak off. RIH with SCBL logged from 5000’ – 3400’. Free pipe at 4380’. POOH RDMO Yellow Jacket. MU milling BHA RIH to 5000’ with 2-7/8’’ tbg. MU Power Swivel. Mill up composite plug as per Yellow Jacket rep. RIH to 5444’ Report Number 6 Report Start Date 1/12/2025 Report End Date 1/13/2025 Last 24hr Summary R/u to circ, Circ 1.5 x, bu, Blew lines out, R/d circ equip, Pooh l/d f/ 5444' t/2662', Fix pipe handler, Cont. pooh l/d f/ 2662' t/122',Chaged out handling eq. L/d Drill collars and mill. R/d rack and catwalk, L/d power swivel from derrick. N/d circ head, set TWC, R/d tarps and floor, removed stairs. N/d BOP's and 7" tbg head, N/u 5" production tree. Test void to 5000psi good test. Test tree to 5000psi good test. Pull TWC. Preform MIT on the 5'' TBG 2500psi for charted 30 min good test. Preform MIT on the IA 2000psi for charted 30 min good test. Continue RDMO ops from KBU 22-06Y. Report Number 7 Report Start Date 1/19/2025 Report End Date 1/20/2025 Last 24hr Summary PTW, JSA with crew. MIRU Fox energy CTU # 10 with 2.0" coil. Start BOPE test with State Rep Kam St. John. TEst all rams and valves 250/3500 psi. NOte one fail pass for manual choke. Transfer N2 from transport to pump unit. Report Number 8 Report Start Date 1/20/2025 Report End Date 1/21/2025 Last 24hr Summary PTW, JSA. Fox Energy CTU 10 with 2.0" coil. Pick injector head and stab lubricator. Make up internal CC , stinger and ball drop reverse out nozzle. Stab on well. PT stack 250/3500 psi. RIH. Perform wieght checks as per procedure. Dry tag PBTD 5345" CTMD. PIck up 24K clean. Park coil at 5342'. N2 cooled down. Onilne with N2 down CT x Casing IA taking returns from coil. Tank strap of 113 bbls when N2 hit surface. 110,000 scf pumped to unload wellbore volume (1200 gallons). Remain on bottom for 25 minutes to dry tubing /casing walls. POOH to surface. SHut down N2 and close in well at CTU choke skid. Tagged up at surface. Total N2 pumped 165K or 1800 gallons. CLose master and swab valve and trap 1120 psi SITP. Bleed down CT string to open top tank. RIg down FOx CTU and demobe from field. Report Number 9 Report Start Date 1/25/2025 Report End Date 1/26/2025 Last 24hr Summary PTW/PJSM. MIRU Yellow Jacket E-line. P-test 250/2,500 psi. Run GPT - fluid level at 5,290'. Perforate UB 5B Sand (5,264' - 5,283') with well shut-in. Flow test well. Run GPT - fluid level at 5,250'. Pressure up on well with gas and pushed fluid down to 5,300'. Set CIBP at 5,259'. SDFN. Report Number 10 Report Start Date 1/26/2025 Report End Date 1/27/2025 Last 24hr Summary PTW/PJSM. Perforate UB 5A Lower Sand (5,230' - 5,244') with well shut-in. Flow test well. Run GPT - fluid level at 5,243'. Perforate UB 5A Upper Sand (5,217' - 5,222') with well shut-in. SDFN and flow test well. Report Number 11 Report Start Date 1/28/2025 Report End Date 1/29/2025 Last 24hr Summary PTW/PJSM. Run GPT - fluid level at 5,170'. Pressure up on well with gas and pushed fluid down to 5,220'. Set CIBP at 5,215'. Perforate UB-5 Sand (5,201' - 5,211') with well shut-in. Flow test well. Run GPT - no fluid level seen. Perforate UB Sand (4,868' - 4,883') with well shut-in. RDMO E-line. Turn well over to Production to flow test. Field: Kenai Gas Field Sundry #: 324-687 State: Alaska Rig/Service:Permit to Drill (PTD) #:215-044Permit to Drill (PTD) #:215-044 Wellbore API/UWI:50-133-20650-00-00 Page 2/2 Well Name: KEU KBU 22-06Y Report Printed: 2/5/2025WellViewAdmin@hilcorp.com Alaska Weekly Report - Operations Report Number 12 Report Start Date 1/31/2025 Report End Date 2/1/2025 Last 24hr Summary 1,800 psi MIT – IA (5” x 7-5/8” annulus) - passed. Field: Kenai Gas Field Sundry #: 324-687 State: Alaska Rig/Service: Page 1 of 2 Updated by SAR 02-13-25 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PBTD = 8,724’ MD / 8,319’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No.Depth ID OD Item 1 18’4.276”11.00”Tubing Hanger 2 5,019’4.276”6.875”10 ft Swell Packer (Water Swell) 3 5,215’5”CIBP 4 5,259’5” CIBP 5 6,450’2.441”CIBP w/ 20’ of cement 6 7,510’2.441”CIBP (12/7/23) 7 7,635’2.441”CIBP w/ 10’ of cmt (12/5/23) 8 8,510’2.441”CIBP w/ 10ft of cement (11/17/23) 9 8,768’4.276”Milled & push CIBP 10 8,990’-4.276”CIBP w/ 25ft of cement (8/20/22) 11 10,065’-3.710”Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8"244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5”132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8”45 bbls of 15.3#. TOC 6,030’ based on CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00”Surf 136' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 1,524’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 8,012’ TUBING 5"Production 18 L-80 DWC/C-HT 4.276”Surf 10,184’ 2-7/8”Production 6.5 L-80 8RD EUE 2.441”5,905’8,773’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBL TOC 5,008’ 10 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Date Size Status Top Beluga/Upper Tyonek Pool, 4845’ MD & 4691’ TVD UB 4,868’4,883’4,712’4,762’1/28/25 2-3/4”Open UB 5 5,201’5,211’5,023’5,032’1/28/25 2-3/4”Open UB 5A Upper 5,217’5,222’5,037’5,042’1/26/25 2-3/4”Isolated UB 5A Lower 5,230’5,244’5,050’5,063’1/26/25 2-3/4”Isolated UB 5B 5,264’5,283’5,082’5,099’1/25/25 2-3/4”Isolated LB 1B 6,461’6,473’6,201’6,212’12/30/23 2”Isolated LB 1C 6,520’6,526’6,257’6,262’12/30/23 2”Isolated LB 2B 6,792’6,812’6,511’6,530’12/30/23 2”Isolated LB 2E 6,962’6,974’6,670’6,682’12/30/23 2”Isolated LB 3 6,998’7,006’6,704’6,712’12/30/23 2”Isolated LB 3B Upr 7,069’7,075’6,770’6,776’12/30/23 2”Isolated LB 3B Mid 7,083’7,091’6,783’6,791’12/29/23 2”Isolated LB 4A Upr 7,218’7,224’6,910’6,915’12/29/23 2”Isolated LB 4A 7,231’7,251’6,922’6,940’12/8/23 2”Isolated PERFORATION DETAIL continued on following page LB 1 - L4B L TY 72_8 Fish: Milled CIBP to 8768’ (10/2/23) with Rig 401 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 11 LB 4C L- 5A L CBL TOC 6,030’ 6 7 9 8 5 CBL TOC ~4382’ Tubing cut @ 5905’ Milled 5” CIBP pushed to 5444’ 3&4 Page 2 of 2 Updated by SAR 02-13-25 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 4B L 7,275’ 7,293’ 6,963’ 6,980’ 12/8/23 2” Isolated LB 4B L 7,275’ 7,285’ 6,963’ 6,372’ 1/18/24 2.125” Isolated LB 4B L 7,285’ 7,293’ 6,372’ 6,980’ 1/17/24 2.125” Isolated LB 4C L 7,341’ 7,355’ 7,025’ 7,038’ 12/7/23 2” Isolated LB 5A Up 7,420’ 7,426’ 7,098’ 7,104’ 12/7/23 2” Isolated LB 5A Mid 7,434’ 7,442’ 7,111’ 7,119’ 12/8/23 2” Isolated LB 5A L 7,447’ 7,460’ 7,123’ 7,136’ 12/7/23 2” Isolated LB5AL 7,449’ 7,459’ 7,125’ 7,135’ 1/17/24 2.125” Isolated LB 5C 7,522’ 7,552’ 7,193’ 7,221’ 12/6/23 2” Isolated LB 6A 7,584’ 7,590’ 7,251’ 7,257’ 12/6/23 2” Isolated TY 72 8 7,645’ 7,685’ 7,336’ 7,345’ 11/18/23 2” Isolated UT-1B 7,825’ 7,840’ 7,476’ 7,490’ 11/17/23 2” Isolated UT 4D (coal) 8,552’ 8,578’ 8,157’ 8,181’ 11/6/23 2-1/8” Strip Isolated UT 4E (coal) 8,674’ 8,690' 8,272’ 8,287’ 11/3/23 2-1/8” Strip Isolated LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075' 6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091' 6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224' 6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251' 6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293' 6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341' 7,355' 7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420' 7,426' 7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434' 7,442' 7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460' 7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250216 Well API #PTD #Log Date Log Company Log Type AOGCC Eset # BRU 232-04 50283100230000 132037 1/18/2025 AK E-LINE Perf CLU 08 50133205340000 204005 2/13/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 1/2/2025 YELLOWJACKET SCBL CLU 10RD2 50133205530200 224135 12/13/2024 YELLOWJACKET SCBL CLU 7 50133205310000 203191 1/25/2025 YELLOWJACKET SCBL IRU 44-36 50283200890000 193022 1/21/2025 AK E-LINE Plug/Perf KALOTSA 10 50133207320000 224147 2/11/2025 YELLOWJACKET SCBL KALOTSA 9 50133207310000 224145 1/26/2025 YELLOWJACKET SCBL KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL KU 13-06A 50133207160000 223112 1/12/2025 YELLOWJACKET SCBL MRU M-25 50733203910000 187086 1/15/2024 AK E-LINE PPROF NCIU A-21 50883201990000 224086 1/6/2024 AK E-LINE Plug/Perf PBU 06-05A 50029202980100 224115 1/14/2025 HALLIBURTON RBT PBU 09-35B 50029213140200 224122 2/3/2025 HALLIBURTON RBT PBU B-12B 50029203320200 224133 1/20/2025 HALLIBURTON RBT PBU D-12 50029204430000 180015 12/19/2024 BAKER SPN PBU F-08B 50029201350200 212040 1/27/2025 HALLIBURTON RBT PBU NK-41A 50029227780100 197158 12/18/2024 YELLOWJACKET CBL PBU S-100A 50029229620100 224083 1/5/2025 HALLIBURTON RBT Revision Explanation: Annotations added to processed log. Please include current contact information if different from above. 162-037 T40080 T40081 T40082 T40082 T40083 T40084 T40085 T40086 T40087 T40088 T40089 T40090 T40091 T40092 T40093 T40094 T40095 T40096 T40097 KBU 22-06Y 50133206500000 215044 1/11/2025 YELLOWJACKET SCBL Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.02.18 13:06:47 -09'00' 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, Cmt Sqz 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): 10,200'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 10,500psi 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 chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: 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 FEEA028142 215-044 50-133-20650-00-00 Hilcorp Alaska, LLC Proposed Pools: L-80 TVD Burst 8,773 10,140psi 1,506' Size 136' 7-5/8"8,012' 1,524' MD See Attached Schematic 6,890 psi 5,210 psi 136' 7,651' 136' 1,524' December 16, 2024 2-7/8" 10,184' Perforation Depth MD (ft): 8,012' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 22-06YCO 510C Same 9,682'5" 1,682 psi 10,184' See schematic Length N/A N/A 9,697' 7,510' 7,182' Kenai Beluga-Up Tyonek Gas, Tyonek Gas 16" 10-3/4" See Attached Schematic No Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:35 am, Dec 06, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.12.06 10:17:05 - 09'00' Noel Nocas (4361) 324-687 10-404 Rig 401 BOP test to 2500 psi CT BOP test to 2500 psi A.Dewhurst 17DEC24 DSR-12/16/24 Submit 5" CBL and obtain approval from AOGCC before perforating. X BJM 12/23/24 MEUIRUMOF Gregory C. Wilson Digitally signed by Gregory C. Wilson Date: 2024.12.24 12:01:57 -09'00'12/24/24 RBDMS JSB 123024 Well Prognosis Well: KBU 22-06Y Date: 12-2-24 Well Name:KBU 22-06Y API Number:50-133-20650-00 Current Status:SI Gas well Permit to Drill Number:215-044 First Call Engineer:Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer:Scott Warner (907) 830-8863 (c) Maximum Expected BHP:2192 psi @ 5099’ TVD (Based on 0.43 psi/ft gradient)) Max. Potential Surface Pressure:1682 psi (Based on 0.1 psi/ft gas gradient to surface) Applicable Frac Gradient:0.624 psi/ft using 12.0 ppg EMW FIT at the surface casing shoe 4/12/15 Shallowest Potential Perf TVD:MPSP/(0.624-0.1) = 1682 psi / 0.524 = 3209‘ TVD Top of Pools per CO 510C:Beluga/Upper Tyonek Pool: 4845’ MD, 4691' TVD Brief Well Summary KBU 22-06Y was drilled and completed in the Tyonek D Sands in 2015 by Hilcorp. It was perf’d and produced in the D3A and in 2016 the D2 was added. At its peak, it was producing at rates around 6600 mcfd. In mid-2021, Tyonek and Upper Beluga/Tyonek Pools were commingled when the Ty 72_8 and the UT 1B were added with subpar results. The Tyonek Gas Pool was isolated in August of 2022 with a plug set at 8,990’. Rate was stable until additional lower Beluga perfs were added and killed the well. A workover was conducted in 2023 to cement in a 2-7/8” tubing string and try to return original production, with being more selective with perforations, but the well never sustained any stable flow. The purpose of this work/sundry is to isolate current perfs, cut and pull 2-7/8” tubing, complete a remedial cement squeeze, drill out the cement retainer and plug, blow well dry with N2 and perforate the well in the upper Beluga sands, which are in the Beluga/Upper Tyonek Pool per CO 510C. Well Status: SI gas producer Notes Regarding Wellbore Condition x Production casing is 5” 18# L-80 tubing. x Max Inclination: 23deg @ 9014’ x Max DLS: ~4 degrees / 100’ at 753’ MD x 2-7/8” Cement with CBL – TOC @ 6,030’ x 5” Cement with RBCL – TOC @ 5,008’ x 7-5/8” Cement with RBCL – TOC @ 3,670’ Eline Procedure 1. Review all approved COAs 2. MIRU E-line, PT lubricator to 2000/250 psi 3. RIH and set CIBP @ ~6450’, place one 30ft bailer of cement on plug (~20ft of cement) Note: This plug is not a pool isolation plug, additional perfs will be added in current pool after the tubing is changed out. 4. Fill tubing with 8.4 ppg Produced water (~37 bbls) a. 0.0058 bbl/ft x 6450 = 37.33 bbls 5. RIH and cut tubing at ~5900’ (fluid in 2-7/8” x 5” annulus is 8.4 ppg water) 6. Perform jug test to 1500 psi (ensure cutter didn’t compromise the 5” casing) Tyonek gas pool is already isolated with cement. Well Prognosis Well: KBU 22-06Y Date: 12-2-24 7. POOH & RDMO Eline Procedure: 1. MIRU Hilcorp rig #401 2. Circulate well ~100bbls a. Annulus volume = .0097 bbl/ft x 5900 ft = 57.4 bbls b. Tubing volume = 0.0058 bbls/ft x 5900 ft = 34.2 bbls c. Total volume = 91.6 bbls 3. Set BPV / TWC 4. NU 7” BOP’s and test a. Provide 24 hr notice to AOGCC b. PT to 250psi low / 2500psi high c. Test with 2-7/8” 5. Pull BPV / TWC 6. Monitor well to ensure its static, fill well as necessary 7. Pull 2-7/8” tubing and rack back (~5000ft of tubing) 8. MIRU Eline, RU lubricator and PT to 250/1000 psi 9. PU 5” composite bridge plug, RIH and set at 5000’ 10. PU casing punch for 5” casing 11. Pressure up well to 325 psi (5” x 7-5/8” annulus is filled with 9.7 ppg mud @ 4808’ TVD) 12. Casing punch @ ~4970’ & POOH 13. Ensure there is circulation, and pump out 9.7 ppg mug from annulus (108 bbls of mud) a. 5” x 7-5/8” annulus volume = 0.0216 bbls/ft x 4970ft = 107.5 bbls 14. RDMO Eline 15. PU 5” cement retainer on 2-7/8” tubing 16. RIH and tag composite plug, PU and set retainer at 4960’ a. Test backside to ensure retainer is set b. Confirm circulation through retainer 17. RU Cementers 18. Pump 27.5 bbls of 15.3 ppg cement down tubing a. Annulus volume = 0.0216 bbl/ft x 1270ft = 27.5 bbls b. Displace cement with 8.4 ppg water ~ 28 bbls i. 2-7/8” tubing = 0.0058 bbl/ft x 4960ft = 28.7 bbls 19. Unsting from retainer 20. Circulate tubing clean 21. POOH 22. PU bit/mill and drill collar for 2-7/8” tubing 23. RIH and drill out retainer, cement & plug chasing to at least 5300’ 24. POOH laying down tubing & BHA a. Send to Tuboscope for 10% inspection 25. Set BPV / TWC 26. ND BOPs, NU Tree, test to 5000psi 27. Pull TWC 28. RDMO Rig 401 Completion procedure 29. MIRU E-line 30. Log CBL in 5” production liner from 5000 to above TOC (planned 3700’) x Send CBL to the state for review Well Prognosis Well: KBU 22-06Y Date: 12-2-24 31. RDMO EL 32. MIT-T to 2500psi for 30 minutes (charted) 33. MIT-IA to 2000 psi for 30 min (charted) 34. MIRU Coil tubing 35. PT lubricator to 250/3500psi x Provide AOGCC 24hr-notice for BOP test 36. PU reverse nozzle, RIH, tag and reverse out fluid from well with N2. Total recovery should be 105 bbls of water a. Strap tank pre/post unload b. If tag is not deeper than 5300’ PU motor and mill and cleanout well 37. POOH leaving 1500 psi of N2 on well after reversing fluid out 38. RDMO coil tubing Perf Procedure 8. MIRU E-line 9. PT lubricator to 250/2500psi 10. PU 2-3/4” HC perf guns and perforate proposed intervals bottoms up, testing each sand as desired by reservoir engineer Sands Top MD Btm MD Top TVD Btm TVD FT UB ±4,868’ ±4,883’ ±4,712’ ±4,762’ ±15’ UB 5 ±5,201’ ±5,211’ ±5,023’ ±5,032’ ±10’ UB 5A Upper ±5,217’ ±5,222’ ±5,037’ ±5,042’ ±5’ UB 5A Lower ±5,230’ ±5,244’ ±5,050’ ±5,063’ ±14’ UB 5B ±5,264’ ±5,283’ ±5,082’ ±5,099’ ±19’ 11. Make correlation pass and send log in to Operations Engineer, Reservoir Engineer and the Geologist. a. Record initial and 5/10/15 minute tubing pressures after firing b. Above perfs will be shot in the Kenai Beluga/Upper Tyonek Gas Pool governed by CO 510C 12. RD E-Line Unit and turn well over to production 13. Operations to flow well and test zones 14. Test SVS as per 20 AAC 25.265 once stable flow is achieved x Notify AOGCC 24hrs in advance of testing SVS E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 15. MIRU Eline and N2 pump truck 16. Pressure test equipment to 3,500 psi High/250 psi Low 17. Eline run PT to find fluid level 18. RU N2 and push fluid below perfs (verify fluid depth with PT tool) 19. Set 5” CIBP or patch to isolate water or sand production Coil Tubing Procedure (Contingency) If necessary to cleanout or unload well with coiled tubing: Well Prognosis Well: KBU 22-06Y Date: 12-2-24 20. MIRU Coiled Tubing Unit, PT BOPE to 3,500 psi High/250 psi Low x Provide AOGCC 24hrs notice of BOP test 21. PU wash nozzle or motor & mill, RIH and cleanout well to below perfs or proposed plug depth 22. Set plug as necessary with coil or Eline 23. PU CT jet nozzle and RIH, unload fluid from the wellbore with nitrogen a. Reverse circ out any fluid if perfs are isolated/plugged back and in cased hole 24. RDMO coil tubing Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Proposed Wellhead Diagram 4. Rig 401 BOP Diagram 5. Coil tubing BOP Diagram 6. Nitrogen SOP Page 1 of 2 Updated by CAH 02-15-24 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PBTD = 8,724’ MD / 8,319’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No.Depth ID OD Item 1 18’4.276”11.00”Tubing Hanger 2 5,019’4.276”6.875”10 ft Swell Packer (Water Swell) 3 7,510’2.441”CIBP (12/7/23) 4 7,635’2.441”CIBP w/ 10’ of cmt (12/5/23) 5 8,510’2.441”CIBP w/ 10ft of cement (11/17/23) 6 8,768’4.276”Milled & push CIBP 7 8,990’-4.276”CIBP w/ 25ft of cement (8/20/22) 8 10,065’-3.710”Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8"244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5”132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8”45 bbls of 15.3#. TOC 6,030’ based on CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00”Surf 136' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 1,524’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 8,012’ TUBING 5"Production 18 L-80 DWC/C-HT 4.276”Surf 10,184’ 2-7/8”Production 6.5 L-80 8RD EUE 2.441”Surf 8,773’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBL TOC 5,008’ 8 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 1B 6,461’6,473’6,201’6,212’12/30/23 2”Open LB 1C 6,520’6,526’6,257’6,262’12/30/23 2”Open LB 2B 6,792’6,812’6,511’6,530’12/30/23 2”Open LB 2E 6,962’6,974’6,670’6,682’12/30/23 2”Open LB 3 6,998’7,006’6,704’6,712’12/30/23 2”Open LB 3B Upr 7,069’7,075’6,770’6,776’12/30/23 2”Open LB 3B Mid 7,083’7,091’6,783’6,791’12/29/23 2”Open LB 4A Upr 7,218’7,224’6,910’6,915’12/29/23 2”Open LB 4A 7,231’7,251’6,922’6,940’12/8/23 2”Open LB 4B L 7,275’7,293’6,963’6,980’12/8/23 2”Open LB 4B L 7,275’7,285’6,963’6,372’1/18/24 2.125”Open LB 4B L 7,285’7,293’6,372’6,980’1/17/24 2.125”Open LB 4C L 7,341’7,355’7,025’7,038’12/7/23 2”Open LB 5A Up 7,420’7,426’7,098’7,104’12/7/23 2”Open LB 5A Mid 7,434’7,442’7,111’7,119’12/8/23 2”Open LB 5A L 7,447’7,460’7,123’7,136’12/7/23 2”Open LB5AL 7,449’7,459’7,125’7,135’1/17/24 2.125”Open PERFORATION DETAIL continued on following page LB 1 - L4B L TY 72_8 Fish: Milled CIBP to 8768’ (10/2/23) with Rig 401 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 6 LB 4C L- 5A L RA @ 8004 RA @ 8293 RA @ 8563 RA @ 8826 RA @ 9072 RA @ 9359 RA @ 9605 RA @ 9891 7 CBL TOC 6,030’ 3 4 6 5 Page 2 of 2 Updated by CAH 02-15-24 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 5C 7,522’ 7,552’ 7,193’ 7,221’ 12/6/23 2” Isolated LB 6A 7,584’ 7,590’ 7,251’ 7,257’ 12/6/23 2” Isolated TY 72 8 7,645’ 7,685’ 7,336’ 7,345’ 11/18/23 2” Isolated UT-1B 7,825’ 7,840’ 7,476’ 7,490’ 11/17/23 2” Isolated UT 4D (coal) 8,552’ 8,578’ 8,157’ 8,181’ 11/6/23 2-1/8” Strip Isolated UT 4E (coal) 8,674’ 8,690' 8,272’ 8,287’ 11/3/23 2-1/8” Strip Isolated LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075' 6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091' 6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224' 6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251' 6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293' 6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341' 7,355' 7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420' 7,426' 7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434' 7,442' 7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460' 7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated Page 1 of 2 Updated by CAH 11-30-24 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 PROPOSED PBTD = 8,724’ MD / 8,319’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11.00” Tubing Hanger 2 5,019’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 ~6,450’ 2.441” CIBP w/ 20’ of cement 4 7,510’ 2.441” CIBP (12/7/23) 5 7,635’ 2.441” CIBP w/ 10’ of cmt (12/5/23) 6 8,510’ 2.441” CIBP w/ 10ft of cement (11/17/23) 7 8,768’ 4.276” Milled & push CIBP 8 8,990’ - 4.276” CIBP w/ 25ft of cement (8/20/22) 9 10,065’ - 3.710” Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8" 244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5” 132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8” 45 bbls of 15.3#. TOC 6,030’ based on CBL CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00” Surf 136' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 1,524’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012’ TUBING 5" Production 18 L-80 DWC/C-HT 4.276” Surf 10,184’ 2-7/8” Production 6.5 L-80 8RD EUE 2.441”5,900’ 8,773’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBLTOC 5,008’ 8 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Date Size Status Top Pool 6, 4591’ MD & 4453’ TVD Top Beluga/Upper Tyonek Pool, 4845’ MD & 4691’ TVD UB ±4,868’ ±4,883’ ±4,712’ ±4,762’ TBD Proposed UB 5 ±5,201’ ±5,211’ ±5,023’ ±5,032’ TBD Proposed UB 5A Upper ±5,217’ ±5,222’ ±5,037’ ±5,042’ TBD Proposed UB 5A Lower ±5,230’ ±5,244’ ±5,050’ ±5,063’ TBD Proposed UB 5B ±5,264’ ±5,283’ ±5,082’ ±5,099’ TBD Proposed LB 1B 6,461’ 6,473’ 6,201’ 6,212’ 12/30/23 2”Isolated LB 1C 6,520’ 6,526’ 6,257’ 6,262’ 12/30/23 2”Isolated LB 2B 6,792’ 6,812’ 6,511’ 6,530’ 12/30/23 2”Isolated LB 2E 6,962’ 6,974’ 6,670’ 6,682’ 12/30/23 2”Isolated LB 3 6,998’ 7,006’ 6,704’ 6,712’ 12/30/23 2”Isolated LB 3B Upr 7,069’ 7,075’ 6,770’ 6,776’ 12/30/23 2”Isolated LB 3B Mid 7,083’ 7,091’ 6,783’ 6,791’ 12/29/23 2”Isolated LB 4A Upr 7,218’ 7,224’ 6,910’ 6,915’ 12/29/23 2”Isolated LB 4A 7,231’ 7,251’ 6,922’ 6,940’ 12/8/23 2”Isolated LB 1 - L4B L TY 72_8 Fish:Milled CIBP to 8768’ (10/2/23) with Rig 401 Fish:Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, S pangs, oil jars, knuckle jt, stem, & rope socket 9 LB 4C L- 5A L CBL TOC 6,030’ 4 Scott Warner (907) 830-8863 (c)5 7 6 3 CBL TOC 3700’ Tubing cut @ 5900’ Page 2 of 2 Updated by CAH 11-30-24 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 PROPOSED PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 4B L 7,275’ 7,293’ 6,963’ 6,980’ 12/8/23 2”Isolated LB 4B L 7,275’ 7,285’ 6,963’ 6,372’ 1/18/24 2.125”Isolated LB 4B L 7,285’ 7,293’ 6,372’ 6,980’ 1/17/24 2.125”Isolated LB 4C L 7,341’ 7,355’ 7,025’ 7,038’ 12/7/23 2”Isolated LB 5A Up 7,420’ 7,426’ 7,098’ 7,104’ 12/7/23 2”Isolated LB 5A Mid 7,434’ 7,442’ 7,111’ 7,119’ 12/8/23 2” Isolated LB 5A L 7,447’ 7,460’ 7,123’ 7,136’ 12/7/23 2”Isolated LB5AL 7,449’ 7,459’ 7,125’ 7,135’ 1/17/24 2.125” Isolated LB 5C 7,522’ 7,552’ 7,193’ 7,221’ 12/6/23 2” Isolated LB 6A 7,584’ 7,590’ 7,251’ 7,257’ 12/6/23 2” Isolated TY 72 8 7,645’ 7,685’ 7,336’ 7,345’ 11/18/23 2” Isolated UT-1B 7,825’ 7,840’ 7,476’ 7,490’ 11/17/23 2” Isolated UT 4D (coal) 8,552’ 8,578’ 8,157’ 8,181’ 11/6/23 2-1/8” Strip Isolated UT 4E (coal) 8,674’ 8,690' 8,272’ 8,287’ 11/3/23 2-1/8” Strip Isolated LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075'6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091'6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224'6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251'6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293'6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341'7,355'7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420'7,426'7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434'7,442'7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460'7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated Kenai Gas Field KBU 22-06Y Proposed 11/19/2024 Valve, Upper Master, WKM-M, 5 1/8 5M FE, HWO, DD trim Valve, Swab, WKM-M, 5 1/8 5M FE, HWO, DD trim Tree cap, Otis, 5 1/8 5M FE X 9 ½ Otis Quick Union Crossover spool, 5 1/8 5M FE X 5 1/8 10M FE Valve, Wing, WKM-M, 3 1/8 5M FE, HWO, DD trim Starting head, Seaboard, 16 ¾ 3M X 16'’ SOW, w/ 2- 2 1/16 5M SSO Multibowl Wellhead, SMB-22, 11 5M X 16 ¾ 3M, w/ 4- 2 1/16 5M SSO 16'’ 10 ¾’’ 7 5/8'’ 5'’ Valve, SSV, Barber, 3 1/8 5M FE, w/ Barber Hydraulic self contained operator Adapter, Seaboard-EN, 11 5M stdd x 5 1/8 10M top, w/ 7'’ PP bottom Kenai Gas Field KBU 22-06Y 16 x 10 ¾ x 7 5/8 x 5 Cross, stdd, 5 1/8 5M X 3 1/8 5M Tubing hanger, SMB-22 ported, 11 X 5'’ 18# DWC/C csg btm x 5.875-4 stub acme LH box top, 5'’ type H BPV prep, 4.261 bore, DD material Valve, Master, WKM-M, 5 1/8 5M FE, HWO, DD trim The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 13-5/8"Spherical Annular Height: 46" Weight: 12,806 13-5/8"LWS Double BOP Height: 37" Width: 93" Weight 9,900 lbs. TOP RAMS 2-7/8" TO 5-1/2" MULTI- RAMS BOTTOM RAMS BLIND RAMS 13-5/8"Mud Cross W/ 4- 1/16" outlets Height:28.5" Width 31" Dual 4-1/16" Manual Gate valves W/ DSA to 2-1/16" 4-1/16" Manual Gate valve & 4-1/16" HCR W/ DSA to 2-1/16" Full Mud Cross Assy. width w/ valves installed Width: 98.5" Weight: 2200 lbs. Kill side Choke side Height Addition for Ring Gaskets: 0" BOP Total Height: 111.5" BOP Total weight: 24,906 lbs. 13-5/8" 5m BOP Package W/ 4-1/16" Valves 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. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/20/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240320 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 19RD 50133205790100 219188 2/2/2024 AK E-LINE Perf CLU 14 50133206840000 219078 12/11/2023 AK E-LINE Perf IRU 41-01 50283200880000 192109 11/15/2023 AK E-LINE PERF KBU 22-06Y 50133206500000 215044 12/29/2023 AK E-LINE PERF MPU C-14 50029213440000 185088 3/4/2024 AK E-LINE Whipstock MPU L-62 50029236850000 220059 3/3/2024 AK E-LINE TubingPunch NCIU A-17 50883201880000 223031 12/13/2024 AK E-LINE GPT /Plug /Perf Paxton 6 50133207070000 222054 2/27/2024 AK E-LINE Plug/Perf PBU BORE V-109 50029231200000 202202 2/13/2024 AK E-LINE TubingPunch Please include current contact information if different from above. T38657 T38658 T38659 T38660 T38661 T38662 T38663 T38664 T38665 KBU 22-06Y 50133206500000 215044 12/29/2023 AK E-LINE PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.21 13:14:02 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/15/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240315 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 12/6/2023 AK E-LINE Cement-JetCut BCU 13 50133205250000 203138 2/11/2024 AK E-LINE CIBP-Perf BCU 19RD 50133205790100 219188 2/20/2024 AK E-LINE Perf-CIBP BRU 232-26 50283200770000 184138 11/26/2023 AK E-LINE GPT-PLUG-PERF BRU 244-27 50283201850000 222038 2/27/2024 AK E-LINE GPT-Perf GP ST 18742 37 (AN- 37) 50733203940000 187109 11/22/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF KBU 42-6 50133205460000 204209 2/16/2024 AK E-LINE Patch PBU L-122 50029231470000 203051 12/7/2023 AK E-LINE Patch NCIU A-12B 50883200320200 223053 12/6/2023 AK E-LINE Perf-GPT NCIU A-17 50883201880000 223031 12/10/2023 AK E-LINE Perf-GPT NCIU B-02 50883200900100 197210 3/9/2024 AK E-LINE GPT-Perf SRU 241-33B 50133206960000 221053 3/6/2024 AK E-LINE GPT-Cmnt-CIBP- Perf Please include current contact information if different from above. T38630 T38630 T38631 T38632 T38633 T38634 T38635 T38636 T38637 T38638 T38639 T38640 T38641 KBU 22-06Y 50133206500000 215044 11/3/2023 AK E-LINE GPT-PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.18 08:49:06 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 3/14/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240314 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 13 50133205250000 203138 1/20/2024 AK E-LINE GPT/PL BCU 13 50133205250000 203138 1/4/2023 AK E-LINE JetCut/CBL BRU 221-35 50283201930000 223077 11/18/2023 AK E-LINE Perf HV B-13 50231200320000 207151 12/22/2023 AK E-LINE CBL IRU 41-01 50283200880000 192109 11/16/2023 AK E-LINE Perf KBU 22-06Y 50133206500000 215044 1/16/2024 AK E-LINE GPT/Perf KTU 32-07H 50133205110000 202043 10/27/2023 AK E-LINE PPROF KU 3-06A 50133207160000 223112 1/12/2024 AK E-LINE CBL KU 21X-32 50133202040000 169100 12/8/2023 AK E-LINE JetCut MPU CFP-02 50029212580000 184242 3/9/2024 READ CaliperSurvey NCI A-18 50883201890000 223033 12/8/2023 AK E-LINE Perf/GPT NIA NK-18 50029224210000 193177 12/13/2023 AK E-LINE IPROF PTM P1-13 50029223720000 193074 12/9/2023 AK E-LINE Cement TBU M-11 50733205900000 210145 1/8/2024 AK E-LINE Perf TBU M-15 50733204220000 190109 2/7/2024 AK E-LINE GPT/Perf Please include current contact information if different from above. T38615 T38615 T38616 T38617 T38618 T38619 T38620 T38621 T38622 T38623 T38624 T38625 T38626 T38627 T38628 KBU 22-06Y 50133206500000 215044 1/16/2024 AK E-LINE GPT/Perf Meredith Guhl Digitally signed by Meredith Guhl Date: 2024.03.15 11:38:35 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Lift 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 10,200 feet See Schematic feet true vertical 9,697 feet N/A feet Effective Depth measured 7,510 feet 5,019 feet true vertical 7,182 feet 4,853 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)2-7/8" 6.5# / L-80 8,773' MD 8,364'' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A N/A; 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:Belugla/Upper Tyonek Gas Pool 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: Chad Helgeson, Operations Engineer 323-511 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 chelgeson@hilcorp.com 907-777-8405 N/A measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 610 Size 136' 0 3000 0 220 15 Production Liner 8,012' 10,184' measured TVD 7-5/8" 5" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-044 50-133-20650-00-00 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: FEDA 028142 Kenai Gas Field - Beluga/Upper Tyonek Pool - Tyonek Gas Pool 1 Kenai Beluga Unit (KBU) 22-06Y Plugs Junk measured LengthCasing Structural 7,651' 9,682' 8,012' 10,184' 136'Conductor Surface Intermediate 16" 10-3/4" 136' 1,524' 4,790psi 10,500psi 5,210psi 6,890psi 10,140psi 1,524'1,506' Burst Collapse 2,470psi 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 8:26 am, Feb 16, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.02.15 15:18:17 - 09'00' Noel Nocas (4361) DSR-2/16/24 RBDMS JSB 022824 Page 1/7 Well Name: KEU KBU 22-06Y Report Printed: 2/15/2024www.peloton.com Well Operations Summary Jobs Actual Start Date:9/27/2023 End Date: Report Number 1 Report Start Date 9/7/2023 Report End Date 9/8/2023 Operation Report Number 2 Report Start Date 9/27/2023 Report End Date 9/28/2023 Operation Operations remove flowlines, wellhouse, prep site for rig to move in. Report Number 3 Report Start Date 9/28/2023 Report End Date 9/29/2023 Operation PJSM, Discuss well operations & rigging up Spot in & rig up equipment, Mix 70 bbls KCL Report Number 4 Report Start Date 9/29/2023 Report End Date 9/30/2023 Operation PJSM, Discuss nipple down & nipple up operations Pump 26 bbls 6% kcl, Pressured up to 800 psi, Bleed back pressure, Well Static, Install 5" BPV, Nipple down tree & 11" x 5" 5m flange Nipple up new 11" x 7" 5m wellhead flange torque to 3330 ft/lbs, pressure test voids to 5000 psi-good, Nipple up BOPE function & test-good. Pressure test BOPE 250 low/ 3000 high all rams & annular, inner & outer valves. Blow everything dry, Shut in & secure well Report Number 5 Report Start Date 9/30/2023 Report End Date 10/1/2023 Operation PJSM, Discuss daily operations, Communication & preparing for tasks Nipple up Cross-over & striping head on annular, Finish rigging up tubing handling equipment, MIx 6% KCL 8.7 ppg \nMake up dry rod & retrieve BPV, small amount of pressure, Pump 6 bbls 6% kcl & remove BPV, Pick up 4" mill, 6 x 3-1/8" DC, 100 jts 2-7/8" ph-6 depth-3240' Shut in & secure well, Blow down lines & winterize equipment Report Number 6 Report Start Date 10/1/2023 Report End Date 10/2/2023 Operation PJSM, Discuss daily operations picking up tubing & loader operations. Pick up 2-7/8", PH-6 tubing from 3230' to 7286' Spot in & rig up swivel, Function Test & set torque @ 3k. Attempt to establish circulation string plugged, surge string till circulating, Circulate string volume 38 bbls. Wash from 7286' to 7316' Mill CIBP @ 7310' to 7312'. Circulate bottoms up thru choke as S.O.P., small gas returns, well static. Shut in & secure well for the night. Report Number 7 Report Start Date 10/2/2023 Report End Date 10/3/2023 Operation PTSM, PTW, Mix 6% KCL & fill pits, check well static, P/U 3 singles w/ swivel, RIH chasing BP F/7335' t/7428' w/no issues, up wt 65k, dn wt 44k, R/D swivel hang back in mast, r/u handling tools, troubleshoot leak & repair on tongs. RIH p/u 2 7/8" wk string, RIH chasing CIBP down t/8713', tagged up, R/U circulating line, pump & wk down t/ 8723' stopped moving, pump 2 bpm, 900 psi L/D joint, p/u swivel m/u, p/u joint. Wash, ream & wk plug down f/ 8723' t/8740', CBU clean getting back sand/silt, 2 bpm, 900 psi rot 60 rpm, tq 1500-1800 Cont. Wash, ream & wk plug down t/8765' progress slowed continued down t/8768', consult with engineering, not making headway, called TD CBU, R/D swivel, p/u handling Eq. Pull t/ 8738', secure well for night. Report Number 8 Report Start Date 10/3/2023 Report End Date 10/4/2023 Operation PJSM, PTW, check well static. fill hole 10 bbls, POOH l/d 2 7/8" wk string, f/ 8738' t/2075' Repair hyd fitting on HPU, & c/o tongs to McCoys Cont. l/d 2 7/8" wk string F/2075' to BHA @187' C/O handling tools, L/D BHA, secure well for night. Report Number 9 Report Start Date 10/4/2023 Report End Date 10/5/2023 Operation PJSM, PTW, check well good, fill hole 15 bbls, c/o elevators, load skate with pipe. API: 50-133-20650-00-00 Field: Kenai Gas Field Sundry #: 323-511 State: Alaska Rig/Service:Permit to Drill (PTD) #:215-044 Page 2/7 Well Name: KEU KBU 22-06Y Report Printed: 2/15/2024www.peloton.com Well Operations Summary Operation M/U float shoe t/ 2 7/8" L-80 6.5# EUE 8 rd completion, cont RIH p/u tubing, installing centralizers, after first 2 installed string had to be worked in hjole, ran next 8 joints w/o centralizers then started installing, ran 4 and string stalled out again,v POOH uninstalled last 4 centralizes last 4 off & installed on middle of tubing instead of cross collar, ran in hole t/~750' string stalled out. Pulled out of hole & racked back completion, removing all centralizers including 2 cross collar's RIH installing centralizers every 3rd joint. t/718' rig went down Troubleshoot, & get running again & service. Cont. RIH P/U 2 7/8" completion f/718' installing centralizers every 3rd joint. t/ 1429' String Dragging again, Fill pipe, Cont. in hole installing centralizers every 4th joint t/ 1940psi, up wt 16k, dn wt 7k. Secure well, Rest crew Report Number 10 Report Start Date 10/5/2023 Report End Date 10/6/2023 Operation PJSM, PTW, check well good, Cont. RIH p/u 12 7/8" L-80 6.5# EUE 8rd completion f/1940', filling pipe every ~1500' to tag @ 8778' up wt 66k, dn wt 28k P/U t/ 8765' CBU clean, Secure well for night. Report Number 11 Report Start Date 10/6/2023 Report End Date 10/7/2023 Operation PJSM, PTW, Check Well good, Space out string, L/D jt 275, Break out Jt 274, M/U space out pups, M/U jt 274, RIH, M/U hanger & landing joint Land, land hanger, up wt 66k, dn wt 28k, RILD pins. Spot cement Eq., & rig up same, M/U CMT/circ sub, CBU @ 2BPM, 550 psi, 2.5BPM, 900psi. loss of 7 bbls while circ. Cont. R/U cement lines & manifold. PJSM, CMT job, Mix 45 bbls 6%KCL in CMT batch tank 2, Flood lines pump down hole 3bbls, shut in PT surface lines t/1850psi Batch up CMT t/15.3ppg, Pump @ 2.5 BPM 200-400 psi, shut in, flush pump lines clean, line up on 6% KCL open to plug, pump displacement @ 2.5bpm, FCP 1200 psi, bumped plug pressure up t/1800psi, held pressure, open up flush side entry sub, pressure back up on plug t/1600 psi & lock in. Pit returns 13bbls short for job. R/D cmt lines & CMT unit, Start r/d 401 aux eq. Move & stage on pad for KBU 13-08 Workover. Report Number 12 Report Start Date 10/7/2023 Report End Date 10/8/2023 Operation PJSM, PTW, Pull & breakdown landing joint, install TWC. R/D floor, n/d BOPE, Prep & scope down mast, lay over same, secure lines, n/u tree & test void t/5k good, test tree t/ 5k good. Mobe carrier & base beam to G&I pad for KBU 13-08, roll up liner & felt. Report Number 13 Report Start Date 10/8/2023 Report End Date 10/9/2023 Operation Arrive in office, complete PTW, & perform JSA Rig up W/L - PT Lubricator to 150/1500 pass RIH w/ 2.31" GR to 8646' KB work tools to 8657'. OOH w/GR w/ signs of cement Lay down W/L - Mobe to 13-08 to support rig. Report Number 14 Report Start Date 10/9/2023 Report End Date 10/10/2023 Operation AK Eline check in at office, complete PTW, JSA RU Eline and PT 250/2500, passed PU CBL, RIH and log cement from 8607 to 5800. TOC shown at 6030'. POOH and RD Eline Report Number 15 Report Start Date 10/10/2023 Report End Date 10/11/2023 Operation SL arrive in field, Complete PTW & JSA Rig up 0.160 wire Swab well down from surface to 3700' KB. Had lots of trouble with tubing damaging swab cups. Used 1 gal of friction reducer and it helped. SDFN, will continue to swab to 8500' Report Number 16 Report Start Date 10/26/2023 Report End Date 10/27/2023 Operation Rig up coil tbg and support equipment Test Bope and related surface equipment to 250 & 3500 psi hi, AOGCC Jim Regg, waived witness Rig up BOPE to well head and rig up flow back equipment Depart location Report Number 17 Report Start Date 10/27/2023 Report End Date 10/28/2023 Operation Report Number 18 Report Start Date 10/28/2023 Report End Date 10/29/2023 API: 50-133-20650-00-00 Field: Kenai Gas Field Sundry #: 323-511 State: Alaska Rig/Service: Page 3/7 Well Name: KEU KBU 22-06Y Report Printed: 2/15/2024www.peloton.com Well Operations Summary Operation Had ice plug in reel and radiator hose leaking on Coil tbg tractor, Schlumberger mechanic changed out hose Pressure test MHA to 3500 psi make up Motor stab on well, Pressue test to 4000 psi. Open well Rih Weight check at 3000 ft. 12k, weight check at 6000 ft, 16k, weight check at 8000 ft. 23k tagged up at 8681' CTM. Pump on line, pumping at 1 bpm at 2800 psi, milled from 8681'T/ 8733' CTM Pumped bottoms up at 1 bpm 2800 psi, while doing multiple wiper trips from 8733 to 8540' Drop 9/16 ball and open circ sub, N2 online displace well with N2 pumping at 1400 scfm. recovered 57bbls of fluid to return tank. Pressuring up well to 2500 psi with N2. OOH, secure well with 2550 on tubing, break lubricator, lay down Yellow Jacket Tools, set coil injector in rack. SDFN. Report Number 19 Report Start Date 10/29/2023 Report End Date 10/30/2023 Operation PTW PJSM, rig down and move coil unit to 13-08 well Report Number 20 Report Start Date 11/2/2023 Report End Date 11/3/2023 Operation Arrive in field, Complete PTW, PJSM. Start Rig up. Had crane truck battery issues on controls for crane. Repaired. Found flange leak above upper master valve. Ops made repairs. Completed RU and PT 250/3500 psi RIH w/ GPT. Tag fill 8724'. FL @ 8550. Send log to town for correlation. RIH w 10' x 2-1/8" Spiral strip gun, 4 SPF 60 deg phase to shoot lower UT 4E zone, 8680-8690'. Made tie-in pass, send log to town, adjusted 1' up. position gun one. CCL to TS = 8', placing CCL to be at 8672' with top shot at 8680'. Fired gun one, POOH. Start 2325 psi/5 Min 2326/ 10 Min 2325/ 15 Min 2321. OOH. All shots fired. L/D Gun one. P/U Gun Two RIH w/ 10' x 2-1/8" Spiral Strip gun, 4 SPF, 60 deg phase to shoot lower UT 4E zone 8674-8684' (4ft overlap in existing perfs from gun one). made tie-in pass. Sent log to town. Approved. Positioned gun two. CCL to TS = 8'/CCL t be at 8666' to place top shot at 8674'. Fire Gun TWO. POOH. Start PSI 2274 / 5 Min 2275 / 10 Min 2274 / 15 Min 2272. OOH. All shots fired. L/D Gun TWO. Lay down and secure well and equipment. Nite cap BOP's. Turn well over to production to flow test. Return to AK E-Line shop. Plan forward: Evaluate well test to determine further work. Arrive in field, Complete PTW, PJSM. Start Rig up. Had crane truck battery issues on controls for crane. Repaired. Report Number 21 Report Start Date 11/6/2023 Report End Date 11/7/2023 Operation PJSM and PTW SITP 106psi. RU AK Eline M/U 1-11/16" GPT. RIH and tag at 8,720'. Fluid level observed and 8,510ft (top open perf 8,674'). POOH Pressure up well with 650psi of sales gas. M/U and RIH 1-11/16 gun gamma, weight bars, E-line jars and 2.125" OD x 10' Strip gun, 4spf, 14.2gm (CCL to top shot 8.0') Send logs to town, on depth. Pull on depth and perforate UT 4D from 8,568-8,578. SITP 650psi, no change in 15min. POOH, all shots fired. M/U and RIH 1-11/16 gun gamma, weigh bars, E-line jars and 2.125" OD x 10' Strip gun, 4spf, 14.2gm (CCL to top shot 8.0'). Pull on depth and perforate UT 4D from 8,558-8,568. SITP 644psi, no change in 15min POOH, all shots fired. M/U and RIH 1-11/16 gun gamma, weigh bars, E-line jars and 2.125" OD x 6' Strip gun, 4spf, 14.2gm (CCL to top shot 8.0'). Pull on depth and perforate UT 4D from 8,552-8,558. SITP 638psi, no change in 15min POOH, all shots fired. RDMO Production to flow the well overnight Report Number 22 Report Start Date 11/11/2023 Report End Date 11/12/2023 Operation MIRU Hot oil truck Perform Injection/LOT Report Number 23 Report Start Date 11/11/2023 Report End Date 11/12/2023 Operation Report Number 24 Report Start Date 11/12/2023 Report End Date 11/13/2023 Operation PTW,JSA. MIRU SBL CTU fluid pump and blow down tank. 1720 psi remains on well from previous injection the prior day. Bleed WHP to zero. No gas in returns. Mix up batch of 60/40 for freeze protect. PT pump lines 250/4800 psi. Open swab. Online at 1.1 bbls/min with 6% KCL until break over at 3590 psi. Injected 10 bbls. Change gears. Increase rate to 2.1 bbls/min 3900 psi. 5 bbls injected. Increase rate to 4.0 bbls/min. Inject remaining 60 bbls of 6% KCL at 4300 psi average injection pressure. 85 bbls of 6% KCL injected for intervention. IA 0 during entire job. Pump 3 bbls of freeze protect through pump and wellhead. Shut down and monitor Leak off pressure. API: 50-133-20650-00-00 Field: Kenai Gas Field Sundry #: 323-511 State: Alaska Rig/Service: Page 4/7 Well Name: KEU KBU 22-06Y Report Printed: 2/15/2024www.peloton.com Well Operations Summary Operation Finished monitoring LOT. Rig down Pump truck. Install crystal gauge on tree cap. Open swab and monitor leak off throughout the night. Report Number 25 Report Start Date 11/12/2023 Report End Date 11/13/2023 Operation Report Number 26 Report Start Date 11/14/2023 Report End Date 11/15/2023 Operation Held PJSM and approve PTW, Load equipment on trailers and haul to location. Spot in and R/u SLB CTU #1 and associated equipment. Prep to test BOP's Tested BOP's as per regs 250L-3500H, good test. Witness was waived by Jim Regg. Blew down lines, R/u winterization. SDFN. Report Number 27 Report Start Date 11/15/2023 Report End Date 11/16/2023 Operation Thaw end of CT pump two volumes, drop 1.00" drift ball on second. Recovered ball. MU BHA : 1.75" CTC, pull test to 12k-lbs, pressure test to 3900 psi, 1.75" DFCV, 1.75" Stinger, 2.00" JSN RIH start pumping N2 Tag bottom twice at 8707'. PU 10' start lifting well to tanks on surface. Hand well over to Ops for testing. Take well out of test and RIH Pumped 3 bottoms up plus. Total of 3 bbls recovered at surface. Reduce N2 rate to 400 scf, close choke and POOH OOH, secure well leaving 2020 psi on Tbg. SDFN Report Number 28 Report Start Date 11/16/2023 Report End Date 11/17/2023 Operation RDMO coil tubing equipment Pressure up wellbore to 3500 psi 28 gallons of N2 used Report Number 29 Report Start Date 11/17/2023 Report End Date 11/18/2023 Operation MIRU Eline run GPT, set CIBP @ 8510', Add Perf UT 1B 7825'-7840' Pressure at well came up slightly from 200 to 206 psi. POOH and LD. Flow well during the night. Report Number 30 Report Start Date 11/18/2023 Report End Date 11/19/2023 Operation Eline: RIH w/ 20' 2" HSC 6 spf, 60 deg phasing, 6.8 grams. tie-in w/0' correction WHP before add perf=76.03 psi Perforate Tyonek zone 7665'-7685' 5 min= 76.84 psi 10 min= 75.46 psi 15 min= 75.34 psi OOH w/gun all shots fired Eline: RIH w/ 20' 2" HSC 6 spf, 60 deg phasing, 6.8 grams. tie-in w/0' correction WHP before add perf=61 psi Perforate Tyonek zone 7645'-7665' 5 min= 60.34 psi 10 min= 61.03psi 15 min= 62 psi OOH w/gun all shots fired RDMO. Job Complete. Report Number 31 Report Start Date 11/28/2023 Report End Date 11/29/2023 Operation Report Number 32 Report Start Date 12/5/2023 Report End Date 12/6/2023 Operation YJ E-line and Fox Energy N2 arrive at KGF office, sign in, obtain PTW and hold PJSM. Mobe to location. Wait for tractor to arrive to spot N2 pump and transport. RU E-line and N2 lines, allow for N2 cool down. MU GPT, wt. bars and move to well. PT 250 psi / 4000 psi w/ N2. Open swab and begin pumping N2 at 800 scfm. Walk tubing pressure up to 3500 psi. API: 50-133-20650-00-00 Field: Kenai Gas Field Sundry #: 323-511 State: Alaska Rig/Service: Page 5/7 Well Name: KEU KBU 22-06Y Report Printed: 2/15/2024www.peloton.com Well Operations Summary Operation Off line with N2. RIH w/ GPT and locate FL at 7265' (380' above target perfs). 7645'-7685'. Kick on pump and continue depressing fluid (3500 psi limit). Total = 100,669 scfs Run GPT survey and locate fluid at 7650' . POOH. OOH. MU GR/CCL, 1.68" setting tool w/ 2.10" OD CIBP. Open swab and RIH, correlate, confirm tie-in and set CIBP at 7635'. POOH. RU flow back tank and draw well down to 500 psi. MU 2" x 15' cement dump bailer, mix & fill bailer with 2.50 gal. cement. RIH and dump on CIBP. POOH. Est. TOC at 7625'. OOH. Secure well and rig back e-line. Report Number 33 Report Start Date 12/6/2023 Report End Date 12/7/2023 Operation YJ E-line arrive at KGF office, PTW and PJSM. Mobe to location. Rig back on well. MU Gun Gamma Ray/CCL and 2" x 6' RTG (6spf/60D) (6.8 gm Razor chgs) perf gun. (10.5' CCL T.S.). Move to well. Open swab, RIH, correlate, confirm on depth and perforate LB 6A interval (7584' - 7590'). Start: 204 psi 5 min: 207 psi / 10 min: 207 psi / 15 min: 206 psi . POOH OOH. Gun covered in sand sheath. MU Gun #2 (30'), RIH, correlate, confirm on depth and perforate LB 5C interval (7522' - 7552'). Start: 196 psi / 5 min: 209 psi / 10 min: 210 psi / 15 min: 212 psi Gun blown up hole, stuck, worked line up to 1500 lb. overpull and came free. POOH. At surface unable to close master valve. Closed WLV rams on line, PU lub, inspected damaged line, clamped & cut damaged line, MU lubricator and open WLV, pull gun into lub and close swab. LD spent gun, gun covered in sand. Rehead line. M/U GPT, RIH and locate FL at 7570', between perf intervals. POOH. OOH. Secure well, SDFN and turn over to production to flow test. Report Number 34 Report Start Date 12/7/2023 Report End Date 12/8/2023 Operation YJ E-line arrive at KGF office, PTW and PJSM. Mobe to location. Rig back on well. M/U GPT, locate gas cut fluid at 7170' (352' above perfs at 7522'-52') and solid fluid at 7540'. Orders to abandon LB 6A & LB 5C zones.POOH. OOH. M/U setting tool with 2.10" CIBP. RIH, tie-in and set plug at 7510'. POOH. Jump gas to well 239 psi. OOH. M/U 2" x 13'(btm) & 8'(top) switch guns. RIH, correlate, confirm on depth. Perforate LB 5A lwr (7447'-60'). Blown up hole, free tools, line shorted. POOH. Start-239 psi / 10 min: 251 psi. OOH. Rehead line. Top 8' gun flooded. M/U 2" x 6'(btm) & 14' (top) switch guns. RIH, pressurize tubing to 451psi. Correlate, confirm on depth and shoot LB 5A upper (7420'-26'). Start: 461 psi / 10min: 468psi Position and shoot LB 4CL (7341'-55'). Start: 468 psi / 5 min: 475 psi / 10 min: 475 / 15 min: 476 psi. POOH. OOH. M/U GPT, RIH and locate fluid level at 7351'. (Bottom of LB 4CL perfs). POOH. OOH. Secure well, SDFN and turn over to production to flow test. Report Number 35 Report Start Date 12/8/2023 Report End Date 12/9/2023 Operation YJ E-line arrive at KGF office, PTW and PJSM. Mobe to location. Rig back on well. M/U GPT, locate gas cut fluid at 6850' down to 7420'. Water gradient from 7420' to 7510'. POOH. OOH. M/U 2" x 8' perf gun. Pressure up tubing to 400 psi. RIH, correlate, confirm on depth and shoot LB 5A mid (7434'-42'). Start: 420 psi / 5 min: 422 pi / 10 min: 424 psi / 15 min: 426 psi. POOH. OOH. M/U 2" x 18' perf gun. RIH, correlate, shift +1', position and shoot LB 4BL (7275'-93'). Start: 454 psi / 10 min: 465 psi / 15 min: 472 psi. POOH. OOH. M/U 2" x 20'perf gun. RIH, correlate, confirm on depth and shoot LB 4A (7231-7251'). Start: 580 psi / 5 min: 589 psi / 10 min: 598 psi / 15 min: 604 psi. POOH. OOH. SITP 640 psi. Ops flow well to 57 psi. M/U GPT, RIH flowing and locate gas/water gradient at 4550' - 7350'. Log down and locate true water gradient at 7350' to PBTD 7510'. POOH. OOH. Secure well, drop 4 soap sticks, RDMO E-line and turn over to production to flow well. Job complete. API: 50-133-20650-00-00 Field: Kenai Gas Field Sundry #: 323-511 State: Alaska Rig/Service: Page 6/7 Well Name: KEU KBU 22-06Y Report Printed: 2/15/2024www.peloton.com Well Operations Summary Report Number 36 Report Start Date 12/29/2023 Report End Date 12/30/2023 Operation Trouble starting crane in cold weather. Repaired. Travel to KGF. PJSM & Permit. Travel to location. MIRU AK E-Line. P/U Gun ONE 6' x 2" HC (6SPF/60) to shoot LB 4A Upr Zone 7218' to 7224'. CCL to TS = 9.2' / CCL to be at 7208.8' to place TS at 7218'. PT 250 / 3500 PSI. Test good. RIH w/ Gun ONE. Made tie in pass. Sent log to town. Town adjusted 1' +. Position Gun ONE. Fire Gun ONE. POOH. Start PSI: 735 / 5 Min 742 / 10 Min 746 / 15 Min 750. OOH. L/D Gun ONE. All shots fired. Dry end cap. P/U Gun TWO 8' x 2" (6SPF/60) to shoot LB 3B Mid Zone 7083' to 7091'. CCL to TS = 10.2' / CCL to be at 7072.8' to place TS at 7083'. Made tie in pass. Sent log to town. Town approved. Position Gun TWO. Fire Gun TWO. POOH. Start PSI: 821 / 5 Min 833 / 10 Min 835 / 15 Min 838. OOH. L/D Gun TWO. All shots fired. Dry end cap. Turn well over to Production to flow overninght. Secure well & equipment. SDFN. Report Number 37 Report Start Date 12/30/2023 Report End Date 12/31/2023 Operation Travel to KGF. PJSM & Permit. Travel to location. Thaw equipment. MIRU AK E-Line. P/U Gun THREE 6' x 2" HC (6SPF/60) to shoot LB 3B Upr Zone 7069' to 7075'. CCL to TS = 8.4' / CCL to be at 7060.6' to place TS at 7069'. RIH w/ Gun THREE. Made tie in pass. Sent log to town. Town approved. Position Gun THREE. Fire Gun THREE. POOH. Start PSI: 710 / 5 Min 747 / 10 Min 756 / 15 Min 760. OOH. L/D Gun THREE. All shots fired. Dry end cap. P/U Gun FOUR 8' x 2" (6SPF/60) to shoot LB 3B Zone 6998' to 7006'. CCL to TS = 10.2' / CCL to be at 6987.8' to place TS at 6998'. RIH w/ Gun FOUR. Bleed tubing from 880 to 675 PSI. Made tie in pass. Sent log to town. Town approved. Position Gun FOUR. Fire Gun FOUR. POOH. Start PSI: 686 / 5 Min 697 / 10 Min 707 / 15 Min 712. OOH. L/D Gun FOUR. All shots fired. Dry end cap. P/U Gun FIVE 12' x 2" (6SPF/60) to shoot LB 2E Zone 6962' to 6974'. CCL to TS = 10.2' / CCL to be at 66951.8' to place TS at 6998'. RIH w/ Gun FIVE. Bleed tubing from 808 to 665 PSI. Made tie in pass. Sent log to town. Town approved. Position Gun FIVE. Fire Gun FIVE. POOH. Start PSI: 680 / 5 Min 692 / 10 Min 697 / 15 Min 703. OOH. L/D Gun FIVE. All shots fired. Dry end cap. P/U Gun SIX 20' x 2" (6SPF/60) to shoot LB 2B Zone 6792' to 6812'. CCL to TS = 8.4' / CCL to be at 6783.6' to place TS at 6792'. RIH w/ Gun SIX. Bleed tubing from 812 to 670 PSI. Made tie in pass. Sent log to town. Town adjusted 1' down. Position Gun SIX. Fire Gun SIX. POOH. Start PSI: 702 / 5 Min 716 / 10 Min 723 / 15 Min 731. OOH. L/D Gun SIX. All shots fired. Dry end cap. P/U Gun SEVEN 6' x 2" (6SPF/60) to shoot LB 1C Zone 6520' to 6526'. CCL to TS = 8.4' / CCL to be at 6511.6' to place TS at 6520'. RIH w/ Gun SEVEN. Bleed tubing from 830 to 660 PSI. Made tie in pass. Sent log to town. Town approved. Position Gun SEVEN. Perforate LB 1C zone 6520’ to 6526’. POOH. Start PSI: 674 / 5 Min 682 / 10 Min 691 / 15 Min 696. OOH. L/D Gun SEVEN. All sots fired. End cap dry. RDMO AK E-Line. Return crew & equipment to shop. Report Number 38 Report Start Date 1/16/2024 Report End Date 1/17/2024 Operation PJSM, Spot in & rig up on well, Pick up CCl/GR/GPT, Make up lube on wellhead & pressure test 250/3000-good test., Attempt to run in hole tag @ 23', Work string multiple times still no pass, Pump methanol and work till past. At 940' find bird cage in line wrap with tape, pull out of hole & secure welll strip off 1000' line, Rehead & shut down. Report Number 39 Report Start Date 1/17/2024 Report End Date 1/18/2024 Operation PJSM, Start & warm equipment, Pick up lube & check tools-good, Pressure test lube 250/3000-good, Crane would not start, Work on equipment (0730-1000). Run in the hole with CCL/GR/GPT, Fluid level @ 5540', Tag bottom @ 7475', Pull out of hole, Secure well & lay down lube. Pick up 2.125" x 10' strip gun, 4 spf, 15 degree phasing (snake gun), 14.2 grams, CCL-TS=8', Stab onto well with lube & open swab valve, Run in hole, Correalate from 7475' to 6100', Send to town, Adjust 2' down, Pull into position CCL @ 7441', Perf 7449-7459' (LB 5AL). Good break, Pull out of hole OG psi: 1688' Pick up 2.125" x 8' strip gun, 4 spf, 15 degree phasing (snake gun), 14.2 grams, CCL-TS=8', Stab onto well with lube & open swab valve, Run in hole, Correalate from 7475' to 6900', Send to town, Adjust zero on depth, Pull into position CCL @ 7277', Perforate 7285-7293' (LB 4BL) Good break, Pull out of hole OG psi: 1655 1656 psi @ 5 min/ 1653 psi @ 10 min / 1650 psi @ 15 min OOH, all shots fired. LDFN Report Number 40 Report Start Date 1/18/2024 Report End Date 1/19/2024 Operation PTW, JSA with E-line crew. Inspect tools and equipment. Make up toolstring and fire check. Stab on well. PT lubricator 250/3500 psi. BHA 5x2 head, 5'x 1.69" weight bar, 1.69" Jars, 1.69" GR/CCL, TD, shock sub, 2.125"x 10' snake strip gun loaded 4 spf, OAL = 38', OAW = 250 lbs, Max OD 2.125". RIH. Initial SITP 1720 psi, Fluid level 5540'. API: 50-133-20650-00-00 Field: Kenai Gas Field Sundry #: 323-511 State: Alaska Rig/Service: Page 7/7 Well Name: KEU KBU 22-06Y Report Printed: 2/15/2024www.peloton.com Well Operations Summary Operation Pull correlation pass. Send log to town. On depth. Pull into postion. CCL to top shot 8'. Park CCL at 7267' Perforate LB 4BL from 7275'-7285'. Good indication of fire. 750 lb overpull after guns fired. Jars went off. POOH to surface. Tool string stuck in tree at surface. Hold tailgate meeting. Lightly cycle tree valves to determine tool location. Not able to shut in . Hand spang 4' of tools OOH. Hand spanged out of rope socket. Wire remains in grease head. Pack off with 1000 psi. Tools still across tree. RU field triplex pump. Pump 4 bbls of diesel down well. Tool string remains across tree. Hold safety meeting to discuss well kill operations. Production open well an flow down to 13 psi. RU Fox energy coil pump. PT lines 250/3500 psi. Bullhead 30 bbls of 6% KCL down tubing. Well on vac. Pop off lubricator and MU pulling strap to tool string. Pull up with boom truck. Secure fish. Break toolstring above firing shock sub. Lay down lubricator. Latch and pull remaining firing head and 10' strip gun. Close swab valve. All tools recovered. Turn well over to proudciton. RIg down AK E-line. API: 50-133-20650-00-00 Field: Kenai Gas Field Sundry #: 323-511 State: Alaska Rig/Service: Page 1 of 2 Updated by CAH 02-15-24 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PBTD = 8,724’ MD / 8,319’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No.Depth ID OD Item 1 18’4.276”11.00”Tubing Hanger 2 5,019’4.276”6.875”10 ft Swell Packer (Water Swell) 3 7,510’2.441”CIBP (12/7/23) 4 7,635’2.441”CIBP w/ 10’ of cmt (12/5/23) 5 8,510’2.441”CIBP w/ 10ft of cement (11/17/23) 6 8,768’4.276”Milled & push CIBP 7 8,990’-4.276”CIBP w/ 25ft of cement (8/20/22) 8 10,065’-3.710”Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8"244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5”132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8”45 bbls of 15.3#. TOC 6,030’ based on CBL CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00”Surf 136' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 1,524’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 8,012’ TUBING 5"Production 18 L-80 DWC/C-HT 4.276”Surf 10,184’ 2-7/8”Production 6.5 L-80 8RD EUE 2.441”Surf 8,773’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBL TOC 5,008’ 8 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 1B 6,461’6,473’6,201’6,212’12/30/23 2”Open LB 1C 6,520’6,526’6,257’6,262’12/30/23 2”Open LB 2B 6,792’6,812’6,511’6,530’12/30/23 2”Open LB 2E 6,962’6,974’6,670’6,682’12/30/23 2”Open LB 3 6,998’7,006’6,704’6,712’12/30/23 2”Open LB 3B Upr 7,069’7,075’6,770’6,776’12/30/23 2”Open LB 3B Mid 7,083’7,091’6,783’6,791’12/29/23 2”Open LB 4A Upr 7,218’7,224’6,910’6,915’12/29/23 2”Open LB 4A 7,231’7,251’6,922’6,940’12/8/23 2”Open LB 4B L 7,275’7,293’6,963’6,980’12/8/23 2”Open LB 4B L 7,275’7,285’6,963’6,372’1/18/24 2.125”Open LB 4B L 7,285’7,293’6,372’6,980’1/17/24 2.125”Open LB 4C L 7,341’7,355’7,025’7,038’12/7/23 2”Open LB 5A Up 7,420’7,426’7,098’7,104’12/7/23 2”Open LB 5A Mid 7,434’7,442’7,111’7,119’12/8/23 2”Open LB 5A L 7,447’7,460’7,123’7,136’12/7/23 2”Open LB5AL 7,449’7,459’7,125’7,135’1/17/24 2.125”Open PERFORATION DETAIL continued on following page LB 1 - L4B L TY 72_8 Fish: Milled CIBP to 8768’ (10/2/23) with Rig 401 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 6 LB 4C L- 5A L RA @ 8004 RA @ 8293 RA @ 8563 RA @ 8826 RA @ 9072 RA @ 9359 RA @ 9605 RA @ 9891 7 CBL TOC 6,030’ 3 4 6 5 Page 2 of 2 Updated by CAH 02-15-24 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 5C 7,522’ 7,552’ 7,193’ 7,221’ 12/6/23 2” Isolated LB 6A 7,584’ 7,590’ 7,251’ 7,257’ 12/6/23 2” Isolated TY 72 8 7,645’ 7,685’ 7,336’ 7,345’ 11/18/23 2” Isolated UT-1B 7,825’ 7,840’ 7,476’ 7,490’ 11/17/23 2” Isolated UT 4D (coal) 8,552’ 8,578’ 8,157’ 8,181’ 11/6/23 2-1/8” Strip Isolated UT 4E (coal) 8,674’ 8,690' 8,272’ 8,287’ 11/3/23 2-1/8” Strip Isolated LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075' 6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091' 6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224' 6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251' 6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293' 6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341' 7,355' 7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420' 7,426' 7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434' 7,442' 7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460' 7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/25/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240125 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# HV B-12 50231200310000 207123 1/3/2024 Yellowjacket GPT-PERF HV B-13 50231200320000 207151 12/13/2023 Yellowjacket SCBL HV B-17 50231200490000 215189 1/4/2024 Yellowjacket GPT-PERF HV B-16A 50231200400100 222070 1/12/2024 Yellowjacket GPT-PERF KBU 22-06Y 50133206500000 215044 12/5/2023 Yellowjacket GPT-PERF KTU 43-6XRD2 50133203280200 205117 12/4/2023 YELLOWJACKET GPT-PERF KU 21X-32 50133202040000 169100 12/23/2023 AK E-Line CALIPER TBU M-11 50733205900000 210145 11/10/2023 AK E-Line PL/PERF Please include current contact information if different from above. T38451 T38452 T38453 T38454 T38455 T38456 T38457 T38458 1/31/2024 KBU 22-06Y 50133206500000 215044 12/5/2023 Yellowjacket GPT-PERF Kayla Junke Digitally signed by Kayla Junke Date: 2024.01.31 09:35:23 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/12/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240112 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 221-35 50283201930000 223077 11/4/2023 AK E-LINE CBL END 1-27 50029216930000 187009 11/16/2023 YELLOWJACKET PERF KALOTSA 4 50133206650000 217063 9/28/2023 YELLOWJACKET PERF KALOTSA 8 50133207050000 222003 11/29/2023 YELLOWJACKET PERF KBU 13-8 50133203040000 177029 11/5/2023 YELLOWJACKET PERF KBU 22-06Y 50133206500000 215044 11/9/2023 YELLOWJACKET GPT KBU 22-06Y 50133206500000 215044 11/17/2023 YELLOWJACKET PLUG-PERF KBU 11-08Z 50133206290000 214044 8/24/2023 AK E-LINE GPT/CIBP/PERF KBU 22-06Y 50133206500000 215044 10/9/2023 AK E-LINE CBL KBU 23-05 50133206300000 214061 10/10/2023 AK E-LINE PLT KBU 43-07Y 50133206250000 214019 10/6/2023 AK E-LINE CIBP/PERF MPU I-01 50029220650000 190090 11/18/2023 YELLOWJACKET PERF PAXTON 12 50133207100000 223014 11/20/2023 YELLOWJACKET PERF PAXTON 7 50133206430000 214130 9/18/2023 YELLOWJACKET CBL PAXTON 7 50133206430000 214130 10/7/2023 YELLOWJACKET PERF SRU 224-10 50133101380100 222124 12/27/2023 YELLOWJACKET GPT-PLUG-PERF SRU 224-10 50133101380100 222124 11/4/2023 YELLOWJACKET PERF SRU 231-33 50133101630100 223008 11/8/2023 YELLOWJACKET PERF-PLUG-GPT SRU 231-33 50133101630100 223008 11/3/2023 YELLOWJACKET PERF SRU 231-33 50133101630100 223008 10/17/2023 YELLOWJACKET PLUG-PERF-GPT SRU 232-15 50133207140000 223091 12/6/2023 YELLOWJACKET GPT-PERF SRU 232-15 50133207140000 223091 12/2/2023 YELLOWJACKET SCBL Please include current contact information if different from above. T38273 T38275 T38277 T38278 T38279 T38280 T38280 T38281 T38282 T38283 T38284 T38285 T38286 T38287 T38287 T38288 T38288 T38289 T38289 T38289 T38290 T38290 1/18/2024 KBU 22-06Y 50133206500000 215044 10/9/2023 AK E-LINE CBL KBU 22-06Y 50133206500000 215044 11/9/2023 YELLOWJACKET GPT KBU 22-06Y 50133206500000 215044 11/17/2023 YELLOWJACKET PLUG-PERF Kayla Junke Digitally signed by Kayla Junke Date: 2024.01.18 11:52:00 -09'00' 1 Junke, Kayla M (OGC) From:McLellan, Bryan J (OGC) Sent:Wednesday, December 20, 2023 4:30 PM To:Chad Helgeson Cc:Donna Ambruz Subject:RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Additional perf Request Hilcorp has approval to add the perfs proposed below as part of sundry 323‐511. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Wednesday, December 20, 2023 2:22 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22‐06Y (PTD# 215‐044) Sundry # 323‐511 Additional perf Request Bryan, We conƟnue to look for the gas that we used to get from this well, but haven’t found it yet. We thought we would be successful prior to geƫng to this point in the well, but we have not. We would like to add the following sands to this sundry 323‐511, which are all in the Beluga/Upper Tyonek Gas Pool perf CO 510C. We plan to leave current zones that are open with a small amount of water on them open, and not plug them back. Sands Top MD Btm MD Top TVD Btm TVD LB 1 ±6,380’ ±6,400’ ±6,125’ ±6,144’ LB 1A ±6,420’ ±6,432’ ±6,162’ ±6,174’ LB 1B ±6,461’ ±6,473’ ±6,201’ ±6,212’ LB 1C ±6,520’ ±6,526’ ±6,257’ ±6,262’ LB 2B ±6,792’ ±6,812’ ±6,511’ ±6,530’ LB 2E ±6,962’ ±6,974’ ±6,670’ ±6,682’ LB 3 ±6,998’ ±7,006’ ±6,704’ ±6,712’ LB 3B Upr ±7,069’ ±7,075’ ±6,770’ ±6,776’ LB 3B Mid ±7,083’ ±7,091’ ±6,783’ ±6,791’ LB 4A Upr ±7,218’ ±7,224’ ±6,910’ ±6,915’ Please let me know if you need any addiƟonal informaƟon for these addiƟonal sands. AƩached is a Current/Proposed SchemaƟc of the well. Thanks 2 Chad Helgeson From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Friday, December 1, 2023 3:31 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: [EXTERNAL] RE: KBU 22‐06Y (PTD# 215‐044) Sundry # 323‐511 Additional perf Request Chad, Hilcorp has approval to add the addiƟonal perfs menƟoned below as part of Sundry 323‐511. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, December 1, 2023 3:15 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: KBU 22‐06Y (PTD# 215‐044) Sundry # 323‐511 Additional perf Request Bryan, We completed our unsuccessful test of the coals at KGF in well KBU 22‐06Y. We are conƟnuing uphole with perforaƟng the convenƟonal sands in the well. There are 2ea sands that were not included in the sundry to perf that are in the middle of the exisƟng proposed perfs. We would like to add the following sands to perf in the well. These are all in the Beluga/Upper Tyonek Gas Pool perf CO 510C. LB5C 7,522‐7,552’ (30Ō) LB6A 7,584‐7590’ (6Ō) Please let me know if you need any addiƟonal informaƟon for these addiƟonal sands. AƩached is a Current SchemaƟc of the well. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 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. 3 Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907‐777‐8405 ‐ O 907‐229‐4824 ‐ C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Page 1 of 2 Updated by CAH 12-20-23 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 CURRENT/PROPOSED PBTD = 8,724’ MD / 8,542’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11.00” Tubing Hanger 2 5,019’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 7,510’ 2.441” CIBP (12/7/23) 4 7,635’ 2.441” CIBP w/ 10’ of cmt (11/5/23) 5 8,510’ 2.441” CIBP w/ 10ft of cement (11/17/23) 6 8,768’ 4.276” Milled & push CIBP 7 8,990’ - 4.276” CIBP w/ 25ft of cement (8/20/22) 8 10,065’ - 3.710” Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4” 110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8" 244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5” 132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8” 45 bbls of 15.3#. TOC 6,030’ based on CBL CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven 109 X-56 Weld 15.00” Surf 136' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 1,524’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012’ TUBING 5" Production 18 L-80 DWC/C-HT 4.276” Surf 10,184’ 2-7/8” Production 6.5 L-80 8RD EUE 2.441” Surf 8,773’ 1 16” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBL TOC 5,008’ 8 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 1 ±6,380’ ±6,400’ ±6,125’ ±6,144’ TBD LB 1A ±6,420’ ±6,432’ ±6,162’ ±6,174’ TBD LB 1B ±6,461’ ±6,473’ ±6,201’ ±6,212’ TBD LB 1C ±6,520’ ±6,526’ ±6,257’ ±6,262’ TBD LB 2B ±6,792’ ±6,812’ ±6,511’ ±6,530’ TBD LB 2E ±6,962’ ±6,974’ ±6,670’ ±6,682’ TBD LB 3 ±6,998’ ±7,006’ ±6,704’ ±6,712’ TBD LB 3B Upr ±7,069’ ±7,075’ ±6,770’ ±6,776’ TBD LB 3B Mid ±7,083’ ±7,091’ ±6,783’ ±6,791’ TBD LB 4A Upr ±7,218’ ±7,224’ ±6,910’ ±6,915’ TBD LB 4A 7,231’ 7,251’ 6,922’ 6,940’ 12/8/23 2” Open LB 4B L 7,275’ 7,293’ 6,963’ 6,980’ 12/8/23 2” Open LB 4C L 7,341’ 7,355’ 7,025’ 7,038’ 12/7/23 2” Open LB 5A Up 7,420’ 7,426’ 7,098’ 7,104’ 12/7/23 2” Open LB 5A Mid 7,434’ 7,442’ 7,111’ 7,119’ 12/8/23 2” Open LB 5A L 7,447’ 7,460’ 7,123’ 7,136’ 12/7/23 2” Open LB 5C 7,522’ 7,552’ ±7,193’ ±7,221’ 12/6/23 2” Isolated LB 6A 7,584’ 7,590’ ±7,251’ ±7,257’ 12/6/23 2” Isolated TY 72 8 7,645’ 7,685’ 7,336’ 7,345’ 11/18/23 2” Isolated UT-1B 7,825’ 7,840’ 7,476’ 7,490’ 11/17/23 2” Isolated UT 4D (coal) 8,552’ 8,578’ 8,157’ 8,181’ 11/6/23 2-1/8” Strip Isolated UT 4E (coal) 8,674’ 8,690' 8,272’ 8,287’ 11/3/23 2-1/8” Strip Isolated PERFORATION DETAIL continued on following page LB 1 - L4B L TY 72_8 Fish: Milled CIBP to 8768’ (10/2/23) with Rig 401 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish: 31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 6 LB 4C L- 5A L RA @ 8004 RA @ 8293 RA @ 8563 RA @ 8826 RA @ 9072 RA @ 9359 RA @ 9605 RA @ 9891 7 CBL TOC 6,030’ 3 4 6 5 Page 2 of 2 Updated by CAH 12-20-23 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 CURRENT/PROPOSED PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075' 6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091' 6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224' 6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251' 6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293' 6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341' 7,355' 7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420' 7,426' 7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434' 7,442' 7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460' 7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz Subject:RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Additional perf Request Date:Friday, December 1, 2023 3:30:00 PM Chad, Hilcorp has approval to add the additional perfs mentioned below as part of Sundry 323-511. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, December 1, 2023 3:15 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Additional perf Request Bryan, We completed our unsuccessful test of the coals at KGF in well KBU 22-06Y. We are continuing uphole with perforating the conventional sands in the well. There are 2ea sands that were not included in the sundry to perf that are in the middle of the existing proposed perfs. We would like to add the following sands to perf in the well. These are all in the Beluga/Upper Tyonek Gas Pool perf CO 510C. LB5C 7,522-7,552’ (30ft) LB6A 7,584-7590’ (6ft) Please let me know if you need any additional information for these additional sands. Attached is a Current Schematic of the well. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz Subject:RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Cement Bond Log Date:Tuesday, November 7, 2023 4:56:00 PM Chad, Hilcorp has approval to perform the pressure fall-off test as described below and to perforate the remaining intervals listed in the approved sundry 323-5511. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, November 7, 2023 3:45 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Cement Bond Log Bryan, We perforated the coal sands on this well and had a very slow buildup (<100 psi in 3 days). Our reservoir team asked if we could do a leakoff/falloff test on these coals to see if they are permeable at all. We want to confirm that the gas test with only coals open isn’t a wellbore damage from cement invasion or mud that perf guns weren’t able to get past. We are also perforated the well with 2” guns with 2 strings of pipe at this depth, so not a lot of penetration. I was not sure if a this testing required a change of program or if we need approval to perform a falloff test, so I am trying to receive confirmation we can proceed with below either with an email or direction for a change of program. Current Conditions (Schematic updated & attached) The well is currently at 100 psi and fluid level of ~8500’ after perforating. Coals at 8674-8690 & 8552-8578 are currently open in the 2-7/8” tubing. Proposed plan The proposed steps forward would be: 1. MIRU, pump truck/skid, PT lines to 4500 psi CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. 2. Fill well with water (KCl) ~50bbls 3. Pressure up well to 4000 psi and monitor leakoff. 4. Once complete with this test, we would blow well down with N2 and see if it flows or start adding the rest of the perfs in the approved sundry. 5. Flow well Please let me know if you want to discuss or need additional information. We also still need approval for perforating the remaining sands post CBL submitted several weeks ago. Regards Chad From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Thursday, November 2, 2023 2:50 PM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Cement Bond Log Chad, Hilcorp is approved to perforate the zones you described immediately below. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 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: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, November 2, 2023 10:47 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Loepp, Victoria T (OGC) <victoria.loepp@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Cc: Donna Ambruz <dambruz@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Cement Bond Log I am looking for some help while Bryan is out. Below is communication we had about the cement bond log (attached) we ran on KBU 22-06Y between the 2-7/8” tubing and the 5” liner. Can you please review and provide Hilcorp approval to perforate the proposed lowest coal zones we have requested at 8674-8690 and 8552-8578’? The TOC in this interval is at 6,030’. We are ready to perforate the zone from 8674-8690’ tomorrow. Chad From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, October 19, 2023 11:06 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: RE: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Cement Bond Log We maintained returns while pumping, but we did lose 13bbls throughout the job. Also FYI, we were unable to swab the well all the way down, so we are waiting on coil to blow the well dry and clean out the bottom 100ft of cement we got in the bottom of the tubing, so we have not perforated anything, which is why I haven’t bugged you for approval yet. Chad From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, October 19, 2023 10:36 AM To: Chad Helgeson <chelgeson@hilcorp.com> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: [EXTERNAL] RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Cement Bond Log Chad, Why do you think the TOC is so much lower than planned? Did you have losses while pumping cement? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 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. Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Tuesday, October 10, 2023 7:54 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com> Subject: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 Cement Bond Log Bryan, Attached is the CBL for the 2-7/8” x 5” annulus we completed yesterday. The TOC is at 6,030’. There is some limited bond of cement between 7950 and 8470, but this should not impact our completion of the well. We are swabbing the well down today, and will hopefully be perforating on Thursday. Let me know if you have any questions on this log. Thanks Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________KENAI BELUGA UNIT 22-06Y JBR 11/21/2023 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:0 Tested with a 2 7/8" test joint. Tested 3 LEL & H2S stations. Very good test once the initial shell test was completed. Test Results TEST DATA Rig Rep:Kevin ReedOperator:Hilcorp Alaska, LLC Operator Rep:Josh Stephenson Rig Owner/Rig No.:Hilcorp 401 PTD#:2150440 DATE:9/29/2023 Type Operation:WRKOV Annular: 250/3000Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopJDH230929205103 Inspector Josh Hunt Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 3 MASP: 2734 Sundry No: 323-511 Control System Response Time (sec) Time P/F Housekeeping:P PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid W Misc NA Upper Kelly 1 P Lower Kelly 0 NA Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 8 PNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 7" 5M P #1 Rams 1 2 7/8 x 3 1/2" P #2 Rams 1 Blinds P #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 2 1/16" 5M P HCR Valves 1 2 1/16" 5M P Kill Line Valves 3 2 1/16" 5M P Check Valve 0 NA BOP Misc 0 NA System Pressure P3000 Pressure After Closure P2500 200 PSI Attained P12 Full Pressure Attained P31 Blind Switch Covers:PAll Stations Bottle precharge P Nitgn Btls# &psi (avg)P6-1750psi ACC Misc NA0 NA NATrip Tank P PPit Level Indicators NA NAFlow Indicator P PMeth Gas Detector P PH2S Gas Detector 0 NAMS Misc Inside Reel Valves 0 NA Annular Preventer P6 #1 Rams P3 #2 Rams P3 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill NA0 CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Regg, James B (OGC); Howard Hooter - (C); Donna Ambruz Subject:RE: KBU 22-06Y (PTD# 215-044) Sundry # 323-511 BOP Change Date:Thursday, September 21, 2023 12:09:00 PM Attachments:Yellowjacket 7-1 16 inch Type U BOP Stack Drawing.pdf Chad, Hilcorp has approval to use the BOP stack as proposed in the attached diagram. Note that I’ve corrected the PTD number in the subject line of this email. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Thursday, September 21, 2023 11:25 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Regg, James B (OGC) <jim.regg@alaska.gov>; Howard Hooter - (C) <Howard.Hooter@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com> Subject: KBU 22-06Y (PTD# 214-044) Sundry # 323-511 BOP Change Bryan, We would like to change the BOP stack I originally proposed on KBU 22-06Y from a 7” triple ram to the dual ram we used on Paxton 7. The stack I submitted was being used on the slope and the primary reason I submitted the proposed stack was it was a lower cost to rent for the job, but it is unavailable. This meets requirements on this workover. Let me know if you need anything more for this BOP change on the workover for KBU 22-06Y. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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 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. EQUIPMENT HEIGHT 99.09" ADDITION FOR RING GASKETS TOTAL STACK HEIGHT 2 each @ 0.50" 99.59" OPEN AND CLOSE DATA OPEN CLOSE 2-1/16" 5M HCR 0.61 0.52 HEIGHT DATA AND WEIGHT DATA 7-1/16" 5M ANNULAR 3.21 4.57 7-1/16" 10M RAMS (PER SET)1.3 1.3 7-1/16" 5M ANNULARSHAFFER STYLE HEIGHT: 30.9" WEIGHT: 3042 LBS 7-1/16" 5M TYPE U BOP HEIGHT: 44.19" WEIGHT: 6400 LBS 7-1/16" 5M TYPE U STACK 7-1/16" 5M DRILLING SPOOL HEIGHT: 24" WEIGHT: 1600 LBS KILL SIDE: 2 EACH 2-1/16" 5M MGV CHOKE SIDE: 1 EACH 2-1/16" 5M MGV AND 1 EACH 2-1/16" 5M HCR 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: CTCO, N2, Cmt Sqz 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): 10,200'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 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 5,019' MD - 4,853' TVD; N/A 9,697'10,065'9,571' Kenai Beluga-Up Tyonek Gas, Tyonek Gas 16" 10-3/4" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 22-06YCO 510C Same ~2,734psi N/A Length September 20, 2023 5" Perforation Depth MD (ft): 8,012' See Attached Schematic 6,890 psi 5,210 psi 136' 7,651' 136' 1,524' Size 136' 7-5/8"8,012' 1,524' MD Hilcorp Alaska, LLC Proposed Pools: 18.0# / L-80 TVD Burst 10,184' 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 FEEA028142 215-044 50-133-20650-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 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 t N 66 Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 11:39 am, Sep 08, 2023 323-511 Digitally signed by Aras Worthington (4643) DN: cn=Aras Worthington (4643) Date: 2023.09.08 10:05:05 -08'00' Aras Worthington (4643) Perform MITIA of 2-7/8" x 5" annulus to 2500 psi within 30 days of the final set of perforations to be shot under this sundry. SFD 9/12/2023 DSR-9/12/23 X BJM 9/12/23 BOP test to 3000 psi 10-404 *&: JLC 9/13/2023 09/13/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.13 19:12:06 -05'00' RBDMS JSB 120623 Well Prognosis Well: KBU 22-06Y Date: 9-6-23 Well Name: KBU 22-06Y API Number: 50-133-20650-00 Current Status: SI Gas well Permit to Drill Number: 215-044 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Maximum Expected BHP: 3,563 psi @ ~8,287’ TVD (Normal gradient zones at .43 psi/ft) Max. Potential Surface Pressure: 2,734 psi (Gas gradient to surface (0.10psi/ft)) Brief Well Summary KBU 22-06Y was drilled and completed in the Tyonek D in 2015 by Hilcorp. It was perf’d and produced in the D3A and in 2016 the D2 was added. At its peak, it was producing at rates around 6600 mcfd. In mid-2021, Tyonek and Upper Beluga/Tyonek Pools were commingled with the Ty 72_8 and the UT 1B were added with subpar results. Additional upper Tyonek sands were perforated in late 2021 and the well stabilized. The Tyonek Gas Pool was isolated in August of 2022 with a plug set at 8,990’. Rate was stable until additional lower Beluga perfs were added and killed the well. A CIBP was set trying to isolate the wet zones, but the well has never recovered and has been shut-in. The purpose of this work/sundry is to mill out the CIBP, cleanout the well to 8,790’ in the Beluga/Upper Tyonek Gas Pool and run a 2-7/8” scab liner cemented in place. Two deep coal zones will be perforated and tested. If those are unsuccessful, they will be plugged back and zones that were productive prior to shooting a wet sand will be attempted to return to production. Well Status: SI gas producer since August of 2022. Notes Regarding Wellbore Condition x Production tubing is 5” 18# L-80 tubing. x Min Id is 4.276”. x Coil tag on 9/25/22 @ 7310 (CIBP) x Current Pressures (T/I/O): 10/710/0 x Max Inclination: 23deg @ 9014’ x Max DLS: ~4 degrees / 100’ at 753’ MD x MIT History: o MIT-IA of 5-1/2” x 7-5/8” casing passed to 1500 psi on 10/23/20 after completion x 5-1/2” Cement with RBCL – TOC @ 5,008’ x 7-5/8” Cement with RCBL – TOC @ 3,670’ Procedure: 1. MIRU Hilcorp rig #401 2. Fill well with produced water (~8.5ppg) and ensure well is dead 3. Set BPV / TWC 4. NU 7” BOP’s and test a. Provide 24 hr notice to AOGCC b. PT to 250psi low / 2500psi high c. Test with 2-7/8” 5. Pull BPV / TWC 6. Monitor well to ensure its static, fill well as necessary BOP test to 3000 psi Well Prognosis Well: KBU 22-06Y Date: 9-6-23 7. MU milling BHA and RIH on tubing 2-7/8” 8RD EUE & PH6 as needed 8. Tag CIBP at 7,310’ and mill plug and work to 8,790’. a. Establish milling parameters and mill/cleanout well to full joint past 8,790’ b. If unable to get returns, pump salt pills as necessary 9. POOH and laydown milling BHA Contingency: If milling/cleanout proves challenging due to lack of returns, may elect to spot or dump bail squeeze cement at perfs to heal losses, and/or aid in milling. 10.MU 2-7/8” liner/scab assembly w/ cement shoe 11.RIH with 2-7/8” liner and land at ±8,780’ 12.Cement 2-7/8” liner in place with ~15.8 ppg cement with LCM as necessary a.Planned TOC ~5500’ in 2-7/8” x 5” Annulus b.Cement volume of ~32bbls 13. Set BPV / TWC 14. ND BOPs, NU Tree, test to 5000psi Completion procedure 15. MIRU E-line and pressure control equipment 16. PT lubricator to 250psi low / 3500psi high 17. Log CBL of 2-7/8” production liner from PBTD to above TOC 18. RDMO EL 19. MIT-T to 3500psi for 30 minutes (charted) 20. MIRU SL and pressure control equipment 21. PT lubricator to 250psi low / 3500psi high 22. Swab well to tank ~51 bbls 23. RDMO SL 24. Pressure up well with N2 for perforating, approximately 2500 psi Perf procedure 25. MIRU Eline, pressure test lubricator, 250psi low / 4000psi High 26. PU and RIH W/perf guns. Perforate with perf guns phasing. If necessary, bleed N2 pressure down as requested by the OE to establish a drawdown on the formation, prior to perforating. 27. Proposed Perforated Intervals: Coals MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) UT 4D ±8,552’ ±8,578’ ±8,157’ ±8,181’ 26’ UT 4E ±8,674’ ±8,690' ±8,272’ ±8,287’ 16' a.Proposed perfs. also shown on the proposed schematic in red font. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c. Use Gamma/CCL to correlate d. Verify PTs are open to SCADA or Krystal gauge is on well before perforating. Record tubing pressures before and after each perforating run at 0, 5, 10, and 15 min intervals post shot. e. These coals are in the Beluga/ Upper Tyonek Gas Pool per CO 510C. 28. Test coals individually. May include PT surveys, flowing well, swabbing fluid off well, etc. ppg,,, These coals are in the Beluga/ Upper Tyonek Gas Pool per CO 510C. Well Prognosis Well: KBU 22-06Y Date: 9-6-23 29. RD e-line 30. Turn well over to production 31. Test zones per Reservoir engineer. If coals are non productive, plug back coals Contingency perforating if coals are not productive or have low rate: 32. MIRU Eline, pressure test lubricator, 250psi low / 3500psi High 33. PU and RIH W/perf guns. If necessary, bleed N2 pressure down as requested by the OE to establish a drawdown on the formation, prior to perforating. 34. Proposed Perforated Intervals to be shot bottom up: Sands MD Top MD Bottom TVD Top TVD Bottom Total Footage (MD) LB 4A ±7,231’ ±7,251’ ±6,922’ ±6,940’ ±20 LB 4B L ±7,275’ ±7,293’ ±6,963’ ±6,980’ ±18 LB 4C L ±7,341’ ±7,355’ ±7,025’ ±7,038’ ±14 LB 5A Up ±7,420’ ±7,426’ ±7,098’ ±7,104’ ±6 LB 5A Mid ±7,434’ ±7,442’ ±7,111’ ±7,119’ ±8 LB 5A L ±7,447’ ±7,460’ ±7,123’ ±7,136’ ±13 TY 72_8 ±7,645’ ±7,674’ ±7,308’ ±7,335’ ±29 TY 72_8 ±7,675’ ±7,685’ ±7,336’ ±7,345’ ±10 TY 73_1 ±7,712’ ±7,721’ ±7,371’ ±7,379’ ±9 TY 73_1 ±7,729’ ±7,735’ ±7,386’ ±7,392’ ±6 UT-1B ±7,825’ ±7,840’ ±7,476’ ±7,490’ ±15 TY 78_2 Up ±8,277’ ±8,293’ ±7,901’ ±7,916’ ±16 TY_78_2 L ±8,300’ ±8,325’ ±7,923’ ±7,946’ ±25 UT 4A L ±8,365’ ±8,383’ ±7,983’ ±8,000’ ±18 a.Proposed perfs. also shown on the proposed schematic in red font. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c. Use Gamma/CCL to correlate. d. Verify PTs are open to SCADA or Krystal gauge is on well before perforating. Record tubing pressures before and after each perforating run at 0, 5, 10, and 15 min intervals post shot. e. These coals are in the Beluga/ Upper Tyonek Gas Pool per CO 510C. 35. POOH 36. RD E-line 37.Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Contingencies: I) Coil Tubing & Nitrogen Procedure (Contingency if fill is encountered after perforating, cement stringers after cementing, or fluid won’t push back into formation): 1. MIRU Coiled Tubing, notify AOGCC 24 hours in advance of BOP test, PT BOPE to 3500 psi 2. Clean out to TD 3. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU Perform MITIA to 2500 psi in 2-7/8" x 5" annulus within 30 days of shooting the last set of perfs under this sundry. -bjm pg,,, Beluga/ Upper Tyonek Gas Pool per CO 510C. Well Prognosis Well: KBU 22-06Y Date: 9-6-23 II) E-line Procedure (Contingency if water is encountered after perforating): 1. MIRU E-Line, PT lubricator to 3000 psi 2. Use N2 to push water into formation, monitoring with GPT 3. RIH and set plug above the perforations OR set patch over the wet perforations Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Proposed Wellhead Diagram 4. Rig 401 BOP Diagram 5. Coil tubing BOP Diagram 6. Nitrogen SOP Updated by DMA 08-01-23 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 SCHEMATIC PBTD = 8,965’ MD / 8,542’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No.Depth ID OD Item 1 18’4.276”11.00”Tubing Hanger 2 5,019’4.276”6.875”10 ft Swell Packer (Water Swell) 3 7,333’4.276”CIBP 9/25/22 4 8,990’-4.276”CIBP w/ 25ft of cement (8/20/22) 5 10,065’-3.710”Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8"244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5”132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00”Surf 136' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 1,524’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 8,012’ TUBING 5"Production 18 L-80 DWC/C-HT 4.276”Surf 10,184’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBL TOC 5,008’ 4 D-3B D-2A UT 1B PERFORATION DETAIL Sands Top (MD)Btm (MD)Top (TVD)Btm (TVD)Date Size Status LB 1 6,380'6,400'6,125'6,144'8/9/2022 3-3/8”Open LB 1A 6,420'6,432'6,163'6,174'8/9/2022 3-3/8”Open LB 1B 6,461'6,473'6,201'6,213'8/9/2022 3-3/8”Open LB 1C 6,520'6,526'6,256'6,263'8/9/2022 3-3/8”Open LB 2B 6,792'6,812'6,512'6,530'8/9/2022 3-3/8”Open LB 2C 6,839'6,847'6,556'6,563'8/8/2022 3-3/8”Open LB 2D 6,871'6,904'6,586'6,616'8/8/2022 3-1/8”Open LB 2E 6,962'6,974'6,670'6,682'8/8/2022 3-1/8”Open LB 3 6,998'7,006'6,704'6,712'8/8/2022 3-1/8”Open LB 3B U 7,069'7,075'6,771'6,776'8/8/2022 3-1/8”Open LB 3B M 7,083'7,091'6,784'6,791'8/8/2022 3-1/8”Open LB 4A U 7,218'7,224'6,910'6,915'8/8/2022 3-1/8”Open LB 4A 7,231'7,251'6,922'6,940'8/5/2022 3-1/8”Open LB 4B L 7,275'7,293'6,963'6,980'8/5/2022 3-1/8”Open LB 4C L 7,341'7,355'7,025'7,038'8/5/2022 3-1/8”Isolated LB 5A U 7,420'7,426'7,098'7,104'8/4/2022 3-1/8”Isolated LB 5A M 7,434'7,442'7,111'7,119'8/4/2022 3-1/8”Isolated LB 5A L 7,447'7,460'7,123'7,136'8/4/2022 3-1/8”Isolated TY 72_8 7,645’7,655’7,308’7,318’7/12/2021 3-3/8”Isolated TY 72_8 7,675’7,685’7,336’7,345’7/12/2021 3-3/8”Isolated UT 1B 7,825’7,840’7,476’7,490’6/14/2021 2-7/8”Isolated D1 9,324’9,338’8,876’8,890’10/1/2021 2-7/8”Isolated D-2A 9,454’9,494’8,997’9,035’6/16/2016 2-7/8”Isolated D3 9,747’9,757’9,274’9,284’10/1/2021 2-7/8”Isolated D-3B 9,812’9,847’9,334’9,367’5/30/2015 3.5” PJN Isolated LB 1 - L4B L TY 72_8 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 5 LB 4C L- 5A L RA @ 8004 RA @ 8293 RA @ 8563 RA @ 8826 RA @ 9072 RA @ 9359 RA @ 9605 RA @ 9891 3 Page 1 of 2 Updated by DMA 09-08-23 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 PROPOSED PBTD = 8,965’ MD / 8,542’ TVD TD = 10,200’ MD / 9,697’ TVD Ty Gas Pool #1 Top @ 9,432’ Beluga/Up Ty Gas Pool JEWELRY DETAIL No.Depth ID OD Item 1 18’4.276”11.00”Tubing Hanger 2 5,019’4.276”6.875”10 ft Swell Packer (Water Swell) 3 8,750’4.276”Milled & push CIBP 4 8,990’-4.276”CIBP w/ 25ft of cement (8/20/22) 5 10,065’-3.710”Cement Retainer RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8"244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5”132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,008’ (RCBL 5-23-15 TOC) 2-7/8”32 bbls of 15.3#. planned TOC @ ~5,500’ CASING DETAIL Size Type Wt Grade Conn.ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00”Surf 136' 10-3/4"Surf. Csg 45.5 L-80 BTC 9.950”Surf 1,524’ 7-5/8"Intermediate 29.7 L-80 BTC 6.875"Surf 8,012’ TUBING 5"Production 18 L-80 DWC/C-HT 4.276”Surf 10,184’ 2-7/8”Production 6.4 L-80 8RD 2.44 Surf 8,700’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 CBL TOC 5,008’ 4 D-3B D-2A UT 1B PERFORATION DETAIL Coals Top MD Btm MD Top TVD Btm TVD Date Size Status UT 4D ±8,552’±8,578’±8,157’±8,181’Proposed TBD UT 4E ±8,674’±8,690'±8,272’±8,287’Proposed TBD Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 4A ±7,231’±7,251’±6,922’±6,940’Proposed TBD LB 4B L ±7,275’±7,293’±6,963’±6,980’Proposed TBD LB 4C L ±7,341’±7,355’±7,025’±7,038’Proposed TBD LB 5A Up ±7,420’±7,426’±7,098’±7,104’Proposed TBD LB 5A Mid ±7,434’±7,442’±7,111’±7,119’Proposed TBD LB 5A L ±7,447’±7,460’±7,123’±7,136’Proposed TBD TY 72 8 ±7,645’±7,674’±7,308’±7,335’Proposed TBD TY 72 8 ±7,675’±7,685’±7,336’±7,345’Proposed TBD TY 73 1 ±7,712’±7,721’±7,371’±7,379’Proposed TBD TY 73 1 ±7,729’±7,735’±7,386’±7,392’Proposed TBD UT-1B ±7,825’±7,840’±7,476’±7,490’Proposed TBD TY 78 2 Up ±8,277’±8,293’±7,901’±7,916’Proposed TBD TY 78 2 L ±8,300’±8,325’±7,923’±7,946’Proposed TBD UT 4A L ±8,365’±8,383’±7,983’±8,000’Proposed TBD LB 4A ±7,231’±7,251’±6,922’±6,940’Proposed TBD LB 4B L ±7,275’±7,293’±6,963’±6,980’Proposed TBD PERFORATION DETAIL continued on following page LB 1 - L4B L TY 72_8 Fish: Milled CIBP pushed to 8,790’ (9/24/22) Fish:31.5’ SL Tool String @ 9,006’, 3.5” DD Bailer, Spangs, oil jars, knuckle jt, stem, & rope socket 5 LB 4C L- 5A L RA @ 8004 RA @ 8293 RA @ 8563 RA @ 8826 RA @ 9072 RA @ 9359 RA @ 9605 RA @ 9891 3 Proposed TOC 5500’ Page 2 of 2 Updated by DMA 09-08-23 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00-00 PROPOSED PERFORATION DETAIL - Continued Sands Top MD Btm MD Top TVD Btm TVD Date Size Status LB 1 6,380' 6,400' 6,125' 6,144' 8/9/2022 3-3/8” Isolated LB 1A 6,420' 6,432' 6,163' 6,174' 8/9/2022 3-3/8” Isolated LB 1B 6,461' 6,473' 6,201' 6,213' 8/9/2022 3-3/8” Isolated LB 1C 6,520' 6,526' 6,256' 6,263' 8/9/2022 3-3/8” Isolated LB 2B 6,792' 6,812' 6,512' 6,530' 8/9/2022 3-3/8” Isolated LB 2C 6,839' 6,847' 6,556' 6,563' 8/8/2022 3-3/8” Isolated LB 2D 6,871' 6,904' 6,586' 6,616' 8/8/2022 3-1/8” Isolated LB 2E 6,962' 6,974' 6,670' 6,682' 8/8/2022 3-1/8” Isolated LB 3 6,998' 7,006' 6,704' 6,712' 8/8/2022 3-1/8” Isolated LB 3B U 7,069' 7,075' 6,771' 6,776' 8/8/2022 3-1/8” Isolated LB 3B M 7,083' 7,091' 6,784' 6,791' 8/8/2022 3-1/8” Isolated LB 4A U 7,218' 7,224' 6,910' 6,915' 8/8/2022 3-1/8” Isolated LB 4A 7,231' 7,251' 6,922' 6,940' 8/5/2022 3-1/8” Isolated LB 4B L 7,275' 7,293' 6,963' 6,980' 8/5/2022 3-1/8” Isolated LB 4C L 7,341' 7,355' 7,025' 7,038' 8/5/2022 3-1/8” Isolated LB 5A U 7,420' 7,426' 7,098' 7,104' 8/4/2022 3-1/8” Isolated LB 5A M 7,434' 7,442' 7,111' 7,119' 8/4/2022 3-1/8” Isolated LB 5A L 7,447' 7,460' 7,123' 7,136' 8/4/2022 3-1/8” Isolated TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/2021 3-3/8” Isolated TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/2021 3-3/8” Isolated UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/2021 2-7/8” Isolated D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/2021 2-7/8” Isolated D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/2016 2-7/8” Isolated D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/2021 2-7/8” Isolated D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/2015 3.5” PJN Isolated Kenai Gas Field KBU 22-06Y Proposed 08/09/2023 Kenai Gas Field KBU 22-06Y 16 x 10 ¾ x 7 5/8 x 5 x 2 7/8 Starting head, Seaboard, 16 ¾ 3M X 16'’ SOW, w/ 2- 2 1/16 5M SSO Multibowl Wellhead, SMB-22, 11 5M X 16 ¾ 3M, w/ 4- 2 1/16 5M SSO 16'’ 10 ¾’’ 7 5/8'’ 5'’ Valve, Master, WKM-M, 3 1/8 5M FE, HWO, DD trim Valve, Upper master, WKM-M, 3 1/8 5M FE, HWO, DD trim Valve, Swab, WKM-M 3 1/8 5M FE, HWO, DD trim BHTA, Otis, 3 1/8 5M FE x 6.5 Otis quick union top Tubing head, Cactus C-HPS, 11 5M x 7 1/16 5M, w/ 2- 2 1/16 5M SSO Tubing hanger, Cactus-EN-CL, 7 x 3 1/2 EUE 8rd lift and susp, w/ 3'’ type H BPV profile Adapter, Cactus-EN, 7 1/16 5M Stdd x 3 1/8 5M prepped for 5 ½ extended neck hanger 2 7/8'’ !"" $% &’()*!’" +),-*!.(!$/.’*( /0& )*1(2!()& ’//0"’* $. ’,,)& "23 ,(0++)+ ($. 4 %"5 (&3 !,’4 ’ $. 6 7879:;<<< &=.3 .*7 >;:<6<;:<<<7?77 (* $. ’,,)& "23 * $. 6 7879:;<<< &=.3 .*73 ,(0++)+ $(($& 4 ($.3 =!(@ A?B C 7879:;D &=.3 ,(0++)+ $0(")( 6<:<6<;:<<<C>7C 7 7 C C ? ? 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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. Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/23/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221123 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# PAXTON 6 50133207070000 222054 8/1/2022 Yellowjacket PERF BCU-7A 50133202840100 214060 8/2/2022 Yellowjacket GPT-PERF KBU 43-07Y 50133206250000 214019 8/3/2022 Yellowjacket PERF KBU 22-06Y 50133206500000 215044 8/4/2022 Yellowjacket GPT-PERF SRU 32A-33 50133101640100 191014 8/21/2022 Yellowjacket GPT-PERF HVB 16A 50231200400100 222070 8/23/2022 Yellowjacket PERF PAXTON 10 50133206910000 220064 8/26/2022 Yellowjacket PERF HVB-16A 50231200400100 222070 8/27/2022 Yellowjacket PERF PAXTON 10 50133206910000 220064 8/29/2022 Yellowjacket PERF KALOTSA 4 50133206650000 217063 9/1/2022 Yellowjacket GPT-PERF KALOTSA 4 50133206650000 217063 9/6/2022 Yellowjacket PERF-GPT Please include current contact information if different from above. By Meredith Guhl at 9:26 am, Nov 29, 2022 T37305 T37306 T37306 T37307 T37307 T37308 T37309 T37310 T37311 T37311 T37312 KBU 22-06Y 50133206500000 215044 8/4/2022 Yellowjacket GPT-PERF Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.11.29 09:43:24 -09'00' By Anne Prysunka at 12:44 pm, Oct 19, 2022 5HJJ-DPHV% 2*& )URP %URRNV3KRHEH/ 2*& 6HQW )ULGD\2FWREHU 30 7R .DUVRQ.R]XE & &F 5HJJ-DPHV% 2*& 6XEMHFW 5( )R[ $WWDFKPHQWV )R[ 5HYLVHG[OV[ <ĂƌƐŽŶ͕ ƚƚĂĐŚĞĚŝƐĂƌĞǀŝƐĞĚƌĞƉŽƌƚĐŚĂŶŐŝŶŐƚŚĞƐƵŶĚƌLJηƚŽƌĞĨůĞĐƚϯϮϮͲϱϰϴ;ĂĐŽƵƉůĞŶƵŵďĞƌƐǁĞƌĞƚƌĂŶƐƉŽƐĞĚͿ͘WůĞĂƐĞ ƵƉĚĂƚĞLJŽƵƌĐŽƉLJ͘ dŚĂŶŬLJŽƵ͕ WŚŽĞďĞ WŚŽĞďĞƌŽŽŬƐ ZĞƐĞĂƌĐŚŶĂůLJƐƚ ůĂƐŬĂKŝůĂŶĚ'ĂƐŽŶƐĞƌǀĂƚŝŽŶŽŵŵŝƐƐŝŽŶ WŚŽŶĞ͗ϵϬϳͲϳϵϯͲϭϮϰϮ 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. &ƌŽŵ͗<ĂƌƐŽŶ<ŽnjƵďͲ;ͿфŬŬŽnjƵďΛŚŝůĐŽƌƉ͘ĐŽŵх ^ĞŶƚ͗^ĂƚƵƌĚĂLJ͕^ĞƉƚĞŵďĞƌϮϰ͕ϮϬϮϮϯ͗ϭϵWD dŽ͗ZĞŐŐ͕:ĂŵĞƐ;K'Ϳфũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀх͖KK'WƌƵĚŚŽĞĂLJфĚŽĂ͘ĂŽŐĐĐ͘ƉƌƵĚŚŽĞ͘ďĂLJΛĂůĂƐŬĂ͘ŐŽǀх͖ ƌŽŽŬƐ͕WŚŽĞďĞ>;K'ͿфƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀх Đ͗:ƵĂŶŝƚĂ>ŽǀĞƚƚфũůŽǀĞƚƚΛŚŝůĐŽƌƉ͘ĐŽŵх͖ŽŶŶĂŵďƌƵnjфĚĂŵďƌƵnjΛŚŝůĐŽƌƉ͘ĐŽŵх͖ƌĂĚ'ĂƚŚŵĂŶͲ;Ϳ фƌĂĚ͘'ĂƚŚŵĂŶΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗&ŽdžϴϬϵͲϮϯͲϮϮ 'ŽŽĚĨƚĞƌŶŽŽŶ͕ ƚƚĂĐŚĞĚŝƐƚŚĞKW ƚĞƐƚƌĞƉŽƌƚĨŽƌ&ŽdžϴdhϬϵͲϮϯͲϮϬϮϮ͘ <ĞŶĂŝĞůƵŐĂhŶŝƚ<hϮϮͲϬϲz;WdϮϭϱͲϬϰϰͿ;^ƵŶĚƌLJϯϮϮͲϱϰϴͿ͘ ZĞŐĂƌĚƐ͕ Karson Kozub ǣΪͳȋͻͲȌͷͲǦͳͺͲͳ ̷ Ǥ &$87,21 7KLVHPDLORULJLQDWHGIURPRXWVLGHWKH6WDWHRI$ODVNDPDLOV\VWHP'RQRWFOLFNOLQNVRURSHQ DWWDFKPHQWVXQOHVV\RXUHFRJQL]HWKHVHQGHUDQGNQRZWKHFRQWHQWLVVDIH .HQDL%HOXJD8QLW< 37' ƌĞǀŝƐĞĚƌĞƉŽƌƚĐ 7KHLQIRUPDWLRQFRQWDLQHGLQWKLVHPDLOPHVVDJHLVFRQILGHQWLDODQGPD\EHOHJDOO\SULYLOHJHGDQGLVLQWHQGHGRQO\IRUWKHXVHRIWKHLQGLYLGXDORUHQWLW\QDPHG DERYH,I\RXDUHQRWDQLQWHQGHGUHFLSLHQWRULI\RXKDYHUHFHLYHGWKLVPHVVDJHLQHUURU\RXDUHKHUHE\QRWLILHGWKDWDQ\GLVVHPLQDWLRQGLVWULEXWLRQRUFRS\RIWKLV HPDLOLVVWULFWO\SURKLELWHG,I\RXKDYHUHFHLYHGWKLVHPDLOLQHUURUSOHDVHLPPHGLDWHO\QRWLI\XVE\UHWXUQHPDLORUWHOHSKRQHLIWKHVHQGHU VSKRQHQXPEHULVOLVWHG DERYHWKHQSURPSWO\DQGSHUPDQHQWO\GHOHWHWKLVPHVVDJH :KLOHDOOUHDVRQDEOHFDUHKDVEHHQWDNHQWRDYRLGWKHWUDQVPLVVLRQRIYLUXVHVLWLVWKHUHVSRQVLELOLW\RIWKHUHFLSLHQWWRHQVXUHWKDWWKHRQZDUGWUDQVPLVVLRQ RSHQLQJRUXVHRIWKLVPHVVDJHDQGDQ\DWWDFKPHQWVZLOOQRWDGYHUVHO\DIIHFWLWVV\VWHPVRUGDWD1RUHVSRQVLELOLW\LVDFFHSWHGE\WKHFRPSDQ\LQWKLVUHJDUGDQG WKHUHFLSLHQWVKRXOGFDUU\RXWVXFKYLUXVDQGRWKHUFKHFNVDVLWFRQVLGHUVDSSURSULDWH STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION *All BOPE reports are due to the agency within 5 days of testing* SSu bm itt t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:8 DATE: 9/23/22 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2150440 Sundry #322-548 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/3000 Annular: Valves:250/3000 MASP:2321 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.NA Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 0NA Test Fluid Water Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0NAPit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0NAH2S Gas Detector NA NA #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 2 2"P Time/Pressure Test Result HCR Valves 0NASystem Pressure (psi)3000 P Kill Line Valves 2 2"FP Pressure After Closure (psi)2450 P Check Valve 0NA200 psi Attained (sec)4 P BOP Misc 0NAFull Pressure Attained (sec)11 P Blind Switch Covers: All stations YES CHOKE MANIFOLD:Bottle Precharge:P Quantity Test Result Nitgn. Bottles # & psi (Avg.):NA No. Valves 5P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NA #1 Rams 15 P Coiled Tubing Only:#2 Rams 11 P Inside Reel valves 1P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:1 Test Time:3.5 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice YES Date/Time 9/21/22 13:38hrs Waived By Test Start Date/Time:9/23/2022 10:00 (date) (time)Witness Test Finish Date/Time:9/23/2022 13:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Inside Kill line valve F/P. The valve was greased and cycled then passed on the second test. Accumulator system 4 bottles at 1400psi. Terence Rais Hilcorp Alaska Karson Kozub KBU 22-06Y Test Pressure (psi): Trais@FoxEnergyAK.com kkozub@hilcorp.com Form 10-424 (Revised 08/2022)2022-0923_BOP_Fox8_KBU_22-06Y 9 9 9 9 9 99 9 9 9 9 9 9 9 MEU 1$ - 5HJJ FP 1$ David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/3/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221003 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU 12A 501332053001 214070 8/10/2022 Halliburton CH PPROF BRU 222-34 502832018600 222039 9/15/2022 Halliburton CH RBT BRU 244-27 502832018500 222038 9/13/2022 Halliburton CH RBT END 1-45 500292199100 189124 8/11/2022 Halliburton CH PERF KBU 22-06Y 501332065000 215044 8/22/2022 Halliburton CH PPROF KBU 43-07Y 501332062500 214019 9/7/2022 Halliburton CH PPROF MPU C-24A 500292302001 209134 8/3/2022 Halliburton CH COILFLAG MPU L-46 500292355100 215118 9/10/2022 Halliburton CH MFC24 MPU S-34 500292317100 203130 9/3/2022 Halliburton CH MFC24 NS-10 500292298500 200182 8/18/2022 Halliburton CH WFL- TMD3D NS-32 500292317900 203158 8/17/2022 Halliburton CH WFL- TMD3D PBU 04-30 500292134500 185089 9/17/2022 Halliburton CH RMT3D PBU 05-24A 500292220401 204218 9/12/2022 Halliburton CH CAST PBU 11-16 500292158100 186078 9/10/2022 Halliburton CH PPROF PBU 11-27A 500292163801 222036 8/20/2022 Halliburton CH RBT PBU C-24B 500292081602 212063 8/16/2022 Halliburton CH PPROF PBU E-100A 500292281901 218157 9/20/2022 Halliburton CH LDL PBU S-106 500292299900 201012 9/12/2022 Halliburton CH RBT Please include current contact information if different from above. T37103 T37104 T37105 T37106 T37107 T37108 T37109 T37110 T37111 T37112 T37113 T37114 T37115 T37116 T37117 T37118 T37119 T37120 KBU 22-06Y 501332065000 215044 8/22/2022 Halliburton CH PPROF Kayla Junke Digitally signed by Kayla Junke Date: 2022.10.05 11:39:32 -08'00' 5HJJ-DPHV% 2*& )URP .DUVRQ.R]XE & NNR]XE#KLOFRUSFRP! 6HQW 7KXUVGD\$XJXVW 30 7R 5HJJ-DPHV% 2*& '2$$2*&&3UXGKRH%D\ %URRNV3KRHEH/ 2*& &F -XDQLWD/RYHWW 'RQQD$PEUX] 6XEMHFW 5( )R[ $WWDFKPHQWV )R[&78[OV[ ƚƚĂĐŚĞĚŝƐĂĐŽƌƌĞĐƚĞĚǀĞƌƐŝŽŶǁŝƚŚƚŚĞ;ŽƚƚůĞWƌĞĐŚĂƌŐĞͿĐŚĂŶŐĞĚĨƌŽŵEͬƚŽWĂƐƐ͘ ZĞŐĂƌĚƐ͕ KarsonKozub ǣΪͳȋͻͲȌͷͲǦͳͺͲͳ ̷ Ǥ &ƌŽŵ͗<ĂƌƐŽŶ<ŽnjƵďͲ;Ϳ ^ĞŶƚ͗dŚƵƌƐĚĂLJ͕ƵŐƵƐƚϮϱ͕ϮϬϮϮϰ͗ϭϮWD dŽ͗ũŝŵ͘ƌĞŐŐΛĂůĂƐŬĂ͘ŐŽǀ͖K'͘/ŶƐƉĞĐƚŽƌƐΛĂůĂƐŬĂ͘ŐŽǀ͖ƉŚŽĞďĞ͘ďƌŽŽŬƐΛĂůĂƐŬĂ͘ŐŽǀ Đ͗:ƵĂŶŝƚĂ>ŽǀĞƚƚфũůŽǀĞƚƚΛŚŝůĐŽƌƉ͘ĐŽŵх͖ŽŶŶĂŵďƌƵnjфĚĂŵďƌƵnjΛŚŝůĐŽƌƉ͘ĐŽŵх ^ƵďũĞĐƚ͗&ŽdžϴϬϴͲϮϭͲϮϬϮϮ 'ŽŽĚĨƚĞƌŶŽŽŶ͕ ƚƚĂĐŚĞĚŝƐƚŚĞKW ƚĞƐƚƌĞƉŽƌƚĨŽƌ&ŽdžϴdhϬϴͲϮϭͲϮϬϮϮ͘ <ĞŶĂŝĞůƵŐĂhŶŝƚϮϮͲϬϲz;WdϮϭϱͲϬϰϰͿ;^ƵŶĚƌLJϯϮϮͲϰϴϲͿ͘ ZĞŐĂƌĚƐ͕ KarsonKozub ǣΪͳȋͻͲȌͷͲǦͳͺͲͳ ̷ Ǥ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ll BOPE reports are due to the agency within 5 days of testing* SSu bm it t o :jim.regg@alaska.gov; AOGCC.Inspectors@alaska.gov; phoebe.brooks@alaska.gov Rig Owner: Rig No.:8 DATE: 8/21/22 Rig Rep.: Rig Email: Operator: Operator Rep.: Op. Rep Email: Well Name:PTD #2150440 Sundry #322-486 Operation: Drilling: Workover: x Explor.: Test: Initial: x Weekly: Bi-Weekly: Other: Rams:250/3000 Annular:N/A Valves:250/3000 MASP:2321 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result/Type Test Result Quantity Test Result Housekeeping P Well Sign P Upper Kelly 0NA Permit On Location P Hazard Sec.NA Lower Kelly 0NA Standing Order Posted P Misc.NA Ball Type 0NA Test Fluid Water Inside BOP 0NA FSV Misc 0NA BOP STACK:Quantity Size/Type Test Result MUD SYSTEM:Visual Alarm Stripper 1 1.75"P Trip Tank NA NA Annular Preventer 0NAPit Level Indicators NA NA #1 Rams 1 1.75" BS P Flow Indicator NA NA #2 Rams 1 1.75" PS P Meth Gas Detector NA NA #3 Rams 0NAH2S Gas Detector NA NA #4 Rams 0NAMS Misc 0NA #5 Rams 0NA #6 Rams 0NAACCUMULATOR SYSTEM: Choke Ln. Valves 2 2"P Time/Pressure Test Result HCR Valves 0NASystem Pressure (psi)3000 P Kill Line Valves 2 2"P Pressure After Closure (psi)2450 P Check Valve 0NA200 psi Attained (sec)4 P BOP Misc 0NAFull Pressure Attained (sec)11 P Blind Switch Covers: All stations YES CHOKE MANIFOLD:Bottle Precharge: 1400 P Quantity Test Result Nitgn. Bottles # & psi (Avg.): NA NA No. Valves 5P ACC Misc 0NA Manual Chokes 2P Hydraulic Chokes 0NA Control System Response Time:Time (sec) Test Result CH Misc 0NA Annular Preventer 0 NA #1 Rams 15 P Coiled Tubing Only:#2 Rams 11 P Inside Reel valves 1P #3 Rams 0 NA #4 Rams 0 NA Test Results #5 Rams 0 NA #6 Rams 0 NA Number of Failures:0 Test Time:3.5 HCR Choke 0 NA Repair or replacement of equipment will be made within days. HCR Kill 0 NA Remarks: AOGCC Inspection 24 hr Notice YES Date/Time 8/20/22 13:29hrs Waived By Test Start Date/Time:8/21/2022 12:00 (date) (time)Witness Test Finish Date/Time:8/21/2022 15:30 BOPE Test Report Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Jim Regg Fox Accumulator system 4 bottles at 1400psi. 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Received By: Date: Date: 09/02/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20220902 Well API #PTD #Log Date Log Company Log Type Notes AOGCC Eset # END 3-11 50029218480000 188087 8/1/2022 Halliburton CALIPER + Report KALOTSA 4 50133206650000 217063 7/18/2022 Halliburton PPROF + Processing KBU 22-06Y 50133206500000 215044 7/14/2022 Halliburton PPROF + Processing KTU 24-06H 50133204900000 199073 7/21/2022 Halliburton PPROF + Processing KU 24-05B 50133206830000 219072 7/20/2022 Halliburton PPROF + Processing MPU C-24A 50029230200100 209134 7/28/2022 Halliburton COIL FLAG MPU I-17 50029232120000 204098 7/19/2022 Halliburton FREEPOINT NS-10 50029229850000 200182 7/23/2022 Halliburton CALIPER + Report NS-32 50029231790000 203158 7/24/2022 Halliburton CALIPER + Report PBU 18-02C 50029207620300 213009 7/14/2022 Halliburton CAST/CBL PBU C-10B 50029203710200 211092 7/15/2022 Halliburton PPROF + Processing PBU L5-03 50029236230000 219033 7/25/2022 Halliburton PPROF + Processing Please include current contact information if different from above. 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W/͗ϱϬͲϭϯϯͲϮϬϲϱϬͲϬϬͲϬϬ ^, Dd/ WdсϭϬ͕Ϭϲϱ͛Dͬϵ͕ϱϳϭ͛ds dсϭϬ͕ϮϬϬ͛Dͬϵ͕ϲϵϳ͛ds dLJ'ĂƐWŽŽůηϭ ĞůͬhƉƉĞƌ dLJŽŶĞŬWŽŽů : t >Zz d/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϭϴ͛ϰ͘Ϯϳϲ͟ϭϭ͘ϬϬ͟dƵďŝŶŐ,ĂŶŐĞƌ Ϯ ϱ͕Ϭϭϵ͛ϰ͘Ϯϳϲ͟ϲ͘ϴϳϱ͟ϭϬĨƚ^ǁĞůůWĂĐŬĞƌ ;tĂƚĞƌ^ǁĞůůͿ ϯϭϬ͕Ϭϲϱ͛Ͳϯ͘ϳϭϬ͟ĞŵĞŶƚZĞƚĂŝŶĞƌ ZdĂŐĞƉƚŚƐ͕D ϴ͕ϬϬϰ͛ ϴ͕ϮϵϯΖ ϴ͕ϱϲϯΖ ϴ͕ϴϮϲΖ ϵ͕ϬϳϮΖ ϵ͕ϯϱϵΖ ϵ͕ϲϬϱΖ ϵ͕ϴϵϭΖ KW E,K> ͬ D Ed d/> ϭϬͲϯͬϰ͟ϭϭϬ>ŽĨϭϮ͘ϬηůĞĂĚĐĞŵĞŶƚ͘ϰϳ>ŽĨϭϱ͘ϮηƚĂŝůĐĞŵĞŶƚ ;WĞƌĨŽƌŵdŽƉ:ŽďĨƌŽŵϴϵ͘ϲ͛ǁͬϭϴďďůŽĨϭϮηĐŵƚͿ ϳͲϱͬϴΗϮϰϰ>ŽĨϭϭ͘Ϭη>ŝƚĞZ d ůĞĂĚĐĞŵĞŶƚ͕Ϯϵ͘ϱ>ŽĨϭϱ͘ϴηƚĂŝůĐĞŵĞŶƚ͕dKϯ͕ϲϳϬ͛;>ĚĂƚĞĚϰͬϮϵͬϭϱͿ ϱ͟ϭϯϮ>͛ƐŽĨϭϱ͘ϯη ůŽŬĐĞŵĞŶƚ͘^ƋƵĞĞnjĞƚŚƌƵƌĞƚĂŝŶĞƌ͘dKϱ͕Ϯϭϵ͛ĂůĐƵůĂƚĞĚ ^/E' d/> ^ŝnjĞdLJƉĞtƚ'ƌĂĚĞŽŶŶ͘/dŽƉƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶϭϬϵyͲϱϲtĞůĚϭϱ͘ϬϬ͟^ƵƌĨϭϯϲΖ ϭϬͲϯͬϰΗ^ƵƌĨ͘ƐŐϰϱ͘ϱ>ͲϴϬdϵ͘ϵϱϬ͟^ƵƌĨϭ͕ϱϮϰ͛ ϳͲϱͬϴΗ/ŶƚĞƌŵĞĚŝĂƚĞϮϵ͘ϳ>ͲϴϬdϲ͘ϴϳϱΗ^ƵƌĨϴ͕ϬϭϮ͛ dh/E' ϱΗWƌŽĚƵĐƚŝŽŶϭϴ>ͲϴϬtͬͲ,dϰ͘Ϯϳϲ͟^ƵƌĨϭϬ͕ϭϴϰ͛ ϭϲ͟ ϭϬͲϯͬϰ͟ ´ ϳͲϱͬϴ͟ >dKϯ͕ϲϳϬ͛ ƐƚdKϱ͕Ϯϭϵ͛ '% '$ hdϭ W Z&KZd/KE d/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿĂƚĞ^ŝnjĞ^ƚĂƚƵƐ >ϭцϲ͕ϯϴϬΖцϲ͕ϰϬϬΖцϲ͕ϭϮϱΖцϲ͕ϭϰϰΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >ϭцϲ͕ϰϮϬΖцϲ͕ϰϯϮΖцϲ͕ϭϲϯΖцϲ͕ϭϳϰΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >ϭцϲ͕ϰϲϭΖцϲ͕ϰϳϯΖцϲ͕ϮϬϭΖцϲ͕ϮϭϯΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >ϭцϲ͕ϱϮϬΖцϲ͕ϱϮϲΖцϲ͕ϮϱϲΖцϲ͕ϮϲϯΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >Ϯцϲ͕ϳϵϮΖцϲ͕ϴϭϮΖцϲ͕ϱϭϮΖцϲ͕ϱϯϬΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >Ϯцϲ͕ϴϯϵΖцϲ͕ϴϰϳΖцϲ͕ϱϱϲΖцϲ͕ϱϲϯΖϴͬϴͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >Ϯцϲ͕ϴϳϭΖцϲ͕ϵϬϰΖцϲ͕ϱϴϲΖцϲ͕ϲϭϲΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >Ϯ цϲ͕ϵϲϮΖцϲ͕ϵϳϰΖцϲ͕ϲϳϬΖцϲ͕ϲϴϮΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϯцϲ͕ϵϵϴΖцϳ͕ϬϬϲΖцϲ͕ϳϬϰΖцϲ͕ϳϭϮΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϯhцϳ͕ϬϲϵΖцϳ͕ϬϳϱΖцϲ͕ϳϳϭΖцϲ͕ϳϳϲΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϯDцϳ͕ϬϴϯΖцϳ͕ϬϵϭΖцϲ͕ϳϴϰΖцϲ͕ϳϵϭΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϰhцϳ͕ϮϭϴΖцϳ͕ϮϮϰΖцϲ͕ϵϭϬΖцϲ͕ϵϭϱΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϰцϳ͕ϮϯϭΖцϳ͕ϮϱϭΖцϲ͕ϵϮϮΖцϲ͕ϵϰϬΖϴͬϱͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϰ>цϳ͕ϮϳϱΖцϳ͕ϮϵϯΖцϲ͕ϵϲϯΖцϲ͕ϵϴϬΖϴͬϱͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϰ>цϳ͕ϯϰϭΖцϳ͕ϯϱϱΖцϳ͕ϬϮϱΖцϳ͕ϬϯϴΖϴͬϱͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϱhцϳ͕ϰϮϬΖцϳ͕ϰϮϲΖϳ͕ϬϵϴΖϳ͕ϭϬϰΖϴͬϰͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϱDцϳ͕ϰϯϰΖцϳ͕ϰϰϮΖϳ͕ϭϭϭΖϳ͕ϭϭϵΖϴͬϰͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϱ>цϳ͕ϰϰϳΖцϳ͕ϰϲϬΖϳ͕ϭϮϯΖϳ͕ϭϯϲΖϴͬϰͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ dzϳϮͺϴϳ͕ϲϰϱ͛ϳ͕ϲϱϱ͛ϳ͕ϯϬϴ͛ϳ͕ϯϭϴ͛ϳͬϭϮͬϮϬϮϭϯͲϯͬϴ͟KƉĞŶ dzϳϮͺϴϳ͕ϲϳϱ͛ϳ͕ϲϴϱ͛ϳ͕ϯϯϲ͛ϳ͕ϯϰϱ͛ϳͬϭϮͬϮϬϮϭϯͲϯͬϴ͟KƉĞŶ hdϭϳ͕ϴϮϱ͛ϳ͕ϴϰϬ͛ϳ͕ϰϳϲ͛ϳ͕ϰϵϬ͛ϲͬϭϰͬϮϬϮϭϮͲϳͬϴ͟KƉĞŶ ϭϵ͕ϯϮϰ͛ϵ͕ϯϯϴ͛ϴ͕ϴϳϲ͛ϴ͕ϴϵϬ͛ϭϬͬϭͬϮϬϮϭϮͲϳͬϴ͟KƉĞŶ ͲϮϵ͕ϰϱϰ͛ϵ͕ϰϵϰ͛ϴ͕ϵϵϳ͛ϵ͕Ϭϯϱ͛ϲͬϭϲͬϮϬϭϲϮͲϳͬϴ͟KƉĞŶ ϯϵ͕ϳϰϳ͛ϵ͕ϳϱϳ͛ϵ͕Ϯϳϰ͛ϵ͕Ϯϴϰ͛ϭϬͬϭͬϮϬϮϭϮͲϳͬϴ͟KƉĞŶ Ͳϯϵ͕ϴϭϮ͛ϵ͕ϴϰϳ͛ϵ͕ϯϯϰ͛ϵ͕ϯϲϳ͛ϱͬϯϬͬϮϬϭϱϯ͘ϱ͟W:EKƉĞŶ > dzϳϮͺϴ &ŝƐŚ͗ϯϭ͘ϱ͛^>dŽŽů^ƚƌŝŶŐ͕ϯ͘ϱ͟ĂŝůĞƌ͕^ƉĂŶŐƐ͕ŽŝůũĂƌƐ͕ŬŶƵĐŬůĞũƚ͕ƐƚĞŵ͕ΘƌŽƉĞƐŽĐŬĞƚ 6SHFLILFIRRWDJHYDOXHVIRUWKHWRSDQGERWWRP RIHDFKSHUIRUDWHGLQWHUYDODUHUHTXLUHGRQWKH IRUP6)' hƉĚĂƚĞĚďLJ,ϬϴͲϭϱͲϮϮ <ĞŶĂŝ'ĂƐ&ŝĞůĚ tĞůů͗<hϮϮͲϬϲz Wd͗ϮϭϱͲϬϰϰ W/͗ϱϬͲϭϯϯͲϮϬϲϱϬͲϬϬͲϬϬ WZKWK^ WdсϭϬ͕Ϭϲϱ͛Dͬϵ͕ϱϳϭ͛ds dсϭϬ͕ϮϬϬ͛Dͬϵ͕ϲϵϳ͛ds dLJ'ĂƐWŽŽůηϭ ĞůͬhƉƉĞƌ dLJŽŶĞŬWŽŽů : t >Zz d/> EŽ͘ĞƉƚŚ/K/ƚĞŵ ϭϭϴ͛ϰ͘Ϯϳϲ͟ϭϭ͘ϬϬ͟dƵďŝŶŐ,ĂŶŐĞƌ Ϯ ϱ͕Ϭϭϵ͛ϰ͘Ϯϳϲ͟ϲ͘ϴϳϱ͟ϭϬĨƚ^ǁĞůůWĂĐŬĞƌ ;tĂƚĞƌ^ǁĞůůͿ ϯϭϬ͕Ϭϲϱ͛Ͳϯ͘ϳϭϬ͟ĞŵĞŶƚZĞƚĂŝŶĞƌ ZdĂŐĞƉƚŚƐ͕D ϴ͕ϬϬϰ͛ ϴ͕ϮϵϯΖ ϴ͕ϱϲϯΖ ϴ͕ϴϮϲΖ ϵ͕ϬϳϮΖ ϵ͕ϯϱϵΖ ϵ͕ϲϬϱΖ ϵ͕ϴϵϭΖ KW E,K> ͬ D Ed d/> ϭϬͲϯͬϰ͟ϭϭϬ>ŽĨϭϮ͘ϬηůĞĂĚĐĞŵĞŶƚ͘ϰϳ>ŽĨϭϱ͘ϮηƚĂŝůĐĞŵĞŶƚ ;WĞƌĨŽƌŵdŽƉ:ŽďĨƌŽŵϴϵ͘ϲ͛ǁͬϭϴďďůŽĨϭϮηĐŵƚͿ ϳͲϱͬϴΗϮϰϰ>ŽĨϭϭ͘Ϭη>ŝƚĞZ d ůĞĂĚĐĞŵĞŶƚ͕Ϯϵ͘ϱ>ŽĨϭϱ͘ϴηƚĂŝůĐĞŵĞŶƚ͕dKϯ͕ϲϳϬ͛;>ĚĂƚĞĚϰͬϮϵͬϭϱͿ ϱ͟ϭϯϮ>͛ƐŽĨϭϱ͘ϯη ůŽŬĐĞŵĞŶƚ͘^ƋƵĞĞnjĞƚŚƌƵƌĞƚĂŝŶĞƌ͘dKϱ͕Ϯϭϵ͛ĂůĐƵůĂƚĞĚ ^/E' d/> ^ŝnjĞdLJƉĞtƚ'ƌĂĚĞŽŶŶ͘/dŽƉƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶϭϬϵyͲϱϲtĞůĚϭϱ͘ϬϬ͟^ƵƌĨϭϯϲΖ ϭϬͲϯͬϰΗ^ƵƌĨ͘ƐŐϰϱ͘ϱ>ͲϴϬdϵ͘ϵϱϬ͟^ƵƌĨϭ͕ϱϮϰ͛ ϳͲϱͬϴΗ/ŶƚĞƌŵĞĚŝĂƚĞϮϵ͘ϳ>ͲϴϬdϲ͘ϴϳϱΗ^ƵƌĨϴ͕ϬϭϮ͛ dh/E' ϱΗWƌŽĚƵĐƚŝŽŶϭϴ>ͲϴϬtͬͲ,dϰ͘Ϯϳϲ͟^ƵƌĨϭϬ͕ϭϴϰ͛ ϭϲ͟ ϭϬͲϯͬϰ͟ ´ ϳͲϱͬϴ͟ >dKϯ͕ϲϳϬ͛ ƐƚdKϱ͕Ϯϭϵ͛ '% '$ hdϭ W Z&KZd/KE d/> ^ĂŶĚƐdŽƉ;DͿƚŵ;DͿdŽƉ;dsͿƚŵ;dsͿĂƚĞ^ŝnjĞ^ƚĂƚƵƐ >ϭцϲ͕ϯϴϬΖцϲ͕ϰϬϬΖцϲ͕ϭϮϱΖцϲ͕ϭϰϰΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >ϭцϲ͕ϰϮϬΖцϲ͕ϰϯϮΖцϲ͕ϭϲϯΖцϲ͕ϭϳϰΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >ϭцϲ͕ϰϲϭΖцϲ͕ϰϳϯΖцϲ͕ϮϬϭΖцϲ͕ϮϭϯΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >ϭцϲ͕ϱϮϬΖцϲ͕ϱϮϲΖцϲ͕ϮϱϲΖцϲ͕ϮϲϯΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >Ϯцϲ͕ϳϵϮΖцϲ͕ϴϭϮΖцϲ͕ϱϭϮΖцϲ͕ϱϯϬΖϴͬϵͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >Ϯцϲ͕ϴϯϵΖцϲ͕ϴϰϳΖцϲ͕ϱϱϲΖцϲ͕ϱϲϯΖϴͬϴͬϮϬϮϮϯͲϯͬϴ͟KƉĞŶ >Ϯцϲ͕ϴϳϭΖцϲ͕ϵϬϰΖцϲ͕ϱϴϲΖцϲ͕ϲϭϲΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >Ϯ цϲ͕ϵϲϮΖцϲ͕ϵϳϰΖцϲ͕ϲϳϬΖцϲ͕ϲϴϮΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϯцϲ͕ϵϵϴΖцϳ͕ϬϬϲΖцϲ͕ϳϬϰΖцϲ͕ϳϭϮΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϯhцϳ͕ϬϲϵΖцϳ͕ϬϳϱΖцϲ͕ϳϳϭΖцϲ͕ϳϳϲΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϯDцϳ͕ϬϴϯΖцϳ͕ϬϵϭΖцϲ͕ϳϴϰΖцϲ͕ϳϵϭΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϰhцϳ͕ϮϭϴΖцϳ͕ϮϮϰΖцϲ͕ϵϭϬΖцϲ͕ϵϭϱΖϴͬϴͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϰцϳ͕ϮϯϭΖцϳ͕ϮϱϭΖцϲ͕ϵϮϮΖцϲ͕ϵϰϬΖϴͬϱͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ >ϰ>цϳ͕ϮϳϱΖцϳ͕ϮϵϯΖцϲ͕ϵϲϯΖцϲ͕ϵϴϬΖϴͬϱͬϮϬϮϮϯͲϭͬϴ͟KƉĞŶ 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Chmielowski Digitally signed by Jessie L. 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0' tĞůůWƌŽŐŶŽƐŝƐ tĞůů͗<hϮϮͲϬϲz ĂƚĞ͗ϳͬϮϮͬϮϮ ^ĂŶĚƐ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ >ϰ>цϳ͕ϯϰϭΖ цϳ͕ϯϱϱΖ цϳ͕ϬϮϱΖ цϳ͕ϬϯϴΖ >ϱh цϳ͕ϰϮϬΖ цϳ͕ϰϮϲΖ цϳ͕ϬϵϴΖ цϳ͕ϭϬϰΖ >ϱD цϳ͕ϰϯϰΖ цϳ͕ϰϰϮΖ цϳ͕ϭϭϭΖ цϳ͕ϭϭϵΖ >ϱ> цϳ͕ϰϰϳΖ цϳ͕ϰϲϬΖ цϳ͕ϭϮϯΖ цϳ͕ϭϯϲΖ Ă͘ tĞůůǁŝůůďĞƐŚŽƚǁŝƚŚƚŚĞǁĞůůĨůŽǁŝŶŐ ď͘ WƌŽƉŽƐĞĚƉĞƌĨƐƐŚŽǁŶŽŶƚŚĞƉƌŽƉŽƐĞĚƐĐŚĞŵĂƚŝĐŝŶƌĞĚĨŽŶƚ͘ Đ͘ &ŝŶĂůWĞƌĨƐƚŝĞͲŝŶƐƐŚĞĞƚǁŝůůďĞƉƌŽǀŝĚĞĚŝŶƚŚĞĨŝĞůĚĨŽƌĞ džĂĐƚƉĞƌĨŝŶƚĞƌǀĂůƐ͘ Ě͘ ^ƉĂĐŝŶŐĂůůŽǁĂŶĐĞŝƐďĂƐĞĚŽŶŽŶƐĞƌǀĂƚŝŽŶKƌĚĞƌϱϭϬ͘ Ğ͘ ZĞĐŽƌĚƚƵďŝŶŐƉƌĞƐƐƵƌĞƐďĞĨŽƌĞĂŶĚĂĨƚĞƌĞĂĐŚƉĞƌĨŽƌĂƚŝŶŐƌƵŶ͘ Ĩ͘ ZĞĐŽƌĚϱ͕ϭϬĂŶĚϭϱŵŝŶƵƚĞƉƌĞƐƐƵƌĞƐĂĨƚĞƌĨŝƌŝŶŐŐƵŶƐ͘ ϯ͘ WKK,ĂŶĚZ Ͳ>ŝŶĞ͘ ϰ͘ dƵƌŶǁĞůůŽǀĞƌƚŽƉƌŽĚƵĐƚŝŽŶ͘ ͲůŝŶĞWƌŽĐĞĚƵƌĞ;ŽŶƚŝŶŐĞŶĐLJͿ ϭ͘ /ĨĂŶLJnjŽŶĞƉƌŽĚƵĐĞƐƐĂŶĚĂŶĚͬŽƌǁĂƚĞƌŽƌŶĞĞĚƐŝƐŽůĂƚĞĚ͗ Ϯ͘ D/Zh Ͳ>ŝŶĞĂŶĚƉƌĞƐƐƵƌĞĐŽŶƚƌŽůĞƋƵŝƉŵĞŶƚ͘WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬƉƐŝ>ŽǁͬϮ͕ϱϬϬƉƐŝ,ŝŐŚ͘ ϯ͘ Z/,ĂŶĚƐĞƚĂĂƐŝŶŐWĂƚĐŚŽƌƐĞƚĂ/WĂďŽǀĞƚŚĞnjŽŶĞĂŶĚĚƵŵƉϮϱ͛ŽĨĐĞŵĞŶƚŽŶƚŽƉŽĨƚŚĞ ƉůƵŐ͘ ƚƚĂĐŚŵĞŶƚƐ͗ ϭ͘ ƵƌƌĞŶƚtĞůů^ĐŚĞŵĂƚŝĐ Ϯ͘ WƌŽƉŽƐĞĚtĞůů^ĐŚĞŵĂƚŝĐ hƉĚĂƚĞĚďLJZZϭϬͲϴͲϮϭ <ĞŶĂŝ'ĂƐ&ŝĞůĚ tĞůů͗<hϮϮͲϬϲz Wd͗ϮϭϱͲϬϰϰ W/͗ϱϬͲϭϯϯͲϮϬϲϱϬͲϬϬ ^, Dd/ WdсϭϬ͕Ϭϲϱ͛Dͬϵ͕ϱϳϭ͛ds dсϭϬ͕ϮϬϬ͛Dͬϵ͕ϲϵϳ͛ds ZdĂŐĞƉƚŚƐ͕D ϴ͕ϬϬϰ͛ ϴ͕ϮϵϯΖ ϴ͕ϱϲϯΖ ϴ͕ϴϮϲΖ ϵ͕ϬϳϮΖ ϵ͕ϯϱϵΖ ϵ͕ϲϬϱΖ ϵ͕ϴϵϭΖ : t >Zz d/> EŽ͘ ĞƉƚŚ / K /ƚĞŵ ϭ ϭϴ͛ ϰ͘Ϯϳϲ͟ ϭϭ͘ϬϬ͟ dƵďŝŶŐ,ĂŶŐĞƌ Ϯ ϱ͕Ϭϭϵ͛ ϰ͘Ϯϳϲ͟ ϲ͘ϴϳϱ͟ ϭϬĨƚ^ǁĞůůWĂĐŬĞƌ ;tĂƚĞƌ^ǁĞůůͿ ϯ ϭϬ͕Ϭϲϱ͛ Ͳ ϯ͘ϳϭϬ͟ ĞŵĞŶƚZĞƚĂŝŶĞƌ KW E,K> ͬ D Ed d/> ϭϬͲϯͬϰ͟ϭϭϬ>ŽĨϭϮ͘ϬηůĞĂĚĐĞŵĞŶƚ͘ϰϳ>ŽĨϭϱ͘ϮηƚĂŝůĐĞŵĞŶƚ ;WĞƌĨŽƌŵdŽƉ:ŽďĨƌŽŵϴϵ͘ϲ͛ǁͬϭϴďďůŽĨϭϮηĐŵƚͿ ϳͲϱͬϴΗ Ϯϰϰ>ŽĨϭϭ͘Ϭη>ŝƚĞZ d ůĞĂĚĐĞŵĞŶƚ͕Ϯϵ͘ϱ>ŽĨϭϱ͘ϴηƚĂŝůĐĞŵĞŶƚ͕dKϯ͕ϲϳϬ͛;>ĚĂƚĞĚϰͬϮϵͬϭϱͿ ϱ͟ ϭϯϮ>͛ƐŽĨϭϱ͘ϯη ůŽŬĐĞŵĞŶƚ͘^ƋƵĞĞnjĞƚŚƌƵƌĞƚĂŝŶĞƌ͘dKϱ͕Ϯϭϵ͛ĂůĐƵůĂƚĞĚ W Z&KZd/KE d/> ^ĂŶĚƐ dŽƉ ;DͿ ƚŵ ;DͿ dŽƉ ;dsͿ ƚŵ ;dsͿ ĂƚĞ ^ŝnjĞ ^ƚĂƚƵƐ dzϳϮͺϴ ϳ͕ϲϰϱ͛ ϳ͕ϲϱϱ͛ ϳ͕ϯϬϴ͛ ϳ͕ϯϭϴ͛ ϳͬϭϮͬϮϭ ϯͲϯͬϴ͟ KƉĞŶ dzϳϮͺϴ ϳ͕ϲϳϱ͛ ϳ͕ϲϴϱ͛ ϳ͕ϯϯϲ͛ ϳ͕ϯϰϱ͛ ϳͬϭϮͬϮϭ ϯͲϯͬϴ͟ KƉĞŶ hdϭ ϳ͕ϴϮϱ͛ ϳ͕ϴϰϬ͛ ϳ͕ϰϳϲ͛ ϳ͕ϰϵϬ͛ ϲͬϭϰͬϮϭ ϮͲϳͬϴ͟ KƉĞŶ ϭ ϵ͕ϯϮϰ͛ ϵ͕ϯϯϴ͛ ϴ͕ϴϳϲ͛ ϴ͕ϴϵϬ͛ ϭϬͬϭͬϮϭ ϮͲϳͬϴ͟ KƉĞŶ ͲϮ ϵ͕ϰϱϰ͛ ϵ͕ϰϵϰ͛ ϴ͕ϵϵϳ͛ ϵ͕Ϭϯϱ͛ ϲͬϭϲͬϭϲ ϮͲϳͬϴ͟ KƉĞŶ ϯ ϵ͕ϳϰϳ͛ ϵ͕ϳϱϳ͛ ϵ͕Ϯϳϰ͛ ϵ͕Ϯϴϰ͛ ϭϬͬϭͬϮϭ ϮͲϳͬϴ͟ KƉĞŶ Ͳϯ ϵ͕ϴϭϮ͛ ϵ͕ϴϰϳ͛ ϵ͕ϯϯϰ͛ ϵ͕ϯϲϳ͛ ϱͬϯϬͬϭϱ ϯ͘ϱ͟W:E KƉĞŶ ^/E' d/> ^ŝnjĞ dLJƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌʹ ƌŝǀĞŶ ϭϬϵ yͲϱϲ tĞůĚ ϭϱ͘ϬϬ͟ ^ƵƌĨ ϭϯϲΖ ϭϬͲϯͬϰΗ ^ƵƌĨ͘ƐŐ ϰϱ͘ϱ >ͲϴϬ d ϵ͘ϵϱϬ͟ ^ƵƌĨ ϭ͕ϱϮϰ͛ ϳͲϱͬϴΗ /ŶƚĞƌŵĞĚŝĂƚĞ Ϯϵ͘ϳ >ͲϴϬ d ϲ͘ϴϳϱΗ ^ƵƌĨ ϴ͕ϬϭϮ͛ dh/E' ϱΗ WƌŽĚƵĐƚŝŽŶ ϭϴ >ͲϴϬ tͬͲ,d ϰ͘Ϯϳϲ͟ ^ƵƌĨ ϭϬ͕ϭϴϰ͛ ´ ´ ´ ´ &%/72& ¶ (VW72& ¶ '% '$ dzϳϮͺϴ hdϭ hƉĚĂƚĞĚďLJDϬϳͲϮϭͲϮϮ <ĞŶĂŝ'ĂƐ&ŝĞůĚ tĞůů͗<hϮϮͲϬϲz Wd͗ϮϭϱͲϬϰϰ W/͗ϱϬͲϭϯϯͲϮϬϲϱϬͲϬϬ WZKWK^ WdсϭϬ͕Ϭϲϱ͛Dͬϵ͕ϱϳϭ͛ds dсϭϬ͕ϮϬϬ͛Dͬϵ͕ϲϵϳ͛ds : t >Zz d/> EŽ͘ ĞƉƚŚ / K /ƚĞŵ ϭ ϭϴ͛ ϰ͘Ϯϳϲ͟ ϭϭ͘ϬϬ͟ dƵďŝŶŐ,ĂŶŐĞƌ Ϯ ϱ͕Ϭϭϵ͛ ϰ͘Ϯϳϲ͟ ϲ͘ϴϳϱ͟ ϭϬĨƚ^ǁĞůůWĂĐŬĞƌ ;tĂƚĞƌ^ǁĞůůͿ ϯ ϭϬ͕Ϭϲϱ͛ Ͳ ϯ͘ϳϭϬ͟ ĞŵĞŶƚZĞƚĂŝŶĞƌ ZdĂŐĞƉƚŚƐ͕D ϴ͕ϬϬϰ͛ ϴ͕ϮϵϯΖ ϴ͕ϱϲϯΖ ϴ͕ϴϮϲΖ ϵ͕ϬϳϮΖ ϵ͕ϯϱϵΖ ϵ͕ϲϬϱΖ ϵ͕ϴϵϭΖ KW E,K> ͬ D Ed d/> ϭϬͲϯͬϰ͟ϭϭϬ>ŽĨϭϮ͘ϬηůĞĂĚĐĞŵĞŶƚ͘ϰϳ>ŽĨϭϱ͘ϮηƚĂŝůĐĞŵĞŶƚ ;WĞƌĨŽƌŵdŽƉ:ŽďĨƌŽŵϴϵ͘ϲ͛ǁͬϭϴďďůŽĨϭϮηĐŵƚͿ ϳͲϱͬϴΗ Ϯϰϰ>ŽĨϭϭ͘Ϭη>ŝƚĞZ d ůĞĂĚĐĞŵĞŶƚ͕Ϯϵ͘ϱ>ŽĨϭϱ͘ϴηƚĂŝůĐĞŵĞŶƚ͕dKϯ͕ϲϳϬ͛;>ĚĂƚĞĚϰͬϮϵͬϭϱͿ ϱ͟ ϭϯϮ>͛ƐŽĨϭϱ͘ϯη ůŽŬĐĞŵĞŶƚ͘^ƋƵĞĞnjĞƚŚƌƵƌĞƚĂŝŶĞƌ͘dKϱ͕Ϯϭϵ͛ĂůĐƵůĂƚĞĚ ^/E' d/> ^ŝnjĞ dLJƉĞ tƚ 'ƌĂĚĞ ŽŶŶ͘ / dŽƉ ƚŵ ϭϲ͟ŽŶĚƵĐƚŽƌ ʹ ƌŝǀĞŶ ϭϬϵ yͲϱϲ tĞůĚ ϭϱ͘ϬϬ͟ ^ƵƌĨ ϭϯϲΖ ϭϬͲϯͬϰΗ ^ƵƌĨ͘ƐŐ ϰϱ͘ϱ >ͲϴϬ d ϵ͘ϵϱϬ͟ ^ƵƌĨ ϭ͕ϱϮϰ͛ ϳͲϱͬϴΗ /ŶƚĞƌŵĞĚŝĂƚĞ Ϯϵ͘ϳ >ͲϴϬ d ϲ͘ϴϳϱΗ ^ƵƌĨ ϴ͕ϬϭϮ͛ dh/E' ϱΗ WƌŽĚƵĐƚŝŽŶ ϭϴ >ͲϴϬ tͬͲ,d ϰ͘Ϯϳϲ͟ ^ƵƌĨ ϭϬ͕ϭϴϰ͛ ϭϲ͟ ϭϬͲϯͬϰ͟ ´ ϳͲϱͬϴ͟ >dKϯ͕ϲϳϬ͛ Ɛƚ dK ϱ͕Ϯϭϵ͛ '% '$ hdϭ W Z&KZd/KE d/> ^ĂŶĚƐ dŽƉ;DͿ ƚŵ;DͿ dŽƉ;dsͿ ƚŵ;dsͿ ĂƚĞ ^ŝnjĞ ^ƚĂƚƵƐ >ϭ цϲ͕ϯϴϬΖ цϲ͕ϰϬϬΖ цϲ͕ϭϮϱΖ цϲ͕ϭϰϰΖ WƌŽƉŽŽƐĞĚ d >ϭ цϲ͕ϰϮϬΖ цϲ͕ϰϯϮΖ цϲ͕ϭϲϯΖ цϲ͕ϭϳϰΖ WƌŽƉŽŽƐĞĚ d >ϭ цϲ͕ϰϲϭΖ цϲ͕ϰϳϯΖ цϲ͕ϮϬϭΖ цϲ͕ϮϭϯΖ WƌŽƉŽŽƐĞĚ d >ϭ цϲ͕ϱϭϵΖ цϲ͕ϱϮϲΖ цϲ͕ϮϱϲΖ цϲ͕ϮϲϯΖ WƌŽƉŽŽƐĞĚ d >Ϯ цϲ͕ϳϵϮΖ цϲ͕ϴϭϮΖ цϲ͕ϱϭϮΖ цϲ͕ϱϯϬΖ WƌŽƉŽŽƐĞĚ d >Ϯ цϲ͕ϴϯϵΖ цϲ͕ϴϰϳΖ цϲ͕ϱϱϲΖ цϲ͕ϱϲϯΖ WƌŽƉŽŽƐĞĚ d >Ϯ цϲ͕ϴϳϭΖ цϲ͕ϵϬϰΖ цϲ͕ϱϴϲΖ цϲ͕ϲϭϲΖ WƌŽƉŽŽƐĞĚ d >Ϯ цϲ͕ϵϲϮΖ цϲ͕ϵϳϰΖ цϲ͕ϲϳϬΖ цϲ͕ϲϴϮΖ WƌŽƉŽŽƐĞĚ d >ϯ цϲ͕ϵϵϴΖ цϳ͕ϬϬϲΖ цϲ͕ϳϬϰΖ цϲ͕ϳϭϮΖ WƌŽƉŽŽƐĞĚ d >ϯh цϳ͕ϬϲϵΖ цϳ͕ϬϳϱΖ цϲ͕ϳϳϭΖ цϲ͕ϳϳϲΖ WƌŽƉŽŽƐĞĚ d >ϯD цϳ͕ϬϴϯΖ цϳ͕ϬϵϭΖ цϲ͕ϳϴϰΖ цϲ͕ϳϵϭΖ WƌŽƉŽŽƐĞĚ d >ϰh цϳ͕ϮϭϴΖ цϳ͕ϮϮϰΖ цϲ͕ϵϭϬΖ цϲ͕ϵϭϱΖ WƌŽƉŽŽƐĞĚ d >ϰ цϳ͕ϮϯϭΖ цϳ͕ϮϱϭΖ цϲ͕ϵϮϮΖ цϲ͕ϵϰϬΖ WƌŽƉŽŽƐĞĚ d >ϰ> цϳ͕ϮϳϱΖ цϳ͕ϮϵϯΖ цϲ͕ϵϲϯΖ цϲ͕ϵϴϬΖ WƌŽƉŽŽƐĞĚ d >ϰ>цϳ͕ϯϰϭΖ цϳ͕ϯϱϱΖ цϳ͕ϬϮϱΖ цϳ͕ϬϯϴΖ WƌŽƉŽŽƐĞĚ d >ϱh цϳ͕ϰϮϬΖ цϳ͕ϰϮϲΖ цϳ͕ϬϵϴΖ цϳ͕ϭϬϰΖ WƌŽƉŽŽƐĞĚ d >ϱD цϳ͕ϰϯϰΖ цϳ͕ϰϰϮΖ цϳ͕ϭϭϭΖ цϳ͕ϭϭϵΖ WƌŽƉŽŽƐĞĚ d >ϱ> цϳ͕ϰϰϳΖ цϳ͕ϰϲϬΖ цϳ͕ϭϮϯΖ цϳ͕ϭϯϲΖ WƌŽƉŽŽƐĞĚ d dzϳϮͺϴ ϳ͕ϲϰϱ͛ ϳ͕ϲϱϱ͛ ϳ͕ϯϬϴ͛ ϳ͕ϯϭϴ͛ ϳͬϭϮͬϮϬϮϭ ϯͲϯͬϴ͟ KƉĞŶ dzϳϮͺϴ ϳ͕ϲϳϱ͛ ϳ͕ϲϴϱ͛ ϳ͕ϯϯϲ͛ ϳ͕ϯϰϱ͛ ϳͬϭϮͬϮϬϮϭ ϯͲϯͬϴ͟ KƉĞŶ hdϭ ϳ͕ϴϮϱ͛ ϳ͕ϴϰϬ͛ ϳ͕ϰϳϲ͛ ϳ͕ϰϵϬ͛ ϲͬϭϰͬϮϬϮϭ ϮͲϳͬϴ͟ KƉĞŶ ϭ ϵ͕ϯϮϰ͛ ϵ͕ϯϯϴ͛ ϴ͕ϴϳϲ͛ ϴ͕ϴϵϬ͛ ϭϬͬϭͬϮϬϮϭ ϮͲϳͬϴ͟ KƉĞŶ ͲϮ ϵ͕ϰϱϰ͛ ϵ͕ϰϵϰ͛ ϴ͕ϵϵϳ͛ ϵ͕Ϭϯϱ͛ ϲͬϭϲͬϮϬϭϲ ϮͲϳͬϴ͟ KƉĞŶ ϯ ϵ͕ϳϰϳ͛ ϵ͕ϳϱϳ͛ ϵ͕Ϯϳϰ͛ ϵ͕Ϯϴϰ͛ ϭϬͬϭͬϮϬϮϭ ϮͲϳͬϴ͟ KƉĞŶ Ͳϯ ϵ͕ϴϭϮ͛ ϵ͕ϴϰϳ͛ ϵ͕ϯϯϰ͛ ϵ͕ϯϲϳ͛ ϱͬϯϬͬϮϬϭϱ ϯ͘ϱ͟W:E KƉĞŶ > dzϳϮͺϴ 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 10,200 feet N/A feet true vertical 9,697 feet N/A feet Effective Depth measured 10,065 feet 5,019 feet true vertical 9,571 feet 4,853 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)5" 18# / L-80 10,184' MD 9,682' TVD Packers and SSSV (type, measured and true vertical depth)Swell Prk; N/A 5,019' MD 4,853' 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: Contact Name: Contact Email: Authorized Title:Contact Phone: 321-508 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 968 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 10 25 Jake Flora, Operations Engineer jake.flora@hilcorp.com 907-777-8442Dan Marlowe, Operations Manager, 907-283-1329 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 6 8051,349 0 19 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 136' 1,524' 800 Structural TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-044 50-133-20650-00-00 N/A 5. Permit to Drill Number:4. Well Class Before Work: FEDA 028142 Kenai Gas Field - Beluga/Upper Tyonek Pool - Tyonek Gas Pool 1 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 3. Address: Kenai Beluga Unit (KBU) 22-06Y 2. Operator Name:Hilcorp Alaska, LLC measuredPlugs Junk measured N/A Length 136' 1,524' Size Conductor Surface Intermediate 16" 10-3/4" 7-5/8" Production Liner 8,012' Casing 136' 1,506' 7,651'8,012'4,790psi 5,210psi 6,890psi Burst Collapse 2,470psi t Fra O A PG , R 6. A Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Meredith Guhl at 1:25 pm, Jan 21, 2022 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2022.01.21 12:11:56 -09'00' Dan Marlowe (1267) RBDMS HEW 1/28/2022 DSR-1/24/22 Rig Start Date End Date 10/1/21 1/16/22 10/08/2021 - Friday RU Yellowjacket E-Line, PT Lubricator to 2500 psi. Perforate Tyonek D3 9747-9757' w 2-7/8 6spf. No rate change, Perforate Tyonek D1 9324-9338', rate increased to 5000 MCFD. RDMO. Arrive at office - do Permit and JSA- travel to location. Rig up Slickiline. P/T LUB and WLV 2500. RIH/w 1.75"x 5' DD bailer to 9890' SLM ( 9901' RKB)w/t POOH OOH/w Full Bailer of Sand sticky like Substance Break off Bailer and Spangs Makeup tools;RIH/w Tandem P/T Gauges to 9891' RKB see Survey Stop Sheet for Detail. OOH Download Gauges- Data GOOD send to Jerry Butler. Rig down clean and secure area and well. Turn in Permit. Leave location. 01/16/2022 - Sunday Production evaluation complete, closing out sundry. We did not add higher proposed perforations that trigger new MITIA. 10/01/2021- Friday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06Y 50-133-20650-00-00 215-044 Updated by CRR 10-8-21 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00 SCHEMATIC PBTD = 10,065’ MD / 9,571’ TVD TD = 10,200’ MD / 9,697’ TVD RA Tag Depths, MD 8,004’ 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11.00” Tubing Hanger 2 5,019’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 10,065’ - 3.710” Cement Retainer OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement. 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8" 244 BBL of 11.0# LiteCRETE lead cement, 29.5 BBL of 15.8# tail cement, TOC 3,670’ (CBL dated 4/29/15) 5” 132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,219’ Calculated PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD)Date Size Status TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/21 3-3/8” Open TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/21 3-3/8” Open UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/21 2-7/8” Open D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/21 2-7/8” Open D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/16 2-7/8” Open D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/21 2-7/8” Open D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/15 3.5” PJN Open CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00” Surf 136' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 1,524’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012’ TUBING 5" Production 18 L-80 DWC/C-HT 4.276” Surf 10,184’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 Est TOC 5,219’ 3 D-3B D-2A TY 72_8 UT 1B ,,, ,/// p D1 9,324’ 9,338’ 8,876’ 8,890’ 10/1/21 2-7/8” Open UT 1B 7,825 7,840 7,476 7,490 6/14/21 2 7/8 Open ’’’ ’/”//,,, ,/// p D3 9,747’ 9,757’ 9,274’ 9,284’ 10/1/21 2-7/8” Open D 2A 9,454 9,494 8,997 9,035 6/16/16 2 7/8 Open Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/18/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 22-06Y (PTD 215-044) Perf 10/01/2021 Please include current contact information if different from above. 37' (6HW Received By: 11/09/2021 By Abby Bell at 4:38 pm, Nov 09, 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 10,200 feet N/A feet true vertical 9,697 feet N/A feet Effective Depth measured 10,065 feet 5,019 feet true vertical 9,571 feet 4,853 feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)5" 18# / L-80 10,184' (MD) 9,682' (TVD) 5,019 (MD) Packers and SSSV (type, measured and true vertical depth)Swell Packer 4,853 (TVD) N/A & 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 5,210psi 6,890psi Burst Collapse 2,470psi 136' 1,506' 7,651'8,012'7-5/8" measuredPlugs Junk measured N/A Length 136' 1,524' Size Conductor Surface Intermediate 16" 10-3/4" Production Liner 8,012' Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 215-044 50-133-20650-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA 028142 Kenai Gas Field / Beluga/Upper Tyonek Pool & Tyonek Gas Pool 1 3. Address: Kenai Beluga Unit (KBU) 22-06Y Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 4 780898 0 24 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 136' 1,524' N/A 780 Structural TVD 321-245 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 838 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 8 15 Ted Kramer tkramer@hilcorp.com (907) 777-8420Dan Marlowe - Operations Manager L G Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 11:40 am, Oct 20, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.10.20 11:21:51 -08'00' Dan Marlowe (1267) DSR-10/20/21 RBDMS HEW 10/21/2021 BJM 10/21/21 SFD 10/20/2021 Updated by DMA 07-14-21 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00 SCHEMATIC PBTD = 10,065’ MD / 9,571’ TVD TD = 10,200’ MD / 9,697’ TVD CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven 109 X-56 Weld 15.00” Surf 136' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 1,524’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012’ TUBING 5" Production 18 L-80 DWC/C-HT 4.276” Surf 10,184’ 1 16” 10-3/4” 5” JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11.00” Tubing Hanger 2 5,019’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 10,065’ - 3.710” Cement Retainer 7-5/8” CBL TOC 3,670’ 2 OPEN HOLE / CEMENT DETAIL 10-3/4” 110 BBL of 12.0# lead cement 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8" 244 BBL of 11.0# LiteCRETE lead cement 29.5 BBL of 15.8# tail cement TOC 3,670’ (CBL dated 4/29/15) 5” 132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,219’ Calculated RA Tag depths: PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Date Size Status TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/21 3-3/8” Open TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/21 3-3/8” Open UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/21 2-7/8” Open D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/16 2-7/8” Open D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/15 3.5” PJN Open Est TOC 5,219’ 9,605’ 9,891’ 9,359’ 9,072’ 8,826’ 8,536’ 8,293’ 8,004’ 3 D-3B D-2A TY 72_8 UT 1B Rig Start Date End Date 6/14/21 7/12/21 07/12/2021 - Monday Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. Add two 3-1/8" x 7' wts to tool string. Tool string with perf gun weighs 750 lbs. While getting ready to PT field had gas alarm. Shut down engines and went to Muster Area. False alarm. Went back to well. PT to 250 psi low and 3000 psi high. RIH w/Gun #1, 3-3/8" x 15' (10' of charges), 6 spf, 60 deg phase and tie into OHL, Run correlation log and send to town. Get ok to perf from 7,675' to 7,685' w/116 psi. Spot and fired gun. After 5 min - 114.6 psi, 10 min - 113.2 psi and 15 min - 112.6 psi. POOH. All shots fired/gun was dry. RIH w/Gun #2, 3-3/8" x 15' (10' of charges), 6 spf, 60 deg phase and tie into OHL, Run correlation log and send to town. Get ok to perf from 7,645' to 7,655' w/112 psi. Spot and fire w/112 psi, After 5 min - 112.2psi, 10 min - 112 psi. and 15 min - 111.9 psi. POOH. All shots fired/gun was dry. Rig down lubricator and secure well. Turn well over to field and rig down rest of equip. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06Y 50-133-20650-00-00 215-044 06/14/2021 - Monday Sign in. Mobe to location. PTW and JSA. Spot and rig up equipment. PT lubricator to 250 psi low and 3,000 psi high. RIH w/GPT tool and tie-in to OHL. Going in hole found gas cut/soapy fluid from 4,700' to 6,400' and from 6,400' to 8,350' was probably a 10% gas/soap cut fluid. Ran GPT log and send to town. Town said to subtract 17' on log. Coming out of hole found cut Gas/soap fluid top at 6,476' instead of 4,700'. Seems like we stirred soap/gas up and was changing frequently. POOH. RIH w/ 2-7/8" x 2' HC, 6 spf, 60 deg perf gun and tie into GPT log. Run correlation log and send to town. Town said we are on depth with 2' gun to fire it and let the pressure build before firing 15' gun. Spot and fire gun from 7,833' to 7,835' w/flowing 830K at 68 psi. After 5 min - 869K at 69 psi, 10 min - 900K at 69 psi and 15 min - 912K at 68psi. POOH. All shots fired/Gun wet. RIH w/ 2-7/8" x 15' HC, 6 spf, 60 deg perf gun and tie into GPT log. Run correlation log and send to town. Get ok to perf from 7,825' to 7,840' w/FTP 886K at 65.6 psi, After 5 min - 891K /66 psi, 10 min -no change and 15 min - 917K/65 psi. All shots fired/Gun Wet. Rig down lubricator and equipment, secure well and turn well over to field. perf from perf from w 7,675' to 7,685' w Spot and fire gun from 7,833' to 7,835' w 7,645' to 7,655' t ok to perf from 7,825' to 7,840' w 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? 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): 10,200'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 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: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 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 Swell Packer; N/A Perforation Depth MD (ft): 5,019' MD - 4,853' TVD; N/A 18.0# / L-80 Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: October 1, 2021 5" 7-5/8"8,012' 1,524' 8,012' See Attached Schematic 7,651' 136' 1,524' 16" 10-3/4" 136' Burst 10,184' MD 6,890 psi 5,210 psi 136' 1,506' Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY TVD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 A-028142 215-044 50-133-20650-00-00 Kenai Beluga Unit (KBU) 22-06Y Kenai Gas Field - Beluga/Upper Tyonek Pool - Tyonek Gas Pool 1 CO 510b COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic jake.flora@hilcorp.com 9,697'10,065'9,571'1,878 psi N/A Perforation Depth TVD (ft): Tubing Size: Length Size Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 1:34 pm, Sep 27, 2021 321-508 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.09.27 11:39:09 -08'00' Dan Marlowe (1267) X MITIA to 2000 psi required within 10 days of return to production after perforating. Provide 24 hrs notice for AOGCC witness. 2214 psi - bjm PLT required within 30 days of production after perforating to allocate production per CO 510B. 10-404 Perforate f Perforate New Pool SFD 9/27/2021 DSR-9/27/21 SFD 9/27/2021 BJM 9/29/21 dts 9/29/2021 JLC 9/29/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.29 10:17:06 -08'00' RBDMS HEW 9/30/2021 Well Prognosis Well: KBU 22-06Y Date: 9-20-2021 Well Name:KBU 22-06Y API Number:50-133-20650-00 Current Status:Gas well Leg:N/A Estimated Start Date:10/01/21 Rig:E-line Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:215-044 First Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Second Call Engineer:Todd Sidoti (907) 777-844.(O)(907) 632-4113 AFE Number: Current Bottom Hole Pressure: ~ 600 psi @ 7,308’ TVD (7,645’ MD) Maximum Expected BHP: ~ 2910 psi @ 6,961’ TVD Max. Allowable Surface Pressure: ~ 2214 psi (Based on KBU 22-06Y RFT data and gas gradient to surface (0.10 psi/ft as per 20AAC.280 (b)(4) Well Status KBU 22-06Y is currently producing ~900 MCFD and 5-10 BWPD @ 20 psi FTP. Brief Well Summary KBU 22-06Y was drilled and completed in the Tyonek D in 2015 by Hilcorp. It was perf’d and produced in the D3A and in 2016 the D2 was added. At its peak, it was producing at 6600 mcfd. In mid-2021, the Ty 72_8 and the UT 1B were added with subpar results. The well has cum’d 6.6 BCFTD. Wellbore Condition 7/17/2021 CBL logged, TOC in 3-1/2” x 9-5/8” annulus is 4030’ Minimum ID is 4.276”. 5/14/2021 RIH w/ 3.5” fluted centralizer to 9,917 RKB. Tagged fill. E-Line Procedure 1. MIRU E-line, PT lubricator to 2500 psi High. 2. Perforate the below sands: Conservation order and pool (CO 510B, Beluga/Upper Tyonek Gas Pool). Sand Top, MD ft Bottom, MD ft Top, TVD ft Bottom, TVD ft Total ftg, MD LB1 ±6,390’±6,402’±6,135’±6,147’±12’ LB1A ±6,419’±6,435’±6,161’±6,177’±16’ LB1B ±6,460’±6,475’±6,200’±6,215’±15’ LB1E ±6,621’±6,630’±6,352’±6,361’±9’ LB2E ±6,947’±6,955’±6,656’±6,664’±8’ LB2E ±6,967’±6,975’±6,676’±6,684’±8’ LB4A ±7,217’±7,243’±6,909’±6,935’±26’ LB4B ±7,274’±7,289’±6,961’±6,976’±15’ Beluga/Upper Tyonek Gas Pool) -00 DLB This is a cut and paste error from a different well. ~ 2214 psi (Based on K Well Prognosis Well: KBU 22-06Y Date: 9-20-2021 TY_D1 ±9,324’ ±9,338’ ±8,876’ ±8,890’ ±14’ TY_D3 ±9,747’ ±9,757’ ±9,274’ ±9,284’ ±10’ TY_D4B ±10,002’ ±10,016’ ±9,510’ ±9,524’ ±14’ a) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. b) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c) Use Gamma/CCL to correlate. d) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals after firing gun. e) CO 510B Rule #5 allows comingling of the Beluga/Upper Tyonek Pool, Tyonek Pool #1, and the Kenai Deep Tyonek Pools, and requires an annual PLT. The annual PLT occurred most recently on 7/17/2021. 3. POOH. 4. RD e-line. 5. Turn well over to production. 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 / 2,500 psi High. 3. RIH and set a Casing Patch or set a CIBP above the zone and dump 25’ of cement on top of the plug. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 6. MITIA to 2300 psi within 10 days of return to production after perforating. bjm 7. Production log required within 30 days of stable production to allocate production between pools. bjm Updated by DMA 07-14-21 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00 SCHEMATIC PBTD = 10,065’ MD / 9,571’ TVD TD = 10,200’ MD / 9,697’ TVD CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven 109 X-56 Weld 15.00” Surf 136' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 1,524’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012’ TUBING 5" Production 18 L-80 DWC/C-HT 4.276” Surf 10,184’ 1 16” 10-3/4” 5” JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11.00” Tubing Hanger 2 5,019’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 10,065’ - 3.710” Cement Retainer 7-5/8” CBL TOC 3,670’ 2 OPEN HOLE / CEMENT DETAIL 10-3/4” 110 BBL of 12.0# lead cement 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8" 244 BBL of 11.0# LiteCRETE lead cement 29.5 BBL of 15.8# tail cement TOC 3,670’ (CBL dated 4/29/15) 5” 132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,219’ Calculated RA Tag depths: PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Date Size Status TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/21 3-3/8” Open TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/21 3-3/8” Open UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/21 2-7/8” Open D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/16 2-7/8” Open D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/15 3.5” PJN Open Est TOC 5,219’ 9,605’ 9,891’ 9,359’ 9,072’ 8,826’ 8,536’ 8,293’ 8,004’ 3 D-3B D-2A TY 72_8 UT 1B Updated by TRH 20Sep2021 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00 PROPOSED PBTD = 10,065’ MD / 9,571’ TVD TD = 10,200’ MD / 9,697’ TVD RA Tag Depths, MD OPEN HOLE / CEMENT DETAIL 10-3/4”110 BBL of 12.0# lead cement 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8" 244 BBL of 11.0# LiteCRETE lead cement 29.5 BBL of 15.8# tail cement TOC 3,670’ (CBL dated 4/29/15) 5” 132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,219’ Calculated JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11.00” Tubing Hanger 2 5,019’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 10,065’ - 3.710” Cement Retainer 8,004' 8,293' 8,563' 8,826' 9,072' 9,359' 9,605' 9,891' CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00” Surf 136' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 1,524’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012’ TUBING 5" Production 18 L-80 DWC/C-HT 4.276” Surf 10,184’ 116” 10-3/4” 5” 7-5/8” CBL TOC 3,670’ 2 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Date Size Status LB1 ±6,390’ ±6,402’ ±6,135’ ±6,147’ TBD PROPOSED LB1A ±6,419’ ±6,435’ ±6,161’ ±6,177’TBD PROPOSED LB1B ±6,460’ ±6,475’ ±6,200’ ±6,215’ TBD PROPOSED LB1E ±6,621’ ±6,630’ ±6,352’ ±6,361’ TBD PROPOSED LB2E ±6,947’ ±6,955’ ±6,656’ ±6,664’ TBD PROPOSED LB2E ±6,967’ ±6,975’ ±6,676’ ±6,684’ TBD PROPOSED LB4A ±7,217’ ±7,243’ ±6,909’ ±6,935’ TBD PROPOSED LB4B ±7,274’ ±7,289’ ±6,961’ ±6,976’ TBD PROPOSED TY 72_8 7,645’ 7,655’ 7,308’ 7,318’ 7/12/21 3-3/8” Open TY 72_8 7,675’ 7,685’ 7,336’ 7,345’ 7/12/21 3-3/8” Open UT 1B 7,825’ 7,840’ 7,476’ 7,490’ 6/14/21 2-7/8” Open TY_D1 ±9,324’ ±9,338’ ±8,876’ ±8,890’ TBD PROPOSED D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/16 2-7/8” Open TY_D3 ±9,747’ ±9,757’ ±9,274’ ±9,284’ TBD PROPOSED D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/15 3.5” PJN Open TY_D4B ±10,002’ ±10,016’ ±9,510’ ±9,524’ TBD PROPOSED Est TOC 5,219’ 3 D-3B D-2A TY 72_8 UT 1B 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 KBU 22-06Y (PTD 215-044) 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 11:18 am, Aug 03, 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 KBU 22-06Y (PTD 215-044) 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 1:46 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 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): 10,200'N/A Casing Collapse Structural Conductor Surface 2,470 psi Intermediate 4,790 psi Production 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: Ted Kramer Operations Manager Contact Email: Contact Phone: 777-8420 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 tkramer@hilcorp.com 9,697'10,065'9,571'1,878 psi N/A Perforation Depth TVD (ft):Tubing Size: Length Size COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 A-028142 215-044 50-133-20650-00-00 Kenai Beluga Unit (KBU) 22-06Y Kenai Gas Field - Beluga/Upper Tyonek Pool - Tyonek Gas Pool 1 CO 150a Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY TVD Burst 10,184' MD 6,890 psi 5,210 psi 136' 1,506' 7,651' 136' 1,524' 16" 10-3/4" 136' 7-5/8"8,012' 1,524' 8,012' See Attached Schematic 5,019' MD - 4,853' TVD; N/A 18.0# / L-80 Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: June 8, 2021 5" Swell Packer; N/A Perforation Depth MD (ft): m n P 66 t Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 1:52 pm, May 18, 2021 321-245 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.05.18 13:45:54 -08'00' Taylor Wellman (2143) DSR-5/18/21 CO 510A bjm 10-404 X DLB 05/20/2021BJM 6/8/21 dts 6/8/2021 JLC 6/8/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.06.08 15:31:18 -08'00' RBDMS HEW 6/9/2021 Well Prognosis Well: KBU 22-06Y Date: 5-18-2021 Well Name: KBU 22-06Y API Number: 50-133-20650-00 Current Status: Gas well Leg: N/A Estimated Start Date: 6/8/2021 Rig: N2 / E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-044 First Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) AFE Number: Maximum Expected BHP: 2626 psi @ 7,476’ TVD (Based on offset well BHP data) Max. Potential Surface Pressure: 1,878 psi (Based on KBU 22-06Y RFT data and gas gradient to surface (0.10psi/ft)) Brief Well Summary KBU 22-06Y was drilled and completed in the Tyonek D in 2015 by Hilcorp. It was perf’d and produced in the D3A and in 2016 the D2 was added. At its peak, it was producing at 6500 mcfd and has cum’d 6.4 BCF TD. KBU 22-06Y is currently producing ~1000 MCFD and 5 BWPD @ 23 psi FTP. The purpose of this Sundry is to add the UT 1B and the TY 72_8 sands. Notes Regarding Wellbore Condition x Production tubing is 5” 18# L-80 tubing. x Min Id is 4.276”. x Latest SL Tag was 5/14/21 at 9896’ W/ a 3.50” fluted centralizer. E-Line Procedure 1. MIRU E-line and pressure control equipment. PT lubricator to 3,000 psi High. 2. RIH with GPT tool to confirm fluid level. 3. Based on Fluid Level, determine if field gas or Nitrogen is needed to push fluid away to open perforations. Contingency: If Fluid Level is not an issue, then consider shooting a 2’ gun into the best part of the new zone to allow well pressure to equalize with the new perforations. 4. PU and RIH with 2-7/8” Perforating gun, 6 to 12 SPF, 60 degree phasing. Proposed Perforation Intervals: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Reservoir Pressure TY 72_8 ±7,645’ ±7,685’ 40' ±7,308’ ±7,345’ 1,041 psi UT 1B ±7,825’ ±7,840’ 15' ±7,476’ ±7,490’ 2,626 psi a) Proposed perforations are also shown on the proposed schematic in red font. b) Final Perforation tie-in sheet will be provided in the field for exact perforation 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. -00 DLB Well Prognosis Well: KBU 22-06Y Date: 5-18-2021 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 at 5 min., 10 min. and 15 min intervals after firing gun. f) The listed Sands are governed by Conservation Order 510A. g) Sand intervals will be shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. 5. POOH. 6. RD E-line. 7. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Safety Concerns for N2 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 (if venting Nitrogen during this job). x Ensure all crews are aware of stop work authority. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure – N2 Operations Downhole Revised: 5/30/15 Updated by DMA 6/30/16 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00 SCHEMATIC PBTD = 10,065’ MD / 9,571’ TVD TD = 10,200’ MD / 9,697’ TVD CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16” Conductor – Driven 109 X-56 Weld 15.00” Surf 136' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 1,524’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012’ TUBING 5" Production 18 L-80 DWC/C-HT 4.276” Surf 10,184’ 1 16” 10-3/4” 5” JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11.00” Tubing Hanger 2 5,019’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 10,065’ - 3.710” Cement Retainer 7-5/8” CBL TOC 3,670’ 2 OPEN HOLE / CEMENT DETAIL 10-3/4” 110 BBL of 12.0# lead cement 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8" 244 BBL of 11.0# LiteCRETE lead cement 29.5 BBL of 15.8# tail cement TOC 3,670’ (CBL dated 4/29/15) 5” 132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,219’ Calculated RA Tag depths: PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Date Size Status D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/16 2-7/8” Open D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/15 3.5” PJN Open Est TOC 5,219’ 9,605’ 9,891’ 9,359’ 9,072’ 8,826’ 8,536’ 8,293’ 8,004’ 3 D-3B Fluid Level: 9,655’ D-2A Updated by TRH 12May2021 Kenai Gas Field Well: KBU 22-06Y PTD: 215-044 API: 50-133-20650-00 PROPOSED PBTD = 10,065’ MD / 9,571’ TVD TD = 10,200’ MD / 9,697’ TVD CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16”Conductor – Driven 109 X-56 Weld 15.00” Surf 136' 10-3/4" Surf. Csg 45.5 L-80 BTC 9.950” Surf 1,524’ 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012’ TUBING 5" Production 18 L-80 DWC/C-HT 4.276” Surf 10,184’ 116” 10-3/4” 5” JEWELRY DETAIL No. Depth ID OD Item 1 18’ 4.276” 11.00” Tubing Hanger 2 5,019’ 4.276” 6.875” 10 ft Swell Packer (Water Swell) 3 10,065’ - 3.710” Cement Retainer 7-5/8” CBL TOC 3,670’ 2 OPEN HOLE / CEMENT DETAIL 10-3/4”110BBL of 12.0# lead cement 47 BBL of 15.2# tail cement (Perform Top Job from 89.6’ w/ 18 bbl of 12# cmt) 7-5/8" 244 BBL of 11.0# LiteCRETE lead cement 29.5 BBL of 15.8# tail cement TOC 3,670’ (CBL dated 4/29/15) 5” 132 BBL’s of 15.3# EZ Blok cement. Squeeze thru retainer. TOC 5,219’ Calculated RA Tag depths: PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) Date Size Status TY 72_8 ±7,645’ ±7,685’ ±7,308’ ±7,345’ TBD Proposed UT 1B ±7,825’ ±7,840’ ±7,476’ ±7,490’ TBD Proposed D-2A 9,454’ 9,494’ 8,997’ 9,035’ 6/16/16 2-7/8” Open D-3B 9,812’ 9,847’ 9,334’ 9,367’ 5/30/15 3.5” PJN Open Est TOC 5,219’ 9,605’ 9,891’ 9,359’ 9,072’ 8,826’ 8,536’ 8,293’ 8,004’ 3 D-3B D-2A TY 72_8 UT 1B 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. 215044 Seth Nolan • Hilcorp Alaska, L! 6 GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 DATA LOGGED Hilcnrp Alfcrka,.LU. Fax: 907 777-8510 K. BENDER E-mail: snolan@hilcorp.com DATE 09/30/16 EIVED To: Alaska Oil & Gas Conservation Commission Makana Bender OCT 0 3 2016 Natural Resource Technician II 333 W 7th Ave Ste 100 AOGCO Anchorage, AK 99501 DATA TRANSMITTAL KBU 22-06Y KBU 22-06Y Log prints and digital data Prints: copp � �(1`Y' L.12 Perforation Record 5" MD 99�® CD1: digital Elog Data KBU 22-06Y PERF 16JUN16 LAS.zip 6/22/2016 8:25 AM zip Archive 56 KB j KBU 22-06Y PERF16JtJPtl6.pdf 6/22/2016 8:22 AM PDF Document 851 KB KBU 22-06Y_PERF16JUN16_irng.tif 6/22/2016 8:22 AM TIF File 2,479 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 By: V STATE OF ALASKA RECEIVED AL OIL AND GAS CONSERVATION COMAION REPORT OF SUNDRY WELL OPERATIONS JUL g 2016 1.Operations Abandon LI Plug Perforations U Fracture Stimulate ❑ Pull Tubing LJ ACgChutdown LJ Performed: Suspend ❑ Perforate ❑., Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ 3rforate New Pool ❑ Repair Well 0 Re-enter Susp Well 0 Other: 0 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑✓ Exploratory 0 215-044 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20650-00 7.Property Designation(Lease Number): 8.Well Name and Number: A-028142 Kenai Beluga Unit(KBU)22-06Y 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 Pool-Tyonek Gas Pool 1 11.Present Well Condition Summary: Total Depth measured 10,200 feet Plugs measured N/A feet true vertical 9,697 feet Junk measured N/A feet Effective Depth measured 10,065 feet Packer measured 5,019 feet true vertical 9,571 feet true vertical 4,853 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 16" 136' 136' Surface 1,524' 10-3/4" 1,524' 1,506' 5,210 psi 2,470 psi Intermediate 8,012' 7-5/8" 8,012' 7,651' 6,890 psi 4,790 psi Production Liner qq°� WO FEB ttl Perforation depth Measured depth See Attached Schematic r�r- 9�9� � N"'�'.l`:' � t+ tl True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 5" 18.0#/L-80 10,184' 9,682'ND Packers and SSSV(type,measured and true vertical depth) Swell Pkr:N/A 5,019'MD 4,853'ND N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 3296 0 210 199 Subsequent to operation: 0 6198 1 235 212 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑, Exploratory 0 Development 2 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-304 Contact Taylor Nasse-777-8354 Email tnassea.hilcorp.com Printed Name Chad Helgeson Title Operations Engineer ) Signature A I���I Phone 907-777-8405 Date 7/icjl/ 7/26 16 RBDMS \A/ 2"'. 2 2 2016 Sub Originalnly Form 10-404 Revised 5/2015 • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 22-06Y E-Line 50-133-20650-00 215-044 6/15/16 6/16/16 Daily Operations: 06/15/2016-Wednesday PTW and JSA. Rig up lubricator, pressure test 250 psi low and 3,000 psi. RIH w/3.95" gauge ring. Tag TD @ 9,992' WLM, 10,010' KB. Hard bottom. Rig down. Secure wellhead. 06/16/2016-Thursday PTW and JSA. Spot equipment and PT 250 psi low and 3,000 psi high. Arm gun. RIH w/2-7/8" x 20' Connex HC, 6 spf, 60 deg phase and tie into Halliburton LWD log dated Apr 12, 2015. Flowing tubing pressure 220 psi. Ran correlation log and send to town. Get ok to perf from 9,474' to 9,494'. Spotted shot, shut well in and fired shot when pressure got to 300 psi. We kept well flowing around 310 psi. POOH. All shots fired. Gun was wet. Gamma ray/CCL quit working and the other tool they had out wasn't working either. Waited while tool was brought out from shop. Arm gun. RIH w/2- 7/8" x 20' Connex HC, 6 spf, 60 deg phase and tie into Halliburton LWD log dated Apr 12, 2015. Flowing tubing pressure 306 psi. Ran correlation log and send to town. Get ok to perf from 9,454' to 9,474'. Spotted shot and fired gun with 306 flowing tubing pressure. Pressure stayed at 306 psi. Wasn't sure if gun fired. POOH.All shots fired and gun was wet. Rig down lubricator and turn well over to field. Flowing tubing pressure 310 psi. • 0 Kenai Gas Field } Well: KBU 22-06Y , H SCHEMATIC PTD: 215-044 API: 50-133-20650-00 Hilcorp Alaska,LLC CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 1,4 16" 1r 16" Conductor— 109 X-56 Weld 15.00" Surf 136' ' `. Driven 1 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 1,524' .2 7 5/8" Intermediate 29.7 L 80 BTC 6.875" Surf 8 012' 10-3/4" " ' TUBING CBL TOC 5" Production 18 L-80 DWC/C-HT 4.276" Surf 10,184' 3,670' t)014 -0.0 2 J`; Est TOC , :° , ? • • o ,11 1 . i • o o i r r j • :1 .-• 0 G • • J J N 0 CV Z 'i c E • r • i_ J O O O Q Cl _U NI , CD 2 N E cm 0 • > a O. N Q �. 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Q O CL Q 0 0 O O O O O O O O O O O O O O O 3 W J N N N N N N N N N N N N N N N N Nco Q --- --- --- --- --- --- N N N N --- --- --- --- --- N N VJ Z N 0) IX drt NNNNNNNNNNNNNNNNNLO N CO EL E W oJ 4. .a ON 0CO N NN UQ ; • • o o 0 O N 9 I (7,- co ic N Z D. N 1 I Q ; U_ T c , c L o Z I 1 CO 1Q cn CO 1 0 IX J N UJ 1 IX a are UJ O V E a _ C7 Z Q ti QCO 7 J . co 11 CL co o C g G O .� o N a UN U w 'et d o E 0 cv N V 0�. Z in M 'c:-.) Q N W J in M W H N m N r 100 CO N R R o 0 Q Z Y m ICC o —�" EI d 1 0 "' • O N C) p O M 0 O p >. N O m = N d W @ IX 6• O c. O ° c o N Z C 06 O Vl V p O Q O 0 ..... I C U J y N .- a) ell C.7 a a ccoo u E o Od0oCo 0 0a 2 t..) or T� \ i//7,. ', i yyy.'4, THE STATE Alaska Oil and Gas �, of/� L /\ c J /�\I1 Conservation Commission r1 1-17 333 West Seventh Avenue 1. GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 1Q. Main: 907.279.1433 • ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 OLe`Y Re: Kenai Gas Field, Beluga/Upper Tyonek Pool and Tyonek Gas Pool 1, KBU 22-63\- Permit to Drill Number: 215-044 Sundry Number: 316-304 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, Cathy P oerster Chair DATED thisay of June, 2016. RBDMS 1A- JUi4 1 3 2016 RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JUN 0 2 2016 APPLICATION FOR SUNDRY APPROVALS pi ' C%// 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate Q - Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory ❑ Development E 215-044 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service El 6.API Number: Anchorage,Alaska 99503 50-133-20650-00 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510a Kenai Beluga Unit(KBU)22-06Y . Will planned perforations require a spacing exception? Yes ❑ No ❑., 9. Property Designation(Lease Number): 10.Field/Pool(s): A-028142 Kenai Gas Field-Beluga/Upper Tyonek 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): 10,200' - 9,697' 10,065' 9,571' 830 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 16" 136' 136' Surface 1,524' 10-3/4" 1,524' 1,506' 5,210 psi 2,470 psi Intermediate 8,012' 7-5/8" 8,012' 7,651' 6,890 psi 4,790 psi Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 5" 18.0#/L-80 10,184' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Swell Packer;N/A 5,019'MD-4,853'TVD;N/A 12.Attachments: Proposal Summary n 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: June 16,2016 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS 0 - WAG ❑ GSTOR ❑ SPLUG Cl Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasSe gehllcorp.cot71 Printed Name Chad Helgeson Title Operations Manager Signature &://e..//jPhone 907-777-8405 Date ''/ /' ` COMMISSION USE ONLY 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 ,d Subsequent Form Required: r(, `/ L.' ( RBDMS w' JUN 1 3 2016 ^J/ APPROVED BY p // Approved by:a1:47 /%`�',.11�-_- COMMISSIONER THE COMMISSION Date: `o —O —< 4 Submit Form and Form 10-403 Revised 11/2015 0 RtGarNtiAirlid for 72 onths from the date of approval. Attar ments in Duplicate Well Prognosis Well: KBU 22-06Y Date:6/1/16 klilcorp Alaska.LL Well Name: KBU 22-06Y API Number: 50-133-20650-00 Current Status: Producing Gas Well Leg: N/A Estimated Start Date: 6/16/15 Rig: N/A Reg.Approval Req'd: 10-403 Sundry Number: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-044 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907)903-0341 (C) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824 (C) AFE Number Current Flowing Bottom Hole Pressure: —240 psi at 9,367 TVD (Pressure survey on 04/21/16) Est. Bottom Hole Pressure of new sand: —500 psi at 9,035' TVD (Based on SI BHP survey of offset well) Max. Potential Surface Pressure: —830 psi (Based on SI BHP survey on 04/21/16) Current Surface Pressure: —188 psi (flowing from D-3B sand) Brief Well Summary: Kenai Gas Field well KBU 22-06Y was drilled as a Grass roots monobore completion in May 2015 to target gas sands in the Beluga/Upper Tyonek and Tyonek formations. It was originally completed in the Tyonek D-3B sand in May 2015. The purpose of this work/sundry is to perforate the D 2A interval. Notes Regarding Wellbore Condition • The well currently has the D-3B sand open and is flowing 3.1 MMSCFD at 200 psig. • MIRU slickline and make GR and drift run to tag bottom prior to performing work. E-Line Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 250 psi low/3,000 psi high. 2. Perforate the Tyonek sands with 3-3/8" 6 SPF 60 deg phased perf guns(verify with Reservoir engineer desired pressure on well prior to perforating-300 psi), bleed well down if necessary prior to perforating. All intervals are planned for 12 SPF so each zone may be shot twice. Depths are from the Halliburton LWD log dated April 12th, 2015. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Proposed Perforated Intervals Sands Top (MD) Btm (MD) FT Tyonek D-2A ±9,454 ±9,494 ±40 3. POOH. 4. Flow through test separator and record water and gas rates. 5. If the D-2A is not commercial or wet,the zone will be permanently plugged back with a casing patch. 6. RD e-line. 7. Turn well over to production. Attachments: 1. Current and Proposed Well Schematics 2. X-Span patch specifications Kenai Gas Field II Well: KBU 22-06Y ACTUAL SCHEMATIC PTD: 215-044 API: 50-133-20650-00 Hilcorp Alaska,LLC CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16" ' 1 r 16" Conductor- 109 X-56 Weld 15.00" Surf 136' * Driven ij.. 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 1,524' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012' 10-3/4" ' TUBING 5" Production 18 L-80 DWC/C-HT 4.276" Surf 10,184' CBL TOC r 3,670' ,' '' , r 2 " " Est TOC _k 44 ', 't, 5,219' OPEN HOLE/CEMENT DETAIL BA Tag `:. 'a 1".' 10-3/4" 110 BBL of 12.0#lead cement '5"1' ';/-11 47 BBL of 15.2#tail cement(Perform Top Job from 89.6'w/18 bbl of 12#cmt) depths: 4 , , „ ' ►, � r, 244 BBL of 11.0#LiteCRETE lead cement * 7-5/8" 29.5 BBL of 15.8#tail cement 8,004' - �' r" t� 7-g/8" TOC 3,670'(CBL dated 4/29/15) *,,.: .% .. 5" 132 BBL's of 15.3#EZ Blok cement. Squeeze thru retainer. TOC 5,219'Calculated x' 8,293' o JEWELRY DETAIL ;"b No. Depth ID OD Item Le 1 18' 4.276" 11.00" Tubing Hanger J r 2 5,019' 4.276" 6.875" 10 ft Swell Packer(Water Swell) 8,536' ofo. 3 10,065' - 3.710" Cement Retainer PERFORATION DETAIL 8,826' Sands Top(MD) Btm(MD) Top(ND) Btm(ND) Date Size Status ,�:, D-3B 9,812' 9,847' 9,334' 9,367' 5/30/15 3.5" PJN Open 9,072' " , 9,359' 1 9,605' . Fluid Level:9,655' D-3B 9,891' a 3 ' PBTD=10,065' MD/9,571'TVD TD=10,200' MD/9,697'ND Downhole Revised: 5/30/15 Updated by STP 6/02/15 Kenai Gas Field • Well: KBU 22-06Y II PROPOSED SCHEMATIC PTD: 215-044 API: 50-133-20650-00 Hilcorp Alaska,LLC CASING DETAIL Size Type Wt Grade Conn. ID Top Btm t., 16"L I16" Conductor— 109 X-56 Weld 15.00" Surf 136' Driven a 10-3/4" Surf.Csg 45.5 L-80BTC 9.950" Surf 1,524' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012' 10-3/4"L TUBING CBL TOC 5" Production 18 L-80 DWC/C-HT 4.276" Surf 10,184' 3,670' 2 = Est TOC 5,219' OPEN HOLE/CEMENT DETAIL RA Tag 10-3/4" 110 BBL of 12.0#lead cement depths: - 47 BBL of 15.2#tail cement(Perform Top Job from 89.6'w/18 bbl of 12#cmt) 244 BBL of 11.0#LiteCRETE lead cement 8,004' 7-5/8" 7-5/8" 29.5 BBL of 15.8#tail cement TOC 3,670'(CBL dated 4/29/15) 5" 132 BBL's of 15.3#EZ Blok cement. Squeeze thru retainer. TOC 5,219'Calculated 8,293' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.276" 11.00" Tubing Hanger 2 5,019' 4.276" 6.875" 10 ft Swell Packer(Water Swell) 8,536' 3 10,065' - 3.710" Cement Retainer PERFORATION DETAIL 8,826' x Sands Top(MD) Btm(MD) Top(ND) Btm(ND) Date Size Status ." 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Nn Co 0O v V) ' co C I r F' co 7 co V' 10 CO 4-01.-:• to 4 0 oQLa O (4,tO Nn ("f CO co 4 tP.. `- •.M- F c)N O W 215044 Seth Nolan Hilcorp Alaska, LLC 6 9 GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 Hilrnrp:UitaciL 1.1.1 Fax: 907 777-8510 DATA LOGGED E-mail: snolan@hilcorp.com ji1/201v M.K.BENDER DATE 01/20/16 To: Alaska Oil & Gas Conservation Commission RECEIVED Makana Bender Natural Resource Technician II FEB 0 2 2016 333 W 7th Ave Ste 100 Anchorage, AK ®GC 99501 A'p i C DATA TRANSMITTAL KBU 22-06Y KBU 22-06 Elog prints and digital data Prints: PRESSURE EXPRESS LOG CD1: digital Elog Data Hilcorp KBU 22-06Y OHS 1/19/20164:47 PM File folder Hilcorp KBU 22-06Y LOG 1/22/2016 11:49 AM File folder YLA Hilcorp KBU 22-06Y_XPT_Pressure Summ... 4/21/2015 5:31 AM Microsoft Excel C... 17 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 ReceivedM, (/ ) Date: ZQ.J ✓...�i/�a0t� ! • • 21 5044 II Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 ItiI urp.tlnrka.LI l Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATE 06/15/15 DATA LOGGED 1/C6/2015 M.K.BENDEP To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 ��� '� Anchorage, AK E.' 0 99501 2.015JUN 2 4 DATA TRANSMITTAL KBU 22-06Y AOGC KBU 22-06 Elog and Mudlog prints and digital data Prints: 5" Formation Log MD 2"/5" ROP-DGR-EWR-ARD-ALD-CTN MD 2" Formation Log MD 2"/5" DGR-EWR-ADR-ALD-CTN TVD 2" Gas Ratio Log MD END OF WELL REPORT 2" Drilling Engineering Log MD Cement Bond Log CD1: digital Elog Data 2 5 9 8 5 4. CGM 5/14/20158:22 AM File fclder Definitive Survey 5/14/2015 8:22 AM File fclder DLIS+LAS 5/14/2015 8:22 AM File folder EMF 5/14/20158:22 AM File folder 4,, PDF 5/14/20158:22 AM File fclder TIFF 5/14/2015 8:23 AM File fclder CD2: digital Mudlog Data 2 5 9 8 6 EMF Log Viewer 6/8/2015 2:09 PM File folder , Halliburton Log Viewer 6/8/2015 2:09 PM File folder , KBU 22-06Y FINAL LOGS 6/8/2015 2:13 PM File folder KBU 22-06Y LAS EXPORTS 618/2015 2:13 PM File folder 0 KBU 22-06Y FINAL END OF WELL REPORT 6/212015 10:35 AM PDF Document 1,984 KB Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By: fi) iz 6..eorzie: 1 • Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 H lrnrp:tInnka.U.(,, Fax: 907 777-8510 E-mail: snolan@hilcorp.com CD3: CBL Data 2 5 9 8 7 HILCORP KBU_22-06Y_RCBL_23M.AY15 5/28/2015 2:39 PM PDF Document HILCORP_KBU_22-06Y_RCBL_23MAY15_i,. 5/28/2015 2:39 PM TIFF File HILCORP KBU 22-06Y RCBL 23MAY15 ,.. 5/28/2015 2:39 PM LAS File HILCORP KBU 22-06YRCBL 23MAY15 R... 5/28/2015 2:39 PM LAS File 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 Receiv �y Date: .11 • • Hilcorp Alaska, LLC Post Office Box 244027 V ED RECO Anchorage,AK 99524-4027 3800 Centerpoint Drive Suite 1400 JUN 11 2015 Anchorage,AK 99503 Phone: 907/777.8389 June 17, 2015 itt1 Fax: 907/777.8301 Alaska Oil and Gas Conservation Commission 333 W. 7t''Ave., Suite 100 Anchorage, Alaska 99501 Re: KBU 22-06Y Form 10-407 PTD: 215-044 API: 50-133-20650-00-00 Dear Commissioner: Please find the enclosed Well Completion Form 10-407 for KBU 22-06Y. Please do not hesitate to contact me should you have any questions or need additional information. Sincerely, 'ijt HIL ORP ALASKA, LLC Cody Dinger Drilling Technician (907)777-8389 cdinger@hilcorp.com loft RECEIVED • S JUN 17 2015 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION AOGCC WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a.Well Status: Oil ❑ Gas❑✓ . SPLUG ❑ Other ❑ Abandoned ❑ Suspended❑ lb.Well Class: 20AAC 25.105 20AAC 25.110 Development ❑� ' Exploratory ❑ GINJ❑ WINJ ❑ WAG❑ 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.: • 5/30/2015 - 215-044/315-309 • 3.Address: 7. Date Spudded: 15.API Number: 3800 Centerpoint Drive, Suite 1400 Anchorage,AK 99503 • 4/7/2015 50-133-20650-00-00, • 4a. Location of Well(Governmental Section): 8. Date TD Ruched: 1 16.Well Name and Number: Surface: 1196'FWL,420'FSL,Sec 6,T4N, R11W, SM,AK •4/M2015 Kenai Beluga Unit(KBU)22-06Y- Top of Productive Interval: 9. KB(ft above MSL): 84 . 17. Field/Pool(s): Kenai Gas Field/ - 2039'FNL, 1557'FWL,Sec 6,T4N, R11W, SM,AK GL(ft above MSL): 65.5 . Tyonek Gas Pool 1 Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 1907'FNL, 1585'FWL, Sec 6,T4N, R11W, SM,AK - 10,065'MD/9,571'TVD - Unit Tract 26; Fee A028142- 4b. Location of Well(State Base Plane Coordinates, NAD 27): 11.Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 272112.27 - y- 2362472.99 - Zone- 4 10,200'MD/9,697'TVD - N/A TPI: x- 272612.88 y- 2365281.25 Zone- 4 12. SSSV Depth MD/TVD: 20.Thickness of Permafrost MD/TVD: Total Depth: x- 272643.73 y- 2365413.28 Zone- 4 N/A/N/A N/A 5. Directional or Inclination Survey: Yes ✓❑attached) No ❑ 13.Water Depth, if Offshore: 21. Re-drill/Lateral Top Window MD/TVD: Submit electronic and printed information per 20 AAC 25.050 N/A (ft MSL) N/A 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion,suspension,or abandonment,whichever occurs first.Types of logs to be listed include, but are not limited to:mud log,spontaneous potential, gamma ray,caliper, resistivity, porosity, magnetic resonance,dipmeter,formation tester,temperature,cement evaluation,casing collar locator,jewelry, and perforation record. Acronyms may be used.Attach a separate page if necessary 5"FEL MD,2"FEL MD,2"GRL MD,2"DEL MD, 275"ROP-DGR-EWR-ARD-ALD-CTN MD,275"DGR-EWR-ADR-ALD-CTN TVD, CBL 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 • 10-3/4" 45.5 L-80 0 1,524' 0 1,506' 13-1/2" 110 bbls 12#/47 bkls2# 0-top Job-18 bbls 12#\ 7-5/8" 29.7 L-80 0 8,012' 0 7,651' 9-7/8" 244 bbls 11#/29.5 15.8# 5" 18 L-80 0 10,184' 0 9,682' 6-3/4" 132 bbls 15.3#pumped thru cmt retainer @ 10,065'MD 24.Open to production or injection? Yes El No ❑ 25.TUBING RECORD If Yes, list each interval open(MD/TVD of Top and Bottom; Perforation Size SIZE DEPTH SET(MD) PACKER SET(MD/TVD) and Number): 5" 10,184' 5,019'MD/4,853'TVD 1. 9,812'-9,847'MD/9,334'-9,367'TVD(3.5"PJN)6 SPF 26.ACID, FRACTURE, CEMENT SQUEEZE, ETC. ,„, ,,i,. Was hydraulic fracturing used during completion? Yes ❑ No ❑ 4; Per 20 AAC 25.283(i)(2)attach electronic and printed information ° -*Ii-• • DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 27. PRODUCTION TEST Date First Production: Method of Operation(Flowing,gas lift,etc.): 5/31/2015 Flowing Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 6/3/2015 24 Test Period 0 2138 0 N/A N/A Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity-API(corr): Press. 691 N/A 24-Hour Rate m.0. 0 2138 - 0 N/A „/„., ' RBDM Form 10-407 Revised 5/2015 CONTINUED ON PAGE 2 A 2 7 2015 Submit ORIGINIAL onl ` 6 '/Z//,/ - 4/443_ iG 28.CORE'DATA Conventional i(s): Yes ❑ No E • Sidewall Core Yes ❑ No ❑✓ If Yes, list formations and intervals cored(MD/TVD, From/To),and summarize lithology and presence of oil,gas or water(submit separate pages with this form, if needed). Submit detailed descriptions,core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes ❑ No E 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 information, including reports, per 20 AAC 25.071. Sterling A8 3613' 3539' Sterling A9 3664' 3587' Sterling Al0 3687' 3609' Sterling All 3759' 3677' Sterling B1 3840' 3752' Sterling B2 3930' 3837' Sterling C 4580' 4443' Upper Beluga 4861' 4706' Middle Beluga 5524' 5324' Lower Beluga 6367' 6113' Tyonek 7611' 7277' Tyonek D1 9274' 8828' Formation at total depth: Tyonek D4 31. List of Attachments: Wellbore Schematic, Days vs Depth, MW vs Depth, Daily Composite Reports, Definitive Driectional Surveys, Casing and Cement Reports 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. Contact: Monty Myers Email: mmyers hIICorp.com Printed Name: Monty Myers Title: Drilling Engineer SignaturePhone: 907-777-8431 Date: 4 . / 7. Z 0 I s INSTRUCTIONSIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed.All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item la: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class-Service wells:Gas Injection,Water Injection,Water-Alternating-Gas Injection, Salt Water Disposal,Water Supply for Injection, Observation, or Other. Item 4b: TPI(Top of Producing Interval). Item 9: The Kelly Bushing and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits(ex:50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030,submit all electronic data and printed logs within 90 days of completion,suspension, or abandonment,whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump,Submersible,Water Injection, Gas Injection, Shut-in,or Other(explain). Item 28: Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Pursuant to 20 AAC 25.071,submit detailed descriptions,core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability,fluid saturation,fluid composition,fluid fluorescence,vitrinite reflectance,geochemical,or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070,attach to this form:well schematic diagram,summary of daily well operations,directional or inclination survey, and other tests as required including, but not limited to:core analysis,paleontological report, production or well test results. Form 10-407 Revised 5/2015 Submit ORIGINAL Only • ' • Kenai Gas Field II Well: KBU 22-06Y ACTUAL SCHEMATIC PTD: 215-044 API: 50-133-20650-00 IIih•urp Alaska.I.LC F 91 CASING DETAIL (41 Size Type Wt GradeConn. ID Top Btm en I16" 1 16" CondDr ctor 109 X-56 Weld 15.00" Surf 136' I* 10-3/4" Surf.Csg 45.5 1-80 BTC 9.950" Surf 1,524' 7-5/8" Intermediate 29.7 1-80 BTC 6.875" Surf 8,012' 10-3/4" . ' TUBING CBL TOC 5" Production 18 L-80 DWC/C-HT 4.276" Surf 10,184' 3,670' 2 Est TOC 5,219' OPEN HOLE/CEMENT DETAIL RA Tag 10-3/4" 110 BBL of 12.0#lead cement depths: 47 BBL of 15.2#tail cement(Perform Top Job from 89.6'w/18 bbl of 12#cmt) 244 BBL of 11.0#LiteCRETE lead cement 8,004' ./T^ 1: 1, 7-5/8" 7-5/8" 29.5 BBL of 15.8#tail cement TOC 3,670'(CBL dated 4/29/15) 5" 132 BBL's of 15.3#EZ Blok cement. Squeeze thru retainer. TOC 5,219'Calculated 8,293' JEWELRY DETAIL No. Depth ID OD Item 1 18' 4.276" 11.00" Tubing Hanger 2 5,019' 4.276" 6.875" 10 ft Swell Packer(Water Swell) 8,536' in 3 10,065' - 3.710" Cement Retainer PERFORATION DETAIL 8 826' Sands Top(MD) Btm(MD) Top(TVD) Btm(ND) Date Size Status D-3B 9,812' 9,847' 9,334' 9,367' 5/30/15 3.5" PJN Open ` 9,072' 9,359' 9,605' 7 Fluid Level:9,655' - Ar-.` D-3B 9,891' 3 S, s" .. PBTD=10,065'MD/9,571'ND TD=10,200' MD/9,697'ND Downhole Revised: 5/30/15 Updated by STP 6/02/15 • • Hilcorp Energy Company Composite Report Well Name: KEU KBU 22-06Y Field:Kenai Gas Field County/State: ,Alaska I(LAT/LONG): evation(RKB): 18 API#: 50-133-20650-00-00 Spud Date: 4/7/2015 Job Name: 1510328D KBU 22-06Y Drilling Contractor Saxon Drilling AFE#: 1510328D AFE$: A ttMty Date Ops Summary 4/4/2015 The crews rig down elect.system;Mud lines;stream lines Mud pumps;Pits;Briddle up the derrick lines prep derrick for scoope down;remove wind walls from rig floor;R/D roughneck;;Crews lowered down the gas buster;Scoped down derrick and prep derrick to be lowered;Disconnect all Hydr.lines from the derrick;unspool and Lay derrick over;lnstall beams in cellar area;remove drive-lines from Draw-works and remove Kill line from rig and prepare miscellaneous part for transport 4/5/2015 PJSM,Demob-Pipe shed,Pits,Pump houses,remove derrick and demob. Demob boilers,gen shacks,sub and pony subs. Rig 100%demob. Clean and rackout mats and containment from KBU 31-18.;Set pony subs,sub,boilers. Set and pin derrick. Set gen shacks,pump houses,pits and pipe shed.;Hook up all utility lines in the mud pits;motor room and pump room;PJSM;Raise derrick(no problems)prepare the derrick to scope and hooking up miscellaneous equipment;Pick up&pin torque tube;Scoped Derrick up and Pin(no problems);Bridle down;Rig up&Pick up Top Drive;plug in power&service lines;;Rig 169 is 95%set in 75%rigged up 4/6/2015 Continue rigging up on well KBU 22-06Y. R/U top drive. Spot silo's.Set 3rd party shacks and hook up svc lines. Install Handy-Berm around perimeter of rig.;M/U water line from well and fill rig tanks. Fill pits w/FW. Start building spud mud. Set windwalls and pin on floor. Demob camp and r/u 100%on new location. Rig is 80%rigged up.;Installed turn buckles on torque tube,changed out wash pipe,hung tongs and changed out dies,continue building spud mud;function test#1 mud pump;and test all surface lines;hook up Hyd.and elect.lines in pipe shed,install test plug and N/U surface riser.and loading pipe shed to pick up drillpipe;Rig Accepted @ 0600 hrs.April 7th 4/7/2015 Rig arcaptanre checklist complete. Pull test plus Load and Tally 4 1/2"drill pipe. 19 jts HWDP. Total Safety calibrated sensors 10/20 H2S,20/40 LEL and bump tested(good).;P/U and rack back 30 stds drill pipe. Rack back 10 stds drill pipe. Tagged btm @ 140'MD. Rig up Halliburton gas trap(mud loggers);M/U BHA#1- M/U 13.5"varel(.7394 TFA),1.5°Mtr(290/801 x 360)TFO=130.34,DM collar,TM collar,(2)8"NM flex DC's,xo,HWDP. Flood conductor. PT surface lines 3k (good).;Hold pre spud meeting.cpird well tag at 140' drill 13 1/2"hole from 140'to 360',pumping 423 Qpm.950 psi.50 rpm,torq 5000 ft/lbs.MW 9 ppg,vis 165.;Stage pump to 470 gpm,1100 psi.Circulate hole clean reciprocating pipe,Rack 4 stds HWDP in derrick.M/U 2-6"NMFC,XOs,2 stds HWDP,jars with XOs, 1 std HWDP and top drive.;Continue drilling from 360'to 855'pumping 470 gpm,1315 psi.Slide wob 6-11k,rotate wob 5-8k.75 rpm,torq 5500 ft/lbs.P/U 40k,S/O • 40k,ROT 40k.MW 9 ppg,vis 144.No losses.;Pump hi vis sweep @ 620',sweep back on time with 100%increase in cuttings. 1.28 slide hrs,3.29 rotate hrs.0.97'above the line,1.96'left of the Iine.;;Hauled 150 bbls cuttings to KGF for total of 150 bbls,Hauled 0 bbls class II junk fluid to KGF for total of 0 bbls 4/8/2015 Drig F/858'-T/1530'MD(TD),1512'ND. Pump @ 470 gpm,1475 psi on,85 diff psi,50%F/O,8-10k WOB,80 rpm,7k tq on,6k tq off,58k up,55k dn,58k rot;Pump 20 bbl hiv sweeps @ 865'(25%increase),1250'(25%increase),Sweeps came back on time.;Circulate and condition mud @ 1530'while reciprocating pipe. Pump @ 500 gpm,1542 psi,53%F/O,50 rpm,5k tq. Pump 20 bbl hi vis sweep w/50%increase in cuttings. Sweep came back on time;Flow check well (static). TOH F/1530'-T/173'MD. Hole displacement-4 bbls for trip. 58k up,55k dn. Tripped out clean T/173'.;Svc rig. Grease D.W,IR,Crown,Blocks,TD and check brakes.;TIH F/173'-T/1530'MD. No fill.Tripped in clean.;Pump 20 bbl hi vis nut plug sweep,sweep back at calculated stks with 10%increase in cuttings.Condition mud lowering YP from 35 to 18.Flowcheck well,static.;POH from 1530'to 790'.Rack HWDP,jars and 2-6"NMFCs in derrick,L/D BN XO,2-8" NMFCs,TM and DM collars,motor and bit,bit grade=1,1,Wr,A,E,I,NO,TD.;Clean up rig floor,Pull 15"ID Wear bushing.Make hanger dummy run per Cameron rep.22.40'to land.R/U to run 10 3/4"surface casing.Load casing into pipe shed.;R/U long bails,elevators,power tongs and slip bowl.;PJSM,inspect,Baker loc and M/U shoe track with centralizers over stop collars 10'from ea.end on shoe jt and 1 ea.on thread locked jt and FC jt.Check float operation.;Continue to P/U and RIH with 10 3/4"BTC 45.5#L-80 surface casing from 129'to 700'using optimum M/U torq @ 10500 ft/lbs @ base of triangle.Fill on the fly and stop and fill every 5 jts ran.;Install 1 centralizer every other jt over collar to 300',use dog collar clamp on first 15 jts ran.TIH at a moderate speed.;;Hauled 260 bbls cuttings to KGF for total of 410 bbls,Hauled 485 bbls class II junk fluid to KGF for total of 485 bbls 4/9/2015 _ Continue to P/U and RIH with 10 3/4"BTC 45.5#L-80 surface casing from 700'to 1499'with no issue&.'P/U hanger and landing jt. Landout on depth w/32k string wt. P/U 3'to clear wellhead. Break circulation.;Stage pumps up to 255 gpm,50 psi,20%F/O w/no losses observed. Condition mud 8.9 ppg,46 vis,18 yp. SN, re-land hanger on depth.;R/U SLB tandem drop plug cement head,4 pt head. Continue circulating w/rig @ 255 gpm,77 psi,20%F/O w/no Iosses.;PJSM,cmt as follows-wet lines 5 bbls H20,P/T lines 4500(good),Rig pump 42 bbls 10#mudpush II,turn over to SLB,drop btm plug;pump-110 bbls 124,Type:extended,2.43 yld,lead cmt. 47 bbls 15.2#,Type:conventional,1.22 yld,tail cement. Pump cmt @ 5 BPM avg. Drop top plug. SLB displace w/8.9#spud mud,4.5 BPM avg.;Pumped 138.5(calculated 138)bbls to bump. Bumped w/FCP 400 @ 1.7 BPM,psi up to 800 psi,held 5 min,bled back.5 bbls,floats held.;Maintained 100% returns throughout job,38.5 bbls mud push retumed to surface,no cement observed @ surface via annulus valves. CIP @ 17:40.;Estimated TOC @ 56'. Used 1. final lift psi vs calc lift psi along with mud push returns to surface. Casing was not reciprocated during job.;Flush and blow down cement line,R/D cementers.Flush S wellhead with water.;Backout and pull landing jt.Install packoff,RILDS,inject plastic per Cameron rep.UD landing jt.;N/D 16"riser,flowline,bleeder and hole fill line.Clean pits.;M/U Multibowl wellhead,install 10 3/4"packoff seals test wellhead to 3500 psi for 15 min per Cameron rep.;N/U wellhead and test hanger void to 250 psi for 5 min and 3100 psi for 15 min per Cameron rep.Set 11"BOP stack in cellar with crane.;Install test plug,N/U 11"spacer spool,Set BOP stack in place. N/U 11"5M BOPE.;;Hauled 120 bbls cuttings to KGF for total of 530 bbls,Hauled 460 bbls class II junk fluid to KGF for total of 945 bbls. 4/10/2015 Continue to N/U BOPE. Suspend Nipple up operations to R/U E-line. Install wear bushing.;R/U Pollard E-line. Run temps logs followed by CBL logs. Send and discuss with drilling engineer. Sim ops-Cut window in conductor for top job. R/U SLB cmfrs and standby for orders.;RIH w/top job tubing to tag up depth of 71' from G/L. R/U and circulate 9 bbls water,pump 18 bbls 124 lead cmt,cmt retums @ 7.5 bbls pumped(calculated was 7.5 bbls F/71'to surface);CIP @ 13:45. AOGCC Inspector Lou Grimaldi witnessed tag,cmt pump and wash up. Reviewed logs. Ok to proceed with normal operations.;Continue nipple up T-3 Class IV 61 11",5M stack. 2 7/8"x 5"VBR's in upper and lower pipe rams. Install flowline,catch can,mud lines,4 pt stack.Function BOPE.;R/U test equipment using 4 1/2" test jt.Flood BOP and lines with water,perform body test to 3500 psi.Test BOPE,AOGCC rep Jim Regg waived witness on 4/9/15 @ 08:52 am.;Test upper and 1l lower 2 7/8"x 5"VBR,blind ram,upper and lower!BOP,FOSV,dart valve,mud cross valves,choke manifold valves to 250 psi low 5 min ea.3500 psi high 10 min J C ea.;Test annular to 250 psi low 5 min.2500 psi high 10 min.;Perform electric and manual choke press bleed test.Chart record all pressure tests.Choke manifold valve#1 failed initial test, rebuild valve,retested ok.Perform accumulator drawdown test.;R/D test equipment.Note:Total safety bump tested gas alarms on 4/7/2015.;Install 10 1/8"ID wear bushing.Close blind ram,test 10 3/4"casing to 2600 psi for 30 min.1.47 bbls pumped,5 psi pressure bleed in 30 min.Good test, ,{ bleed off pressure,open blind ram.;Blow down choke manifold,gas buster and top drive.;Move HWDP from ODS to DS of derrick.Drift and P/U 4 1/2"Drill pipe for intermediate section and rack in derrick.TIN to 1200',POH racking back 20 stds at a time.(180 stds jts total);;Hauled 145 bbls cuttings to KGF for total of 675 bbls, Hauled 560 bbls class II junk fluid to KGF for total of 1505 bbls. i ! 4/11/2015 Continue to drift,P/U,TIH with 4 1/2"drill pipe and rack in derrick.160 jts total.;Clean rig floor,load tools to pipeshed and rig floor.;M/U directional BHA#2,9 7/8" MM65 PDC bit,1.50 deg mud motor,TFO=313.58°.smart tools,download MWD,install RA sources and shallow test(OK).MU NMDC with corrosion ring in top.;TIH with jars and HWDP,BHA=786.54',continue to TIH to 1000'.;PJSM.Hang blocks,String new drilling line.Reset and test crown-o-matic.;Single in the hole 20 jts(180 total)from 1000'to 1405',M/U 1 std and top drive.;Break circulation,pump 458 gpm,40 rpm,tag cement @ 1426',slow pumps and circulate out clabered mud.P/U 57K,S/O 52K,ROT 54K,off bttm torq 6000 ft/lbs'gill ramant frnm 149x'ta00in0 plug nn rtapth®l4'5(' Drill FE exiting FC @ 1439',drill out shoe track,tag shoe on depth,drill shoe from 1422'to 1423';Use remaining 8.9 ppg spud mud to drill FE and cement.;;Hauled 40 bbls cuttings to KGF for total of 715 bbls,Hauled 140 bbls class II junk fluid to KGF for total of 1645 bbls. 4/12/2015 Drill 10 3/4"shoe track,cmt F/1523'-T/1530'MD. 456 gpm,1216 psi,40%F/O,40 rpm,5.6k tq on,3.3k tq off,2.6k-3.4k wob.;Drill new hole F/1530'-T/1550' k// MD. 456 gpm,1260 psi,40%F/O,40 rpm,6k tq on,3.3k tq off,3k wob,0 bgg,57k up,55k dn,56k rot. Displace 9.0 ppg spud mud w/9.2 KCUPolymer mud.;Circulate and condition mud. 9.2 ppg,46 vis. Pump @ 455 gpm,1100 psi,40%F/O. Flowcheck(static).;R/U and perform FIT test. Psi up to 225 psi shut in hold w/psi stabilizing @ 200 psi. FIT w/9 2 MW,FIT=12.0 ppq EMW.;Drtg F/1550'-T/2442'MD. 493 gpm,1250 psi off,1340 psi on,42%F/O,80 rpm,6.5k tq 1 on,3k tq off,3-7k wob,5 bgg,68k up,64k dn,66k rot.;Pump 20 bbls hi vis sweep @ 2152'w/40%increase in cuttings(mostly silt/sand. No coal �I% observed).;Drilling from 2442'to 3207'pumping 490 gpm,1370 psi.WOB 3-7k,80 rpm,torq 7100 ft/lbs.Average ROP 118 fph.P/U 81K,S/O 74K,ROT 76K.torq `tik off 6200 ft/lbs.;Pump 20 bbls hi vis sweep @ 2524',sweep back on time w/30%increase in cuttings,mostly sand,siltstone and some clay.MW 9.2 ppg,vis 55, ECD 9.54 ppg.BGG 4u No losses.;Cleanup wellbore,Pump hi vis sweep around,sweep back on time with 40%increase in sandstone,siltstone and sand w/trace of coal.Flow check well,no flow;Pulling on elevators,wiper trip from 3207'to inside 10 3/4"casing shoe @ 1472'with no issues.On trip out displacement took 4 bbls over calculated.;Service draworks,top drive,crown and brake Iinkage.;TIH from 1472'to 3147'with no issues,safety ream last stand.2'of fill;Drilling from 3207'to 3307'pumping 487 gpm,1391 psi.3-5k WOB.80 rpm,torq 7000 ft lbs.ECD 9.45 ppg.MW 9.1 ppg,vis 55.BGG 60u.No Iosses;Pump 20 bbl hi vis sweep @ 3225',sweep back on time with 60%increase in sand and siltstone with some clay .68 slide hrs,8.69 rotate hrs.6.68'above the line,1.42'left of the Iine.;;Hauled 165 bbls cuttings to KGF for total of 880 bbls,Hauled 664 bbls class II junk fluid to KGF for total of 2309 bbls. 4/13/2015 Drillina 9 7/8"hole from 3307'to 4058'MD Pump @ 474 gpm,1480 psi on,40%F/O,88 diff psi,80 rpm,8k tq on,6.1k tq off,4-7k wob. Observed 35 bbl loss @ 3765'MD w/sustained losses 40 bph;Condition hole @ 4058'MD due to losses(60-70 BPH). Increase H2O @ 40 BPH w/inc to 30 ppb Icm background. Once losses stabilized 30 bph,continue drilling ahead at reduced rate-100 ft/hr Max;Continue drilling ahead @ reduced rate F/4058-T/4190'MD.Losses increased to 70 BPH @ 4120'MD. Pump @ 444 gpm,1250 psi on,20%flow meter,70 diff psi,80 rpm,8k tq on,6.1k tq off;Circulate and condition hole to heal losses. Losses cont @ 70 BPH. Spot 20 bbl Icm pill @ 4190'MD. Flowcheck(24 bph losses).;Pull wiper trip.Pump and backream from 4190'to 3014'due to swabbing issues.;Build 20 bbl sweep consisting of 12 ppb walnut and 20 gallons of condet to clean bit and BHA.Pump at 445 gpm,1145 psi,with sweep at bit rotate 80 ��/ t4 rpm.;Flowcheck to verify no swabbing or surging when moving pipe.Static loss rate at 18 bph.;TIH from 3014'to 3630'with very little displacement white easing in YJ( the hole.;Attempt to circulate,shakers would not handle returns at min rate,screen down shaker from 140#to 120#and 80 mesh screens.Pump 306 gpm,614 psi shearing out new mud.;increase pump rate to 356 gpm,752 psi.CBU and continue to shear new mud.Final rate 445 gpm,1080 psi.9 bbls loss while circulating. Flowcheck well,static.;TIH from 3660'to 4135,M/U top drive wash last stand to bttm with no losses.;Drill from 4190'to 4259'pumping 442 gpm,1186 psi.2-4k wob,80 rpm,torq 7200 ft/lbs.P/U 95K,S/O 80K,ROT 89K.MW 9.1 ppg,vis 50,ECD 9.49 ppg.Losses at 12 bph.;3.05 slide hrs,5.41 rotate hrs.0.95'below the line,1.38'left of the line.;;Losses to the well in the last 24 hrs=880 bbls 9.2 ppg drilling mud Hauled 100 bbls cuttings to KGF for total of 980 bbls,Hauled 385 bbls class II junk fluid to KGF for total of 2694 bbls. 4/14/2015 Cont drilling 9 7/8"hole from 4259'to 4879',rotating wob 6K,452 gpm-1446 psi,80 rpm-8100 ft/lbs on bolt torque,46 to 100 ft/hr ROP.Sliding wob 2K,454 gpm- 1368 psi,114 psi diff,27 ft/hr ROP,;MW 9.3/vis 57,ECD 9.5 ppg,BGG 28 to 73 units,20 to 30 bph loss rate while drilling,30 ppb background LCM in system. Received 60 jnts 7 5/8"casing.;Cont drilling from 4879'to 5189'pumping 452 gpm,1624 psi.WOB 6k,75 rpm,torq 8800 fifths,P/U 112K,S/O 90K,ROT 102K, torq off 7700 ft/lbs.ECD 9.64 ppg,MW 9.3 ppg,vis 58.40 bph losses.;CBU,pump survey.Spot 20 bbls hi vis walnut,40 ppb LCM pill out of bit.;Pull wiper trip from 5189',pull 5 stds,5 min flowcheck @ 4860'.Static loss rate @ 6 bph.POH to 4000'with no overpulls.14.8 bbls over calculated displacement.;TIH from 4000'to 5127'.M/U top drive,safety ream final stand.4.4 bbl less calculated displacement on trip back in.;Cont drilling from 5189'to 5412'pumping 452 gpm,1732 psi.wob 6k,slide wob 2k.Diff 133 psi.75 rpm,torq 9200 ft/lbs.P/U 117K,S/O 90K,ROT 105K,torq off 7500 ft/Ibs.;Average ROP 77 fph.MW 9.3+ppg,58 vis.ECD 9.69 ppg.BGG 54-160u.Losses continue 40-50 bph,maintain 30 ppb background LCM.;Pump hi vis nut plug sweep @ 5211',sweep back 200 stks late with 60% increase consisting of 70%sand,20%siltstone,10%coal.;2.41 slide hrs,12.56 rotate hrs.2.81'above the line,2.60'right of the line.;;Losses to the well in the last 24 hrs=980 bbls,total=1800 bbls drlg mud. Hauled 50 bbls cuttings to KGF for total of 1030 bbls,Hauled 190 bbls class II junk fluid to KGF for total of 2694 bbls 4/15/2015 Cont drilling 9 7/8"hole from 5412'to 5902',rotating wob 6 to 12K,451 gpm-1614 psi,80 rpm-8700 ftAbs on bolt torque,12 to 97 ft/hr ROP.Sliding wob 5K,447 gpm-1617 psi,90 to 120 psi diff,;25 to 40 ft/hr ROP.MW 9.3 ppg/vis 58,ECD's 9.7 ppg.BGG 60 to 90 units,connection gas 400 to 700 units.Loss rate at 47 bph first 8 hrs,then reduced to 29 bph.Background LCM at 30 ppb.;Loss rate at 47 bph f/5412'to 5762',reduced to 25 bph f/5762'to 5834',then to 8 bph from 5834'. Increased pump rate to 475 gpm and reduced background LCM to 20 ppb at 5834'.;Cont drilling 9 7/8"hole from 5902'to 6181'pumping 469 gpm,1895 psi.WOB 5-7K,75 rpm,10500 fUlbs P/U 128K,S/O 104K,ROT 118K.Torq off 7500 ft/lbs.ECD 9.73,MW 9.4 ppg,vis 57.;Average ROP 50 fph.BGG 57u.Loss rate currently at 16 bph,maintain 30 ppb background LCM. 2.53 slide hrs,12.78 rotate hrs.5.15'above the line,1'right of the line.;Pump 20 bbl hi vis nut plug sweep with condet to cleanup wellbore.Sweep back on time with 25%increase consisting of 80%siltstone,10%clay,10%sand.;Wiper to 10 3/4"shoe.POH on elevators f/6181'to 5860',5 min flowcheck,static loss rate 3 bph. cont POH f/5860'to 5311'with 20k overpulls @ 5424',5392',5362',unable to cont on elevators.;Pump out due to swabbing from 5311'to 5280'with 30k overpull @ 5280,backream tight hole from 5280'to 5100',pump out from 5100'to 4750',able to pull on elevators from 4750'to 2200'.;Note:while pulling on elevators, displacement 2 bbls over calculated on every 5 stds pulled from 4750';;Losses to the well in the last 24 hrs=580 bbls,total=2380 bbls Brig mud. Hauled 80 bbls cuttings to KGF for total of 1110 bbls,Hauled 240 bbls class II junk fluid to KGF for total of 3124 bbls 4/16/2015 Continue POH from 2200'to 10 3/4"casing shoe @ 1524'and stopped at 1468'.Calculated hole fill 30 bbls,actual hole fill 50 bbls for entire trip.;Service rig and topdrive while monitor well for losses.Well static.;TIH on elevators from 1468'to 5310'with no issues,but encountered tight hole at 5310'.;Washed and reamed to bottom from 5310'to 6179'Made numerous attempts to trip on elevators but tight hole each stand.Pumped at 208 gpm,rotated at 40 rpm-7200 ft/bs off bolt torque.No fill.;Resume directional drilling 9 7/8"hole from 6181'to 6429',sliding wob 2 to 5K,451 gpm-1603 psi,70 to 120 psi diff,6 to 30 ft/hr ROP.Rotating wob 5K,451 gpm-1828 psi,80 rpm-10,000 ft/lbs on;bott torq,95 ft/hr,MW 9.5 ppgNis 58,ECD's at 9.7 ppg,BGG 20 to 45 units,connection gas 200 units.Had a site visit by HSE Reps Matt Hogge and Carl Jones with no issues,did not tour the rig.;Cont drilling 9 7/8"hole from 6429'to 6584'pumping 480 gpm,1745 psi.WOB 4- 7k,sliding 2-6k,80 rpm,torq 10k ft/lbs.P/U 132K,S/O 103K,ROT 118K,torq off 8800 ftAbs.;Diff 160 psi.ECD 9.81,MW 9.5 ppg,vis 51.No Iosses.;Cont drilling from 6584'to 6690'pumping 481 gpm,1750 psi.slide wob 2-4k,wob 5-7k.80 rpm,torq 10500 ft/lbs.P/U 138K,S/O 105K,ROT 120K.ECD 9.69,MW 9.4 ppg,vis 54.No losses.;Average rop 38 fph.BGG 26u.9.01 slide hrs,4,24 rotate hrs. 4.47'below the line,0.55'left of the line.;;Losses to the well in the last 24 hrs=52 bbls,total=2432 bbls Brig mud. Hauled 80 bbls cuttings to KGF for total of 1190 bbls,Hauled 235 bbls class II junk fluid to KGF for total of 3359 bbls • • 4/17/2015 Cont drilling 9 7/8"hole from 6690'to 7142',Sliding wob 4K,500 gpm-1962 psi,40 to 300 psi diff,10 to 50 ft/hr ROP.Rotating wob 6K,500 gpm-1993 psi,45 to 80 rpm-10,000 to 10,800 ft/lbs on;bott torque.MW 9.4 ppg/vis 51,ECD's at 9.7 ppg.BGG 30 to 179 units,connection gas 400 units.Pumped a sweep at 6747'with maybe 10%increase in cuttings at shakers.Added two drums lube at 6870';for sliding which greatly reduced stick/slip and motor stalling.;Cont drilling 9 7/8"hole from 7142'to 7174',pumped a 20 bbl hi-vis nutplug sweep at 7165'while rotating last of stand down,in prep for wiper trip.;Cont circ sweep out of hole,502 gpm- 1896 psi,45 rpm-9285 ft lbs off bott torque,BGG 27 units.Sweep back on time w/30%increase consisting of 90%sand and 10%coal.Flowcheck well,static.;Pull wiper on elevators from 7174'to 5500'with numerous 30k overpulls on every stand to 5850',work ea.full stand-then pulling easily.POH from 5850'to 5500'with no futher issues.;7.4 bbls over calculated displacement on trip out.;M/U top drive,circulate and rotate pipe.Service drawworks,blocks,crown and washpipe.;TIH from 5500',safety ream last stand.No issues on trip back in the hole.No fill.4 bbls over calculated displacement on trip back in the hole;Shakers loaded up with sand and some coal.,circulate until shakers can handle full rate @ 504 gpm;Continue drilling from 7174'to 7336'pumping 504 gpm,2150 psi.diff 50-90 psi.Slide wob 2- 5k.WOB 6-8k,80 rpm,torq 11700 ft/lbs.P/U 147K,5/O 117K,ROT 127K.Torq off 9500 fUlbs.;ECD 9.68,MW 9.4 ppg vis 50,BGG 88u.No losses.Pump 20 bbl hi vis sweep with walnut and condet @ 7210',sweep back on time,25%increase consisting of 80%siltstone,20%sand.;Average rop 46 fph.9.08 slide hrs,4.94 rotate hrs.5.70'below the line and 0.15'left of the line.;;No losses to the well in the last 24 hrs,total losses=2432 bbls drlg mud. Hauled 90 bbls cuttings to KGF for total of 1280 bbls,Hauled 265 bbls class II junk fluid to KGF for total of 3624 bbls 4/18/2015 Cont directional drilling 9 7/8"hole from 7336'to 7648'.Sliding wob 6 to 13K,507 gpm-1840 psi,130 psi diff,10 to 40 ft/hr ROP.Rotating wob 4 to 10K,504 gpm- 2166 psi,80 rpm-10,800 ft/lbs;on bolt torque,77 to 98 ft/hr ROP.MW 9.5 ppgNis 48,ECD's at 9.7 ppg.BGG 37 units,connection gas 450 units.Still sliding majority of the time.;Cont directional drilling 9 7/8"hole from 7648'to 7826'pumping 501 gpm,2239 psi.Slide wob 2-3k,wob 6-7k,80 rpm,torq 11600 ft/lbs.P/U 160K,S/O 125K,ROT 138K.ECD 9.63,MW 9.4 ppg,vis 49.;Cont directional drilling from 7826'to 7883'pumping 500 gpm,2038 psi.Diff 60 psi,slide wob 2-5k. WOB 7k,80 rpm,torq 11400 ft/lbs.P/U 162K,S/O 125K,ROT 141K.torq off 9800 ft/Ibs.;ECD 9.68,MW 9.4 ppg.BGG 19u,No losses.;Mud pump#2 engine fuel valve feeding day fuel tank was in the closed position causing MP 2 engine to run out of fuel.Work pipe and circulate using#1 MP until#2 MP up and running.;Cont `l drilling from 7883'to 8028'(81 intermediate section TD in 90%siltstone,10%coal formation pumping 500 gpm,2150 psi.5-7k wob,80 rpm,torq 12000 ftilbs.;ECD 9.7,MW 9.49 ppg,vis 48.Average ROP 39 fph.No losses.Load 20 bbl hi vis sweep with walnut and condet in drill pipe.;11.55 slide hrs.5.97 rotate hrs.3.47'below / i the line,1.27'right of the line.;;No losses to the well in the last 24 hrs,total losses=2432 bbls drlg mud. Hauled 100 bbls cuttings to KGF for total of 1380 bbls,Hauled 380 bbls class II junk fluid to KGF for total of 4004 bbls 4/19/2015 Circulate 20 bbl hi vis sweep around at 8028'(TD),500 gpm-1970 psi,80 rpm-9800 fUlbs off bott torque,had a max of 2786 units gas.Flow check(well static).Up wt 168K.;POOH from 8028'to 6995'on elevators,pump up hole from 6995'to 6930',POOH on elevators from 6930'to 5436',pump up hole from 5436'to 5040', then POOH on elevators to 1439'(inside casing).;Service rig and topdrive,Halliburton Rep repaired centrifuge.;TIH from 1439'to 7057'setting down 5k,attempt to work thru,wash passed 7057'easily,TIH from 7057'to 7637'setting down 10k,wash and ream from 7637'to 7854',;making several attempts to trip on elevators, TIH on elevators from 7854'setting down 5k©7909',wash and ream from 7909'to bottom @ 8028',tag 6'of fill.;Circulate at lower rate until shakers can handle fluid pumping 274 gpm,800 psi,at BU gas peaked @ 9522u,MW in 9.65 ppg,gas cut MW out 8.7 ppg,make 1 full circulation,;gas leveled off at 7550u,Increase MW from 9.65 ppg to 9.9 ppg with barite.Pump 400 gpm,1050 psi after 1st circulation.MW 9.9 ppg in/out with gas leveling out @ 120u.;continue pumping 2nd circulation increasing rate to 460 gpm,1600 psi.(Reciprocate and rotate pipe while circulating)Final BGG 38u.MW 9.9 ppg in/out.ECD 10.05,no losses.;lncrease sweep MW from 9.65 ppg to 9.9 ppg.Pump 40 bbl hi vis sweep with walnut and condet @ 500 gpm,1650 psi,reciprocate and rotate pipe 90 rpm,sweep back on time,;10%increase consisting of 90%coal and 10%siltstone.Get new SPR,flowcheck well,static.;POH on elevators from 8028'to 7295',found wash out 8"below tool joint on stand#13,jt#209 in the string,UD washed jt.continue POH from 7264'to 6024';w/10-15k overpulls from 6980'to 6940',work thru tight spot,passing back thru,clean on 2nd pass.;;No losses to the well in the last 24 hrs,total losses=2432 bbls drig mud. Hauled 65 bbls cuttings to KGF for total of 1445 bbls,Hauled 255 bbls class II junk fluid to KGF for total of 4259 bbls 4/20/2015 Cont POH from 6024'to HWDP at at 786'.Flow check=static.Rack back HWDP and jars,PJSM and remove RA sources.Plug in and upload MWD.Cont POOH LD remaining BHA components.;9 7/8"PDC graded at 1-3-CT-G-X-I-LM-TD and had''/."movement in motor shaft.Calculated hole fill 52 bbls,actual hole fill 83 bbls,fluid in wellbore drops very slowly.SLB loggers on location.;Clear and clean rig floor.Hole taking+/-2 bph.;Held PJSM with Schlumberger logging crew and rig c"" crew.RU sheaves and MU RFT tool assembly.Max OD of tool 5.430".Tool length 31.00'.No lubricator.Handheld cable cutter staged in dog house.;RIH with RFT 11.'? assembly on e-line.Take pressure samples from 3750'to 7855'with no issues.(65 pressure samples total). Monitor well,well taking 2 bph while logging.;POH with logging tools from 7855',UD logging tools.R/D e-line.;;Hauled 9 bbls cuttings to KGF for total of 1454 bbls, Hauled 45 bbls class II junk fluid to KGF for total of 4304 bbls 4/21/2015 RD and release SLB logging crew and equipment.;MU 9 7/8"cleanout BHA(#3)as follows:MM65 PDC bit(re-run)jetted w/6 x 13's,bit sub,9.625"stabilizer,two NM flex DC's,XO,4 jnts HWDP,XO,jars,XO,15 jnts HWDP.;TIH on 4 1/2"CDS-40 DP from 692'to 1496'(just above surface shoe).;MU topdrive and fill pipe/CBU one time at 4 bpm-257 psi.;Cut and slip 128'drill line,re-calibrate Rig Smart system.;TIH on elevators from 1496'to 3667'and encountered tight hole. Washed and reamed to 3727',TIH to 3916',washed and reamed to 3975'.;CBU one time at 427 gpm-1167 psi,80 rpm-7900 ft/lbs off bolt torque.Max 31 units gas at bottoms up.;Cont TIH to 5670',washed and reamed to 5710',TIH to 6520';MU topdrive,fill pipe and CBU one time at 480 gpm-1422 psi,80 rpm-8323 ft/lbs off bolt torque.Max 266 units gas at bottoms up.;Cont TIH to 6580',washed and reamed to 6642',6670'to 6704',6816'to 6828',6872'to 6957',7475'to 7400',7500' to 7516',7641'to 7699',7950 to 8028'with no detectable fill on bottom.;CBU one time at 485 gpm-1540 psi.Pumped 20 bbl hi-vis sweep around to clean hole.Had a max of 4920 units trip gas at bottoms up followed by 4829 units.Gas down to 70 units at end of circ.;POOH on elevators from 8,028'to 3,015'with an occasional 15K over pull;;Hauled 0 bbls cuttings to KGF for total of 1454 bbls,Hauled 0 bbls class II junk fluid to KGF for total of 4304 bbls 4/22/2015 Cont POOH with 9 7/8"cleanout assembly on elevators,from 3015'to HWDP at 692'.Rack back HWDP,LD jars,XO's,NM flex DC's,bit sub and MM65 PDC bit (re-run).Bit graded at 1-3.;Clean and clear rig floor,RU and pull wear ring,change upper rams to 7 5/8".install test nlrtgand test.joint,test upper rams at 250/3500 psi for 5 minutes,test annular at 250/2500 psi for 5;minutes on chart.RD test equipment.Weatherford on location.;Change to long bails on topdrive,RU Weatherford casing run equipment,stage centralizers,RU fill up line,dummy run hanger/landing joint,RKB=19'.;MU 7 5/8"shoe track,fill and check floats(ok), cont PU single in hole with 7 5/8"BTC L-80,29.7#intermediate casing to 1500'.Top fill on the fly,completely fill every 10 joints.;Just above surface shoe,at 1500', MU topdrive and CBU 1 time at 3 bpm-125 psi.No Iosses.;Cont PU single in hole from 1500'to 4065',cont top fill on the fly and completely filling string every 10 joints.;MU topdrive,CBU @ 3bpm 156 psi,605 strk into circ.we started losing returns,static lost rate at 31bph.;Continue RIH with 7 5/8"casing from 4065'to 4775',continually fill on the back side due to static lost of 30bph.40 bph while tripping.Reducing surface volume MW from 9.9 ppg to 9.7 ppg.;;Hauled 25 bbls cuttings to KGF for total of 1479 bbls,Hauled 55 bbls class II junk fluid to KGF for total of 4359 bbls • • 4/23/2015 Cont RIR slowly with 7 5/8"casing,from 4775'to 8012'.While tripping,blend 9.2 ppg mud into 9.9 ppg active system,for a 9.7 ppg.Cont building new volume.;At 5500'getting decent displacement,but by 6900'getting no returns.Fill backside every 5 joints,cont topfilling casing on the fly and completely fill every 10 joints.;MU La.. topdrive and circ swedge on landing joint,attempt to circ at 3 bpm with no returns.Fill backside through kill line,attempt to circ down casing and fluid dropping in / wellbore at 3 bpm.;Re-fill backside then pump at 5 bpm down casing,fluid static in wellbore,no returns with 24 bbls away.Notify Drilling Engineer,decision made to 1 td build volume and perform cement job.;Spot and start RU of SLB cementers,cont building 300 bbls surface volume at 10.0 ppg for displacement.Witness loading plugs in launcher,held PJSM with rig team and SLB cement crew.;lnstalled hardline to Baker cement head.SLB pumped 5 bbls water,tested lines at 2000 psi low and 4000 psi high.Tests good.Rig pumped 10 bbls 9.7 ppg mud followed with 45.5 bbls 10.3 ppg;MUDPUSH II%ppb Cemnet,at 3 bpm-286 psi.Shut down and L>� dropped bottom plug.Lined up SLB pump truck to well.SLB mixed and pumped on the fly 244 bbls(672sx)11 ppg LiteCRETE;lead cement with 1 ppb Cemnet,at 4 to 5 bpm,400 to 100 psi,followed with 29.5 bbls(150sx)15.8 ppg conventional tail cement with 1 ppb Cemnet,at 3 to 4 bpm,170 to 100 psi.Had no returns to;surface.Shut down and dropped top plug.SLB displaced with 10.0 ppg,6%KCL mud at 6 to 6.5 bpm.323 bbls into displacement we started getting slight returns to surface.With 10 bbls to go,;we landed the hanger(2'off seat)and slowed to 2 bpm.No longer getting returns,fluid static in wellbore.Plug did not bump 367 bbls into displacement(calculated at 364 bbls).;Held 447 psi(FCP 1100 psi)for 3 minutes,bled off to pump truck and floats held.Had 3/4 bbl flowback to truck.Fjad..no MudPush to surface.Had no cement to surface.Mix water temp 80 degrees.;Lost 328 throughout job(total pumped 696 bbls,total returns 1 bbl),did not reciprocate string.CIP at 17:40 on 4-23-15.RD and released SLB cementers.Estimated TOC 3765'(loss zone).;Back out landing joint,MU packoff assembly,install packoff. Total Safety on location and tested gas monitor equipment.Shipped out Intermediate directional tools.Test packoff/void at 250/5000 psi;for 30 minutes.Good test. C d J Return long wear bushing with wellhead Rep Clint Chanley.;Close blinds and change upper rams to 2 7/8"x 5"variables.Change out long bails.;P/u test jnt.and test d ✓' ,,✓ plug and install in well head.Rig up test equipment to the rig floor and do a full body test on the system.;Test BOP's;annular 2500/250 rams&valves 3500/250(per Saxon test time hold 10min high 5min low)test was waived by Jim Regg.;;Hauled 0 bbls cuttings to KGF for total of 1479 bbls,Hauled 45 bbls class II junk fluid to KGF for total of 4404 bbls Daily Loss to the hole 1191 bbl. 14- V Fi..iQ 4/24/2015 Blow down choke line and manifold.Install 9"ID wear ring,stage BHA components for PU.;MU Varel 6 3/4"V613PDUX PDC bit jetted with 6 x 10's,5"motor with //�� 1.5°bend,float sub,DM collar,Gamma collar,ADR collar.ALD collar,CTN collar,PWD tool,TM collar.Scribe,download MWD and;shallow pulse test(ok).Load RA sources.RFO 92.88 degrees.;MU one NM flex DC,XO,13 HWDP,jars and 13 more HWDP for a total BHA length of 982'.Cont TIH on DP from derrick to 2992'.Fill pipe.;Single in hole with DP from pipe shed,from 2992'to 4768'and fill pipe.;Cont TIH with DP from derrick,from 4768'to 7871'.;Circ one pipe vol.@ 3bpm 1460psi.;Rig up and test 7 5/8 casing to 3500 psi&hold for 30min.;Rig down testing equipment.;TIH one stand and tag cement @ 7869'(59'above float collar)engaged pumps easing rate up to 262 gpm-1570 psi,30/40 rpm and drilled cement down to top plug at 7887'(42'high).;Drilled into second plug at 7929'. Cont to drill float equip.and 20'new hole at 11K wob,260 gpm-1575 psi,30 rpm.Both plugs drilled fairly fast.;Circ a bottoms up to even out the mud weight.;Pull back to the shoe;rig up and perform a FIT 997psi =12.5 EMW(Actual 910 psi =12.3).;Resume drilling 6 3/4"hole from 8048'to 8067',wob 8K,264 gpm-1620 psi, 70 to 120 psi diff,50 ft/hr ROP.40 rpm-11,200 ft/lbs on.;;Hauled 0 bbls cuttings to KGF for total of 1479 bbls,Hauled 80 bbls class II junk fluid to KGF for total of 4484 bbls 4/25/2015 Cont Wlllina 6 3/4"hole from 8067'to 8646'.Sliding wob 5K,296 gpm-1944,90 to 160 psi diff,12 to 67 ft/hr ROP.Rotating wob 8K,297 gpm-2214 psi,85 rpm- 12,400 ft/lbs on bott torque,49 to 100;ft/hr ROP.MW 10.1 ppg/vis 43,ECD's at 10.9 ppg.BGG 170 to 300 units,connection gas 1726 to 9095 units.Pumped 20 bbl sweep at 8280'with 10%increase in cuttings to surface.;Cont drilling 6 3/4"hole from 8646'to 8984'Sliding wob 5K,296 gpm-2080psi,60 to 110 psi diff,20 to 30 ft/hr ROP.Rotating wob 8K,297 gpm-2214 psi,85 rpm-12,400 ft/lbs on bolt torque,30 to 100;ft/hr ROP.MW 10.3 ppg/vis 43,ECD's at 11.1 ppg.BGG 350 to 1600 units,connection gas 1700 to 8024 units.Pumped 20 bbl sweep at 8714'with 20%increase in cuttings to surface.;Circ hole clean.;Due to increasing gas;we will weight up to a 10.5 before the short trip.;;Hauled 40 bbls cuttings to KGF for total of 1519 bbls,Hauled 113 bbls class II junk fluid to KGF for total of 4597 bbls Distance to the plan 9.9/low .29/left 4/26/2015 Cont circ hole to 10.5 ppg mud at 282 gpm-1900 psi.With 10.5 in/out we have no flow,but still a heavy rolling boil in wellbore.;Cont drilling from 8984'to 9046'while bringing MW up from 10.5 to 10.7.Wth 10.7 ppg still have BGG of 1200 to 1300 units.Had a max of 9689 units gas after drilling through the KF_TY_86-2.;Drilled another stand down(reduced ROP)while increasing MW to 10.9 ppg.Rotating wob 3K,291 gpm-2142 psi,90 rpm-12,800 fUlbs on bolt torque,20 to 50 ft/hr ROP. BGG down to 70 units.;With MW of 10.9 ppg in/out,ECD's were at 11.8 ppg.Decision made to perform wiper trip to shoe at 8012'as we are half way to TD depth. SLB delivered 359 sx of lead cement into silo's.;CBU at 295 gpm-2273 psi,60 rpm-10,700 fl/lbs off bott torque,BGG at 64 units,ECD's reduced to 11.6 ppg. Obtained survey on bottom,checked for flow,no flow.;Pull up hole on elevators(up wt 200K)from 9107'to 8214'with little to no overpull,hole in good shape.At 8214'we had 25K overpull.Tried numerous times to clean up on elevators with no change.;MU topdrive and attempt to pump up through tight spot.Still pulling tight. Backream from 8214'to 8128'.After racking back one stand noticed flow had increased to 6 bph.Top of smart tools at shoe.;Started CBU prior to planned TIH due to flow.Flow show went from 31%(normal drill rate)to 63%in a matter of seconds,mud erupting through the table.Shut down pump,rotation and shut in well.;Driller sounded well control alarm.Shut in against upper rams and auto choke.Had 6 bbl gain in pits before well shut in.With 10.9 ppg,max allowable surface psi=558.Monitor SICP and SIDP.;In 40 minutes,SICP built and stablized at 336 psi,SIDP 0 psi(ported float in BHA).Began circ at 46 spm-135 gpm-720 psi through auto choke and poorboy degasser.Getting returns to shakers after;pumping 22 bbls,holding 276 psi on casing.10.9 ppg in/10.6 ppg out.Circulated one full circ at 8169'with 820 units gas at bottoms up at gas trap.Wth 10.9 in/out shut down pump and;checked for flow at poorboy degasser discharge.No flow.Opened rams and monitored well.No flow,but had a rolling boil in well bore.Cont to circ surface to surface pumping 11.1 ppg down DP.;Notified Drilling Manager,Drilling Engineers and Production personnel at time of closure,also notified Production when well was opened up and cont circulating.Wth 11.1 ppg in/out,shut down;and monitor well for flow.Initial rate 1.7 bph which slowed to 1/2 bph.;TIH on elevators from 8169'to 8587',no issues.Sent AOGCC notification of BOP use as per Industry Guidance Bulletin No.10-003.;At 8587',MU topdrive and stage circ rate up to 284 gpm-2080 psi to circ out any possible influx.20 rpm-10,700 ft/lbs off bott torque.Had a max of 3726 units gas at bottoms up.Flow check well,;no flow;Decision was made too trip to bottom on elevators,no hole problems during TIH f/8587'to 9082'@ 9082'encountered fill.;Washed to bottom easing rate up from 135gpm to 290gpm after reaching bottom we CBU @ 290gpm 2400psi 40 rpm (ECD 11.9)TQ 11.5k.;During the circ.observed max gas of 9200 units but diminished quickly to 920 units.;Cont drilling 6 3/4"hole from 9107'to 9163'. Rotating wob 9K,293 gpm-2380 psi off 2450 on 75 rpm-12,600 ft/lbs on bolt torque,25/100 ECD's 11.9.;Service mud saver on top drive.;Cont drilling 6 3/4"hole from 9163' to 9288'Sliding wob 2-5K,293 gpm-2240psi,75 psi diff,18 fph ROP.Rotating wob 6-9K,293 gpm-2340 psi,85 rpm-12,800 ft/Ibs on bolt torque,25/100;ft/hr ROP. MW 11.1 ppg/vis 53,ECD's at 11.9 ppg.BGG 75 to 140 units.;;Hauled 40 bbls cuttings to KGF for total of 1519 bbls,Hauled 120 bbls class II junk fluid to KGF for total of 4717 bbl Distance to the plan 2.2/low 2.72/left TRT=6.77 TST=.75 Total=7.52 4/27/2015 Cont directional drilling 6 3/4"hole from 9288'to 9801',sliding wob 5 to 6K,293 gpm-2479 psi,89 to 103 psi diff,20 ft/hr ROP.Rotating wob 6K,293 gpm-2673 psi, 75 rpm-13,200 ft/lbs on bott torq;25 to 100 ft/hr ROP.During connection at 9481'we had 1/2 bph flow.Cont drill ahead while increasing MW from 11.1 to 11.2 ppg.;Directional drilling 6 3/4"hole from 9801'to 10200' sliding wob 2 to 4K,292 gpm-2536 psi,65 psi diff,14 ft/hr ROP.Rotating wob 4 to 8K,293 gpm-2820 psi, 80 rpm-13,900 ft/Ibs on bott torq;25 to 100 ft/hr ROP. ECD's at 12.2 ppg.BGG 119 units,connection gas 170 units.Pumped 20 bbl sweep at 9895'with 15% increase in cuttings to surface.;Circ.hole clean @ TD.Pumped 20 bbl sweep at 10,200'.;;Hauled 85 bbls cuttings to KGF for total of 1644 bbls,Hauled 335 bbls class II junk fluid to KGF for total of 5052 bbl Distance to the plan 12.8Aow 5.41Aeft TRT=13.71 TST=3.61 Total=17.32 4/28/2015 Cont circ sweep out of hole at 276 gpm-2586 psi,80 rpm-13,000 ft/lbs off bolt torque.MW at 11.2 ppg,ECD's at 12.2 ppg.BGG 37 units.Had 10%increase in cuttings with sweep to surface.;Take survey on bottom at 10,200'(TD)then flow check.Have flow.Initial rate 3/4 bph initial slowed to 1/4 bph.Cont circ at 270 gpm- 2403 psi and increase MW from 11.2 to 11.4 ppg.;Flow check(static);POOH F/10200'to 8156'. 4.5 bbls over calculated displacement for trip.;Pulled 25k @ 8148' MD. Unable to work passed on elevators.Wash and ream f/8156 to 8,012'MD.Saw significant amounts of coal while backreaming thru tight spots(8148'-8068'). Max gas 9480 @ btms up.;Rig Svc.;CBU @ 8012'MD. 202 gpm,1375 psi,23%F/O,12.15 ECD. 2650 max gas.;Monitor well(static). Build 20 bbl 13.5 ppg,hi vis pill.;Spot 20 bbl 13.5ppg hi vis pill @ 8012'MD for mud cap.;POOH F/8012'-T/6380'monitor well.;Continue P.O.O.H 6,380'to 2,788'monitor well(resolve discrepancy on trip sheet)continue POOH to BHA.;BHA:Racked back HVVDP and NM Flex DC in the derrick;down link MWD;drain motor and break out the bit.;PJSM;Rig up and run Cement Bond Log for intermediate section;;Hauled 20 bbls cuttings to KGF for total of 1664 bbls,Hauled 135 bbls class II junk fluid to KGF for total of 5187 bbl !^� Distance to the plan 12.8Aow 5.41/left -7 -57 • • 4/29/2015 Rig up Halliburton E-line CBL logging tools w/lubricator. Log F/8000'-T/1500'w/GR-Radial CBL. Logs showed TOC @ 3670'MD. R/D Halliburton.;Well showed no gain during logging operations but did doserve minor to moaerate gas breaking out of fluid in stack. Continue to monitor well closely during all operations w/no gains.;Remove wear bushing and RN BOP test equipment.Set test plug.Test upper pipe w/4 1/2",250 low-3500 high.PT super choke and manual choke (test good).Remove test plug.Set wear bushing;M/U 6 3/4"cleanout assy(BHA#5)as per DD. Re-run Varel V613PDUX PDC. Ported float installed in bit sub.;RIH F/873'-T/3718', Filling pipe 25 stnd.;Circ.bottoms up @ 3718'135 gpm 420 psi max gas observed 360 units.;Continue RIH F/3,718-T/6,207'filling every 25 stands.;Circ.bottoms up @ 6,207'135 gpm 560 psi max gas see 520 units(resolve discrepancy on trip sheet).;Continue RIH F/6,207'-T/7,890'filling every 25 stands.;Circ.bottoms up @ 7,890'135 gpm 620 psi max gas see 1075 units.;Slip&Cut 115'of drilling Iine.;Continued RIH encountered tight spot and worked through without pumping on it @ 8890'Driller took the time to work the tight spot without surging.;We continued into the hole to 9112',all though there was no flow a decision was made to CBU to ensure that them was no gas in the hole.;At 1060 strk in to the circulation,we encountered a decrease in pump pressure and an increase in flow at that time the Driller shut down pump then shut in well;while sounding the well control horn.Actions Taken:Monitored SICP and SIDP,lined up and circulated one full circ.through the choke,Beginning pressure 675 psi.;ending SPP 643 psi.After one full circ @ slow pump rate,(135 gpm)checked for flow and had no flow.;Tripping in the hole @ 9334'.;;Hauled 20 bbls cuttings to KGF for total of 1664 bbls,Hauled 135 bbls class II junk fluid to KGF for total of 5187 bbl. 4/30/2015 Wash and Ream F/9334'-T/10,200'MD due to significant tight spots while attempting to trip in on elevators.135 gpm,803 psi,16%flow,40 rpm,12.4k tq.;Circulate and condition mud @ 10,200'MD. 250 gpm,1480 psi,27%flow,65 bgg,40 rpm,12.8k tq. Tagged up on 11'fill,washed down last stand. 11.45 mw in/out.;Monitor well(static). POOH F/10,200'-T/8,008'MD. 240k up,130k dn. Pulled 10-20k over pulling off bottom for first 240'then pulled clean to shoe. 1.5 bbls over calculated for trip.;Circulate and condition mud @ 8008'MD. Pump @ 135 gpm,463 psi,17%flow. Had 8800 units bgg on Pason after 1 1/2 btms up. Found gas trap line to be gas saturated and giving inaccurate readings.;Replaced line from gas trap,bgg went from 8800 units to 1680 units.;Monitor well(static). Pump slug. MN and drop drill pipe ID wiper(mud dog). POOH F/8,008'-T/BHA laying down drill pipe. Trip took 3 bbls over calculated.;Monitor well for 30 min. (NO Flow).;TIH with 3100'+/-of the drill pipe standing in the derrick.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 160 bbls class II junk fluid to KGF for total of 5422 bbl. 5/1/2015 Monitor well @ 3108'MD. Observed moderate gas bubbles breaking out @ surface. Attempt to circulate out gas @ 3108'MD but plugged string with ID drill pipe wiper.;Attempt to float drill pipe wiper to surface as designed. No success. Wait on wireline fishing(Pollard). Continue monitoring gas breaking out @ surface but no gain.;Wreline on location @ 10:30. R/U wireline w/1 1/2"assy on.125"wire. Run as follows:3/4""O"bannon(overshot),bait sub,RB tool,knuckle jt,jars,oil jars,knuckle jt,15'x 1 1/2"stem.;Run in hole w/wireline assy. Tag TOF @ 3081'MD. Work jars and overshot several times,P/U w/no wt increase.Retry w/ same results(4x). POOH w/wireline-Retrieved fish(drill pipe wiper);Circulate and condition mud @ 3108'MD. Wt up from 11.5 ppg to 13 ppg. 135 gpm,285 psi, 19%flow,BGG before wt up 1360,after wt up 1180 units. Gas @ surface calmed down.;Monitor well(gas breaking out but no flow). POOH F/3108'-T/surface. L/D all drill pipe and BHA assy.;R/U test equipment and test upper pipe rams and all valves used in the closure of the BOP's 250/3500;R/D test equipment;PJSM G S y rig up casing/R/U casing:Hold a PJSM on the casing run and discuss having heightened awareness on well control.;Make up and test float equipment(Good)RIH with 5"production casing. 5/2/2015 Continue running 5",18#,L-80,DWC/C-HT production casing F/1300'-T/3098'MD. -3 BBLs for trip.11 k tq on connections.;Power tongs would not shift into low side. L/D and replace with backups.;Continue running 5"as per detail Fl 3098'-T/5058'MD.;Circulate btm's up @ 5,058'MD. 135 gpm,195 psi,19%flow. 440 units BGG.;Continue running 5"as per detail F/5058'to 7823'MD.;Circulate btm's up @ 7823'MD. 135 gpm,416 psi,19%flow. 1400 units BGG.Max 8565 units.;Continue running 5"as per detail Ff7823'T/10,183'(No Problems). Make up landing jnt.&hanger. Land 5"casing on depth,R/D casing equipment.;Make up TD and break circ.@ 135 gpm 660 psi.easing rate up to 252 gpm 1005 psi.max gas 4850 units during circ.;R/U cement head and attempt to circulate.,but xo between the landing jnt.and cement head Ieaked.;Hold PJSM;Test lines 500/4000;Batch mix cement.;Pumped 22 bbl.of 13.0 Mud Push,Bottom plug was dropped follow by 44 bbls of 15.3 lead&82.5 bbls of tail cement,displaced cement with 52bbls 6%KCL;water;casing pressured up to 3500psi when the love„plug landed. After talking over with the cementers it was obvious the plug did not burst.;;FfauledLIbbls cuttings to Rr,3- s class II junk fluid to KGF for total of 5557 bbl. 5/3/2015 Attempt to rupture bottom plug and re-establish circulation. Install packoff,close blind rams and repeatedly psi up to 4800 psi then bleed off every 4-5 min. Monitor 2jt0'~ for returns thru annulus.;No success. R/D SLB cementers and release.;Wait on tools. Unload,strap and tally tools upon arrival. Clean pits and prep for upcoming C cleanout run. Bring tools to rig floor.;R/U weatherford casing. Run lines and power up unit. Hang double stack power tongs,R/U elevators. Bring handling tools to rig floor w/lift nubbins.;Attempt to set TWC to test. Unable to engage top of hanger w/TWC(troubleshoot after cleanout). M/U xo blank off sub to test jt,RIH and /11 MN to top of hanger. Test upper 2 7/8”x 5"VBR's 250/3500;Annular 250/2500. Chart and record same.;Adjust down make up torque to 3500/4000 on top drive t X for the 2 7/8"work string.;Make up 2 7/8"clean out BHA;Single in the hole with 2 7/8"work string to 3250'.;CBU @3250'110 GPM 975 psi.(No Rotation);RIH from _ 3250'MD and tagged top cement plug(fl)3740':set down 5/7k on top of the plug;Wash through cement from 3470'to 3960'@ 110 gpm 10 rpm 1010 psi Diff. c 50/70psi.(Cement has not set up,as we push down on the plug the green cement;washes by the the fins of the plug).;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 350 bbls class II junk fluid to KGF for total of 5907 bbl. 5/4/2015 Wash and ream w/4-1/8"cleanout assy F/4000'-T/4589'MD. Green cement w/no significant tags. Wash down @ 110 gpm,1150 psi(70-80 diff). Overboard retums while washing down.;Tagged up @ 4589'w/2-3k wob,110 gpm,1233 spp,70 diff psi,12%flow. Observed small amounts of black rubber @ shakers, indicating drilling top plug @ 4589'MD.;Svc rig. Change out swivel packing,grease blocks,top drive and drawworks.;Continue drilling cement F/4589'-T/5362'. 110 gpm 1350 psi.0 rot. p/u 60k ski 52k Diff 1001150.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 1305 bbls class II junk fluid to KGF for total of le,Y a 7212 bbl. V 5/5/2015 Continue drilling cement F/5362'-T/5525'MD. 3k wob,112 gpm,1350 psi w/180 diff.;Change out cross over from top drive to 2 7/8"worlcstring due to leaking @ connection.;Continue drilling cement F/5525'-T/5578'MD. 3k wob,112 gpm,1350 psi w/180 diff. ROP continued to diminish to 23 ft/hr prior to trip.;POOH F/ 5578'-T/2740',flowcheck well,gas breaking out at surface.I/A 1000 psi.;Troubleshoot gas migration,drain stack,gas leaking passed production hanger packoff seals.Close upper pipe rams,pressure to 1200 psi.Tighten lockdown scews per Cameron rep.;Bleed off pressure thru choke,open pipe rams,well static,no gas breaking at surface.Continue to monitor I/A,remains at 1000 psi.;POOH F/2740'-T/surface. LJD 3.88 mtr and 4 1/8"3 blade mill. Grade=1,2,Wf,GR,X,I,CT- PJ,PR.;Make up new motor w/4 1/8"6 blade mill.;Service blocks,crown,washpipe and top drive.;TIH with cleanout BHA#7,fill pipe @ 3000'.TIH to 4550'.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 320 bbls class II junk fluid to KGF for total of 7532 bbl. 5/6/2015 TIH with 4 1/8"cleanout assy F/4550'-T/5578'MD.;R/D floor from trip w/power tongs and R/U HT-35 rig tongs for drilling operations. L/D lift nubbins box.;Drilling cement F/5578'-T/5624'MD. 120 gpm,1290 psi off,120 diff,1-3k WOB.;POOH F/5624'-T/surface. C/O 4 1/8"6 blade mill to 4 1/8"Varel L2(SN#1419466). IA 1290 psi @ 15:00.Blow down choke manifold,drain gas buster.;TIH with cleanout BHA#8,fill pipe @ 2500'and 5530',wash last jt from 5589'to 5624'.;Drilling cement F/5624'-T/5965'MD. 112 gpm,1440 psi off,180 diff,3-6k WOB. 50 ft/hr avg ROP.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 209 bbls class II junk fluid to KGF for total of 7741 bbl. 5/7/2015 Drill cement F/5965'-T/6311'MD. 106 gpm(424 rev/min),1280 psi off,180 diff,12%flow,1-3K WOB. 305,280 total revs on bit. LD 2 jts due to bad connections. Dressed#2 MP w/4"liners.;Troubleshoot fwd/rev top drive switch on drillers console. CIO circuit board in top drive house.;Swap to#2 MP(4"liners). Drill cement F/6,311'-T/6,462',85 gpm(340 rev/min),890 psi off,180 diff,10%flow,1-3K wob.Total Safety calibrated and bump tested alarms 10/20 H2S,20/40 LEL;POOH for bit due to bit hours.POH F/6462'to surface,inspect mud motor,Close blind ram.L/D bit,grade=3/4/CD/S,2,3/F/1/16"/ER,WT,NR/ TQ.;RN test equipment,test blind ram to 250 psi low for 10 min and 3500 psi high for 5 min charted,R/D test equipment.I/A 800 psi.;M/U new 4 1/8"L-2 mill tooth bit,serial#1361917,open blind ram.TIH to 6026' filling pipe @ 2500'and 5000'.;Fill pipe,R/U test equipment with 2 7/8"test jt.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 303 bbls class II junk fluid to KGF for total of 8044 bbls. 5/8/2015 RN test equipment and purge air from lines and choke manifold with water.;Service rig;Attempt to test upper pipe. Failed test. Work pipe rams and re-test(fail). Pull test jt and found residual cement on test jt. Drain stack. Found residual cement inside stack.;Open gates on stack and wash residual cement from rams and gates. Work annular and flush. Service doors,rams and button up gates.;Test BOPE 250 low w/5 min hold,3500 high(annular 2500 high)w/10 min hold as per Saxon policy. Chart and record same.Perform electric and manual choke pressure bleed test.;Perform accumulator drawdown test.1 F/P test on upper pipe rams. AOGCC waived witness by Jim Regg.Total safety bump tested gas alarms on 5-7-2015.;R/U and bleed I/A thru choke and gas buster from 700 psi to 0 psi.Blow down choke and gas buster.R/D test equipment.;TIH from 6026'to 6400',wash last stand tagging bottom @ 6462'.;Drill cement from 6462'to 6720'pumping 67 gpm,760 psi,diff 160 psi.3-6k wob.I/A pressure currently 680 psi.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 0 bbls class II junk fluid to KGF for total of 8044 bbls. • a 5/9/2015 Continue drilling cement in 5"casing from 6720'to 7033'pumping 81 gpm,960 psi.Diff 150 psi.3k wob. IA @ 750 PSI.;Continue drilling cement from 7033'to 7091'pumping 81 gpm,970 psi.Diff 165 psi.3k wob.ROP dropped from 40 fph to 19 fph.I/A stabilized @ 850 psi.Turn elevators.;TOH for bit from 7091'to surface.Close blind ram,L/D motor,xo and 4 1/8"bit.Bit grade=2/3/CD/G/F/I/WT,2,NR/PR.;M/U previous mud motor from first cleanout run,xo and new 4 1/8"L-2 mill tooth bit.Open blind ram.TIH to 5000',fill pipe @ 2500'and 5000'.;PJSM,Slip and cut 115'of drilling line.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 154 bbls class II junk fluid to KGF for total of 8198 bbls. 5/10/2015 Finish cut and slip drilling line. Check C.O.M and inspect deadman.;TIH F/5,000'-T/7,091'MD.;Wash down last stand and drill cement F/7,091'-T/7,433'. 67 gpm,7%flow,605 psi off,150 diff,2-3k wob,65k dn,69k up.IA 900 psi.;Continue drilling cement from 7433'to 7814'pumping 67 gpm,730 psi.Diff 140 psi.2-4k wob.P/U 87K,S/O 68K.I/A 950 psi. 18.6=bit hrs/299,000 revs.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 0 bbls class II junk fluid to KGF for total of 8198 bbls. 5/11/2015 Continue drilling cement F/7814'-T/7879'MD. 67 gpm,645 psi off,150 diff,8%flow,3k wob,80k up,68k dn.;ROP diminished to 20 ft/hr w/erratic differential. Saw one stall. Decision made to make bit trip. Displace inside of workstring w/fresh water for handling purposes(floorhands).67 gpm,763 FCP.;POOH F/7879'- T/surface. Rack back DC's,B/O bit. Bit grade 2,2,Wr,A,8,I,ER,HR.Loaded silos w/604 sxs 15.3 tail blend.;M/U New 4 1/8"L2 milltooth(S/N:1419492). Inspect mtr(good). TIH to 4091'MD.;Service rig.;TIH F/4,091'-T/7879'MD.;Drilling cement F/7,879'-T/7,938'MD. 67 gpm,645 psi off,150 diff,8%flow,3k wob,80k up,68k dn. I/A 925 psi.;Continue drilling cement from 7938'to 8345'pumping 67 gpm,810 psi,diff 150 psi.2-3k wob.P/U 91K,S/O 71K.I/A 910 psi.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 338 bbls class II junk fluid to KGF for total of 8536 bbls. 5/12/2015 Cont to drill cement in 5"production casing,with mud motor,from 8345'to 8680',2 to 3K wob,67 gpm-800 psi,140 to 150 psi diff,46 to 50 ft/hr ROP.At 8660' ROP dropped to 23 ft/hr and diff;increased to 170 psi.At this point we have 20 hrs on bottom drilling time with this bit,and have made 801'.Decision made to POOH for new sealed bearing type bit.IA psi=925.;Load drill string with fresh water as we drilled last of joint down.Up wt 98K,dwn wt 72K,POOH from 8680'to 5500';Service rig and topdrive.;Cont POOH from 5500'to surface,UD motor,xo and bit,grade=2,2,Wr,A,8,I,NO,TQ.I/A=930 psi.;M/U xo,M1X motor and new 4 1/8"SRP 624 varel bit#1449806.TIH to 8650',fill pipe every 2500',wash last jt to bottom @ 8680'.P/U 90K,S/O 71K.;Cont to drill cement from 8680'to 8797' pumping 67 gpm,3k wob,diff 90-120 psi.40-45 fph.P/U 95K,S/O 72K.I/A 900 psi.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 231 bbls class II junk fluid to KGF for total of 8767 bbls. 5/13/2015 Cont drilling cement in 5"casing,from 8797'to 9233',wob 2 to 3K,67 gpm-850 psi,118 to 163 psi diff.IA=935 psi.Removed pipeshed modules,cattle chute and windwalls for summer storage.;Cont drilling cement from 9233'to 9380'pumping 67 gpm,880 psi.2-3k wob.Diff 137-150 psi.35-45 fph.P/U 103K,5/0 75K.I/A 940 psi.5 motor stalls from 9372'to 9380',;ROP reduced to 22 fph(289,440 k-revs on bit)decision made to POH.;POH from 9380'to surface,UD motor,xo and bit.Motor stator seal failed.bit grade=2/2/WT/M,N/E/I/NO/DMF;M/U new 4 1/8"SRP 624 bit#1449810,xo,used VIP mud motor,TIH to 1500';;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 68 bbls class II junk fluid to KGF for total of 8835 bbls. 5/14/2015 TIH with 4 1/8"cleanout bha from 1500'to 9380',washing last stand to bottom.;Cont drilling cement in 5"casing from 9380'to 9563',2K wob,67 gpm-873 psi,80 to 130 psi diff,43 to 50 ft/hr.At 9521'we had 4 motor stalls and reduced bit wt to 1K.At 9543'we pumped a 20 bbl;hi-vis nut plug sweep to try and clean up the bit. ROP increased from 13 to 30 ft/hr.;Cont drilling cement in 5"casing from 9563'to 9604'pumping 67 gpm,770 psi.1-2k wob.Diff 60-100 psi.ROP 12-15 fph.P/U 103K,S/O 77K.I/A 950 psi.;Displace pipe w/clean water due to 12.5 ph for tripping.POH due to several motor stalls.;POH from 9604'to surface.UD motor,xo and bit.Stator seal on motor failed,bit grade=2/1/WT/M/E/I/NO/DMF.;M/U xo,new 2 7/8"extreme mud motor,re-run 4 1/8"SRP 624 bit#1449810.RIH to 2569'.;Fill pipe,service top drive,blocks and drawworks.;Continue to RIH from 2569'to 4175'.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 76 bbls class II junk fluid to KGF for total of 8911 bbls. 5/15/2015 RIH with 4 1/8"cleanout bha from 4175'to 9600'washing last stand to bottom.;Resume drilling cement in 5"casing from 9604'to 9665'.WOB 1 to 2K,67 gpm-680 psi,89 to 117 psi diff,31 to 43 ft/hr ROP.With stand drilled down CBU and PU off bott.;Drain BOP stack with vac hose and verify packoff run tool is in wellhead. Clean out suction manifold on pump#2.;Cont drilling cement from 9665'to 9800'.WOB 1 to 2K,67 gpm-695 psi,25 to 48 psi diff,38 ft/hr ROP.;Cont drilling cement from 9800'to 9875'pumping 67 gpm,640 psi,2k wob.Diff 40-80 psi.ROP 38 fph.I/A=970 psi.;Circulate BU,flood choke lines and gas buster.R/U and bleed I/A thru choke and gas buster from 970 psi to 0 psi.;Continue drilling cement from 9875'to 10006'pumping 67 gpm,630 psi,wob 2k,Diff 60-90 psi.ROP 12-19 fph. Monitor I/A for pressure,100 psi in 3 hrs,stabilized @ 900 psi.;;Hauled 0 bbls cuttings to KGF for total of 1664 bbls,Hauled 600 bbls class II junk fluid to KGF for total of 9511 bbls. 5/16/2015 Cont to drill cement in 5"production casing from 10,006'to 10,098'DPM.1 to 2K wob,67 gpm-736 psi,40 to 77 psi diff,14 to 39 ft/hr ROP.At 10,098'diff psi increased to 115 psi.;CBU 1 time at 67 gpm-778 psi and had no sign of wiper plug rubber at bottoms up.Shut down pump.;Vac drill water out of active pit and clean tank bottom.Clean shakers and troughs.Off load 100 bbls 11.7 ppg 6%KCL mud into active pits.Made connection.;Displace well to 6%KCL mud at 67 gpm-870 psi.ICP 1200 psi.Cont to circ until good 11.7 ppg mud in/out.Shipped drill water to G&I.;Cont to drill cement from 10,098'and located wiper plug at 10,101'DPM. Drilled up wiper plug and float collar(top of float collar at 10,102'DPM).Cont to wash down through shoe track(no cement);and tagged top of float shoe at 10,186' DPM.Drilled wiper plug and FC at 67 gpm-1205 psi,2K wob,39 to 110 psi diff.PU to 10,183'.;CBU 1 time at 67 gpm-1279 psi,had 2 SLB Reps on location to verify drilled up wiper plug at shakers.Shut down pump.;RU high pressure hose from annulus to choke manifold.IA=900 psi.Close annular and flood lines,CM and degasser with 11.7 mud.;Attempt to break circ down 2 7/8"drill string and up backside of 5"casing,through the float shoe.Idle pump up to 2500 psi,then allow to bleed back 1000 psi,then bleed to 0 psi at rig floor.;Cont this cycle process a total of 14 times and started to get retums through poorboy degasser with a total of 16.5 bbls pumped.Initial returns at 10.0 ppg.Cont to cycle pump and lost retums;with 38.5 bbls pumped.At this time we were circulating through a full open auto choke.Opened manual choke(both now full open)and cont to cycle pump up to 3000 psi.At 45.5 bbls re-gained retums.;Cont to cycle pump up to 3000 psi through both open chokes,and at 70 bbls into circ cycles,were able to idle pump continuously.ICP 2735 psi.;Cont to idle pump at 67 gpm-2735 psi,dusting MW in active system to maintain 11.7 ppg.Had a max of 4269 units gas and MW out climbed to 12.4 ppg.FCP 2065 psi.Cont to maintain;11.8 ppg going down hole to reduce gas at surface.At bottoms up we routed pump down the kill line rather than drill string,to allow us to increase pump rate and reduce chance of motor or bit;damage, and to circ out the 11.7 ppg mud outside drill string.Cont circ at 2.6 bpm-112 gpm-psi dropped from 2065 to 1594,gas dropped to 67 units slowly.Brought on more 6%mud to be able to utilize;vacuum degasser in active system.Cont circ good 11.8 ppg mud in/out until crew change,down inside of casing via kill line,with annular closed,and up backside of 5"casing.;;Hauled 0 bbls cuttings to G&I Total cuttings hauled=1664 bbls Hauled 325 bbls Class II fluid to G&I Total Class II fluid hauled=9836 bbls 5/17/2015 Shut down pump and monitor for flow at poorboy degasser discharge line.No flow in 30 minutes.;CBU 1 time at 80 spm-112 gpm-1582 psi with 4"liners in pump#2. Pump down kill line,annular closed,down inside of 5"casing,taking returns up backside of 5"casing.Max gas 244 units at bott up.;BGG at 60 units,pump dry job while install psi gauge on annulus valve,POOH from 10,183'racking back 2 7/8"work string.Up wt 100K.LD 10 jnts spiral DC's.Flush motor,break bit.Bit graded at2-3-NR-A-F-I-WT-TD.Had one loose sealed bearing cone.Broke down XO's.Halliburton a-line crew on location.;Clean and clear rig floor.CO elevators to 4 1/2". Load and ship Baker mud motor and XO.;PJSM with rig crew and Halliburton.RU lubricator and sheaves.RIH with 4"OD Gauge Ring to 10,110'with no issues. POOH and lay down gauge ring.;PU and RIH with Halliburton 5"EZ Drill Cement Retainer on Gamma Ray/CCL.Log RA markers @ 9891,9604',and 9358'making 25'correction.Locate FC @ 10,098'.PUH and Park @ 10,051.50'CCL,placing the;top of Retainer @ 10,065',btm @ 10,067'.Intiate setting sequence,pause 7 minutes and set Retainer.PU off retainer clean,RIH and tag fop of retainer to confirm set.;POOH and rig down E-Line.;Monitor IA with 0 psi.PU 5"Casing landing joint.engage pack off,BOLDS and retrieve same with no issues.UD landing jt and pack off.;PU/MU EZ Drill Retainer Stinger Assembly and TIH on 2 7/8"Drill pipe from surface to 8652',(CO report time.;;Hauled 0 bbls cuttings to G&I Total cuttings hauled=1664 bbls Hauled 170 bbls Class II fluid to G&I Total Class II fluid hauled=10,006 bbls • • 5/18/2015 Cont to TIH with cement retainer stinger assembly on 2 7/8"drill pipe,from 8,652'to 10,048'.Schlumberger cementers on location setting up pump equipment.;MU topdrive and pump 67 gpm-1523 psi washing down from 10,048'to just above top of retainer(at 10,065').Down pump,cont to slack off and engage/tag up on retainer at 10,066'DPM.;Cont slack off 20K from string weight of 100K as per Halliburton Retainer Rep.CBU at 67 gpm-1800 psi.Pumping down workstring, `�, it through retainer and up backside of 5"casing.;Had a max of 2801 units gas at bottoms up.Mix 30 bbls 13 ppg Mud Push II while circulating.Increased pump rate to 2 bpm-1882 psi mid circulation.Change to long bails.;PJSM with rig team and SLB cementers.Down pump,remove topdrive,MU XO's and headpin.MU hardline C' from SLB to headpin,MU hardline from mudline to headpin.SLB flushed hardlines to cutting box.;SLB pumped 5 bbls water,tested lines at 2000 psi low and 5000 psi high.Tests good.Rig pumped 27 bbls 13 ppg MUDPUSH II at 2 bpm-1490 psi.Shut down and lined up SLB pump truck to well.(No;wiper plugs)SLB mixed and CS pumped on the fly:132 bbls(549sx)15.3 ppg EZ-Blok Tail cement at 2 to 3 bpm,1500 to 1800 psi.SLB then displaced with 2 bbls water.followed with 43 bbls 11.8 ppg 6%KCL;mud,through cement retainer at 10,065',3 bpm-2800 psi,2 bpm-2400 psi,1.5 bpm-2600 psi.With 45 bbls displaced SLB shut down pump.Rig PU to 100K string weight+10'to unsting from retainer.;CIP at 14:19 hrs on 5-18-15. SLB CBU 93 bbls at 2 to 3 bpm-1800 psi to clear any cement from drillstring and wellbore.Had no MudPush to surface.Had trace of cement to surface.RD and released;Schlumberger.Rig dropped pipe wiper ball and CBU with 11.8 ppg mud at 3 bpm-2091 psi.Mix water temp 86 degrees,lost 30 bbls throughout job(total pumped 162 bbls,total returns 132 bbls),;no string reciprocation.Estimated TOC at 5219'based on volume pumped.;Displaced well to 3%KCL brine at 112 gpm-162 psi.Changed to short bails.Prep rig floor for LD of 2 7/8"DP.Flushed pump 1, choke manifold and poorboy degasser with fresh water.;TOH laying down 2 7/8"drill pipe from 10040'to surface.Lay down HES retainer stinger assembly.;Rig down Weatherford power tongs and 2 7/8"handling equipment.;PU 5"casing landing joint,MU running tool and land packoff report time. 5/19/2015 With BPV set,start ND of BOPE,ship 6%KCL mud to Blossom Pad Tank,clean rig tank bottoms,lay over poorboy degasser,ship cement silo's to Blossom Pad, ship service shacks to Blossom Pad,;welders on location installing grating in pit module#1(rig poorboy degasser removed),ship poorboy degasser(Hilcorp)to Blossom Pad,lower pit module#3 roof for move,C/O oil pan on floor motor.;Total Safety RD gas detection equipment,install adaptor spool on well head,ship excess 5"casing to Tuboscope,ship SLB compressor to SLB yard,ship pallets dry mud product to Blossom Pad,remove;IBOP from topdrive,RD topdrive.Test "P"seals at 5000 psi(good),test hanger void at 5000 psi(good),pull BPV,install 2 way check.NU dry hole tree and test 5000 psi(good),pull 2 way check.;RELEASED RIG at 18:00 hrs on 5-19-15;;Hauled 0 bbls cuttings to G&l Total cuttings hauled 1664 bbls Hauled 640 bbls Class II junk fluid to G&l Total Class II junk fluid hauled 10,646 bbls. Hila Energy Company Compositteport Well Name: KEU KBU 22-06Y Field: Kenai Gas Field County/State: ,Alaska t(LAT/LONG): avation(RKB): API#: 50-133-20650-00-00 Spud Date: Job Name: 1510328C KBU 22-06Y Completion Contractor Saxon Drilling AFE#: 1510328C AFE$: Activity Date Ops Summary 5/22/2015 MI slickline. Safety meeting,spot in equipment,review JSA. Rig up.PT lubricator to 2,500psi. RIH,4.125"swedge and 1.75"sample bailer. Tag T/D @ 10,014'SLM. Sample mud/cement. Rig down. 5/23/2015 MI E-line. Safety meeting,permit,JSA. Rig up,PT lubricator to 2,500psi. Pass 1-CCL tool not picking up collars at 850'. POOH and swap tools. Run 2. Lost Comm with tool string at 4,550'. POOH,found bad knuckle joint. Replace and RIH. Run 3-Reached TD of 10,010'and started logging up. Lost communication with gamma tool. POOH,replaced tool. RIH. Run 4-RCBL logged from 10,010'to 4,600'.,Good cement bond log. POOH. Rig down. 5/25/2015 Pressure test casing 2,730 psi,flat line and charted for 30 minutes. Pressure test tubing to 9,190 psi and charted for 30 minutes. 5/26/2015 NU 5M tree and test on top of 10M master valve. Pressure test tree to 5,000 psi. 5/28/2015 Obtain PTW. Hold safety meeting. Discuss job objectives and procedures. Review Schlumberger JSA and HARC.,Pull pit liner. Rig up CTU 12. Using offshore 1.75 in CT reel due to land reel not having enough coil to reach PBTD. Assist welder and production hands to install SSV,flow line. Rig up BOPs and X over on tree.,Start BOP test. Test all rams,choke skid and valves to 250 low and 4,500 psi high. AOGCC 24 hr notification for BOPE test witness sent 5/17/15 @ 1227. Witness waived by Jim Regg on 5/27/15 @ 1402. Kill port flange had small leak. Bleed down and tighten. Retest,good to go. Test 1-- completed at 1730 hrs.,Secure wellsite. Shut all ground valves. Shut down equipment and leave location. Work permit closed out and turned in with JSA attached. 5/29/2015 Obtain PTW. Hold safety meeting. Discuss job procedures and review JSA and HARC.,Fire equipment. Pick injector head and grab 10 ft lubricator. Pull test CT connector 20K,make up 1.90"cold roll, 1.75"OD DFCV, 1.75"OD straight bar, 1.75"OD ball drop nozzle. Stab on well. Pressure test to 4,500 psi. Bleed down.Open well. Swab valve very hard to turn. Well open.,RIH. Cool down N2 at 4,000 ft. Online with N2 5,000 ft. 1,500 scf/min. Tag PBTD at 10,048 ft CTMD. Pick up string weight. Blow well dry.,Parked on bottom blowing well dry. Straight N2 at surface. Tank strap shows 176 bbls returned. Start POOH., POOH. N2 at surface. Close in choke and pressure up wellbore while POOH.,At surface. WHP 1,270 psi. Swab and master closed. Total bbls returned 176. Confirmed via tank strap and return micro motion. Total N2 pumped 231,000 scf or 2,480 gallons. 2,600 total used for job. Bleed down CTU string.,Rig down CTU 12 equipment. Mobe to CLU-11. Spotted in return tank and choke skid from production. Wellsite secure. Crews off location. 5/30/2015 PTW and JSA.Mobe equipment to location.Rig up lubricator and ASRC crane.MU press/temp tool on line.Pressure test lubricator to 250 psi low and 4,000 psi high.,RIH with pressure/temp tool,tie into open hole log and tag at 10,064'.Ran log and found fluid level at 9,655'. Set tool at 9,830'. BHP at that depth was 1,786 psi. Bled well down to 1,408 psi. BHP and surface pressure was 961.5 psi.POOH.,RIH w/3-1/2"x 20'Nova,6 spf,60 deg phase and tie into SLB Press/Temp log dated 5-30-15. Run correlation log and send to town. Get ok to perf from 9,847'to 9,827'. Spot shot and fired gun with 961.5 psi. Had no pressure gain for 10 min. POOH. All shots fired. TP-998 psi.,RIH w/3-1/2"x 15'Nova,6 spf,60 deg phase and tie into SLB Press/Temp log dated 5-30-15. Run correlation log and send to town. Get ok to perf from 9,827'to 9,812'. Spot shot and fired gun with 1,042 psi. Pressure was 1,046 psi after 5 min. POOH. All shots fired. TP-1,114 psi.,Rig down lubricator and turn well back over to field. TP-1,195 psi. • • Hilcorp Energy Company Kenai Gas Field KGF 14-6 Pad KBU 22-06Y 50-133-20650-00-00 50-133-20650-00-00 Sperry Drilling Definitive Survey Report 01 May, 2015 , ,.. .am . . .� �.: �a, ,.,.�.. .„ ,.. .�■� HALLIBURTON Sperry Drilling • • Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well KBU 22-06Y Project: Kenai Gas Field ND Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Site: KGF 14-6 Pad MD Reference: Actual:KBU 22-06Y @ 83.O0usft(Saxon 169(65GL+18 Well: KBU 22-06Y North Reference: True - Wellbore: KBU 22-06Y Survey Calculation Method: Minimum Curvature Design: KBU 22-06Y 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 KBU 22-06Y Well Position +N/-S 0.00 usft Northing: 2,362,472.99 usft • Latitude: 60°27'38.266 N +E/-W 0.00 usft Easting: 272,112.27 usft • Longitude: 151°15'45.101 W Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usft Ground Level: 65.00 usft • Wellbore KBU 22-06Y Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (°) (nT) BGGM2014 4/7/2015 16.62 73.44 55,326 Design KBU 22-06Y Audit Notes: Version: 1.0 Phase: ACTUAL Tie On Depth: 18.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (0) 18.00 0.00 0.00 3.41 Survey Program Date 5/1/2015 From To (usft) (usft) Survey(Wellbore) Tool Name Description Survey Date 136.28 815.84 KBU 22-06Y MWD(KBU 22-06Y) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 04/07/2015 876.04 1,249.84 KBU 22-06Y MWD Interp(KBU 22-06Y) MWD_Interp Azi+sag Fixed:v2:std dec with interpolated azimuth+sag 04/09/2015 1,312.98 8,082.71 KBU 22-06Y MWD(1)(KBU 22-06Y) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 04/09/2015 8,082.71 10,165.88 KBU 22-06Y MWD(1)(KBU 22-06Y) MWD+SC+sag Fixed:v2:standard dec&axial correction+sag 04/09/2015 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/S +El-W Northing Easting DLS Section (usft) (0) (0) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 18.00 0.00 0.00 18.00 -65.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 UNDEFINED 136.28 0.14 296.20 136.28 53.28 0.06 -0.13 2,362,473.06 272,112.14 0.12 0.06 MWD+SC+sag(1) 196.68 0.05 296.20 196.68 113.68 0.11 -0.22 2,362,473.10 272,112.05 0.15 0.09 MWD+SC+sag(1) 260.38 0.16 297.01 260.38 177.38 0.16 -0.32 2,362,473.16 272,111.95 0.17 0.14 MWD+SC+sag(1) 319.48 0.04 247.96 319.48 236.48 0.19 -0.42 2,362,473.19 272,111.86 0.23 0.17 MWD+SC+sag(1) 385.52 0.44 270.18 385.52 302.52 0.18 -0.69 2,362,473.19 272,111.58 0.61 0.14 MWD+SC+sag(1) 446.80 0.59 301.07 446.80 363.80 0.35 -1.20 2,362,473.36 272,111.08 0.51 0.27 MWD+SC+sag(1) 508.35 0.76 337.05 508.34 425.34 0.89 -1.63 2,362,473.91 272,110.66 0.73 0.79 MWD+SC+sag(1) 570.14 2.90 0.78 570.10 487.10 2.83 -1.77 2,362,475.85 272,110.56 3.60 2.72 MWD+SC+sag(1) 630.94 3.78 4.76 630.79 547.79 6.36 -1.58 2,362,479.38 272,110.81 1.50 6.26 MWD+SC+sag(1) 692.21 5.89 5.71 691.84 608.84 11.50 -1.10 2,362,484.51 272,111.39 3.45 11.42 MWD+SC+sag(1) 5/1/2015 4:10:41PM Page 2 COMPASS 5000.1 Build 73 • • Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well KBU 22-06Y Project: Kenai Gas Field TVD Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Site: KGF 14-6 Pad MD Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Well: KBU 22-06Y North Reference: True Wellbore: KBU 22-06Y Survey Calculation Method: Minimum Curvature Design: KBU 22-06Y Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (11001 (ft) Survey Tool Name 753.97 8.54 5.27 753.11 670.11 19.22 -0.36 2,362,492.22 272,112.28 4.29 19.17 MWD+SC+sag(1) 815.84 10.40 3.42 814.13 731.13 29.37 0.39 2,362,502.35 272,113.23 3.05 29.34 MWD+SC+sag(1) 876.04 11.94 3.88 873.19 790.19 41.01 1.14 2,362,513.97 272,114.19 2.56 41.01 MWD_Interp Azi+sag(2) 938.36 11.45 4.33 934.22 851.22 53.61 2.04 2,362,526.55 272,115.34 0.80 53.64 MWD_InterpAzi+sag(2) 1,002.95 13.41 4.78 997.29 914.29 67.47 3.15 2,362,540.38 272,116.71 3.04 67.54 MWD_InterpAzi+sag(2) 1,065.94 11.81 5.15 1,058.76 975.76 81.17 4.34 2,362,554.06 272,118.16 2.54 81.28 MWD_Interp Azi+sag(2) 1,126.35 11.52 5.57 1,117.92 1,034.92 93.33 5.48 2,362,566.19 272,119.54 0.50 93.49 MWD_InterpAzi+sag(2) 1,188.20 11.57 5.95 1,178.52 1,095.52 105.65 6.72 2,362,578.48 272,121.01 0.15 105.86 MWD_InterpAzi+sag(2) 1,249.84 13.24 6.31 1,238.72 1,155.72 118.81 8.14 2,362,591.62 272,122.68 2.71 119.08 MWD_InterpAzi+sag(2) 1,312.98 12.44 6.66 1,300.28 1,217.28 132.75 9.72 2,362,605.53 272,124.53 1.27 133.09 MWD+SC+sag(3) 1,375.63 13.19 6.20 1,361.37 1,278.37 146.56 11.28 2,362,619.30 272,126.35 1.21 146.97 MWD+SC+sag(3) 1,437.87 11.71 5.76 1,422.14 1,339.14 159.90 12.68 2,362,632.62 272,128.01 2.38 160.38 MWD+SC+sag(3) 1,491.22 12.30 3.30 1,474.33 1,391.33 170.96 13.55 2,362,643.66 272,129.09 1.46 171.47 MWD+SC+sag(3) 1,559.17 12.34 1.93 1,540.71 1,457.71 185.45 14.21 2,362,658.12 272,130.03 0.43 185.96 MWD+SC+sag(3) 1,622.23 12.15 0.87 1,602.34 1,519.34 198.82 14.54 2,362,671.48 272,130.61 0.47 199.33 MWD+SC+sag(3) 1,685.14 12.63 0.04 1,663.78 1,580.78 212.31 14.64 2,362,684.98 272,130.98 0.81 212.81 MWD+SC+sag(3) 1,746.65 13.32 0.09 1,723.72 1,640.72 226.13 14.66 2,362,698.78 272,131.26 1.12 226.60 MWD+SC+sag(3) 1,808.19 13.54 359.40 1,783.58 1,700.58 240.42 14.59 2,362,713.07 272,131.47 0.44 240.86 MWD+SC+sag(3) 1,870.88 13.87 359.83 1,844.48 1,761.48 255.27 14.49 2,362,727.92 272,131.65 0.55 255.68 MWD+SC+sag(3) 1,932.75 13.91 359.39 1,904.54 1,821.54 270.12 14.39 2,362,742.78 272,131.84 0.18 270.50 MWD+SC+sag(3) 1,994.27 13.81 358.68 1,964.27 1,881.27 284.86 14.14 2,362,757.51 272,131.87 0.32 285.19 MWD+SC+sag(3) 2,056.91 13.99 358.88 2,025.08 1,942.08 299.90 13.82 2,362,772.56 272,131.84 0.30 300.19 MWD+SC+sag(3) 2,118.85 13.52 2.24 2,085.24 2,002.24 314.62 13.96 2,362,787.27 272,132.26 1.50 314.90 MWD+SC+sag(3) 2,180.56 13.74 3.15 2,145.21 2,062.21 329.15 14.65 2,362,801.78 272,133.22 0.50 329.44 MWD+SC+sag(3) 2,242.75 12.71 1.68 2,205.75 2,122.75 343.36 15.25 2,362,815.98 272,134.10 1.74 343.66 MWD+SC+sag(3) 2,304.89 12.92 1.60 2,266.35 2,183.35 357.14 15.65 2,362,829.75 272,134.76 0.34 357.44 MWD+SC+sag(3) 2,367.15 11.78 2.91 2,327.16 2,244.16 370.44 16.16 2,362,843.04 272,135.53 1.89 370.75 MWD+SC+sag(3) 2,427.24 11.91 2.85 2,385.98 2,302.98 382.76 16.78 2,362,855.34 272,136.39 0.22 383.08 MWD+SC+sag(3) 2,490.80 12.18 1.95 2,448.14 2,365.14 396.01 17.34 2,362,868.58 272,137.20 0.52 396.34 MWD+SC+sag(3) 2,552.37 12.38 2.08 2,508.30 2,425.30 409.10 17.80 2,362,881.66 272,137.91 0.33 409.43 MWD+SC+sag(3) 2,614.10 12.71 1.56 2,568.55 2,485.55 422.50 18.22 2,362,895.05 272,138.59 0.57 422.84 MWD+SC+sag(3) 2,676.54 12.98 1.98 2,629.43 2,546.43 436.38 18.65 2,362,908.91 272,139.28 0.46 436.71 MWD+SC+sag(3) 2,738.88 12.15 358.75 2,690.28 2,607.28 449.93 18.75 2,362,922.46 272,139.64 1.74 450.25 MWD+SC+sag(3) 2,800.61 12.20 357.23 2,750.62 2,667.62 462.94 18.29 2,362,935.48 272,139.43 0.53 463.21 MWD+SC+sag(3) 2,863.27 12.03 1.27 2,811.89 2,728.89 476.08 18.12 2,362,948.62 272,139.51 1.38 476.32 MWD+SC+sag(3) 2,925.05 12.34 1.90 2,872.27 2,789.27 489.12 18.48 2,362,961.64 272,140.12 0.55 489.35 MWD+SC+sag(3) 2,987.98 12.35 0.16 2,933.75 2,850.75 502.57 18.72 2,362,975.09 272,140.62 0.59 502.79 MWD+SC+sag(3) 3,049.74 12.27 4.95 2,994.09 2,911.09 515.71 19.31 2,362,988.22 272,141.46 1.66 515.95 MWD+SC+sag(3) 3,111.26 12.48 4.64 3,054.18 2,971.18 528.85 20.41 2,363,001.33 272,142.81 0.36 529.13 MWD+SC+sag(3) 3,171.91 12.70 4.89 3,113.37 3,030.37 542.02 21.51 2,363,014.48 272,144.16 0.37 542.34 MWD+SC+sag(3) 5/1/2015 4:10:41PM Page 3 COMPASS 5000.1 Build 73 Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well KBU 22-06Y Project: Kenai Gas Field TVD Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Site: KGF 14-6 Pad MD Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Well: KBU 22-06Y North Reference: True Wellbore: KBU 22-06Y Survey Calculation Method: Minimum Curvature Design: KBU 22-06Y Database: Sperry EDM-NORTH US+CANADA Survey Map Map Vertical MD Inc Azi ND TVDSS +N/-S +EI-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°M00) (ft) Survey Tool Name 3,236.23 13.72 3.99 3,175.99 3,092.99 556.68 22.64 2,363,029.11 272,145.58 1.62 557.04 MWD+SC+sag(3) 3,298.24 13.58 2.31 3,236.25 3,153.25 571.29 23.45 2,363,043.70 272,146.66 0.68 571.67 MWD+SC+sag(3) 3,359.73 14.24 2.81 3,295.93 3,212.93 586.06 24.11 2,363,058.45 272,147.61 1.09 586.45 MWD+SC+sag(3) 3,422.26 14.96 4.81 3,356.45 3,273.45 601.78 25.16 2,363,074.15 272,148.96 1.41 602.21 MWD+SC+sag(3) 3,484.34 15.74 6.93 3,416.31 3,333.31 618.12 26.85 2,363,090.46 272,150.96 1.55 618.63 MWD+SC+sag(3) 3,546.99 17.01 7.63 3,476.42 3,393.42 635.64 29.09 2,363,107.93 272,153.54 2.05 636.25 MWD+SC+sag(3) 3,608.23 18.21 7.68 3,534.79 3,451.79 654.00 31.56 2,363,126.24 272,156.36 1.96 654.72 MWD+SC+sag(3) 3,670.81 19.57 9.39 3,594.00 3,511.00 674.04 34.58 2,363,146.21 272,159.76 2.35 674.90 MWD+SC+sag(3) 3,732.81 20.47 10.88 3,652.25 3,569.25 694.93 38.32 2,363,167.03 272,163.90 1.67 695.98 MWD+SC+sag(3) 3,792.81 20.37 10.27 3,708.48 3,625.48 715.51 42.16 2,363,187.53 272,168.14 0.39 716.75 MWD+SC+sag(3) 3,854.94 20.80 11.66 3,766.64 3,683.64 736.95 46.32 2,363,208.89 272,172.70 1.05 738.40 MWD+SC+sag(3) 3,917.25 20.58 11.61 3,824.93 3,741.93 758.51 50.76 2,363,230.36 272,177.56 0.35 760.19 MWD+SC+sag(3) 3,979.21 21.00 12.83 3,882.86 3,799.86 780.00 55.41 2,363,251.76 272,182.62 0.97 781.92 MWD+SC+sag(3) 4,040.76 21.23 12.61 3,940.28 3,857.28 801.63 60.29 2,363,273.29 272,187.92 0.40 803.80 MWD+SC+sag(3) 4,103.17 21.18 12.30 3,998.46 3,915.46 823.68 65.16 2,363,295.23 272,193.21 0.20 826.09 MWD+SC+sag(3) 4,164.20 20.91 11.32 4,055.42 3,972.42 845.13 69.65 2,363,316.59 272,198.11 0.73 847.77 MWD+SC+sag(3) 4,226.13 20.18 11.43 4,113.41 4,030.41 866.43 73.94 2,363,337.81 272,202.80 1.18 869.30 MWD+SC+sag(3) 4,288.09 20.72 11.28 4,171.47 4,088.47 887.66 78.20 2,363,358.95 272,207.47 0.88 890.74 MWD+SC+sag(3) 4,350.65 21.43 12.34 4,229.84 4,146.84 909.68 82.81 2,363,380.87 272,212.50 1.29 912.99 MWD+SC+sag(3) 4,412.84 21.53 12.27 4,287.71 4,204.71 931.93 87.66 2,363,403.03 272,217.77 0.17 935.49 MWD+SC+sag(3) 4,475.20 21.72 12.65 4,345.68 4,262.68 954.37 92.62 2,363,425.37 272,223.16 0.38 958.19 MWD+SC+sag(3) 4,536.73 21.55 11.93 4,402.88 4,319.88 976.53 97.45 2,363,447.43 272,228.42 0.51 980.60 MWD+SC+sag(3) 4,599.16 21.32 11.25 4,460.99 4,377.99 998.88 102.03 2,363,469.69 272,233.43 0.54 1,003.18 MWD+SC+sag(3) 4,661.20 20.74 10.95 4,518.90 4,435.90 1,020.73 106.32 2,363,491.45 272,238.13 0.95 1,025.24 MWD+SC+sag(3) 4,723.08 20.51 10.64 4,576.81 4,493.81 1,042.14 110.40 2,363,512.78 272,242.62 0.41 1,046.86 MWD+SC+sag(3) 4,785.14 20.33 10.25 4,634.97 4,551.97 1,063.43 114.33 2,363,533.99 272,246.96 0.36 1,068.35 MWD+SC+sag(3) 4,847.60 20.41 10.57 4,693.53 4,610.53 1,084.82 118.25 2,363,555.29 272,251.29 0.22 1,089.93 MWD+SC+sag(3) 4,908.84 21.40 11.97 4,750.73 4,667.73 1,106.24 122.53 2,363,576.64 272,255.98 1.81 1,111.57 MWD+SC+sag(3) 4,970.92 21.42 11.55 4,808.53 4,725.53 1,128.43 127.15 2,363,598.73 272,261.02 ' 0.25 1,133.99 MWD+SC+sag(3) 5,032.69 21.34 10.68 4,866.05 4,783.05 1,150.52 131.49 2,363,620.73 272,265.79 0.53 1,156.31 MWD+SC+sag(3) 5,094.97 21.47 10.36 4,924.03 4,841.03 1,172.87 135.64 2,363,643.00 272,270.36 0.28 1,178.86 MWD+SC+sag(3) 5,156.22 21.86 10.14 4,980.96 4,897.96 1,195.12 139.66 2,363,665.17 272,274.81 0.65 1,201.32 MWD+SC+sag(3) 5,218.36 20.61 10.69 5,038.88 4,955.88 1,217.26 143.73 2,363,687.22 272,279.30 2.04 1,223.65 MWD+SC+sag(3) 5,280.60 20.74 11.31 5,097.11 5,014.11 1,238.83 147.92 2,363,708.71 272,283.91 0.41 1,245.44 MWD+SC+sag(3) 5,341.86 20.95 10.65 5,154.36 5,071.36 1,260.23 152.07 2,363,730.02 272,288.47 0.51 1,267.04 MWD+SC+sag(3) 5,405.26 21.42 9.39 5,213.47 5,130.47 1,282.79 156.06 2,363,752.50 272,292.88 1.03 1,289.80 MWD+SC+sag(3) 5,467.13 21.89 8.74 5,270.98 5,187.98 1,305.34 159.65 2,363,774.97 272,296.91 0.85 1,312.52 MWD+SC+sag(3) 5,529.13 20.98 10.56 5,328.69 5,245.69 1,327.67 163.44 2,363,797.23 272,301.13 1.82 1,335.04 MWD+SC+sag(3) 5,591.03 20.83 10.47 5,386.51 5,303.51 1,349.39 167.47 2,363,818.86 272,305.58 0.25 1,356.96 MWD+SC+sag(3) 5,652.64 20.88 10.35 5,444.09 5,361.09 1,370.96 171.44 2,363,840.36 272,309.95 0.11 1,378.73 MWD+SC+sag(3) 5/1/2015 4:10:41 PM Page 4 COMPASS 5000.1 Build 73 i 0 • Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well KBU 22-06Y Project: Kenai Gas Field TVD Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Site: KGF 14-6 Pad MD Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Well: KBU 22-06Y North Reference: True Wellbore: KBU 22-06Y Survey Calculation Method: Minimum Curvature Design: KBU 22-06Y 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 5,714.16 21.24 9.79 5,501.50 5,418.50 1,392.73 175.30 2,363,862.04 272,314.23 0.67 1,400.69 MWD+SC+sag(3) 5,776.78 21.46 9.40 5,559.82 5,476.82 1,415.20 179.10 2,363,884.44 272,318.46 0.42 1,423.35 MWD+SC+sag(3) 5,839.53 20.47 12.03 5,618.42 5,535.42 1,437.26 183.26 2,363,906.42 272,323.05 2.18 1,445.62 MWD+SC+sag(3) 5,900.70 20.63 11.93 5,675.70 5,592.70 1,458.27 187.72 2,363,927.33 272,327.90 0.27 1,466.85 MWD+SC+sag(3) 5,962.49 20.84 11.09 5,733.48 5,650.48 1,479.70 192.08 2,363,948.68 272,332.68 0.59 1,488.51 MWD+SC+sag(3) 6,023.20 20.96 10.79 5,790.20 5,707.20 1,500.97 196.19 2,363,969.86 272,337.20 0.26 1,509.98 MWD+SC+sag(3) 6,086.10 21.31 9.83 5,848.87 5,765.87 1,523.28 200.25 2,363,992.09 272,341.68 0.78 1,532.50 MWD+SC+sag(3) 6,146.52 21.64 10.25 5,905.09 5,822.09 1,545.06 204.11 2,364,013.79 272,345.95 0.60 1,554.47 MWD+SC+sag(3) 6,209.02 19.76 10.74 5,963.56 5,880.56 1,566.78 208.13 2,364,035.43 272,350.39 3.02 1,576.39 MWD+SC+sag(3) 6,272.53 19.49 10.31 6,023.38 5,940.38 1,587.75 212.03 2,364,056.32 272,354.69 0.48 1,597.56 MWD+SC+sag(3) 6,335.03 19.29 9.69 6,082.33 5,999.33 1,608.19 215.63 2,364,076.68 272,358.68 0.46 1,618.17 MWD+SC+sag(3) 6,398.60 19.30 8.86 6,142.33 6,059.33 1,628.92 219.01 2,364,097.34 272,362.46 0.43 1,639.06 MWD+SC+sag(3) 6,459.32 19.41 10.89 6,199.62 6,116.62 1,648.74 222.47 2,364,117.10 272,366.29 1.12 1,659.06 MWD+SC+sag(3) 6,522.16 19.32 9.86 6,258.91 6,175.91 1,669.24 226.22 2,364,137.51 272,370.44 0.56 1,679.74 MWD+SC+sag(3) 6,583.63 20.15 10.75 6,316.76 6,233.76 1,689.66 229.94 2,364,157.86 272,374.55 1.44 1,700.34 MWD+SC+sag(3) 6,646.15 20.57 11.09 6,375.38 6,292.38 1,711.01 234.06 2,364,179.13 272,379.08 0.70 1,721.91 MWD+SC+sag(3) 6,707.83 21.01 11.41 6,433.04 6,350.04 1,732.49 238.33 2,364,200.52 272,383.76 0.74 1,743.60 MWD+SC+sag(3) 6,769.87 20.88 9.99 6,490.98 6,407.98 1,754.28 242.45 2,364,222.22 272,388.29 0.84 1,765.59 MWD+SC+sag(3) 6,831.53 20.56 8.99 6,548.66 6,465.66 1,775.79 246.04 2,364,243.67 272,392.30 0.77 1,787.29 MWD+SC+sag(3) 6,894.28 21.28 11.54 6,607.27 6,524.27 1,797.83 250.04 2,364,265.63 272,396.72 1.85 1,809.52 MWD+SC+sag(3) 6,956.42 20.98 12.23 6,665.23 6,582.23 1,819.75 254.66 2,364,287.45 272,401.76 0.63 1,831.68 MWD+SC+sag(3) 7,018.50 20.75 11.29 6,723.24 6,640.24 1,841.40 259.16 2,364,309.01 272,406.68 0.65 1,853.56 MWD+SC+sag(3) 7,081.03 20.46 10.57 6,781.77 6,698.77 1,863.00 263.34 2,364,330.53 272,411.26 0.62 1,875.37 MWD+SC+sag(3) 7,141.46 20.87 10.19 6,838.31 6,755.31 1,883.98 267.18 2,364,351.43 272,415.51 0.71 1,896.54 MWD+SC+sag(3) 7,204.21 21.39 11.50 6,896.84 6,813.84 1,906.20 271.44 2,364,373.55 272,420.19 1.12 1,918.97 MWD+SC+sag(3) 7,265.30 21.04 11.01 6,953.79 6,870.79 1,927.88 275.75 2,364,395.15 272,424.92 0.64 1,940.87 MWD+SC+sag(3) 7,327.96 20.73 10.36 7,012.34 6,929.34 1,949.83 279.90 2,364,417.01 272,429.48 0.62 1,963.03 MWD+SC+sag(3) 7,390.13 21.50 11.23 7,070.33 6,987.33 1,971.83 284.09 2,364,438.93 272,434.10 1.34 1,985.24 MWD+SC+sag(3) 7,451.99 20.72 11.03 7,128.04 7,045.04 1,993.69 288.39 2,364,460.70 272,438.82 1.27 2,007.31 MWD+SC+sag(3) 7,513.63 21.17 12.12 7,185.61 7,102.61 2,015.27 292.82 2,364,482.19 272,443.66 0.97 2,029.12 MWD+SC+sag(3) 7,576.56 20.71 11.99 7,244.38 7,161.38 2,037.27 297.52 2,364,504.09 272,448.77 0.73 2,051.36 MWD+SC+sag(3) 7,638.08 21.53 11.33 7,301.77 7,218.77 2,058.97 301.99 2,364,525.71 272,453.67 1.39 2,073.30 MWD+SC+sag(3) 7,699.13 21.37 11.01 7,358.59 7,275.59 2,080.88 306.32 2,364,547.53 272,458.41 0.32 2,095.42 MWD+SC+sag(3) 7,761.50 20.84 9.79 7,416.78 7,333.78 2,102.96 310.37 2,364,569.53 272,462.89 1.10 2,117.71 MWD+SC+sag(3) 7,824.33 21.23 10.07 7,475.42 7,392.42 2,125.18 314.26 2,364,591.67 272,467.20 0.64 2,140.11 MWD+SC+sag(3) 7,886.06 20.71 12.76 7,533.06 7,450.06 2,146.83 318.63 2,364,613.23 272,471.98 1.77 2,161.98 MWD+SC+sag(3) 7,948.70 20.14 12.71 7,591.76 7,508.76 2,168.15 323.45 2,364,634.45 272,477.21 0.91 2,183.56 MWD+SC+sag(3) 7,994.24 19.62 11.85 7,634.59 7,551.59 2,183.28 326.74 2,364,649.52 272,480.79 1.31 2,198.86 MWD+SC+sag(3) 8,021.68 19.08 11.22 7,660.48 7,577.48 2,192.19 328.56 2,364,658.39 272,482.78 2.11 2,207.86 MWD+SC+sag(3) 8,082.71 19.05 10.39 7,718.16 7,635.16 2,211.77 332.30 2,364,677.89 272,486.90 0.45 2,227.62 MWD+SC+sag(3) 5/1/2015 4:10:41PM Page 5 COMPASS 5000.1 Build 73 • • • • Halliburton Definitive Survey Report Company: Hilcorp Energy Company Local Co-ordinate Reference: Well KBU 22-06Y Project: Kenai Gas Field TVD Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Site: KGF 14-6 Pad MD Reference: Actual:KBU 22-06Y @ 83.00usft(Saxon 169(65GL+18 Well: KBU 22-06Y North Reference: True Wellbore: KBU 22-06Y Survey Calculation Method: Minimum Curvature Design: KBU 22-06Y Database: Sperry EDM-NORTH US+CANADA Survey ' Map Map Vertical MD Inc Azi TVD TVDSS +NI-S +El-W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 8,145.89 19.30 10.47 7,777.84 7,694.84 2,232.18 336.06 2,364,698.23 272,491.04 0.40 2,248.22 MWD+SC+sag(4) 8,208.37 19.23 10.36 7,836.82 7,753.82 2,252.45 339.78 2,364,718.43 272,495.16 0.13 2,268.68 MWD+SC+sag(4) 8,269.92 20.86 10.67 7,894.64 7,811.64 2,273.20 343.63 2,364,739.09 272,499.41 2.65 2,289.61 MWD+SC+sag(4) 8,332.07 21.73 10.81 7,952.54 7,869.54 2,295.37 347.84 2,364,761.18 272,504.04 1.40 2,312.00 MWD+SC+sag(4) 8,394.30 21.89 10.00 8,010.32 7,927.32 2,318.11 352.02 2,364,783.83 272,508.65 0.55 2,334.95 MWD+SC+sag(4) 8,456.51 21.89 9.41 8,068.04 7,985.04 2,340.97 355.93 2,364,806.61 272,512.99 0.35 2,358.00 MWD+SC+sag(4) 8,518.62 22.41 9.62 8,125.57 8,042.57 2,364.07 359.80 2,364,829.63 272,517.31 0.85 2,381.29 MWD+SC+sag(4) 8,581.46 19.46 11.17 8,184.26 8,101.26 2,386.15 363.83 2,364,851.63 272,521.76 4.78 2,403.57 MWD+SC+sag(4) 8,642.29 19.02 11.13 8,241.69 8,158.69 2,405.82 367.70 2,364,871.22 272,526.01 0.72 2,423.43 MWD+SC+sag(4) 8,704.72 20.06 10.27 8,300.52 8,217.52 2,426.34 371.58 2,364,891.66 272,530.28 1.73 2,444.15 MWD+SC+sag(4) 8,766.58 21.49 9.41 8,358.36 8,275.36 2,447.95 375.32 2,364,913.20 272,534.44 2.36 2,465.95 MWD+SC+sag(4) 8,827.79 21.77 9.18 8,415.26 8,332.26 2,470.22 378.97 2,364,935.39 272,538.51 0.48 2,488.39 MWD+SC+sag(4) 8,890.40 21.70 8.82 8,473.42 8,390.42 2,493.12 382.59 2,364,958.22 272,542.57 0.24 2,511.47 MWD+SC+sag(4) 8,951.14 22.51 9.21 8,529.69 8,446.69 2,515.69 386.18 2,364,980.72 272,546.59 1.36 2,534.21 MWD+SC+sag(4) 9,014.12 23.02 8.71 8,587.77 8,504.77 2,539.77 389.97 2,365,004.71 272,550.84 0.87 2,558.47 MWD+SC+sag(4) 9,075.69 23.42 8.99 8,644.35 8,561.35 2,563.75 393.70 2,365,028.62 272,555.03 0.67 2,582.64 MWD+SC+sag(4) 9,138.52 22.01 10.12 8,702.30 8,619.30 2,587.68 397.72 2,365,052.46 272,559.51 2.35 2,606.76 MWD+SC+sag(4) 9,200.59 22.30 10.14 8,759.79 8,676.79 2,610.72 401.84 2,365,075.42 272,564.07 0.47 2,630.00 MWD+SC+sag(4) 9,261.75 21.26 12.20 8,816.59 8,733.59 2,632.98 406.23 2,365,097.59 272,568.88 2.11 2,652.49 MWD+SC+sag(4) 9,325.61 19.43 12.88 8,876.46 8,793.46 2,654.65 411.04 2,365,119.17 272,574.11 2.89 2,674.41 MWD+SC+sag(4) 9,387.88 19.92 12.87 8,935.09 8,852.09 2,675.09 415.71 2,365,139.51 272,579.17 0.79 2,695.09 MWD+SC+sag(4) 9,448.71 19.35 12.04 8,992.39 8,909.39 2,695.05 420.12 2,365,159.38 272,583.97 1.04 2,715.27 MWD+SC+sag(4) 9,511.22 19.59 12.29 9,051.32 8,968.32 2,715.42 424.52 2,365,179.66 272,588.75 0.41 2,735.87 MWD+SC+sag(4) 9,572.63 20.13 12.02 9,109.08 9,026.08 2,735.81 428.91 2,365,199.97 272,593.53 0.89 2,756.49 MWD+SC+sag(4) 9,634.55 20.12 12.30 9,167.22 9,084.22 2,756.64 433.40 2,365,220.70 272,598.41 0.16 2,777.54 MWD+SC+sag(4) 9,697.03 19.87 12.15 9,225.93 9,142.93 2,777.52 437.92 2,365,241.49 272,603.34 0.41 2,798.65 MWD+SC+sag(4) 9,759.01 18.85 12.49 9,284.41 9,201.41 2,797.59 442.30 2,365,261.48 272,608.10 1.66 2,818.95 MWD+SC+sag(4) 9,820.42 19.84 12.47 9,342.35 9,259.35 2,817.45 446.70 2,365,281.25 272,612.88 1.61 2,839.04 MWD+SC+sag(4) 9,882.72 20.04 12.18 9,400.91 9,317.91 2,838.21 451.23 2,365,301.91 272,617.81 0.36 2,860.03 MWD+SC+sag(4) 9,944.69 20.51 12.38 9,459.04 9,376.04 2,859.19 455.80 2,365,322.80 272,622.78 0.77 2,881.25 MWD+SC+sag(4) 10,006.69 20.91 12.73 9,517.04 9,434.04 2,880.60 460.57 2,365,344.11 272,627.96 0.68 2,902.89 MWD+SC+sag(4) 10,068.61 21.15 11.85 9,574.83 9,491.83 2,902.31 465.30 2,365,365.72 272,633.10 0.64 2,924.85 MWD+SC+sag(4) 10,131.52 21.95 11.67 9,633.35 9,550.35 2,924.93 470.00 2,365,388.25 272,638.24 1.28 2,947.71 MWD+SC+sag(4) 10,165.88 21.98 11.14 9,665.21 9,582.21 2,937.53 472.55 2,365,400.80 272,641.02 0.58 2,960.44 MWD+SC+sag(4) 10,200.00 • 21.98 11.14 9,696.85 • 9,613.85 2,950.06 475.01 2,365,413.28 272,643.73 0.00 2,973.09 PROJECTED to TD brian.wheeler@halliburton.ud,w+...wm,..M..ew•,a'"-' DOM w......wwwibu°oncorn Checked By: cor.•m,3 .1 «W Approved By: `ar aylor@ha'°burton.com �.�„ °,,,ps,rw Date: 5/1/2015 4:10:41 PM Page 6 COMPASS 5000.1 Build 73 • • Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. KBU 22-06Y Date 9-Apr-15 County Kenai Peninsula Borough State Alaska Supv. Shane Barber/Doug Yessak CASING RECORD TD 1530.00 Shoe Depth: 1524.59 PBTD: 1437.56 Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 103/4 BTC WFD 1.89 1,524.29 1,522.71 2 Jnts 10 3/4 45.5 L-80 BTC 83.60 1,480.90 1,439.11 Fit Clr 10 3/4 BTC WFD 1.55 1,439.11 1,437.56 35 103/4 45.5 L-80 BTC 1,350.32 1,437.56 87.24 Pup jt 10 3/4 45.5 L-80 BTC 20.33 87.24 66.91 1 jt 10 3/4 45.5 L-80 BTC 41.76 66.91 25.15 Hanger w/pup 10 3/4 45.5 L-80 BTC Seaboard 2.75 25.15 22.40 Landing jt 22.40 22.40 0.00 Totals Csg Wt.On Hook: 52,000 Type Float Collar: Model 402 No.Hrs to Run: 9.5 Csg Wt.On Slips: 32,000 Type of Shoe: Bull Nose/303 Casing Crew: WFD Fluid Description: 8.9 ppg Spud Mud Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: 0 Centralizer Placement: 2 bowspring on shoe jnt,1 centralizer middle bakerlok jnt, 14 centralizers every other jnt(17 total) CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 10 Volume pumped(BBLs) 42 Lead Slurry Type: Extended Density(ppg) 12 Volume pumped(BBLs) 110 Mixing/Pumping Rate(bpm): 5 Tail Slurry Type: Conventional Density(ppg) 15.2 Volume pumped(BBLs) 47 Mixing/Pumping Rate(bpm): 5 N Post Flush(Spacer) Type: Density(ppg) Rate(bpm): Volume: ce LL Displacement: Type: Spud Mud Density(ppg) 8.9 Rate(bpm): 4.5 Volume(actual/calculated): 138.5/138 FCP(psi): 400 Pump used for disp: SLB Plug Bumped? x Yes No Bump press 800 Casing Rotated? Yes X No Reciprocated? Yes X No %Returns during job ei ii Cement returns to surface? Yes x No Spacer returns? X Yes No Vol to Surf: 38.5 Cement In Place At: 17:40 PM Date: 4/9/2015 Estimated TOC: 56 Method Used To Determine TOC: Use final lift pressure versus calculated lift pressure along with mud push returns at surface. Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tall Slurry w Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): y Post Flush(Spacer) 0 o Type: Density(ppg) Rate(bpm): Volume: NDisplacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? _Yes No Bump press Casing Rotated? Yes _No Reciprocated? Yes_No %Returns during job Cement returns to surface? Yes_No Spacer returns? Yes_No Vol to Surf: n Cement In Place At: Date: Estimated TOC: .t)y` Method Used To Determine TOC: WELLHEAD �b b Make Seaboard Type Multibowl Serial No. Size 11" W.P. 3000 c Test Head To 3100 PSIG 15 MIN tested OK � t Remarks: This particular report pertains to the surface Casing and Cement. Perform top job. Pumped 18 bbts 128 lead cmt. 10.5 returned to surface. AOGCC inspector Lou Grimaldi witnessed top job operations. • • Hilcarp Energy Company CASING&CEMENTING REPORT Lease&Well No. KBU 22-06Y Date 23-Apr-15 County Kenai Peninsula Borough State Alaska Supv. Rance Pederson CASING RECORD TD 8028.00 Shoe Depth: 8012.77 PBTD: 7928.13 Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top Shoe 75/8 BTC WFD 1.64 8,012.77 8,011.13 2 Jnts 7 5/8 29.7 L-80 BTC 81.63 8,011.13 7,929.50 Flt Clr 7 5/8 BTC WFD 1.37 7,929.50 7,928.13 35 7 5/8 29.7 L-80 BTC 1,402.20 7,928.13 6,525.93 1 RA Marker 7 5/8 29.7 L-80 BTC 38.66 6,525.93 6,487.27 162 7 5/8 29.7 L-80 BTC 6,465.50 6,487.27 21.77 1 Pup Joint 7 5/8 29.7 L-80 BTC 2.22 21.77 19.55 Hanger 103/a^xi5/a° 0.55 19.55 19.00 Totals Csg Wt.On Hook: 217,010 Type Float Collar: Model 402 No.Hrs to Run: 17 Csg Wt.On Slips: Type of Shoe: Bull Nose/303 Casing Crew: WFD Fluid Description: 9.9 ppg 6%kcl/polymer,PV 10,YP 16 Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: 0 Centralizer Placement: 1 bowspring every other joint(90),up to 1015' CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 10.3 Volume pumped(BBLs) 45.5 Lead Slurry Type: LiteCRETE Density(ppg) 11 Volume pumped(BBLs) 244 n Mixing/Pumping Rate(bpm): 4.5 Tail Slurry Type: Conventional Tail Density(ppg) 15.8 Volume pumped(BBLs) 29.5 Mixing/Pumping Rate(bpm): 4 y Post Flush(Spacer) 6- Type: Density(ppg) Rate(bpm): Volume: Li Displacement: Type: 6%KCL Mud Density(ppg) 10 Rate(bpm): 6 Volume(actual/calculated): 367/364 FCP(psi): 1100 Pump used for disp: Schlumberger Plug Bumped? _Yes X No Bump press Casing Rotated? Yes X No Reciprocated? Yes X No.,_� %Retumsduring job 0 Cement returns to surface? Yes Spacer returns? Yes— Vol to Surf: Cement In Place At: 17:40 Date: 4/23/2015 Estimated TOC: 3,765 Method Used To Determine TOC: Previous Drilling Loss Depth Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry w Type: F.. Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): o Post Flush(Spacer) o Type: Density(ppg) Rate(bpm): Volume: co Displacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? _Yes No Bump press Casing Rotated? _Yes _No Reciprocated? Yes - No %Retumsduring job Cement returns to surface? Yes_No Spacer returns? Yes_No Vol to Surf: Cement In Place At Date: Estimated TOC: Method Used To Determine TOC: WELLHEAD Make Seaboard Type MBS System Serial No. Size 11 W.P. 5000 Test Head To 5000 PSIG 15 MIN Yes OK Remarks: This particular report pertains to the Intermediate Casing and Cement i Hilcorp Energy Company CASING&CEMENTING REPORT Lease&Well No. KBU 22-06Y Date 19-May-15 County KPB State Alaska Supv. Rance Pederson CASING RECORD TD 10200.00 Shoe Depth: 10184.00 PBTD: 10065.00 Casing(Or Liner)Detail Setting Depths No.of Jts. Size Wt. Grade THD Make Length Bottom Top SHOE 5" DWC/C Weatherford 1.81 10,183.68 10,181.87 2 5" 18 1-80 DWC/C US STEEL 82.14 10,181.87 10,099.73 Float collar 5" DWC/C Weatherford 1.85 10,099.73 10,097.88 1 5" 18 1-80 DWC/C US STEEL 30.88 10,097.88 10,067.00 Retainer 5" EZ Drill 2.00 10,067.00 10,065.00 1 5" 18 L-80 DWC/C US STEEL 8.97 10,065.00 10,056.03 123 5" 18 L-80 DWC/C US STEEL 5,015.66 10,056.03 5,040.37 Swell Packer 5" 18 L-80 DWC/C Baker 20.99 5,040.37 5,019.38 122 5" 18 L-80 DWC/C US STEEL 4,998.60 5,019.38 20.78 Pup Joint 5" 18 L-80 DWC/C US STEEL 2.27 20.78 18.51 Hgr 5"x 10.75" DWC/C Seaboard 0.51 18.51 18.00 RKB 18 18.00 18.00 0.00 Totals Csg Wt.On Hook: 165,283 Type Float Collar Weatherford 402E No.Hrs to Run: 17 Csg Wt.On Slips: Type of Shoe: Weatherford 303 Casing Crew: Weatherford Fluid Description: 11.8 ppg 6%KCL/Polymer,PV13,YP 16 Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: Centralizer Placement: 60 AT 41'F/shoe to 7921.11'MD CEMENTING REPORT Preflush(Spacer) Type: Mud Push II Density(ppg) 13 Volume pumped(BBLs) 27 Lead Slurry Type: `�� /3S ''�'{ %. Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): / S Tail Slurry 1-.`.> Type: EzBlok Tail 2 nn aDensity(ppg) 15.3 Volume pumped(BBLs) 132 Mixing/Pumping Rate(bpm): 3 S�v Post Flush(Spacer) ..--------- Type: Density(ppg) Rate(bpm): Volume:IX u Displacement: Type: 6%KCL Density(ppg) 11.8 Rate(bpm): 3 Volume(actual/calculated): 45/45 FCP(psi): 2600 Pump used for disp: SLB pump truck Plug Bumped'? Yes X No Bump press ,�,-,;^'I- Casing Rotated? Yes X No Reciprocated? _Yes X No %Returns during job 80 r'4, Cement returns to surface? X Yes No Spacer returns? Yes X No Vol to Surf: .5 bbls cement,no spacer Cement In Place At: 14:19 Date: 5/18/2015 Estimated TOC: 5,219 Method Used To Determine TOC: Volume of cement pumped and displaced Preflush(Spacer) Type: Density(ppg) Volume pumped(BBLs) Lead Slurry Type: Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): Tail Slurry w Type: F Density(ppg) Volume pumped(BBLs) Mixing/Pumping Rate(bpm): o Post Flush(Spacer) o Type: Density(ppg) Rate(bpm): Volume: y Displacement: Type: Density(ppg) Rate(bpm): Volume(actual/calculated): FCP(psi): Pump used for disp: Plug Bumped? _Yes No Bump press Casing Rotated? _Yes _No Reciprocated? _Yes_No %Retums during job Cement returns to surface? Yes_No Spacer returns? Yes_No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Post Job Calculations: Calculated Cmt Vol©0%excess: 83.7 Total Volume cmt Pumped: 132 Cmt returned to surface: 0.5 Calculated cement left in wellbore: 131.5 OH volume Calculated: 43.76 OH volume actual: Actual%Washout: • • KBU 22-06Y Days vs Depth 0 500 KBU 22-06Y Actual 1000 __„-__ KBU 22-06Y Plan 1500 2000 2500 3000 3500 4000 4500 r 5000 a v 5500 a 3 0 6000 a 6500 7000 7500 8000 - 8500 9000 9500 10000 10500 11000 0 5 10 15 20 25 30 35 40 45 50 Days • • KBU 22-06Y MW vs Depth 0 KBU22-06Y Plan I1000 KBU 22-06Y Actual 2000 3000 4000 5000 z 0▪ 6000 v ai ca w 7000 8000 9000 10000 11000 12000 8.0 9.0 10.0 11.0 12.0 13.0 14.0 Mud Density(ppg) • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT ta.Test: Jj Initial U Annual U Special lb.Type Test: ❑Stabilized U Non Stabilized U Multipoint ❑Constant Time ❑Isochronal J Other: Nodal 2.Operator Name: 5.Date Completed: 11.Permit to Drill Number: Hilcorp Alaska, LLC 5/30/2015 215-044 3.Address: 6.Date TO Reached: 12.API Number: 3800 Centerpoint Drive,Suite 1400,Anchorage,AK 99503 4/28/2015 50-133-20650-00-00 4a.Location of Well(Governmental Section): 7.KB Elevation above MSL(feet): 13.Well Name and Number: Surface: 1196'FWL,420'FSL,Sec 6,T4N,R11W,SM,AK 84 Kenai Beluga Unit(KBU)22-06Y Top of Productive Horizon: 8.Plug Back Depth(MD+TVD): 14.Field/Pool(s): 2039'FNL, 1557'FWL,Sec 6,T4N,R11W,SM,AK 10,065'MD/9,571'TVD Total Depth: 9.Total Depth(MD+TVD): Kenai Gas Field/Tyonek Gas Pool 1 1907'FNL, 1585'FWL,Sec 6,T4N,R11W,SM,AK 10,200'MD/9,697'TVD 4b.Location of Well(State Base Plane Coordinates NAD 27): 10.Land Use Permit: 15. Property Designation: Surface: x- 272112.27 y- 2362472.99 Zone- 4 N/A FEE A028142 TPI: x- 272612.88 y- 2365281.25 Zone- 4 16.Type of Completion(Describe): Total Depth: x- 272643.73 y- 2365413.28 Zone- 4 7-5/8"Production String,Perforated 17.Casing Size Weight per foot,lb. I.D.in inches Set at ft. 19.Perforations: From To 10-3/4" 45.5#/L-80 1,524' 9,812'-9,847' 18.Tubing Size Weight per foot, lb. I.D.in inches Set at ft. 5" 18#/L-80 4.276" 10,184' 20. Packer set at ft: 21.GOR cf/bbl: 22.API Liquid Hydrocardbons: 23.Specific Gravity Flowing Fluid(G): 5,019 N/A N/A N/A 24a. Producing through: 24b. Reservoir Temp: 24c.Reservoir Pressure: 24d.Barometric Pressure(Pa): Q Tubing ❑ Casing 165 F° 2200 psia @ Datum 9226 TVDSS 14.7 psia 25.Length of Flow Channel(L): Vertical Depth(H): Gg: %CO2: %N2: %H2S: Prover: Meter Run: Taps: N/A N/A 0.56 0.45 0.47 0 26. FLOW DATA TUBING DATA CASING DATA Prover Choke Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow No. Line X Orifice psig Hw F° psig F° psig F° Hr. Size(in.) Size(in.) 1. X 2. X 3. X 4. X 5. X Basic Coefficient Pressure Flow Temp. Gravity Factor Super Comp. Rate of Flow No. (24-Hour) 4 hwPm Pm Factor F Factor 01 Mcfd Fb or Fp Ft 9 Fpv 1. 1040 3035 2 742 3464 3. 444 3740 4 , 185 3860 5. Temperature for Separator for Flowing No. PrT Tr z Gas Fluid Gg G 1. - 0.929 2. 0.946 3. 0.966 Critical Pressure 673 4. 0.985 Critical Temperature 345 5. Form 10.421 Rev. 7/2009 CONTINUED ON REVERSE SIDE Submit in Duplicate • • Pc Pct P1 3192 pf2 10188864 No. Pt Pt2 Pc2 -Pt2 Pw Pw2 Pc2-Pw2 Ps Ps2 Pf2-Ps2 1. 1040 1081600 9107264 2. 742 550564 9638300 3. 444 197136 9991728 4, 185 34225 10154639 5. 25. AOF (Mcfd) 4,414 n 1 Remarks: I hereby certify that the fore ing is true and correct to the best of my knowledge. SignedTitle Reservoir Engineer Date % f4�jy t DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producin face were reduced to zero psia Fb Basic orifice factor Mcfd/ Pm Fp Basic critical flow prover or positive choke factor Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= 14Z dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil(60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet(TVD) L Length of flow channel, feet(MD) n Exponent(slope)of back-pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back-Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. 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NNnN:,rr.r rr:r:,.,.,•+.r.sr •Q• .sr is PP 1.,Y .Tu tiJJ ��II y to•��VA"e�i�r7i� Sr01HHHHOO41O�i S g9 r T r-x"B 4 h��.��OrvYhO.rrmnhPrim= a. LL V2 LL •�\ MN�guN•-I•i H.,.rNNNNNn K•n n of •^(3 Ot oar PP ABY�H• 3 4 od 12/17/2015 • KBU 22-06YAOGCC 10-421 Submitted 12-17-15.215-044] KBU 22-06Y AOGCC 10-421 Submitted 12-17-15 [PTD 215-044] Donna Ambruz [dambruz@hilcorp.com] Sent: Thursday, December 17, 2015 10:33 AM To: AOGCC Reporting (DOA sponsored) Cc: Jeremy Mardambek [jmardambek@hilcorp.com]; Chad Helgeson [chelgeson@hilcorp.com]; Larry Greenstein [I greenstei n@hi l corp.com] Attachments:KBU 22-06Y AOGCC 10-421 Su—l.pdf (582 KB) FYI — Per AOGCC Industry Guidance Bulletin 15-001 dated October 2, 2015: ...Effective immediately all forms listed above [10-421 (Gas Well Open Flow Potential Test Report)] and any correspondence related to these forms should be submitted to the following email: aogcc.reportingPalaska.gov... Please see the attached 10-421 (Gas Well Open Flow Potential Test Report) for KBU 22-06Y [PTD 215-044]. Thank you. Donna Ambruz Operations/Regulatory Tech Kenai Asset Team Hilcorp Alaska, LLC 3800 Centerpoint Drive,Suite 1400 Anchorage,AK 99503 907.777.8305- Direct 907.777.8310- Fax dambruzPhilcorp.com https://webm ai la.alaska.gov/owa/?ae=Item&t=IPM.Note&i d=RgAAAABKLne2zgP4SoM kepOhCxbSBwBUvQ964rjQTgYgn3632GdIAAAAhhLyAABU vQ964rj QT... 1/1 OF • • I//7; . THE STATE Alaska Oil and Gas uA TAsKA Conservation Commission.>tx � 333 West Seventh Avenue � w ht GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Stan Porhola Operations Engineer I S J Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Pool—Tyonek Gas Pool 1, KBU 22-06Y Sundry Number: 315-309 Dear Mr. Porhola: 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, ,),--t.4.1 4-- Cathy P oerster Chair DATED this 2-7 day of May, 2015 Encl. • • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION MAY 2 0 2015 APPLICATION FOR SUNDRY APPROVALS a s VI-70-5 20 MC 25.280 ACS 1.Type of Request: Abandon❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Suspend❑ Perforate E Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Coil N2 0 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development ❑✓ • 215-044 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ - 6.API Number. Anchorage,Alaska 99503 50-133-20650-00 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510a Kenai Beluga Unit(KBU)22-06Y Will planned perforations require a spacing exception? Yes ❑ No 0 . 9.Property Designation(Lease Number): 10. Field/Pool(s): A-028142 " Kenai Gas Field-Beluga/Upper Tyonek Pool-Tyonek Gas Pool 1 ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 10,200 9,697 10,065 9,571 N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 136' 16" 136' 136' Surface 1,524' 10-3/4" 1,524' 1,506' 5,210 psi 2,470 psi Intermediate 8,012' 7-5/8" 8,012' 7,651' 6,890 psi 4,790 psi Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): N/A N/A 5" 18.0#/L-80 10,184' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Swell Packer; N/A 5,019'MD-4,853'TVD;N/A 12.Attachments: Description Summary of Proposal ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development ❑✓ Service Li 14.Estimated Date for 15.Well Status after proposed work: 5/29/2015 Commencing Operations: OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS E • WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown Li Abandoned ❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email sporholaAhilcorp.com Printed Name Stan Porhola Title Operations Engineer Signature 44 (_ Phone 907-777-8412 Date 5/2.40//c COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: k S-3 09 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes CI No 0 Subsequent Form Required: / — U f C�,,z,tiJ Perls) Approved by: / COMMISSIONERAPPROVED BY THE COMMISSION Date:s–2 7 /S -0 "(S. Grry-dve:d. 1,17411NALor Submit Form and Form 10-403 ise 5/2015 12 months from the date of approval. achments in Duplicate RBDMS_`i� ' MAY 2 8 2015 . ) z/7,/",-." '6 >� 7/ , 's • • Well Prognosis Well: KBU 22-06Y Date: 5/20/2015 Hilcorp Alaska,LL Well Name: KBU 22-06Y API Number: 50-133-20650-00 Current Status: New Gas Well Leg: N/A Estimated Start Date: 5/29/15 Rig: N/A Reg.Approval Req'd: 10-403 Sundry Number: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 215-044 First Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(C) Second Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228(C) Current Bottom Hole Pressure: — 0 psi @ 9,697' TVD (No open perforations) Maximum Expected BHP: — 1,900 psi @ 9,334' TVD (Based on offset wells, EMW= 3.9ppg) Max. Allowable Surface Pressure: — 967 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Kenai Gas Field well KBU 22-06Y was drilled as a Grass roots monobore completion in May 2015 to target gas sands in the Beluga/Upper Tyonek and Tyonek formations. The purpose of this work/sundry is to perforate the well for the initial completion in the Tyonek D sands (Beluga/Upper Tyonek Gas Pool and Tyonek Gas Pool 1). Notes Regarding Wellbore Condition • Plan to tag with slickline before running E-line. • Will run Cement Bond Log before perforating. • Pressure test IA(5" x 7-5/8") to 2,500 psi and chart for 30 min. " • Pressure test tubing (5") to 9,000 psi and chart for 30 min (Pre-Frac Test for future potential Frac). • MIRU Coil Tubing and perform BOPE Test to 250/4,500 psi to displace well over to Nitrogen. • Well will be displaced with Nitrogen before initial perforating at+/- 1,000 psi SITP. E-Line Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 250 psi low/4,000 psi high. Note that the well is pressurized with Nitrogen approximately 1,000 psi. a. Tree connection is 9.5" OTIS. 2. If necessary, bleed Nitrogen pressure down as requested by the RE to establish a drawdown on the formation. RA markers are shown on attached schematic. 3. RIH and perforate the following intervals: Pool Zone Sands Top (MD) Btm (MD) FT SPF Beluga/Upper Tyonek Gas Pool Tyonek UT4E . ±8,675' ±8,778' 103' 6 Beluga/Upper Tyonek Gas Pool Tyonek UT4F ±8,779' ±8,843' 64' 6 Beluga/Upper Tyonek Gas Pool Tyonek 84-6 - ±8,877' ±9,023' 146' 6 Beluga/Upper Tyonek Gas Pool Tyonek 86-2 ` ±9,026' ±9,273' 247' 6 Beluga/Upper Tyonek Gas Pool Tyonek D-1 . ±9,312' ±9,353' 41' 6 • Well Prognosis Well: KBU 22-06Y Date:5/20/2015 Hilcorp Alaska,LL Tyonek Gas Pool 1 Tyonek D-2 • ±9,452' ±9,499' 47' 6 Tyonek Gas Pool 1 Tyonek D-3B . ±9,812' ±9,847' 35' 6 Tyonek Gas Pool 1 Tyonek D-4 • ±9,988' ±10,014' 26' 6 a. Bleed tubing pressure to 1,000 psi before perforating. b. Proposed perfs 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 Cement Bond Log (pending Tie-in log). e. Use Gamma/CCL/to correlate. Utilize Press/Temp tool if available. f. Record tubing pressures before and after each perforating run. g. CO 510A(no well spacing restrictions within 1500' of the unit boundary) 4. RD E-line. 5. Turn well over to production. E-line Procedure (Contingency): 6. If zone produces sand and/or water. 7. MIRU E-line, PT lubricator to 4,000 psi Hi, 250 Low. a. Tree connection is 9.5" OTIS. b. SITP will be+/- 1,000 psi (remaining gas or applied Nitrogen pressure). 8. RIH and set 5" CIBP at depth above zone. Or 9. RIH and set 5" Casing Patch across the zone. 10. Perforate next sand using steps outlined above (1-5). a1-sands listed on proposed completion schematic). y.2i.(y Attachments: As-built Well Schematic Proposed Well Schematic . . Kenai Gas Field II Well: KBU 22-06Y ACTUAL SCHEMATIC PTD: 215-044 API: 50-133-20650-00 Hilcorp Alaska,LLC CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 7 16" 1 Conductor— 16" Driven * 109 X-56 Weld 15.00" Surf 136' , `, 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 1,524' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012' 10-3/4" • a TUBING CBL TOC l`s� 5" Production 18 L-80 DWC/C-HT 4.276" Surf 10,184' 3,670' ,, , , , IA 2 ® , Est TOC « ,* 5,219' OPEN HOLE/CEMENT DETAIL 110 BBL of 12.0#lead cement RA p depths: «� «K', 10-3/4" 47 BBL of 15.2#tail cement(Perform Top Job from 89.6'w/18 bbl of 12#cmt) P i,. ' 244 BBL of 11.0#LiteCRETE lead cement 8,004' .� ` R„ 7_5/8" 7-5/8" 29.5 BBL of 15.8#tail cement e' € TOC 3,670'(CBL dated 4/29/15) t 4' 4. 5" 132 BBL's of 15.3#EZ Blok cement. Squeeze thru retainer. TOC 5,219'Calculated 'at t' 8,293' � JEWELRY DETAIL ,i.lir No. Depth ID OD Item Y rJ 1 18' 4.276" 11.00" Tubing Hanger 2 5,019' 4.276" 6.875" 10 ft Swell Packer(Water Swell) 8,536' 3 10,065' 3.710" Cement Retainer } , PERFORATION DETAIL 8,826' 4 Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) Date Size Status t 4 0 40 9,072' 9,359' 9,605' yy t 9,891' rWell Filled w/ « 8.5 ppg 3%KCL 5" ,� PBTD=10,065' MD/9,571'TVD TD=10,200' MD/9,697'ND Downhole Revised: 5/18/15 Updated by STP 5/20/15 MOW 0 S . Kenai Gas Field 11 Well: KBU 22-06Y PROPOSED SCHEMATIC PTD: 215-044 API: 50-133-20650-00 llilcorp Alaska,LLC CASING DETAIL Size Type Wt Grade Conn. ID Top Btm 16" 1 Conductor- 136' 16" Driven 109 X-56 Weld 15.00 Surf r tJ «to 10-3/4" Surf.Csg 45.5 L-80 BTC 9.950" Surf 1,524' 7-5/8" Intermediate 29.7 L-80 BTC 6.875" Surf 8,012' 44,1 10-3/4 ,SiaTUBING 5" Production 18 L-80 DWC/C-HT 4.276" Surf 10,184' CBL TOC ' 3,670' 'X 2 to, Est TOC a , !=, 5,219' OPEN HOLE/CEMENT DETAIL RA Tag =�, 10-3/4" 110 BBL of 12.0#lead cement depths: ' i , ',' 47 BBL of 15.2#tail cement(Perform Top Job from 89.6'w/18 bbl of 12#cmt) ,� t 244 BBL of 11.0#LiteCRETE lead cement 8,004' "..mi >rs:47-g/8„ 7-5/8" 29.5 BBL of 15.8#tail cement ` �' TOC 3,670'(CBL dated 4/29/15) # 5" 132 BBL's of 15.3#EZ Blok cement. Squeeze thru retainer. TOC 5,219'Calculated 1p 1 di t4 v ,,,,i A 8,293' ,ry JEWELRY DETAIL k'a No. Depth ID OD Item Y 4 1 18' 4.276" 11.00" Tubing Hanger 2 5,019' 4.276" 6.875" 10 ft Swell Packer(Water Swell) 8,536' 3 10,065' - 3.710" Cement Retainer 4t: UT4E PERFORATION DETAIL 01 8,826' UT4F Sands Top(MD) Btm(MD) Top(ND) Btm(ND) Date Size Status t UT4E • 8,675' 8,778' 8,273' 8,369' Proposed 84-6 UT4F • 8,779' 8,843' 8,370' 8,429' Proposed iti 84-6 • 8,877' 9,023' 8,461' 8,596' Proposed 9,072' 86-2 86-2 • 9,026' 9,273' 8,599' 8,827' Proposed 4;, , . D-1 • 9,312' 9,353' 8,864' 8,902' Proposed , 0-1 D-2 • 9,452' 9,499' 8,995' 9,040' Proposed 9,359' 4 D-3B • 9,812' 9,847' 9,334' 9,367' Proposed A D-2 D-4 • 9,988' 10,014' 9,500' 9,524' Proposed 9,605' D-3B 9,891' L D-4 3, s PBTD=10,065' MD/9,571'TVD TD=10,200' MD/9,697'ND Downhole Proposed Updated by STP 5/20/15 • • X15 0144 11 Seth Nolan Hilcorp Alaska, LLC 64 t GeoTech 3800 Centerpoint Drive `L Anchorage, AK 99503 Tele: 907 777-8308 11.i..".1. Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATE 05/29/2015 RECEIVED MAY 21 2015 To: Alaska Oil & Gas Conservation Commission Meredith Guhl AOGCC A Petroleum Geology Assistant !'1 VV 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 22-06Y 5 boxes: Dry Cuttings Transmitted herewith are cuttings from KBU 22-06Y WELL SAMPLE INTERVAL KBU 22-06Y 400'—3800' KBU 22-06Y 3800'—6070' KBU 22-06Y 6070'—8028' KBU 22-06Y 8028'—9430' KBU 22-06Y 9430'—10200' Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Rec`ved ey/ Date: RECEIVED yt.)CIL MAY 21 2015 AOGCC • • u ZZ—Cy Zas—o421-o Regg, James B (DOA) From: Rance Pederson - (C) <rpederson@hilcorp.com> yg(ls Sent: Sunday, April 26, 2015 7:31 PM ? 9 To: DOA AOGCC Prudhoe Bay; Regg, James B (DOA) Cc: Paul Mazzolini; Luke Keller; Monty Myers Subject: Saxon 169, Notice of BOPE Use Attachments: Saxon 169 Notice of BOP Use.docx Please see the attached document. We are currently at 8584' working our way back to bottom at 9107'. Rance Pederson Drilling Foreman Kenai Gas Field 907-776-6776 1 • • 111 Sa 'on Notice of BOP Use • Date/Time: 4/26/2015 at 14:00 hrs. • Well: KBU 22-06Y • Location: Kenai Gas Field, Pad 14-6, Mile 10.5 K-Beach Road • PTD: 215-044 • Rig Name: Saxon 169 • Operator Contact: Rance Pederson at 907-776-6776 / rpederson@hilcorp.com • Operation Summary: Drilled 6 %" production hole to 9107' md. Current mud weight was 10.9 ppg, background gas was 64 units. Pulled up hole for a planned wiper trip from 9107' to Intermediate casing shoe at 8012'. With bit at 8214' we had to make up topdrive due to overpull and tight hole. Attempted to pump up the hole but had to backream to clean up open holees ction. Racked one stand back and during make up of topdrive on next stand, at 8169', noted we had flow that increased to 6 bblsJhour. Decision was made to trip 16 stands back to bottom, circulating bottoms up every 5 stands, to circulate out any influx. With topdrive made up at 8169' we started a circulation. At bottoms up, flow show went from 31% to 63% and Driller shut down pump then shut in well, while sounding the well control horn. • BOPE Used: Upper variable rams (2 7/8" x 5") and auto choke valve. • Reason For BOPE Use: Had drilling mud erupt through rotary table, flow show increased from 31% to 63% in a matter of seconds and a 6 bbl gain to pits. • Actions Taken: Monitored SICP and SIDP, lined up and circulated one full circ through choke and poorboy degasser vessel to circ out gas. After one full circ at slow pump rate, checked for flow and had no flow. Opened well and circulated to 11.1 ppg mud. After flow check, continued to trip in hole to bottom. • Action To Be Taken: At this time, we plan to drill the last 1,000' to TD, then test all components used during shut-in, prior to running Production Casing. wP�orT ,s THE STATE Alaska Oil and Gas 4, ,,;,- �� ofALASlia Conservation Commission ` • ,;) 333 West Seventh Avenue uz_' _ Anchorage, Alaska 99501-3572 :ITh„ I GOVERNOR BILL WALKER Main: 907.279.1433 OF ALAS*� Fax: 907.276.7542 www.aogcc.alaska.gov Monty M Myers 4 6 ,°Lig Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga Upper Tyonek and Tyonek Gas Pool 1, KBU 22-06Y Sundry Number: 315-218 Dear Mr. Myers: 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, Daniel T. Seamount, Jr. Commissioner DATED this / day of April, 2015 Encl. • RECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APR 10 2015 • APPLICATION FOR SUNDRY APPROVALS ®GCC 20 AAC 25.280 1.Type of Request: Abandon a Plug for Redrill ❑ Perforate New Pool a Repair Well❑ Change Approved Program a Suspend a Plug Perforations a Perforate ❑ Pull Tubing a Time Extension ❑ Operations Shutdown a Re-enter Susp.Wet a Stimulate a Alter Casing a Other: Top out Job on surface E. 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC. Exploratory a Development ❑✓ • 215-044• 3.Address: Stratigraphic ❑ Service a 6.API Number. 3800 Centerpoint Dr,Suite 1400 Anchorage AK 99503 50-133-20650-00-00 • 7. If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A • Will planned perforations require a spacing exception? Yes ❑ No aKenai Beluga Unit(KBU)22-06Y 9.Property Designation(Lease Number): 10.Field/Pool(s): • Unit Tract 26; FEE AO28142 ' Kenai Gas Field;Beluga Upper Tyonek;Tyonek Gas Pool 1 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 1530' 1512' 1530' 1512' N/A N/A Casing Length Size MD TVD Burst Collapse Structural • Conductor 118 16 118 118 N/A N/A Surface 1524 10-3/4 1524 1507 5210 2480 Intermediate Production Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): NA NA NA NA NA Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): NA NA 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program a BOP Sketch a Exploratory ❑ Stratigraphic a Development aService a 14.Estimated Date for 15.Well Status after proposed work: 4/10/2015 ✓ Commencing Operations: Oil a Gas ❑✓ • WDSPL a Suspended ❑ 16.Verbal Approval: Date: - –10•i S WINJ a GINJ a WAG a Abandoned ❑ Commission Representative: L,) y� � GSTOR a SPLUG El17. I hereby certify that the foregoing is true find correct to the best of my knowledge. Contact Monty Myers Email mmyers a(�hilcorp.com Printed Name Title Monty M Myers Drilling Engineer Signature Phone 907-777-8431 Date 4/10/2015 COMMISSION USE ONLY Conditions of approval: Notify CommissirTh- t a representative may witness Sundry Number: 15 - 21IC Plug Integrity V BOP Test a Mechanical Integrity Test a Location Clearance a Other: Spacing Exception Required? Yes a No Elf Subsequent Form Required: / C)" 407 <G"""" w ( J APPROVED BY �/#°- Approved by: \ COMMISSIONER THE COMMISSION Date: _ L )461-1/___c _ �/A. o� p 7•'/S Submit Form and Form 10-403(Revised 10/2012 tioot rd �tl ]moi for 12 months from the date of approva At5hments in Duplicate BJ //r"'\��d 4/4370----- 4'. /3.'s DM&� APR 1 8 2015 0 • • Monty Myers Hilcorp Alaska, LLC • Drilling Engineer P.O. Box 244027 Anchorage,AK 99524-4027 Tel 907 777 8431 Email mmyers@hilcorp.com Iiilenrp th, kca.i.LC 4/10/2015 RECEIVED Commissioner APR 10 2015 Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue AOGCC Anchorage, Alaska 99501 Re: KBU(Kenai Beluga Unit)22-06Y(PTD#: 215-044) Dear Commissioner, Enclosed for review and approval is a 10-403 "Change to Approved Procedure" sundry for KBU 22-06Y. This sundry was prepared to incorporate the changes to the 10-3/4"casing cement procedure as a result of not getting cement returns to surface during the primary cement job. Changes include: 1. Temp log run across surface casing. 2. CBL run across surface casing. 3. Conduct top out job of 10-3/4" surface casing. Included is a summary of operations thus far and plan forward. If there are any questions,please contact myself at 907-777-8431. Sincerely, Monty Myers Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 • • Well Prognosis Well: KBU 22-06Y Flilcory Alaska,LI) Date:4/10/2015 Well Name: KBU 22-06Y API Number: 50-133-20650-00-00 Current Status: Cased and cemented Leg: Estimated Start Date: Ongoing Rig: Saxon #169 Reg.Approval Req'd? 10-403 Date Reg. Approval Rec'vd: Regulatory Contact: Cody Dinger 777-8389 Permit to Drill Number: 215-044 First Call Engineer: Monty Myers (907) 777-8431 (0) (907) 538-1168 (C) Second Call Engineer: Luke Keller (907)777-8395 (0) AFE Number: 1510328D Brief Well Summary KBU 22-06Y was spudded on 4-7-2015. 13-1/2" surface hole was drilled to 1530' MD. 10-3/4" surface pipe was run and cemented on 4-9-2015. Cmt returns were not observed at surface. ./ 15:00—18:00 4-9-2015: Wet lines w/5 bbls H20, P/T lines to 4500 psi (good), Rig pump 42 bbls 10# mudpush II, turn over to SLB, drop btm plug. Pump- 110 bbls, 12#,Type: extended, 2.43 yield, lead cement. 47 bbls 15.2#, Type: conventional, 1.22 yield, tail cement. Pump cmt @ 5 BPM avg. Drop top plug. SLB displace w/8.9#spud mud, 4.5 BPM avg. Pumped 138.5 (calculated 138) bbls to bump. Bumped w/FCP 400 @ 1.7 BPM, psi up to 800 psi, held 5 min, bled back.5 bbls, floats held. Maintained 100% returns throughout job, 38.5 bbls mud push returned to surface, no cement observed @ surface via annulus valves. CIP @ 17:40. 08:30 4-10-2015: Run Temp log. Estimated TOC from log at—75 ft. ✓ 'x09:00 4-10-2015: Contact AOGCC representative Lou Grimaldi to discuss plan forward. Received verbal approval from Lou to tag TOC w/top out string. Wait for Lou to arrive on location before proceeding with cement top out job. Top Out Procedure: 1. RIH &tag TOC in 10-3/4" x OH annulus with 3/"top out tubing. 2. Pump 12.0 ppg top out cement until cement returns observed at surface (with AOGCC witness) 3. Proceed with N/U BOPE and testing (BOPE test waived by Jim Regg via email @ 4/9/15 @ 08:52) If unable to tag TOC: 1. R/U wireline equipment and run CBL across surface casing. 2. Consult with AOGCC to develop plan to effectively isolate surface casing annulus. • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, April 10, 2015 11:02 AM To: 'Monty Myers' Subject: RE: KBU 22-06Y 10-403 Top Job p,rb Monty, Sundry looks good ..verbal approval to proceed as proposed in sundry. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwartz@alaska.gov). From: Monty Myers [mailto:mmyers(ahilcorp.com] Sent: Friday, April 10, 2015 10:35 AM To: Schwartz, Guy L (DOA) Subject: KBU 22-06Y 10-403 Top Job Good morning Guy, Attached is the paperwork required for the top job on KBU 22-06Y,a paper copy is also being sent over to you. We have Lou Grimaldi coming out to witness tagging TOC and for the top job. If anything else is required, please let me know. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell:907.538.1168 1 • • Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, April 10, 2015 8:41 AM To: 'Monty Myers' Cc: 'Regg, James B (DOA) (jim.regg@alaska.gov)' Subject: RE: Surface Cement on KBU 22-06Y PTD: 215-044 Monty, Please review guidance document 13-01 for our procedure. You will need to contact the inspector to witness. http://doa.alaska.gov/ogc/bulletins/bul 13-01.pdf Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended recipient of this e-mail,please delete it,without first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226)or(Guy.schwarfz@alaska.gov). From: Monty Myers [mailto:mmyers@hilcorp.com] Sent: Friday, April 10, 2015 6:33 AM To: Schwartz, Guy L(DOA); Regg, James B (DOA) Subject: Surface Cement on KBU 22-06Y PTD: 215-044 Good morning gentlemen, We did not get cement to surface last night on the 10-3/4" surface cement job (details below). We feel it is very close. We will be rigging up to run a temp survey this morning, and also running in with a spaghetti string to tag TOC and do a top job. We are estimating cement to be at 56'. Please let me know if an inspector needs to come out to witness the top job. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Shane Barber- (C) Sent: Thursday, April 09, 2015 7:51 PM To: Monty Myers Cc: Paul Mazzolini; Luke Keller Subject: KBU 22-06Y 1 • CIP &17:40. Did not get cmt back to surface. Pumped 42 bbls 10#mud push, 110 bbls 12# lead,47 bbls 15.2 tail. Displaced w/8.9#spud mud. Saw some interface @ 87 bbls and at 100 bbls into displacement had good mud push to surface for a total of 38.5 bbls returned mud push to surface. Bumped plug on calculated 138.5 bbls. FCP 400 psi @ 1.7 BPM. Bled back .5 bbls and floats held. Calculated lift 360 psi for gauged hole (calculated to rig floor). SLB has 9000#of lead cement already blended in their yard we can use for top job(estimated 40 bbls available). 118'ft conductor, 1388'OH below conductor to shoe. Shane G. Barber I Drilling Foreman Hilcorp Alaska, LLC Kenai Gas Field Office:907-776-6776 Mobile:907-841-5208 sbarber@hilcorp.com 2 • • MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: April 12, 2015 P. I. Supervisor 7( 41' 31'� FROM: Lou Grimaldi SUBJECT: Surface Casing "Top Job" Petroleum Inspector Kenai Beluga Unit 22-06Y PTD 2150440 Hilcorp Alaska LLC Kenai Gas Field Friday, April 10, 2015: I witnessed the tag of top of cement (TOC) and subsequent pumping of "Top Job" cement to bring that level to surface on the surface casing annulus of Hilcorp well "Kenai Beluga Unit 22-06Y" in the Kenai Gas Field. I arrived to find the rig getting rigged up in preparation of pumping the cement. They would tag cement with 3/4" galvanized electrical conduit and pump cement through that. They had made a temperature log run prior to my arrival that indicated good heat of hydration up to a depth of approximately 80 ft. All measurements are corrected to ground level. The rig had already attempted to tag with the conduit but had problems getting in the narrow casing annulus (10 3/4" inside 16"). I inspected the top job pipe and suggested some modifications to the end and collars which was performed. The pipe was again run and made it to 71 ft. The pipe was reciprocated and rotated numerous times but would go no further. I had them circulate 2x hole volume, - good mud push was returned along with a rising pH. I again had them attempt to get deeper but with no progress agreed we could cement at this point. 18 bbl's of 12.3ppg lite cement was pumped with good solid returns of mud push. At 7 bbl's away clabbered cement came to surface which gave way to good indications of fresh cement. 14 bbl's away produced cement returns within 0.1 ppg of pumped blend then an additional 4 bbl's pumped gave good in/out weight. I feel a good top job was performed today. Attachments: None Non-Confidential 2015-0410_S urface_casing_topj ob_KBU_22-06Y_lg.docx 1 of 1 OF 771, • �w\��I�jcv THE STATE Alaska Oil and Gas o fALA V J��l T c 1 T � Conservation CommissionCommissionsion 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 -X"," Main: 907.279.1433 OF ALASI;"' Fax: 907.276.7542 www.aogcc.alaska.gov Monty M. Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek and Tyonek Gas Pools, KBU 22-06Y Hilcorp Alaska, LLC Permit No: 215-044 revised Surface Location: 1196' FWL, 420' FSL, SEC. 6, T4N, R11 W, SM, AK Bottomhole Location: 1617' FNL, 1306' FWL, SEC. 6, T4N, R11 W, SM, AK Dear Mr. Myers: Enclosed is the approved application for permit to drill the above referenced development well. This permit supersedes and replaces the permit previously issued for this well dated March 23, 2015. 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, 0 / P Cathy P. oerster Chair DATED this.0/ day of March, 2015. RE.ChiVtu STATE OF ALASKA 0SKA OIL AND GAS CONSERVATION COMMMAR 2 5 2015 ON PERMIT TO DRILL r(evisea � OC 20 AAC 25.005 A. .x. 1 a.Type of Work: 1 b. Proposed Well Class: Development-Oil ❑ Service- Winj ❑ Single Zone 0 1c.Specify if well is proposed for: Drill- s Lateral ❑ Stratigraphic Test ❑ Development-Gas s . Service-Supply ❑ Multiple Zone II Coalbed Gas ❑ Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blankets Single Well ❑ 11.Well Name and Number: Hilcorp Alaska, LLC Bond No. 022035244 Kenai Beluga Unit(KBU)22-06Y 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400 Anchorage AK 99503 MD: 10,200' • TVD: 9,563' ' Kenai Gas Field 4a. Location of Well(Governmental Section): 7. Property Designation(Lease Number): Beluga/Upper Tyonek Gas Pool t Surface: 1196'FWL,420'FSL,Sec 6,T4N,R11W,SM,AK Unit Tract 26;Fee AO28142 , Tyonek Gas Pool 1 . Top of Productive Horizon: 8. Land Use Permit: 13.Approximate Spud Date: 1189'FSL, 1148'FWL,Sec 6,T4N, R11W,SM,AK N/A 4/18/2015 Total Depth: 9.Acres in Property: 14. Distance to Nearest Property: 1617'FNL, 1306'FWL,Sec 6,T4N, R11W,SM,AK 2494.04 7,750'Unit Tract Boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: 84 ft 15.Distance to Nearest Well Open Surface: x-272112.27 y- 2362472.99 - Zone-4 GL Elevation above MSL: 65.5 ft • to Same Pool: 2604' 16. Deviated wells: Kickoff depth: 1,700 feet • 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 24 degrees Downhole: 4207 psi • Surface: 3251 psi . 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 13-1/2" 10-3/4" 45.5 L-80 Buttress 1,500' Surf Surf 1,500' . 1,500' Lead-553 ft3/Tail-376.8 ft3 9-7/8" 7-5/8" 29.7 L-80 BTC 8,100' Surf Surf 8,100' 7,630' Lead-1230 ft3/Tail-.9.-1-0-ft3 6-3/4" 5" 18 L-80 DWC 10,200' Surf Surf 10,200'. 9,563' 730 ft3 I 't t r" 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): Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plats BOP Sketch s Drilling Programs Time v.Depth Plot s Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report❑ Drilling Fluid Program s 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is truean correct. Contact Luke Keller C,/� EmailIkeller@hilcorp.com Printed Name Title Drilling Engineer Allir Signature ' Phone 907-777-8395 Date 3/25(2_06 Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number:Z/rj-QA./y (QyiSeci, 50-i33.-2Oc 0-00-00 Date: W2VZV/5 requirements. Conditions of approval: -"' If box is checked,well may not be used to explore for,test,or produce coalbed methane,gas hydrates,or gas contained in shales: Q Other: y=., )� S4 / c/' fe,, t Samples req'd: Yes❑ No2 Mud log req'd:Yes No0 7� r A HZS measures: Yes 111No�' Directional svy req'd:Yes No[1]3 C 6z_ g /•1. (T- I rel '-'-'c �^ �' Spacing exception req'd: Yes ❑ No rQi, Inclination-only svy req'd:Yes Nos D.A.,, (�-/-ee Cotta /ex- 4Ipp "-P ( �L ..44c Z`•J.��3�JC 11) �_Z i iic1 / P APPROVED BY - 3/ Approved by. - COMMISSIONER THE COMMISSION Date: // /5 ORIGIN3 -Lf21c Form 10-401(Revised 10/2012) This permit is valid for 4 mb�LFts frote of approval(20 AAC 25.005(g)) Attachments in Duplicate • Luke Keller • Hilcorp Alaska, LLC Drilling Engineer P.O. Box 244027 Anchorage, AK 99524-4027 Tel 907 777 8395 Email Ikeller@hilcorp.com Hilcorp Alaska,lit: March 25th, 2015 RECEIVED Commissioner MAR 2 5 2015 Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 AOGCC Re: KBU 22-06Y PTD revision Dear Commissioner, Enclosed for review and approval is a revision to the Permit to Drill for KBU 22-06Y. We request to drill the intermediate section of the well to 8,100' (was 6,320'). The drilling program is updated and attached to reflect this request as well as associated cement volumes. In addition, the"as-built" surface location plat is attached and differs from the"as-staked" surface plat by>10 ft. A revised directional plan is included that reflects this slight change of surface location. The directional plan was also slightly modified to reduce anti-collision concerns of previous plan. The most recent • version (WP 3.0) is attached. There is no change to TPH or BHL. If you have any questions, please don't hesitate to contact myself at 777-8431 or Paul Mazzolini at 777-8369. Sincerely,2/6 Luke Keller Drilling Engineer Hilcorp Alaska, LLC Page 1 of 1 • • Hilcorp Alaska, LLC Kenai Beluga Unit KBU 22-06Y Drilling Program Kenai Field Revision 1 March 24, 2015 • • 111 KBU 22-06Y Drilling Procedure Hilcorp Ala ka.LLt: 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 29 17.0 Cement 7-5/8" Cement Procedure 31 18.0 Drill 6-3/4"Hole Section 34 19.0 Run 5"Production Long String 40 20.0 Cement 5"Production Long String 43 21.0 RDMO 45 22.0 Perf and Frac 45 23.0 BOP Schematic 46 24.0 Wellhead Schematic 47 25.0 Days Vs Depth 48 26.0 Formation Tops 49 27.0 Anticipated Drilling Hazards 50 28.0 Saxon Rig 169 Layout 53 29.0 FIT Procedure 54 30.0 Choke Manifold Schematic 55 31.0 Casing Design Information 56 32.0 9-7/8"Hole Section MASP 57 33.0 6-3/4"Hole Section MASP 58 34.0 Spider Plot(NAD 27)(Governmental Sections) 59 35.0 Surface Plat(As Built)(NAD 27) 60 36.0 Offset MW vs TVD Chart 61 37.0 Drill Pipe Information 62 • • KBU 22-06Y Drilling Procedure Hilrorp Alaska,LLC 1.0 Well Summary Well Kenai Beluga Unit(KBU)22-06Y Pad&Old Well Designation KBU 22-06Y is a grass roots well on the existing 14-6 pad Planned Completion Type 5"production tubing Target Reservoir(s) Tyonek/Beluga Planned Well TD,MD/TVD 10,200' MD/9,557' TVD • PBTD,MD/TVD 10,100' MD/9,472' TVD Surface Location(Governmental) 1196' FWL,420' FSL, Sec 6,T4N,R11 W, SM,AK • Surface Location(NAD 27) X=272112.27,Y=2362472.99 Surface Location(NAD 83) Top of Productive Horizon 1189'FSL, 1148'FWL, Sec 6, T4N, Rl 1 W, SM,AK (Governmental) TPH Location(NAD 27) X=272163.22, Y=2363142.07 TPH Location(NAD 83) BHL(Governmental) 1617'FNL, 1306'FWL, Sec 6,T4N,R11 W, SM,AK BHL(NAD 27) X=272370.16,Y=2365708.17 BHL(NAD 83) Maximum Anticipated Pressure in 4207 psig , psig(Downhole) Maximum Anticipated Pressure in 3251 psig psig(Surface) AFE Number 1510328D AFE Drilling Days 27 AFE Completion Days AFE Drilling Amount $4.3MM AFE Completion Amount Work String 4-1/2" 16.6# S-135 CDS-40 (Rental Saxon String) KB Elevation above MSL 84.0 ft GL Elevation above MSL 65.6 ft BOP Equipment 11"5M T3-Energy Annular BOP 11" 5M T3-Energy Double Ram 11" 5M T3-Energy Single Ram Page 2 Revision 1 March,2015 • KBU 22-06Y Drilling Procedure Ililrorp Ala':ka,LLC 2.0 Management of Change Information Hilcorp Alaska, LLC litl;.,.,,14 ..Llr� Changes to ApprovedPermit to Drill Date: 3-24-2015 Subject: Changes to Approved Permit to Drill for KBU 22-06Y File#: KBU 22-06Y Drilling Program Any modifications to KBU 22-06Y Drilling Program will be documented and approved below. Changes to an approved APD will be communicated to the BLM and AOGCC. Sec Page Date Procedure Change Approved Approved By BY 15.8 26 3/24/15 Changed Intermediate casing setting Depth to 8100' MM TMD 31-33 57-59 3124/15 Updated MASP Calculation for new depth MM 17 32 3124/15 Updated cement volumes based on new depths MM Page 3 Revision 1 March, 2015 • • KBU 22-06Y Drilling Procedure Hilonrp Ala ka,III'. 3.0 Tubular Program: Hole OD (in) ID(in) Drift Conn Wt Grade Conn Burst Collapse Tension Seco, (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" 5" 4.276" 4.151" 5.563" 18 L-80 DHT/C 9910 10500 422 4.0 Drill Pipe Information: Hole OD (in) ID (in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) (in) ft) (psi) (psi) (k-lbs) 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 1 March, 2015 • KBU 22-06Y Drilling Procedure Hilrur1i iIa.kx,LLC 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; mmyers@hilcorp.com, lkeller@hilcorp.com, & cdinger@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: Julieanna Orczewska: 0:907-777-8444 • Notify Drlg Manager&Drlg Engineer: 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 2. Luke Keller: 0: 907-777-8395 C: 832-247-3785 3. 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 lkeller@hilcorp.com, mmyers@hilcorp.com& cdinger@hilcorp.com 5.5 Casing and Cmt report • Send casing and cement report for each string of casing to lkeller@hilcorp.com, mmyers@hilcorp.com &cdinger@hilcorp.com Page 5 Revision 1 March,2015 . ! 0 KBU 22-06Y Drilling Procedure Itii",,.th...L,,Lir 6.0 Planned Wellbore Schematic Kenai Gas Field II PROPOSED Well; KBU 22-06Y PTD: 000-000 API: 50-000-00000-00 CASING DETAIL ...It_ -:e. Type WI Grade Conn. Top atm 16.`'4 1 Y Conductor— :6" Driven to Set :39 X-56 Weld _5" Surf 130' I Depth 13-3:4' Surf.Csg 45.5 L-53 Buttress 9.95" Surf 1503' 1(_i a- 7-5'6Intermediate 23.7 1.-53 ETC 6.875" Surf 8,103' TOC.900' 5' T,6. ',",. Production "6 L-53 C^1C,C HT 4.276" Surf 10,200` H: '-='-t:^ Ls. _ . .. 4`4_Dr155trip1 -...3-:/2' :3-3.:." S.8—9.3 ppg 4-1/2" 9-7.'5' 7-515' 9—9.5 ppg 4-1/2„ 5--3, 5' :3—11.5 Goa 4-1/2„ JEWELRY DETAIL -. _-.. 10 DD Item _ :8' ..276" __ Tubing Hanger `- 2 5,533' 4.276" 6.575" 13ft Swell Packer(Water Swell) .. iii 2 EXPECTED FLUID MQ TVD Pressure Steri,- IIIIIMMIIVI 3.706 3.591 250 7 S , 44` Stork" 5 2 IMTIMEIF 4.358 4,193 1500 Ster4rr3 Poo 6 4.679 4,489 200 LI ,oerBe.'&,Qa 1111111M1 49'2 4.742 900 Pf9+dfe Be.'a;aa 111.01Wrif5.635 5.373 1000 Lo''AerBe;.Loa 6,420 6.098 1000 L`aoerT,,c ok Ihmusw,:. 7,693 2500 i 7,c-=;ek L! 9.340 8.777 2000 L nr.ek D2 allIIIIIIIIMIM 9.507 8.930 800 T, .ek 1?3Q 111111111M 9 860 9.253 2400 T,oek L31 ,. � 10 084 9.958 700 PBTD=10,107'-tit 9.472'TVD TD=10,200'I t 9.563'TVD Page 6 Revision 1 March, 2015 S KBU 22-06Y Drilling Procedure fhb orl a{a l n LLC 7.0 Drilling / Completion Summary KBU 22-06Y is a 10,200' MD/9,563' 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—200 acre area of the Tyonek D-3B sand and an 80 acre area LB/UT in the southwestern flank of the KGF structure. The reserves for this particular LB/UT location are booked,however,the primary objective(Tyonek D-3B)is not booked and could have significant reserves/rate potential. The base plan is a directional wellbore with a kick off point at 1700' MD. Maximum hole angle will be 24 deg. Vertical section will be 3176 ft. Drilling operations are expected to commence approximately April 18th, 2015. ' 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. 4. N/D conductor riser,N/U &test 11"x 5M T3-Energy BOP. 5. Drill 9-7/8"hole section to 8,100' 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 5"production casing. 7. N/D BOP,N/U tree, RDMO. Reservoir Data Acquisition Program: 13-1/2" Surface hole: Mud logging only,no LWD ' 9-7/8"Intermediate Hole: Mud logging+ GR/Res/Den/Neu LWD, E-line RFT ' 6-3/4"Production Hole: Mud logging+GR/Res/Den/Neu LWD . Page 7 Revision 1 March,2015 1110 • KBU 22-06Y Drilling Procedure Nikon!.Alaska,IA.0 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 KBU 22-06Y. 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 5/5 min (annular to 50%rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • Diverter waiver request requested due to the recent drilling of KBU 32-08 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 KBU 22-06Y. Page 8 Revision 1 March, 2015 • KBU 22-06Y Drilling Procedure HiIcorp Alaska,LIC Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 13-1/2" • No diverter Installed N/A • 11"x 5M T3-Energy(Model 7082)Annular BOP • 11"x 5M T3-Energy Double Ram Initial Test:250/3500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 9-7/8"&6-3/4" • 11"x 5M T-3 Energy Single Ram • 3-1/8"5M Choke Line Subsequent Tests: • 2-1/16"x 5M Kill line 250/3500 • 3-1/8"x 2-1/16"5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon(12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event (BOPs utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running & cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email:guy.schwartz(aialaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email: victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format: http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone: 907-793-1236 (During normal Business Hours) Notification/Emergency Phone: 907-659-2714(Outside normal Business Hours) Page 9 Revision 1 March, 2015 S KBU 22-06Y Drilling Procedure Hileorp Alaeka,LLC 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at a minimum of 111' 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. • TSM 1000 mud pumps are rated at 3633 psi (85%) /333 gpm (100%) with 5-1/2" liners. Page 10 Revision 1 March, 2015 • • KBU 22-06Y Drilling Procedure Hilrorp Alaska,LK.f. 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 up 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: KENAI GAS FIELD SECTION 6, T4N, R11 W, S.M., AK ( NORTH EDGE PADF....T ;1. SCALE i .n, To'0 BERM TOP DG ; ' , \::..• � 1 K.B.U. 1�4-:�. f , N 2362292. N.1 It,0 K.U. 2111 111 E 1412069.33 �,, , - \ I+ ® 4, ® N 2362277.93 E 141279.36 K.B.U. 11-7 > , x11.83 N 2362291.62 218.27 E 1412017.90 K.T.U. 13-6 N 2362230.91 K.U. 14 k C 44 E 1412232.97 Si K.D.U.-,1 E 141162091 Lvo [C] N 2362219.39 O WATER WELL K.B.U.31-7 E 1411864.73 8^CASING N 2362208.96 ® E 1412250.17 , ,,,oi , K.U.21-7 N 2362168.92 E 1411956.82 K.B.U.23-7 0K.U.31.7X N 2362132.82 N 2362132.58 E 1412039.38 `✓ E 1412268.38 ,»„» K.B.U.24-6 K.U.14-6 RD 0 N 2362115.07 wy N 2362061.36 E 1412202.55 12.3' 1411904.54 K.B.U.23X-6 - - N 2362091.92 , ,..x. u »pr w E 1412150.71 K.G.F. PAD 14-6 DI CALM. la..12•1•61KII MD 1. "" 4 A 30 _....cam PAD �....., ....._w... Page 11 Revision 1 March,2015 • S II KBU 22-06Y Drilling Procedure llilrorp Ala.ka,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 RATA 411111.11111111111 . 1 HDBS OI1C1GliC 13450 3030 13500 463 1:.' 6-58'RED 1.00 1.00 2 8"SperryD11 Labe 55-5.3 410 8.000 5.000 121.06 8 558'REG 31.83 ....32.83 Slaty iaer 13 375 3 6"Drectional Collar i 7.850 3.530 147.40 8 6-58"REG 8.88 41..71 4 r biline Stnbdixmr 91,S)12 1x19"gauge 8.000 2 830 12125 149.87 B 13.5!6"REG 380 45-51 T 5 6"1M HOC(FolserI 8.150 4:000 145.20 8 6.5.8'REG 940 ...... 54.91 6 8"Nan Mag Flax Collar 7.600 2.875 132.48 8 858"REG 30.00 6411 7 8'Non Mag Flee Collar 7,070 2 975 135 34 B 6.541"REG 30 CO 114 91 6 X-06-5/8"Reg P X 4-07 IF 8 7.375 2.875 123..46 8 4.1121F 2.25 117.16 9 6.75"Nan Mag Flax Color 6.730 2.675 99.11 8 4-112 IF 30.00 147.16 10 6.75'Non Mag Flex Cater 6.700 3.00 96.06 8 4.1221E 30.00 177.16 11 X-0 4.172"IF P X CDS-403 6.520 2.750 93.54 B 4.5'CDS 40 2.75 179.91 12 6Joins 4-1,2"95105 COS-40 4.500 2.750 41,00 165.x} 36491 13 X-0 CDS-40 P X 4 1.R'IF 5 8.52.1 2.750 93.54 B 4.1 tr 1F 2.75 367.66 14 6141'Wea1l erl3rd DAH Jar 6.250 2 250 91.01 B 4-tl2"IF 3203 39956 15 X-0 4-112 IF P X CDS-40 8 6.520 2.150 93.54 8 4.5"COS-40 2.75 402.41 16 13 J(li»4.112'SWOP 005.40 4.500 2.750 41.00 400.00 80241 TIAN 802.41 BIT DATA Sit Number Naz/as :ix14,34r16 Sit Size (6n) : 13.500 TM (in2) :0.7394 Manuf*Cuter :HOBS Dull Grade in . Model :OHCIORC Dull Grade Out , WM Number MOTOR DATA Motor Number __......... ......... Said (deg)_.. : 1.15 OD(In) :8.000 Nosales (32nd) : 0.0 Manufacturer :Sperry Online Avg DM Preen , Model :SperryDrl Cumul Cir Nra . Serial Number 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 Page 12 Revision 1 March, 2015 I 41111 KBU 22-06Y 11 Drilling Procedure lideorp 11.3 Primary bit will be the Security 13-1/2" QHC1GRC Milled Tooth Bit. These are available from Halliburton. 13 1/2" C . (343mm) QH _ 1 GRC PRODUCT SPECIFICATIONS ADC Cede 117W Total Tooth Count 64 kiage Itnw Tooth Count 36 Journal Angle 33' Offset(1(16") 6 Jet Nozzle Types Standard 8324-4 Extended 3lItu Center Jet (If Center Jetted)501813 Ti.Connection 6-5,1"(API Reg.1 Recommended Make-Up Torque* 28001812C00 Ft*lbs, Bit Weight 1Boxed) 260 Lbs.018 Kg.) Bit Breaker (Matitlegacya) 183777,64408 smr PRODUCT FEATURES • New patented Diamoralm Claw*,tooth bit design • Proprietary Iiiamond 11iCH2000ffl full touch Itordfecing oin 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 motor applications. • Innovative mechanical pressure compensating system prow ides reliable pressure equalization and relief for maximum bearing and Neill life, a Raised tungsten carbide inserts and proprietary hat-diking provides maximum arm protection in abrasive and directional applications while minimizing drill string torque. • QuadPaek Plus Series incorporates its successful*longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. • Center jet feature to prevent bit balling problems Material#540030 •Calculmium kmziionmr umrnundatimm frurn API aul manulltriumrs. 2014 Halliburton.All rights reserved.Sates of Halliburton products and ser ices will be in accord solely with the tefIlli and conditions contained in the contract between Halliburton and the cusion)er that is applicable to the sale. Page 13 Revision 1 March, 2015 • KBU 22-06Y Drilling Procedure Hil.orp Ala.ka,11€ 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. 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/ 1500' 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 1 March,2015 i KBU 22-06Y Drilling Procedure 1184°r1 Alncka,LLC 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 80-1500' 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 1 March,2015 i KBU 22-06Y Drilling Procedure lith M I)A la.kn.1.1.0 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 1 March, 2015 • • KBU 22-06Y Drilling Procedure Hilrorp.Alaska,LLC. Tenaris Casing and Tubing Performance Data Choose pipe size,wall thickness and steel grade to view API connection options and performance data. Size 7. Wall ' Grade ' Connection Unit Pipe Body Data GEOMETRY A Nominal OD 10.750 in Wall Thickness 0.400 in API Drift Diameter 9.794 in Nominal Weight 45.50 lbstft Nominal ID 9.950 in Alternate Drift Diameter 9.875 in Plain End Weight 44.26 Amin Nominal Cross Section 13.006 sq in PERFORMANCE Steel Grade 180 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 Turns 1 PERFORMAICE 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 I Contact Us I 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 1 March,2015 S KBU 22-06Y Drilling Procedure IIiI. p:�Ia ka,td 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 1 March, 2015 • KBU 22-06Y Drilling Procedure HiMorp Alaska,11A 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: 120' x .106 bpf= 12.7 71 16" Conductor x 10-3/4" 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 TAIL: (1500'-1000') x .065 bpf x 1.5 = 58.5 328 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 90 x .096 bpf = 8.7 48.8 10-3/4" Shoe track: Total TAIL: 67.2 376.8 Page 19 Revision 1 March,2015 • • KBU 22-06Y Drilling Procedure IIilrorp 4ia.ka,LLC 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 5 HR 3 HR Thickening 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 S002 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 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 1/2 shoe track volume. Total volume in shoe track is 8.7 bbls. Page 20 Revision 1 March, 2015 • • KBU 22-06Y Drilling Procedure H ileorp 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 lkeller@hilcorp.com, mmyers@hilcorp.com & cdinger@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Revision 1 March, 2015 • S KBU 22-06Y Drilling Procedure II I.orp 11a-ka,111 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 T3-Energy BOP as follows: • BOP configuration from Top down: 11"x 5M T3-Energy annular BOP/11"x 5M T3-Energy Model 6011i double ram/11"x 5M mud cross/I1"x 5M T3-Energy Model 6011i 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 5/5 min. Test annular to 250/2500 psi for 5/5 min. • Ensure to leave "B" section side outlet valves open during BOP testing so pressure does not build up beneath the test plug. 14.5 R/D BOP test assy. 14.6 Dump and clean mud pits, send spud mud to G&I pad for injection. 14.7 Mix 9 ppg 6% KCl/EZ MUD/BDF-499 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. • TSM 1000 mud pumps are rated at 4250 psi (85%) /275 gpm (100%) with 5" liners. Page 22 Revision 1 March,2015 • • KBU 22-06Y Drilling Procedure Hilrorp Alaska,U,C 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 item , III If .;. i 1. th (ft) Ell HDBS MVb'FM Hit 6O t... tam Y 6,5 P 4-1i1'lit€3 0.90 0.90 ma 7°SperryDril Lobe 71B.6.0 Mg 7.000 4.952 ® 93.13 1344/71F 27CO 27.90 .111 Stabilizer -_� '1.825 -- Ell 6 I4 Noii Mfg Float,Seib 6.500 ® 93.9611=1111111191211111 30.35 O 6 354'Int ai B1anAs 915113'gauger 6 770 207 9.625 100.56 6 4.112'IF 7.00 37.355 ® 6 a+A'DM Collar11111111111. 6.69011111111111 103 40 EZEZIMILMIll 46 60 MI 6 w4"FNR.P4 Celli - 6.720 2.000 ® 104.30 13 4.412°IF 14.00 60 80 ® 8 314'DGR Collar • 6.780 1920 ® 97,80 P 4-112'IF 840 8'800 6.750Ira 9.750 11133111231501 3.50 72.50 9 6 3,54'PV C)Collar 6.730 1935 ® 9330 B 4.1771F 500 77.50 10 6 314 tiCIM Collar 6.840 1.920 1.11. 101.70 1113MII 7.00 6450 ® 6 3V TM Collar 6.890 3250 _ 103.60 5 4-1,71F. 9.80 94.30 M 6-314"Non Mag f=lex Colter 6.759 2810 10082 B 4-1,'2`IF 3100 125,30 am 6-3,,4"Next Mag FM:X Collar IIIIMIIIIIII 6.750 2.810 - 10082 IIEEMIMI 31.00 156.30 El 6-314`Non Mag Flex Collar 6 750 2 810 100 82 8 4.112'IF 31)00 186 30 ® 6-314"Non Mag Flex Colles 11111111111111111. 6.750 2.610 100 82 =LI 30.00 216.30 16 X•A 4.112"IF P X CDS-40 B 6 523 2.750 ® 93.54 134 5"CDS 40 2.75 219.05 ® 6 Joints 4.112' 1•114000 CDS-40 4 500 2 687 ®�36.86 186 00 404 05 ari X-O CDS-44 P X 4 1.12'1F o 6.520 2.750 Mom Eamanimm 406.80 19 6-1!4'Weatherfo'd Hyd Jar 6 2550 7 2`550 01.01 5 4.1,7 IF 32.31 439.11 20 X-O 4-VT IF P X COS-4013 111111111111111. 6.520 2.750 ® 93.54 B 4.5"MS-40 NMI MIMI En 13 Joints 4.1,7 HLYDP COS40 4.500 2.687 _ 36.86 430.00 841.06 Taal 641.651 BIT DATA Bit Number Noufka >6x13 Sit Size Did : 9.875 TFA (i'121 0 7777 Manufacdtrgr : HUBS Dull Grade In :NEW Model ;iA1i85 Dull Grade Out Serial Humber . 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. Page 23 Revision 1 March, 2015 • 411, flDrilling 22-06Y Drilling Procedure Hiknelt A Imdia,ilk 15.6 Primary bit will be the Security 9-7/8" MM65. 9-7/8'. (251min) MM65 PRODUCT SPECIFICATIONS A Cutter Type SelectCuttet Si !AIX'Code M323 II Body Type MATRIX row Cutter C twill 46 '1- 4 Ill ' . Cutter Distributionlima auga * / * , FaCe a 24 ,; Gauge 12 0 4,4 da' Lip Drill 6 0 Number of Large Nozzles 6 -4- Number of Medi Ut14 NOZZka tI la. MI, Number of Small Nozzles 0 Number of Micro Nozzles 0 ... Number of Pods(Site) (I 104 t 411.,, Number of Replaceable Ports(Size) 0 Juni,Slot Area 4s4.1 in) 1611 "" Nortualued face V4Shurte 45.40% . , API Connection 4-142 IIEG.PIN Recommended Make Up Torque* 12,461-17,766 Ft*lbs. Nominal Dimensions** Make-Up Face to Nellie 10.81 in 27i mm Gauge Length 2.5 in 4 64 nun Sleeve Length 0 in-0 non Shwa Dianietet 6 in-152 nun Break Out Plate Hvlat,441.4egaey0 181954144040 Approximate Shipping Weight 250Lbs.-113Kg. SPECIAL FEATURES Up-Drill Cutters on Gagc Pads,1416"Relieved Gage Material#771827 *Bit specific weeiomridd mak-up torque is a funs-lion tif the bit C.U.and actual bit sub 0.D.unlined as qxci Pod in API RP7G Section ASU. "siresagn ttifildrik/ilns,ars fawning and tray%lay slightly on manufactured peodum.Ilaliihunon brill Bits and Sett iota inealels arc continuously rweivagti and refined Product specific:10mm 17111-Y change without notice. C 2013 Halliburton.All rights reserved.Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. www.balliburton.com Page 24 Revision 1 March, 2015 KBU 22-06Y ip IITDrilling Procedure Hiker'.Menke,LLC. 15.7 9-7/8"hole section hydraulic summary: ecurit DBSy BIT HYDRAULIC PROGRAM f Prepared For-1'd eorp k.0 324 ey.-Mark Clroulliel Date prepared-119,14 Operator-'t4ltc rp $ Well Namefelo-KOV32.00 8.+1 Type: PDC COntiactor-1 County,liana/ Bit Drerneter: 9.075 f 9urveyfAbitract.-a StalorCaunby•MAMA . .......,.._MO DA- 6400 R Mud%Nevili 1.5 ppg COMPONENTS 10 In, to I 1? P11! 22.cp -: 06059 9 951 1500 2 11, VP 25 107100115 n Hole 9 975 6440 3 1,, fioid Model rn..x.re Oar.,pmsca71,2: +, p 4 1c. Prow Rapt 500 gpm 5 11.Visa,Pump Proem _.. 400q,pei . 9 11'3 Surface equip.?2 7 Motor bypass? 8 TVI)?M5455 R ,: 9 4ofNozzle010j6 . ta....Cae-wee. •. s j_____ 10 ......,..._. Min.TFA 6.3634 tri Drill String, 1288.30 psi 47.62% Total TFA 07+7 in' Annulus: 78.10 psi 2.89% Jet Velocity 206.37 His : Surtace3" 77.46 psi 2.86% Press.Drop 361.62 psi : Special". 900 00 psi 33.27% Sit Hyd.Power 505.45 hp 815. 2,11..71 psi 13.37'Y. H.5.1. •377'1 hplinr Inspect Force 507.37 lid ECD 9.78 ppg T*IatiSPP. 1,psi I 100.00% OD ID Tool Joint t.engthl Cap, Pressure Loss DRILL STRING COMPONENTS in in 001 10, t1! bble PM Drill Ptpe(S)(CDS 40 Connections 4.5 2.820 6.375 3.5 5553' 78.05 50335 H111DP(CDS 40 connections,13 Jiel 4.5 2.88 6.25 2.55 403 2.80 101.00 Weatherford Hyd alar 1CO9 40) 6 2.25 6 2.25 31 0.15 32,50 HWOP(CDS 40 connections,6 Jts} 4,5 2.65 6.25 2.55 186 1,29 92.12 0-0 Sud(CDS 40 Bax It 4-152"If Pin) 6.5 2,75 6.6 2 754 0.03 1,76 4 Joints 6.314""NM Floe Drill Collars 6.75 2,013 6.75 2.5131 120 0.42 47.85 Integral BladoStabliiaer(5.75"Gauge} 0.75 2.75 6.75 2.75! 5 0.04 2.20 MTM 110C'Pulsar) 5.75 "".."..,••«» 8.75 '•'� , •"i WD 16 " 45.0.00 MWD HCUM Collar 6.75 1,42 6.75 1.42% 5 0.01 38.46 MWD-PWD Cotler 6.75 1.47 6.75 1.42.... 5 0.04 3$46 MWD EWRP4 i Gamma Collar 6.75 1.42 6:15 1 42 22 0,04 169.24 MWD Directional Collar 6.75 4.42 6.75 1.42 4 0.02 69.23 Integral BladeStabifraer(9.75'Gauge) 6.75 2.75 6.75 2.75( 5 0.04 2.20 Flout Sub 6.75 2.75 8.75 2.75, 3 0.02 1.32 7>.SperryDrtil Lobe 715-6.0 51g. 7 """'°""1 7 ,.•.,,,...( 2$ """""" 450.00 ANNULAR; Hole PFps 004 Length Cum. Cap. Annular, Critical Type of Presages Less. SECTIONS, vn h5.++ ft Depth 0015 Mtmin' Marin Flow - Casing, 9.95 4. 5 1500 1500 114.75 15581 303.43 L 10"81' Open Hole' 9.875 4.11 4058 5558 301.59 158.61 305.05 L 40"43 Open Hole 9.815 4.5, 403 5961 30.25 158.61. 305.05 L 4.01 Upon Hole 9.875.: $.25 3i 5992 1.16 208.66' 354.13 L 0.77 Open Hole 9.825 48 105 6175 13.96 158.01' 305.05 L 2.13 Open Hole 9.875 65 4 69112 0.21 221,75 364.5191 L 0.11 Open Hole 9.875 0.1'S 120 6302 6.06 235.89 375.49 L 4-00 Open Hole. 9:675 6,75; 5 6307 025 235 89 375 49 1. 0.17 Open Hole 9.075. 6.75. 15 6323 0 91 235 89. 375 49 1. 0.83 Open 1-1010 9.675 6.75 5 6328 0.25 235.89 37549 L 0.17 Open Hole; 9.875, 6.75 5 6333 035 235 89 375 49 L 0.17 Open Hole 9.8751 6.75 22 6355 1.11 235.59 375.49 L 0.73 Open Hole' 9.6751 6.75. 9 6364 0.45 235.89. 375.49 L 030 Open Hotel 9.875. 6.75 5 6349 0.25 235.89, 375.491 L 0.17 Open Halali 6.75' 3 6372 0.15 235.89 375.49 L 0.10 Open Hale 9.915' 71 26 6400 1.32 252.60 387.87 1. 1.18 i i Page 25 Revision 1 March, 2015 • • KBU 22-06Y Drilling Procedure II i.orp Ala.kn,li t.. 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%KC1/PHPA fresh water based drilling fluid. Properties: Mud Plastic MD Viscosity Yii pied. Weight Viscosity ' ," �� 1,500'- 8,100' 9.0—9.5 40-53 15-25 15.25 8.5-9.5 < 11.0 System Formulation: 6% KCL/EZ MUD/BDF-499 Coneentc 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(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 1 March,2015 • KBU 22-06Y Drilling Procedure Ililroxp Alaska,IAA 15.9 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray LWD functioning properly. 15.10 Continue in hole and tag TOC. Note depth tagged on AM report. 15.11 Drill out plugs and shoe track. Clean out rat hole and drill an additional 20' of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 12 ppg EMW. 15.14 Drill 9-7/8"hole section to 8,100' MD/7,630' 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. Page 27 Revision 1 March,2015 0 • II KBU 22-06Y Drilling Procedure IIde ort,.410--k0,Llf 15.15 Casing Point selection • KBU 22-06 is the closest offset to use for correlation to pick casing point. Below is the annotated GR+ gas +resistivity log. • • We want to set the 7-5/8" shoe into the TY 73-1. KBU 22-06 AM .mir _ KBU 22-06 _I -7,233 � � KBU 22-06Y ^��-7,255 /�IJP11. ti--4011A.16;;; L r & lipm__:...„...ge , riveummi 1 i Intermediate casing point in TY 73-1 shale at 7339'-7417' TVD (7760-7850 - 11 r "i MD) in proposed KBU 22-06Y It EWI __AlII _ v- I -11E =MI 111 it ri E Al 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 28 Revision 1 March,2015 • KBU 22-06Y Drilling Procedure Hi!carp Alaska,Li.0 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 on the deck prior to running. • Be sure to count the total # of joints on the deck before running. • Keep hole covered while R/U casing tools. • Record OD's, ID's, lengths, S/N's of all components w/vendor&model info. 16.3 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 1550' 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 29 Revision 1 March,2015 • s KBU 22-06Y Drilling Procedure Hilrorp.Alaska,LLC 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 30 Revision 1 March, 2015 i KBU 22-06Y Drilling Procedure Menrp Alnhka,LLC 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. • 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. 17.4 Pump remaining 35 bbls 10 ppg spacer and drop bottom plug. 17.5 Mix and pump slurry per below calculations: Section: Calculation: Vol(BBLS) Vol(ft3) LEAD: 9-7/8" OH x 7-5/8" csg: (7,600'- 3,000') x .038 bpf x 1.25 = 219 1230 Total Lead: 219 bbls 1230 ft3 TAIL: 500' x .038 bpf x 1.25 = 24 135 9-7/8" OH x 7-5/8" csg: TAIL: 7-5/8" Shoe Track: 90' x .046 bpf= 4.1 23 Total Tail: 28.1 bbls ft3 15.71-0 A-06"/c Page 31 Revision 1 March,2015 KBU 22-06Y Drilling Procedure Hi{rnrp Aln„ka,1.LC Slurry Information Lead Tail System LiteCRETE Conventional Density 11 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: • 8,100' x .0459 bpf= 372 bbls. • Displace with 10 ppg 6% KC1/Kla-Guard 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 32 Revision 1 March, 2015 S KBU 22-06Y Drilling Procedure Hiirnrr Alaska,Ile C 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 lkeller@hilcorp.corn, mmyers@hilcorp.corn & cdinger(a,hilcorp.corn. 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. Page 33 Revision 1 March,2015 • 11 KBU 22-06Y Drilling Procedure Hilror1 Alntika,LLC 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/Blind/Mud cross/VBR. 18.2 Test BOPs on 4-1/2" and 5"test joints. 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 Run CBL on 7-5/8"casing only if cement job did not go according to plan and TOC is in question. 18.6 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. 18.7 Drift& caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 18.8 Ensure TF offset is measured accurately and entered correctly into the MWD software. 18.9 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 34 Revision 1 March,2015 S • KBU 22-06Y IIDrilling Procedure Hilrorp Alaska,LLC 1 8.1 0 P/U below 6-3/4" directional drilling assy: COMPONENT DATA Item Description Scrial Numbilr tt iltil fin) tin; owl Connection (ft) k ongth fft) 1 HOBS EM65D POD bit 4.500 1.583 6.750 47.67 P 3-112"REG 0/5 0.75 2 5"SperryDrill Lobe 67-6.0 stg 5.000 3.120 48 00 8 3-1/2"IF 24.03 24.75 S1ab:2er 6 550 3 Plool Bub 4 1-'i:) ?253 48 64 B 3-lri"IF 1 25 77.00 4 Welded Blade Slebilizo. 4 840 2.003 5.530 52 00 B 3-1t2"IF 5 00 32.60 5 43W DM Collar 4 730 1.250 47 00 8 3-112"IF 9.20 41.20 6 4 3M*Slim Phase 4 Calla' ' 4.760 1.253 48 20 8 3-12"IF 24.50 65.70 7 Inline Stabili2er tli.Sj 4.740 1.920 6.050 50 27 B 3-1.12"IF 3.00 69.20 8 43.4"AU)Gain( . 4 750 1250 5 625 45511 9 3-112°'IF 14 00 83,20 Slut „Tr 5 625 9 4 IA-CTN Collar - 4.750 1.253 50 50 83-112"IF 11.03 94.20 10 4 314"PWD - 4.750 1.250 47.90 B 3-112"IF 9.20 103.40 11 4 314TPA HOC I'User) 4 760 1.250 40 011 14-3-1.+2'IF 11 DO 114 40 •12 4 Nr BA!Collat 4 750 1.250 45 70 B NC 36 26 42 140 El? 13 4 75' Fit.Pi Collo- 4.750 2.250 46 G4 83-1,2"IF 31.00 171 82 14 4 75'Flox Collar 4.750 2.250 46 84 83-IT IF 31.00 202 82 15 X-0 2-1;2'IF Pin X 4-1.2'CDS 40 Box 5.260 2.255 60.22 B 4.5'CDS-40 2.75 206.57 16 6 Janis 4-1:2°Fivi/DP 4.500 2.750 41 00 185.00 390 57 17 X-0 4 1+7 COS-411 Pin X 3 10°IF tinx 5 360 2.250 61 64 9 3 12"IF 2 75 393 32 15 43/4"WttitherfOrd Hyd Jar 4 750 2.253 , 46 34 9 3-1,rF IF 3000 423 32 19 X-0 3-1.'2"IF Fir X 4-1;2"CDS-40 Box 5300 2.750 54 04 B 4.5'CD3-43 2.75 426.07 20 13 Joints 4-12'NW DP 4.500 2.750 41 00 400.00 826.07 Bit NumberNozzles : Gx10 Bd Size (in) : 6.760 TFA 111121 ., 0,4602 Mai-luta-xi-hirer : HOBS Dull Grade In . Model : EM650 Dull Grade Out . Serial Number Page 35 Revision 1 March, 2015 • IIKBU 22-06Y Drilling Procedure Hileery.Alaska,III 18.11 Hydraulics Summary: BIT HYDRAULIC PROGRAMecurity DBS Prepared For-Alitcorp KOU 32.01 By-Mark Drouinst Date prepared-1 i9114 Operstocitelcorp Welt kantealo-Matt 32-06 01 Type- PDC Contractor:1 County.-Kenai Bit Diameter.- 6,75 in SurveyfAbstracti StittloiCountly-#V11$4 . „ MD Out- 9350 0. aimmilamouniiiimmai Mud Weight 484 ppg COMPONENTS ID 10. To(*)J 1 10 PV ',Mt cp Casing 6.975, 4400 2 10 YP1, 11 WIDOW Open Hole 6 75 9350 3 10 Fluid model Acr,v,,.ow-'Vt-Xif Bawd RAS' kti . 4 10 f;OW Rate vs groom t 6 10 MAX.Pinion Nese.",, 4000_1r0 t 6 10 Surface egialp.7 7el i 7 . 1 Molar bypass'? 0 TVD? 795311 9 0 al Nojpele tow .1,44eNso Cataititel V I 10 Min.TFA! 0.1974 In' Drill Skiing, 871.90 psi 35.40% Total TVA 0 4602 in' Annuhisl, 369 97 psi 14.99% Jet Velocity 191.52 Ws &sofas& 2919 psi 1.16% 1 1 Press.Drop 345.31 psi 5114171411 850_00 psi 34.44% Fla Hyd.Power 55.40 hp Sit 346.3 t psi 13.90% H 5,11 - ri.i II,HOW Impact Force 246.69 Ihe ECO 11.41 ppg Totar3PP 2468.37 pal 100.00% 00 ID Toot Joint 1 Length tap, Pressure Lois DRILL STRING COMPONENTS in In. 00 tg 11 bbts Ps' Drill Pipe(SI t CDS 46 Connections 4.5 3-426 6.37$ 3.5 85$1.Si 120.63 319.99 HWDP(COS 40 connections,13 Asi 4.5 2.58 4.25 2.55 4551 2.80 68.47 4-114'''Weatherford Hyd.Oar wet X-0's 5 2.25 6 2_25 35 0.17 12,43 liVaDP(CD5 40 connections.6 AO 4.5 2.69 6.25 2.55 186 129 31.60 X-0 Sob IC05 40 Dos X 3-112-OF Plri) 4,1 2,5 5 2.3k4 0.02 0 92 1 3 Joints NM kurs 13r111Collare 4.75 2$ 425 2.5, 601 0.35 13.61 MWD+Bat Sonic 4.76 1.26 4.75 1.25 261 0.04 112.12 MWD ITS HOC)Puler) 4.75 **"''' '' 11 " 400.00 MWD r PWD 4,75 1.25 4.75 1.25 9 0.01 39.05 MW D rAL0-C7N(Nukes, 415 1,25 4,75 125 25 0.04 10145 i lining Stabilizer(0,.$r 0auge1 475 1,25 4,75 125 3.51 0.01 15.19 MWOIDIrecnonaltSlen Phase 4 4.75 1.25 4.75 1.25 3411 0.05 147.54 6k1 String Stabiliser 16.626Gauge1 4.76 2 435 2 5.5' 0.02 3.23 Float Sub 4.75 2.5 4,75 2 5 2.5 0.02 0.57 5'SperryDrel Lolae63.60 911011011A141 5 ..,,,,,,......... 5 *1-""''''-''' 26 450 00 ANNULAR Hole ID Pipe OD Length Cure Cap. Annulse Crites' Type of Pressure Loss _SECTIONS, _ in.L__ _in. ft Depth bbls Plfreln Mein Flow Poi Casing 4475' 4..,5 6400 6400 167.96 249.49 31010 L 242,12 1 Open hole 6.75; 4.5 2117.5 8517.5 52.07 268.219 314.12 L $9.11 Open Hole 635' 4.5 403 8920.5 9.91 266.21 316.12 L 17.07 H Open ole 6.75 4.7 35 8955.6 0.80 211.14 325.114 L 1.77 Open Hole 615 4.0 186 9141.5 4.57 269.21 311132 L 7.11 Open Hole 1.75 4.7 4 9145.5 4109 207.141 32.5.86 1 020 Open Hole 6,75 4.15 60 9705,5 134 293 05 328.50 L 3.11 Open Hole 6,75 415 26 9731,5 0 511 29309 32650 L 1,38 Open 11019 6.15' 4.75 11 9347,5 0 25 293 05 378 50 L. 0.541 Open Hole 615' 4/5 0 9251,5 0 20 29305' 32650 L. 0.41 Open Hole 6761 410 25 9276.5 0 56 293.051 328 50 L 1.32 Open Hole 6.75 4.75 3.5 9280 0 06 293.05' 328 50 L. 0.19 Open Hole 6.75 4.75 34 9314 0.76 293.05 320 50 L 1.90 Open Hole 6.75 4.75 5.5 9319.5 0.12 293.05 326.50 L 0.29 Open Hole 6.15 4.75 2.6 9322 0.06 293.05 320.50 L 6.13 Open Hole 6.75 5 25 9350 0.56 327.79 343.12 L 1.91 . ; Page 36 Revision 1 March, 2015 S KBU 22-06Y fl Drilling Procedure Iblrorp Alti•la,LI.0 18.12 Primary bit will be the Security EM65D. 6-3/4" (171mm) EM65D PRODUCT SPECIFICATIONS Cutter Type X3-Extreme DriRing IADC Code M323 e *ow aP Body Type MATRIX Total Cutter Count Cutter Distribution Idarg race3 Ft ^' Gauge II A e Up[kill 5 41# Number of Large Nozzles Number of Medium Nozzles a. Number of Small Nozzles ii13P Number of Micro Nozzles 0 Number uf Potts(Size) 1111Pr 444 4 Number ofReplaceable Porta(Size) 0 Junk Slot Area(sq in) 8.68 Nomialized free Volume 34119% • API Connection :2 REG.PIN Recoottninuied Make-Up Torque* 5,173,—7,665 Ft*lbs. Nominal Dimensions** Make-Up Face to Nose 9.42 in-239 nun Gauge Lemph in.$1 MIT Sleeve Length 0 in-0 nwn Shank Diameter 4.5 in-114 nun Break Out Plate(ridatAtetnicytt) Ill1953$'44010 Approximate Shipping Weight 90Lbs.-4IKg. SPECIAL.FEATURES Up-Drill Cutters on Gage Pads,1;16"Stepped Gage,Optimized Dual Row-"Ir Feature Material#761302 *Bit specific recommended make-up torque is a fintetion of the bit ID.and denial bit SA*.O.D.utilized In specified in AN RP'76 Section **Design dimensions ire nominal and tray vary slightly on manufactured grolut.Ilallihomon Drill tits and Services models are oontinuneuly resumed and refined Product iltecilkatoros no change without iCg. C 2013 Halliburton.AU rights reserved.Sales of Halliburton products and services will be in accord solely with the terms and conditions contained in the contract between Halliburton and the customer that is applicable to the sale. Page 37 Revision 1 March,2015 • KBU 22-06Y Drilling Procedure 11,1,mi)Alaka,1.1( 18.13 TIH to TOC. Shallow test MWD on trip in. Note depth TOC tagged at on AM report. 18.14 Conduct casing test to 3500 psi/ 30 min. 18.15 Drill out shoe track and additional 20' new formation. CBU and prep for FIT. 18.16 Drill 6-3/4"hole to 10,200' MD /9,557' TVD • 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 38 Revision 1 March, 2015 • KBU 22-06Y Drilling Procedure Hi!curp 41a40,11C 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/EZ MUD/BDF-499 fresh water based drilling fluid. Properties: MD Mud Viscosity Plastic Yield Point pH ,a HPHT Weight Viscosity ..._., 8,100'- 10-11.5 ppg 40-53 15-25 15-25 8.5-9.5 < 10.0 10,200' System Formulation: 6% KCL/EZ MUD/BDF-499 Product Gond tion Water 0.905 bbl KCI 22 ppb (29 K chlorides) Caustic 0.2 ppb (9 pH) BARAZAN D+ 1.25 ppb (as required 18 YP) 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 39 Revision 1 March,2015 • ! 11 KBU 22-06Y Drilling Procedure H�hurp Ala..ka.LLC 19.0 Run 5" Production Long String 19.1 R/U Weatherford 5" casing running equipment. • Ensure 5" 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 to R/U Tesco or Weatherford CRT so that string can be rotated if necessary 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 5"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 solid body centralizers on every joint to 8,100' MD. Leave the centralizers free floating. • Ensure to install swell packer joint so that it is 500' from the 7-5/8" shoe when landed out. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 5" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 5" 10,700 ft-lbs 12,100 ft-lbs 16,000 ft-lbs Page 40 Revision 1 March,2015 S • KBU 22-06Y Drilling Procedure ii corp Alaska,III Technical Specifications Connection Type: Size(O.D.): Weight(Wall): Grade: _.__... DWC/C-HT Casing 5 in 18.00 OA(0.362 in) L-80 +HMandar: Material Witt L-80 Grade 80,000 Minimum Yield Strength(psi) 1111111111111111111111111111111ru SA 95,000 Minimum Ultimate Strength(psi) VA -USA Pipe Dimensions4 , "7 max. tso 1 5.000 NominalPipeBodyO.D.(in) Prone: 713-479-0 4.276 Nominal Pipe Body l.D.(in) Fax:713- 79- 0.362 Nominal Wall Thickness(in) E-mail:VAMU . orrrn 18.00 NominalWei ght(Ibsift) 17.95 Plain End Weight(Ibslft) "p 5.275 Nominal Pipe BodyArea(,5_q in) Pipe Body Performance Properties 422,000 Minimum Pipe Body' i el d Strength(lbs) 10,490 Minimum Collapse Pressure(psi) 10,140 Minimum Internal Yi el d Pressure(psi) 9.300 Hydrostatic Test Pressure(psi) Connection Dimensions e 5.563 Connection O.D.tin) 4.276 Connedionl.D.(in) 4.151 Connection DriftDiameter(in) 4.06 Make-up Loss(in) 5.275 Critical Area(s_q in) + 100.0 Joint Ef ioency(%) Connection Performance Properties ,�li� 422.000 Joint Strength(lbs) 16,750 Reference String Length(ft) 1.4 Design Factor ,, 457,000 API Joint Strength(I bs) 422.000 Compression Rating(lbs) 10,490 API Collapse Pressure Rating(psi) . 9,910 API Internal Pressure Resistance(psi) 73.3 Maximum Un i axial Ben d Rating[degrees/100ft] Appoximated Field End Torque Values 10,700 Minimum Final Torque(ft-Ibs) 12,100 Maximum Final Torque(ft-I bs) 16.000 Conn edion Yield Torque(ft-lbs) For detailed info mai on on perfo m1 an ce properties.refer to DWC Connection Data Notes on following page(s). ni Connections peafications withinthe control of VALI-USA were correct as of thedate prim.Spec fccrcns ares uttect to charge without notice.Certar correction s peed'cations are dependent on the mechanical properties of the pipe,t.1 ec sar cai properties of mil proprietary pipe grades were obtained from mill publications and are subjeeto charge.Properties of mill preprieiarygrades shoiAd be ccnfiimed wth the mill.Users are advised toobtain currentcomectbn spsbficatiors and verify pipe mechanical properties far each application. Page 41 Revision 1 March, 2015 • • KBU 22-06Y Drilling Procedure HiScarp Alaska,LLC 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 42 Revision 1 March, 2015 • KBU 22-06Y Drilling Procedure e8rorp AIA4a,r,i.c 20.0 Cement 5" 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. 20.5 Pump remaining 15 bbls 12 ppg MUDPUSH II spacer. 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 5" long string Overlap: 500' x 0.022 = 11 61.8 6-3/4" OH x 5" Longstring: (10,200—8,100') x 0.020 x 1.5 = 63 354 Shoe Track: 90' x 0.019 = 1.7 9.5 Total Volume: 76 bbls 425 ft3 Page 43 Revision 1 March, 2015 • • KBU 22-06Y Drilling Procedure HiIcor1,.41n.kn,LLC 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 Blend Thickening Code Description Concentration D046 Antifoam 0.2%BWOC D202 Dispersant 1.5% BWOC Gas Additives D400 0.8%BWOC Migration D154 Extender 8.0% BWOC Expanding D174 1.0% BWOC agent D177 Retarder 0.04 gps 20.7 Drop top plug and displace with filtered 6%KC1. 10,100 ft x .01776 = 179.4 bbls. 20.8 Do not overdisplace by more than 1/2 shoe track. Shoe track volume is 1.7 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 44 Revision 1 March, 2015 • KBU 22-06Y Drilling Procedure IliIcorp 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 lkeller@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 21.0 RDMO 22.1 Install back pressure valve in hanger neck. N/D BOP. 22.2 N/U tree. 22.3 RDMO Saxon Rig#169. 22.4 After rig has departed,pull BPV &run CBL to determine TOC behind 5"production casing. 22.0 Perf and Frac 23.1 A separate Sundry will be submitted to the AOGCC that will cover the perf& frac operations for 7 KBU 22-06Y. 23.2 Ensure to run a CBL across 5"to determine TOC after rig has departed. Expedite this to AOGCC ASAP. 23.3 Test 5"x 7-5/8" annulus to 2500 psi after swell packer has had sufficient time to inflate. Page 45 Revision 1 March,2015 • 11 KBU 22-06Y Drilling Procedure II Irorp Alaska,I.IA 23.0 BOP Schematic Fn Li:- If ' T3-Energy Saxon#169 11"x5M 1111 It IIIIIIIII T-3 Energy BOP ... i.* no • M90160.111 y °ea4 -4111 _ - Manual Manual 'i Man :',ii5' Vallee Valve Valve I a, KM ' �� .INow }. Dhaka Line '1'yr,k:, 1 -r i±l 1 ��: Line ' Ili i ii!liilil .fir_ •*--- Mr T3- nevi. Model61i11 - 111 I — , - Gradin i_ ;_ aim 1111iii111it1III Spmet spool 1 u 11 5M X 11 5M Iti iii 9iI III IEI __41 ..iu_ 1 ■ii•- Seaboard-MSS s sterrr �,� q 1 18743Mx115M -.i 1�■■..7 ,N. 1111 _ +M? I�.�I. xs 4 11r 111171 a' i -.i1r 111 ` Ii_ iii: - 1,7•.. I';IiI— iII� . . II11: Page 46 Revision 1 March, 2015 • KBU 22-06Y II Drilling Procedure Hilcorp.Ala'ka,IA.0 24.0 Wellhead Schematic KBU 22-06Y 19 m MAST!CTIPS 3-1115'iOrvi 4742',104;0 . timith,44:,10:10 III iewt~ miiiit _OW/ No 3-1/1.sv 10h43-1/1.e 1OM 14/.....,NA I.,1111WF aliaMillie IN 3-1115'10MIlr 1 0 Adapter,SM-E-ZGLI tf 11°"5MI x 3-1115'1CM MAS 944-AX 111l1111e1_ _ILII:7. tow it x 3-1J 0"tit ON i ; X 3-4/2 C'u 4110 1004 x ix lall 11110 MI ' =1,1 1,4- j1ay`‘,,a7'.;:lipt i C4i . aprill ttXX-iatr. , gm 2"1 , 9,0 _ r & �` Km IIIII 01.d to- 4 les rim '''''' ' "fes. yes , t-:'.2 • 2-14142-1414 43Ar CASIXO�$ 5t 143-3}1 x to-I/4 4 �c'—3/4 Al ! w/PolesitiXx seat.. tee, mai I- Miriell , ,Irr: li 40 Alf i "- SO C wa �} I 2,4,61 gra 10-3/4 7-1,1 wow dge,rsimarm RD 3.000 F454 Wear,530&10,03,3 me tree asst'.. °. ........ Y6 x10-3/4 x 7-3/8 x 8-112. u ..., -_ P14873 l lit X -aai 1-12 14%01112 I 110 Page 47 Revision 1 March,2015 • • KBU 22-06Y Drilling Procedure Niloorp Alarkn,Ll d: 25.0 Days Vs Depth Days Vs Depth 0 KBU 22-06Y KBU 42-06Y 2000 4000 6000 e N W $003 10000 12000 0 5 10 15 20 25 30 35 Days Page 48 Revision 1 March, 2015 0 KBU 22-06Y Drilling Procedure Hilrorp Alaska,LLC 26.0 Formation Tops ANTICIPATED FORMATION TOPS&GEOHAZARDS EXPECTED FLUIDMD TVD(FT) SUBSEA DEPTH EsT.Pressure X Y Steric.;g gasfwet 3706 3,591 (3507; 250 272163 2363144 1.338817128 Steri ng 5.2 ,gasfwet4358 4,193 (4109' 1500 272184; 2363393 6.879597865 Sterling Pool 6 ` gas 4679 4.489 (4405 200 272194 2363516 0.856795243 Upper Beluga ;` gas 4952 4,742 (4058; 900 272203 2363620 3.649871849 Middle Beluga gas 5635 5,373 (5289, 1000 272224 2363881 3.579149308 Lower Beluga gas 6420 6,098 (6014; 1000 272249 2364181 3.153619093 Upper Tyonek gas 7693 7.273 (7189' 2500 272290 236466- 6.610329036 Tyo,ek D; gas 9340 8,777 (8693; 2000 272340 2365336 4.382082541 TyonekD2 gas 9507 8,930 (8846) 800 272345 2365404 1.722801275 Tyonek D38 gas 9860 9,253 (9169) 2400 272356 2365547 4.987987264 Tyonek D4A gas 10084 9,458 (9374) 700; , 272362 2365638 1.423296597 =Reservoir Objectives =Possible Geo Hazards DATA COLLECTION REQUIREMENTS: Page 49 Revision 1 March, 2015 • KBU 22-06Y Drilling Procedure Hiicorp Alaska,LLC 27.0 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 50 Revision 1 March, 2015 • • KBU 22-06Y Drilling Procedure ud orp Alaska,L1.1: 9-7/8" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. BARACARB 5, 25, 50, 150, 400 & 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. Background concentrations of LCM (sized calcium carbonate) should be btwn 5 — 10 ppb while drilling this interval. There is a high probability of lost returns through the many stacked, depleted sands in this hole section. Hole Cleaning: Maintain rheology w/BARAZAN. 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 1ppb total of PAC L and 1 —2 ppb DEXTRID to maintain a thin/strong wall cake and keep HTHP filtrate below 11 ml/30 min. Maintain MW as necessary using additions of Barite. Maintain 4 ppb BDF-499 for shale/clay inhibition. Maintain 2—4 ppb BAROTROL and 2—4 ppb Soltex for Shale/Coal stabilizer. 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 (BAROTROL, Soltex). • Increase fluid density as required to control a"running coal". • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb Asphasol Supreme pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 51 Revision 1 March,2015 • KBU 22-06Y Drilling Procedure trt,of Alaska,L1.0 6-3/4" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. BARACARB 5, 25, 50, 150, 400 & 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. Background concentrations of LCM (sized calcium carbonate) should be btwn 5 — 10 ppb while drilling this interval. Hole Cleaning: Maintain rheology w/BARAZAN. 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 1ppb total of PAC L and 1 —2 ppb DEXTRID to maintain a thin/strong wall cake and keep HTHP filtrate below 10 ml/30 min. Maintain MW as necessary using additions of Barite. Maintain 4 ppb BDF-499 for shale/clay inhibition. Maintain 6%KCl 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 (BAROTROL, Soltex). • Increase fluid density as required to control a"running coal". • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 52 Revision 1 March, 2015 • • III KBU 22-06Y Drilling Procedure Hilcorp Alaska,LLC 28.0 Saxon Rig 169 Layout 123.-7" 36'-0" 55-6" 3C-0" t ll IIII PRF—AW TALK(TOTAL VOL 395 MIST H II=1 11;� 'Will __.7 .tel �1!filiIll HIHN I 1:3 4' f i 1 l rr;; is 'ligBSI I13I li " u MI'I lIIl[II'C 1-125 an o.. o11t19111n�r. I. � _it iii L ��r 1�,i,l[F - r .- r BEN'" �nrlia�il>l ..,....' . ra!! a ,■dill III111111 INlNNI11NINIIINNIN11111NININ11N1111111NI11111111MIMI MM11I1111N 1111111IIIIIIMIIII IHleluIHI II>!-'1 Imilth 111111111NI111111NNIN11'- ` `lBIIINININIIINBIINIIIIIN�II 1I1111MIK11111P11111MIN1111111N11111111N11111INI11NI11110IeI1I1n'I=ln i11:1111"'"4"11111 IININIyIld11INI1111111NlIINI1INl11llglHl�lHu►► 11 111f111NINIM�l1L., .J_Illi pp 1 .,, _�� n' �h.�.�...�. ■I I __.�. " �._•If a ci�nGrctirn ieE II. .... 1111111111111 1111—■� ,. �;� 1111II1N111IIIIIIIIIIII111111llIIl 11111MIHh twill mon—- - m LII ININIIINIiiva, mIrll rt ,f 11111IIIMINIIIINI11111111111111111IIIM MIIIMINIIIIIIiinlllii pm lnnnll.0 111111111I1111111�1� 1111N111IIIII IIIIIIIIIIIII[pMIMi11MIIIIIl11111NIIII11111111 1IIIIIIIIIIIII M11110111•1 i�NIMN II 111166111111110MMiII 11111ININI1# ,_ ,� -moo_.. �;� ��` ' WHIM! '� 11.41 iHl IlllHlH fIHIt! li . k '� r •' 1 s II lilllilll II�HII•Ii MIIMIIIIIIIIIIII ii OCL€BATOR BUILLk4C f<"I,O.CO$E:1M'APER 7AIAS/fOOLRC.3$, 53'--0" 45'—O" 63'.0" ( 85' 5" Page 53 Revision 1 March, 2015 • . KBU 22-06Y Drilling Procedure 11114 twit Ala%ka.1,11: 29.0 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 54 Revision 1 March,2015 • InE KBU 22-06Y Drilling Procedure IItleorp Alaeka,Lld' 30.0 Choke Manifold Schematic '''G 42 97 24 9362 45,62 191 MI MIa 0 :` 16.43 —1462 � catl IA 43 `}';�y' 0,19 —0.[9 ; �1.1140 _0.14 41S $/ 1,144 tan -A. 0.19—. p 1.+�1• P14 At 'ilf �' `'� lro-iit- 1'r - iIi--i ' 11 1 I I r� .i.. e. WM A,9. Y' .r' ��,. A19.1 1 1.6. Mir m , �.� I9,9 W .,0.. 9.64 i --' 1 I —�. 2,9J filial! 1 In �laA'019 :i 36.03 t 14.62 ��{ .7 1462 aT ~�i Y J lU-_ mow`/� 10.62 � . r.'9 . T ` \g 1 1 roomeOD sa�*I 0.19 MUM , 019 141-i9t 10.50 ` 11�'1�r ;l „ 70.60 �[1�filar\r;[1���'.' 1CTZ7��j1 �13 ,��i l I1.'j. 11:' 4il�' %411 1 I °--11'"I momsar ° m . M Yw9 mCH.Y(34 034 0.19 —0.19 019 0.14 —9.14 O1463i311011 i)/3141,4, ti✓ 3,—61042 —7462 -....,...14.6E-- .-�t462=... .•_•.631•— t{ f.. 4162 4.1.62 Pe,-.1.-K 61.24 fi'l liNIIMIll 1;(003'3403 F.00`X633 - F V C CAD �i r ✓. a 6F. 3' -- ) . 3 �.-...'+Y__ Page 55 Revision 1 March, 2015 • • Int KBU 22-06Y Drilling Procedure Hiir orp Ala4a,1.1.1 31.0 Casing Design Information Calculation &Casing Design Factors Kenai Beluga Unit DATE:2-26-2015 WELL:KBU 22-06Y FIELD: Kenai Gas Field DESIGN BY:Monty M Myers Design Criteria: Hole Size 9-718" Mud Density: 9.5 ppg Hole Size 6-3/4" Mud Density: 11.5 ppg Hole Size Mud Density: Drilling Mode MASP(sec 1): 1254 psi(see attached MASP determination&calculation) MASP(sec 2&3): 2887 psi(see attached MASP determination&calculation) Production Mode MASP: 3288 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" 5' Top(MD) 0 0 0 Top(TVD) 0 0 0 Bottom(MD) 1,500 8,100 10,200 Bottom(TVD) 1,500 7,630 9,563 Length 1,500 8,100 10,200 Weight(ppf) 45.5 29.7 18 Grade L-80 L-80 L-80 Connection BTC BTC DWC/C HT Weight w/o Bouyancy Factor(lbs) 68,250 240,570 183,600 Tension at Top of Section(lbs) 68,250 240,570 183,600 Min strength Tension(1000 lbs) 1040 721 457 Worst Case Safety Factor(Tension) 15.24 3.00 2.49 Collapse Pressure at bottom(Psi) 741 3,769 4,973 Collapse Resistance w/o tension(Psi) 2,480 4,790 10,500 Worst Case Safety Factor(Collapse) 3.35 1.27 2.11 MASP(psi) 1,254 2,887 3,288 Minimum Yield(psi) 5,210 6,890 9,910 Worst case safety factor(Burst) 4.15 2.39 3.01 Page 56 Revision 1 March, 2015 • i 11 KBU 22-06Y Drilling Procedure II I,ori, 9i:,.ka,1.11 32.0 9-7/8" Hole Section MASP Maximum Anticipated Surface Pressure Calculation II 9-7/8"Hole Section KBU 22-06Y Ea1"`''',``" 1" Ninilchik Unit MD TVD Planned Top: 1500 1500 Planned TD: 8100 7630 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Sterling 3,592 250 gas/wet 1.3 0.070 Sterling 5.2 4,194 1500 gas/wet 6.9 0.358 Sterling Pool 6 4,490 200 gas 0.9 0.045 Upper Beluga 4,743 900 gas 3.6 0.190 Middle Beluga 5,374 1000 gas 3.6 0.186 Lower Beluga 6,098 1000 gas 3.2 0.164 Upper Tyonek 7,273 2500 gas 6.6 0.344 TD 7,630 2500 gas 6.3 0.328 Offset Well Mud Densities Well MW range Top(ND) Bottom(TVD) 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/1,500'TVD 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: 1500(ft)x 0.936(psi/ft)= 1404 psi 1404(psi)-[0.1(psi/ft)`1500(ft)j=11254 psi MASP from pore pressure(unknown gas sand at TD,at 9.2 ppg(0.4784 psi/ft) 7,630(ft)x 0.4784(psi/ft)= 3650 psi 3650(psi)-[0.1(psi/ft)'7630(ft))= 2887 psi Summary: 1. MASP while drilling 9-7/8"intermediate hole is governed by fracture gradient at the 10-3/4"casing shoe Page 57 Revision 1 March, 2015 • KBU 22-06Y Drilling Procedure Hal erp 11:,,.k",IAAf 33.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 6-3/4"Hole Section KBU 22-06Y ,�.�... .sa..: Cook Inlet,Alaska MD ND Planned Top: 8100 7630 Planned TD: 10200 9557 Anticipated Formations and Pressures: Formation ND Est Pressure Oil/Gas/Wet PPG Grad Lower Beluga 6,099 1000 gas 3.2 0.164 Upper Tyonek 7,274 2500 gas 6.6 0.344 Tyonek Dl 8,778 2000 gas 4.4 0.228 Tyonek D2 8,931 800 gas 1.7 0.090 TyonekD3B 9,254 2400 gas 5.0 0.259 Tyonek 04 9,459 700 gas 1.4 0.074 TD 9,557 4210 water 8.5 0.441 Offset Well Mud Densities Well Max DrIg MW Top(ND) Bottom(ND) Date KBU 11-17X 10.7 5,464 7,919 2009 KBU 14-08 10.3 5,432 7,746 2008 KBU 41-18X 11.6 5,391 8,651 2008 KBU 24-7X 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: 7630(ft)x 0.936(psi/ft)= 7142 psi 7,142(psi)-[0.1(psi/ft)*7,630(ft)1= 6379 psi Drilling Mode MASP MASP from pore pressure(2/3 wellbore evacuated to gas from"D"at.444 psi/ft) 9,557(ft)x 0.44(psi/ft)= 4014 psi 4,014(psi)-[(0.1(psi/ft)*9,557(ft)*2/3J+[0.44(psi/ft)*9,557(ft)*1/3)1= 1975 psi Production Mode MASP MASP from pore pressure(entire wellbore evacuated to gas from TD): 9,557(ft)x 0.444(psi/ft)= 4243 psi 4,243(psi)-[0.1(psi/ft)*9,557(ft)J= 3288 psi Summary: 1. MASP while drilling 6-3/4"production hole is governed by SIBHP minus 2/3 wellbore evacuated to gas from TD. 2. MASP during production mode is governed by SIBHP minus entire wellbore evacuated to gas from TO. Page 58 Revision 1 March, 2015 0 0 KBU 22-06Y IIDrilling Procedure Bacon,Alaska,M. 34.0 Spider Plot (NAD 27) (Governmental Sections) .. , ‘ . ADL000593 . . , 1 .. , KU 22-6X B14 : ie,.... KBU 22-06Y MIL i 1 I KBU 22-0613114 I FEE AA093836 , 1 KBU 42-6X EffiLit , ! : a a * • a a a x KBU 42-6 BHL t , 6 Iti 6., 13-C6 BH ,,, I! 6, 4 I KU 43-06 BR& 1 II l 3,6 8H14. ------ ' 1, KU 43-06RD BHL \ KTU 43-06X Blic, 0E4 , if Kap 33-06 Blit.,„, : r , J ) N N, ' / 33-06X BH1,,, : „, Ke a:Sas Fie::'Fi.'d Ha 33-01 , , . , KTU 244H BI-IL, N ' 1 P 1 ADL392670 KBU 22-00Y TPI-II . , -,k \ ,i o 1 ef, , \ i / \ \ N o e 1 if , 1 1 I l 1 t ::: ; t,1 , -- SOO4N011111, I, :KBU 21-06Y SHL mu 2446 eft\ Pt,), 'i SOO4N012W \-,,,, A028142 . IOU 08(KU 14X-6:BHL--- , _ - KU *03- .-‘,54 't*--2-'-- - 14 - ''' *,,.. „. i'1,1 I/ KENAI UNIT fvi*.' - -,14-061—„„`.:,,,, w\-- Kenai as Fieldta.d. -1--"-° KBU'I •1r1,13141. N't KBU 34-6 BHL- -- + --- r t rt: t , l<81-1, ., . Kenai Gas,F41."ad rid 4I- / \ C7 \ ,' :',.: 1 :1: ?' -- : , KOU 1 e , : 1 , i t ikBU 11-07 BH11: , KEtu 31,3.7RDN-sHi., KU 31-07X BHLy A-C126 /14 . , , KTU 32-07}-iBHL- KB1„1 at-07E4' r( LI 42-07RD BHL Etre021 Ilimi9 .. . ,. Kt 04(KU 1341BHL ' I. ,,. 1Legend --- Other Surface Well Locations Other Bottom Hole Locations Well Paths Well Pad KDU_04.132rttHL KBU 33-0781,4 KDU 04RD BHL -- r'" .71 Oil and Gas Unit Boundary KU 4-3-12 E-1 KBU 23-07 BHL Hdcorp O&G Minerals it,SLI 43-07X BHL int Kenai Unit 06Y KBU 22- 0 1 r.C.: 2.00;) - ....-- ----- ---3 Fee: kaska State Plane Zone 4,NAD27 1111.0wr .L.4e,III Map Date:224,42015 A Page 59 Revision 1 March, 2015 • • II KBU 22-06Y Drilling Procedure H ilrnrp.Alaska,LI( 35.0 Surface Plat (As Built) (NAD 27) i♦ of. r I, I E,. .OF HORIZONTAL COORDNATES ARE ,KA STATE PLANE 551127 '�,... ....Itt.�10,1r Z>:'NE A GEtERLAINEL3 BV AT ADIRT TO I.�C4OS TRI STA AWRY H4,,NC A 4,,t/ �i'fi 1, ,_ PiIRI INFC+P091Ts)I1 OF AT S='MLONG 151 963?3la'ti #; i°1°""�"°"� N:728A45A2 E:266666.15 ,rte,r"i T 216AS1'S Of VERTICAL DATUM IS MEAN SEA LEVEL. OR 1 s ,1 31 SOUTHWEST CORNER SEC.4 COORDINATE DETERMINED TROM CoRECT i `e�•,.': "'�—"� "'� SURVEY TIE TO THE TCI EXISTING BIM wr.FORE NW CORNER SEC.7A+In STAN A'Manta 7 Y/C Y CORNER SECTIONS F R 7 RECOVERED AND!WIT 11-E FRL;7RA:T'r, "/1�`?%. 4637-S �� SECTION CORNER VALUES. o- 6, ,,,,t;-_.... ,>'`,"~ SCALE ` Fii TtETssL;o;``,, 0 1}3 20: ` } 1 1 1I i fCCT EN:,, t,va[FtGVH INT I / i.,l,I7. .PT.Cha a ! f—'°'_,_._7.— „iarEkU `._ ,, "—r- "'2"4 PR"''R'"P2 KBU 22-06Y AS-BUILT NAD27–" "---•--•_ 1 ., 1.lst' GRID N:2362472.99 =._._ `�. GRID E:272112.27 LATITUDE:60'27'38.2658"N\ Q\ „.,..:_:\ / . 1 ELEV.:65.0 FT.NAVD88 rte.-- 1196'FWL - `\\� \ — 4211'FSL • ® Gy I_ ,;,, \ I, 4141 FjNTS? 1r� Fpir ( � k1 � \ a ■ vi LJ ��_....> w r r a/1.1 Z I 'axsraun:MT .. 1 J r y+NA l•4 !.% "' o .-::1!..%7-"' 7? (- K(,iF PA's 149E 0 . ELLVAI ION=65.6'M.Si. 4211 F: 1 �_ I G"NTRCL Pt OT4 PIP PC. Y.711r Sil Ii♦ ,,,T''' ElEV+45.tR' 111311 RIM ,R—,......,_„..... 0 * Ili fr �- 6 �` SAN COR �, 1 �r E. 1 • Y N 2362069.27 \ r- 16 E 270908.10 " _ z 7 J I I , — _ • 4------4 �. .../.-— GJ _ iet , J �-r / / , . — \ I 4 l \ / ti 1 _ RF.,Lcx}h +7 HILCORP ALASKA LLC RATE T+9PYG n,L ultaw I, KBU 22 06Y AS BUILT E5/111551. ICE KENAi GAS FIELD PAD 14-6 1...' � SURFACE LOCATION DIAGRAM NAD2`I rcTrx, c Y'JKt1{U.l3 i IVARIVRII a 5VE95tak''Main. !9(5[113 NU ,+Fl: FO Kw PP L,J4Il5A,An V.k511 1CR AIRII, v+7iL' MR 285-1tl$ 51%:01i1EA iett.15 616oN PAP PONINEcr10:1« 110,11111<1I.4-La1.II . SO T4N R11W SEWARD MERIDIAN.ALASKA 1, 1 Page 60 Revision 1 March, 2015 • • II KBU 22-06Y Drilling Procedure Hi!carp Alaska,LL(' 36.0 Offset MW vs TVD Chart MW vs TVD Offsets .---. ct z z—ab --?6r44- il KBU 32-08 C 1000 — KBY 43-07Y 2000 1 KBU 11-08Z i —KBU 23-05 3000 ---p KDu 10 1. illi ,.—rt KBU42-06Y 4000 5000 . 6000 11111 x 7000 ; kliok iii, likw '141k 8000 1 )114, 4 4 4 9000 '44111111k ', 10000 11000 12000 N. 13000 l 6 7 8 9 10 11 12 13 14 Mud Weight(PPG) Page 61 Revision 1 March, 2015 • • II KBU 22-06Y Drilling Procedure i Hilrorp Ala ka,II I 37.0 Drill Pipe Information SlzE: 4 1/2" g...,1 PfMMfUf WEIGHT: 16.6 LBS/PT 11111161$111111:18 GRADE: 5-135 RANGE: II(31,59 r1 DRILL PIPE SPECS CONNECTION: COS4O TUBE NEW PREMIUM IN MM IN MM OD 4600 1 14.3 4,365 1 10.9 WALL THICKNESS 0.337 8.6 0,270 6.8 IDI 3.826 97.2 3,826 97.2 FT-LBS N.M FTLBS N.M TORSIONAL.STRENGTH55.453 75200 43,451 58.900 80%TORSIONAL STRENGTH 44.362 60.200 34.761 47.100 LBS DAN LBS DAN TENSILE STRENGTH 595,004 265.300 468,297 208,800 PSI KPA PSI KPA INTERNAL PRESSURE CAPACITY17,693 121,985 16,176 111,530 COLLAPSE CAPACITI' 16,769 115.615 10,959 75561 IN2 MM2 IN2 MM2 CROSS SECTIONAL AREA BODY 4.407 2844 3,469 2238 CROSS SECTIONAL AREA ODI 15.904 10261 14.966 9655 CROSS SECTIONAL AREA ID 11.497 7417 11.497 7417 IN2 MM2 IN* MM2 SECTION MODULUS 4.271 69995 3.347 54845 POI AR SECTION MODU1 US 8.543 139989 6.694 109690 TooL JOINT NEW PREMIUM PSI KPA PSI KPA YIELD STRENGTH 130,000 896.318 1 30,000 896318 IN MM IN MM OD 5.2500 133 4 5.1198 130.0 ID 2.6875 68 3 2,6875 68,3 PIN LENGTH 11,0 :173 4 11.0 279,4 BOX LENGTH 14,0 3556 14.0 355,6 F7.tBBS N-M E9'-Elis N•M TORSIONAL STRENGTH 35.400 48.0001 34,700 47.100 MAX MAKE-UP TORQUE 22.500 30.500 21.400 29.000 RECOMMENDrD MAKE-UP TORQUE 21.200 28.800 20.800 28.200 MIN MAKE-UP TORQUE 19.600 26,600 19.300 26.200 LBS DAN LBS DAN TENSILE STRENGTH 824,400 367.600 804.900 358,900 TOOL JOINT/DRILL PIPE TORSIONAL RATIO 0.64 0.80 I. DRILL PIPE ASSEMBLY WITH CONNECTION LBS/FT KG/M ADJUSTED WEIGHT 17.87 26.64 FT M APPROXIMATE LENG"1"H 31,50 9 60 GAL/FT M2/M FLUID DISPLACEMENT 0,273 0.003394 FLUID CAPACITY 0.577 0.007169 IN MM DRIFT SIZE 2.5625 65 Page 62 Revision 1 March, 2015 • • la FKBU 22-06Y Drilling Procedure Ilileorit 11a-la,HA' COMBINED Loan CURVE FOR 4 1/2"S-135 16.6 u3s/FT DRILL PIPE WITH CDS40 CONNECTIONS i I , 11)..).000 1 , 1 , 6 I 0:000 waro *PAO AWO atiO 0O4 . 2- , .7 ." -0 g s406 1 464 t. , 4 % , * 0M) o ‘ * , * 14 ' * , * , $ * t • % 0 , MOO C rre al.Ati MOOD 31,1..IVIC 4f;,) 50,003 Applied Torpue(tt-lbs) NEW TUBE COMBINED LOAD G ,- ....PREMIUM TURnt F CosiMFD LOAD -MAKE-UP'TORQUE SHOULDER SEPERATION PIN YIELD -E3ox YIELD 60,000 Page 63 Revision 1 March, 2015 • , Hilcorp Energy Company Kenai Gas Field KGF 14-6 Pad KBU 22-06Y KBU 22-06Y Plan: KBU 22-06Y wp3 Standard Proposal Report 12 March, 2015 I -1 ti ill le I ri 11 11 ft. hi 544 )[� C HALLIBURTC3N a Sperry Drilling Services WELL DETAILS:KBU 22-06Y -750- • Ground Level: 65.00 - +N/-S +E/-W orthing Easting Latittude Longitude Slot - i 0.00 0.002362472.99 272112.27 60.4606294 -151.2625281 0- SURVEY PROGRAM - Date:2015-01-29700:00:00 Validated:Yes Version: Depth From Depth To Survey/Plan Tool 750- 18.00 2499.00 KBU 22-WY wp3(KBU 22-WY) MWD+SC+sag 2499.00 10200.00 KBU 22-WY wp3(KBU 22-06Y) MWD+SC+sag 10 3/4 _-. h. 1500- _ ---__ SECTION DETAILS _ Start Dir 3.40/100':1600'MD,1600'T/D Sec MD Inc Azi TVD +N/-S +E/-W Dleg TFace VSect Target 1 18.00 0.00 0.00 18.00 0.00 0.00 0.00 0.00 0.00 2 1600.00 0.00 0.00 1600.00 0.00 0.00 0.00 0.00 0.00 2250- "End Dir:2247.5'MD,2231.68'TVD 3 2247.50 22.01 3.22 223168 12268 6.91 3.40 3.22 122.87 4 3701.49 22.01 3.22 3579.66 66684 37.56 0.00 0.00 667.89 5 3714.83 22.54 3.47 3592.00 671.89 37.86 4.00 10.18 672.95 KBU 22-06/T 6 10093.16 23.65 3.46 9459.00 3169.35 189.01 0.02 -0.26 3174.98 KBU 22-06}T Sterling 7 10200.00 2365 3.48 9556.87 3212.13 191.60 0.00 0.00 3217.84 3000- - KBU 22-06Y TO wp3 - - Start Dir 4°/100':3701.49'MD,3579.66TVD H A LLI B U RTO N .?. 3750- -_ o _ Sterling 5.2Start Dir 0.02°/100':3714.83'MD,3592'T/D Sperry Grilling 0 Lo - _Sterling Pool 6 4500- - - - - - - - - - - - - - - - - - - - Hilcorp Energy Company Calculation Method:Minimum Curvature oet Error System:ISCWSA p -, Upper Beluga Scan Method:Closest Approach 3D Error TS 5250- Warning Method:Error Ratio Conicical N > - Middle Beluga N _ REFERENCE INFORMATION 2 6000- _ _ _ _ _ _ _ _7_�B Co-ordinate(NE)Reference:Well KBU 22-06Y,True North ~ r- Vertical(ND)Reference:Actual:KBU 22-06Y©83.00usft Lower Beluga Measured Depth Reference:Actual:KBU 22-06Y @ 03.00000 Calculation Method:Minimum Curvature 6750-I KBU 22-COY T1 wp3 - Project: Kenai Gas Field - - - - - - - - - - - Site: KGF 14-6 Pad 7500- Upper Tyonek Weil: KBU 22-06Y Wellbore: KBU22-06Y KBU 22-06Y wp3 8250- Tyonek D1 7.V - - _ _ _ - - _ _ End Dir :10093.16 MD,9459'TVD -L--- 9000 -'Tyonek D2- -- -. ._- - - - - - - - - - - - - - - - -_.. - - - -- 1 =Tyonek D3B- - - - - - - - - - - - - - - 9750 s. KBU 22-06Y T2 wp3 5 Tyonek D4A Total Depth:10200'MD,9556.87'TVD - KBU 22-06Y wp3 10500 1 I 1 I I I i I I 1 I i I 1 1 I i I I I I I I i i i i 1 I I I I I 1 I I I I I I I I I I I I I I I I I I I I I I I I I 1 1 I I I I I I I III I I -3750 -3000 -2250 -1500 -750 0 750 1500 2250 3000 3750 4500 5250 6000 6750 Vertical Section at 3.41°(1500 usfltn) HALLIBURTON Project:Kenai leld ECTIOSDETAILS Site: KGF 1 d Sec MD Inc Azi T +N/-S +E/-W Dleg TFace VSea Target Well: KBU2 1 18.00 0.00 0.00 180 0.00 0.00 0.00 0.00 0.00 -_-- 2 160000 0.00 0.00 1600.00 0.00 0.00 0.00 0.00 000 Sperry Drilling Wellbore: KBU 22-06Y 3 2247.50 22.01 3.22 2231.68 12268 6.91 3.40 3.22 122.87 KBU 22-06Y wp3 4 3701.49 22.01 3.22 357966 66684 37.56 0.00 0.00 667.89 5 3714.83 22.54 3.47 359200 671.89 37.88 4.00 10.18 672.95 KBU 22-06Y TO wp3 __ 6 10093.18 23.65 3.46 9459.00 3169.35 189.01 0.02 -0.26 317498 KBU 22-06Y T2 wp3 WELL DETAILS'KBU 22-06Y 7 10200.00 23.65 3.46 955687 3212.13 19160 0.00 0.00 3217.84 Ground Level: 65.00 +N/-S +E/-W Northing Easting Latittude Longitude Slot COMPANY DETAILS: liiloor9 Energy Company 0.00 0.00 2362472.99 272112.27 60.4606294 -151.2625281 " Calculation Method:Minanum Curvature 5" KBU 22-06Y wp3 Scaon r M hod:iSCWSA Clo a[Approach 3D 3300- KBU 22-067 T2 wp3 Error Surface:Elliptical Conic Total Depth:10200'MD,9556.87 TVD - Warning Method:Error Ratio ----- - 3080- -- - - End Dir:10093.16'MD,9459'TVD SURVEY PROGRAM 2860- Date:2015-01-29700:00:00 Validated:Yes Vernon Depth From Depth To Survey/Plan Tool - 18.00 249900 KBU 22-06Y wp3(KBU 22-06Y) MWD+SC+sag 2640- 2499.00 10200.00 KBU 22-06Y wp3(KBU 22-06Y) MWD+SC+sag 2420- - REFERENCE INFORMATION Coordinate(FRE)Reference: Well KBU 22-06Y,True North 2200- �� Vertical(TVD)Reference: Actual:KBU 22-06Y @ 83.00usft Measured Depth Reference: Actual KBU 22-06Y @ 83 00usft - Calculation Method: Minimum Curvature S 1980- - KBU 22-06Y Tl wp3 o - 7 5/8" 1760- 'C -_ 0 - 1540 Start Dir 0.02°/100':3714.83'MD,3592'TVD a 1320- v, 1100- - Start Dir 4°/l00':3701.49'MD,3579.66'TVD 990- KBU 22-06Y TO wp3 660_ -- ` ' 440- End Dir :2247.5'MD,2231.68'TVD 10 3/4" 220- Start Dir 3.4°/100':1600'MD,1600TVD---------- ):.,, o- -r-i-,r_Tr m rTr_rl1-111-1-1-MIT-1,1111,111-1111 itlllirriiirrilrtIIrrrIIn iiiiirtilitiiiiriliiiiiiiiiiiiiiirriiiiiiiiiiiiiiiiiiiirri -2640 -2420 -2200 -1980 -1760 -1540 -1320 -1100 -880 -660 -440 -220 0 220 440 660 880 1100 1320 1540 1760 1980 2200 2420 2640 2860 West(-)/East(+)(550 usft<n) HALLIBURTON KBo2-06Y wp3 • KBU 23X-6 KBU 22-06 Sperry Drilling Services Project: Kenai Gas Field 200— KU 13-6 /000 Site: KGF 14-6 Pad KDU 1 Well: KBU 22-06Y - Wellbore: KBU 22-06Y ' 1Bu 1 PB Plan: KBU 22-06Y wp3 o - Z--,100— X000 KU 21-7X -- C"_"" V�' KU 31-7X 4033— 770 - 0 2000 - C - KBU 11--07 0 , KBU 24-06RD - � 0— KU 14X-6 �Qo - o - 0 2000 I rn o o o KBU 24-06 3667— - -KBU 14-06Y - I I 1q0 I I I I I I I I - -100 0 100 200 300 West(-)/East(+)(150 usft/in) 3300— KBU 22-06Y wp3 7 • KBU 22-06 2933— 9000 - 4000 2567- 8000 C - KU 13-6 2200— o 100_ , KBU 23X-6 + - 6000 3000 C 1833— p0oo 0 - 6000 7 O 5000 r/, 1467- - 5000 - X000 1100— 4000 2000 4000 733- 000 0KBU 24-06RD KDU I ti KDU 1 PB 300, 5000 - 3001 ' 367- 00 o -KBU 24-06 KU 14X-6 0 i o/ � �ro0p � '� o 0 - Y� o 0o , o 0 ��1 2000 o 0 4000 T M Azimuths to True North - o - o Magnetic North:16.62° _ c lcy U2I-7PPo o A� Magnetic Field 19: X14-06Y Strength:55327.1snT - KU 2I-7X Dip Angle:73.44° -367— KBU 11-07 111 Date:3/31/2015 Model:BGGM2014 KBU 23-07 KU 21-7 KU 31-7X -I I I I i I I I I 1 I I I I I I I I I I I I I -1467 -1100 -733 -367 0 367 733 1100 1467 1833 2200 West(-)/East(+)(550 usft/in) • 0 Halliburton H LLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Actual:KBU 22-06Y @ 83.00usft Project: Kenai Gas Field MD Reference: Actual: KBU 22-06Y @ 83.00usft Site: KGF 14-6 Pad North Reference: True Well: KBU 22-06Y Survey Calculation Method: Minimum Curvature ' Wellbore: KBU 22-06Y Design: KBU 22-06Y wp3 , i , , , 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 KGF 14-6 Pad Site Position: Northing: 2,362,394.10 usft Latitude: 60.4603760 From: Map Easting: 271,396.69 usft Longitude: -151.2664830 Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.10° ORM.h,tm_ .�4Aa-' -r,,,r., ,&,.,,n,,..;.< Well KBU 22-06Y Well Position +N/-S 0.00 usft Northing: 2,362,472.99 usf . Latitude: 60.4606294 +E/-W 0.00 usft Easting: 272,112.27 usf . Longitude: -151.2625281 Position Uncertainty 0.00 usft Wellhead Elevation: 0.00 usf Ground Level: - 65.00usft Wellbore KBU 22-06Y Magnetics Model Name Sample Date Declination Dip Angle Field Strength (°) (°) (nT) BGGM2014 3/31/2015 16.62 73.44 55,327 KB206YDesign a U2 - wp3 ,.. .. ,,,w, .� .� �A.. t., '+ ., 1.,VGC 14,M- appMM.,`"-.4. Audit Notes: Version: Phase: PLAN Tie On Depth: 18.00 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (usft) (usft) (usft) (°) 18.00 0.00 0.00 3.41 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +E/-W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) 0100usft) (°/100usft) (°/100usft) (°) 18.00 0.00 0.00 18.00 -65.00 0.00 0.00 0.00 0.00 0.00 0.00 1,600.00 0.00 0.00 1,600.00 1,517.00 0.00 0.00 0.00 0.00 0.00 0.00 2,247.50 22.01 3.22 2,231.68 2,148.68 122.68 6.91 3.40 3.40 0.00 3.22 3,701.49 22.01 3.22 3,579.66 3,496.66 666.84 37.56 0.00 0.00 0.00 0.00 3,714.83 22.54 3.47 3,592.00 3,509.00 671.89 37.86 4.00 3.94 1.84 10.18 10,093.16 23.65 3.46 9,459.00 9,376.00 3,169.35 189.01 0.02 0.02 0.00 -0.26 10,200.00 23.65 3.46 9,556.87 9,473.87 3,212.13 191.60 0.00 0.00 0.00 0.00 3/12/2015 6:17:49PM Page 2 COMPASS 5000.1 Build 73 • • Halliburton HA L. LI B U RTD N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Actual:KBU 22-06Y @ 83.00usft Project: Kenai Gas Field MD Reference: Actual: KBU 22-06Y @ 83.00usft Site: KGF 14-6 Pad North Reference: True Well: KBU 22-06Y Survey Calculation Method: Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +EI-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -65.00 18.00 0.00 0.00 18.00 -65.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 100.00 0.00 0.00 100.00 17.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 200.00 0.00 0.00 200.00 117.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 300.00 0.00 0.00 300.00 217.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 400.00 0.00 0.00 400.00 317.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 500.00 0.00 0.00 500.00 417.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 600.00 0.00 0.00 600.00 517.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 700.00 0.00 0.00 700.00 617.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 800.00 0.00 0.00 800.00 717.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 900.00 0.00 0.00 900.00 817.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 1,000.00 0.00 0.00 1,000.00 917.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 1,100.00 0.00 0.00 1,100.00 1,017.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 1,200.00 0.00 0.00 1,200.00 1,117.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 1,300.00 0.00 0.00 1,300.00 1,217.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 1,400.00 0.00 0.00 1,400.00 1,317.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 1,500.00 0.00 0.00 1,500.00 1,417.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 10 3/4" 1,600.00 0.00 0.00 1,600.00 1,517.00 0.00 0.00 2,362,472.99 272,112.27 0.00 0.00 Start Dir 3.4°/100':1600'MD,1600'TVD 1,700.00 3.40 3.22 1,699.94 1,616.94 2.96 0.17 2,362,475.95 272,112.49 3.40 2.97 1,800.00 6.80 3.22 1,799.53 1,716.53 11.84 0.67 2,362,484.81 272,113.16 3.40 11.85 1,900.00 10.20 3.22 1,898.42 1,815.42 26.59 1.50 2,362,499.55 272,114.28 3.40 26.63 2,000.00 13.60 3.22 1,996.25 1,913.25 47.18 2.66 2,362,520.10 272,115.83 3.40 47.25 2,100.00 17.00 3.22 2,092.70 2,009.70 73.52 4.14 2,362,546.41 272,117.82 3.40 73.63 2,200.00 20.40 3.22 2,187.40 2,104.40 105.52 5.94 2,362,578.38 272,120.24 3.40 105.69 2,247.50 22.01 3.22 2,231.68 2,148.68 122.68 6.91 2,362,595.51 272,121.53 3.40 122.87 End Dir : 2247.5'MD,2231.68'TVD 2,300.00 22.01 3.22 2,280.36 2,197.36 142.33 8.02 2,362,615.13 272,123.01 0.00 142.55 2,400.00 22.01 3.22 2,373.07 2,290.07 179.75 10.13 2,362,652.51 272,125.84 0.00 180.04 2,500.00 22.01 3.22 2,465.77 2,382.77 217.18 12.23 2,362,689.88 272,128.66 0.00 217.52 2,600.00 22.01 3.22 2,558.48 2,475.48 254.60 14.34 2,362,727.26 272,131.49 0.00 255.01 2,700.00 22.01 3.22 2,651.19 2,568.19 292.03 16.45 2,362,764.64 272,134.31 0.00 292.49 2,800.00 22.01 3.22 2,743.90 2,660.90 329.45 18.56 2,362,802.01 272,137.14 0.00 329.97 2,900.00 22.01 3.22 2,836.61 2,753.61 366.88 20.67 2,362,839.39 272,139.96 0.00 367.46 3,000.00 22.01 3.22 2,929.32 2,846.32 404.30 22.77 2,362,876.77 272,142.79 0.00 404.94 3,100.00 22.01 3.22 3,022.03 2,939.03 441.73 24.88 2,362,914.14 272,145.62 0.00 442.43 3,200.00 22.01 3.22 3,114.73 3,031.73 479.16 26.99 2,362,951.52 272,148.44 0.00 479.91 3,300.00 22.01 3.22 3,207.44 3,124.44 516.58 29.10 2,362,988.90 272,151.27 0.00 517.40 3,400.00 22.01 3.22 3,300.15 3,217.15 554.01 31.21 2,363,026.27 272,154.09 0.00 554.88 3,500.00 22.01 3.22 3,392.86 3,309.86 591.43 33.32 2,363,063.65 272,156.92 0.00 592.37 3,600.00 22.01 3.22 3,485.57 3,402.57 628.86 35.42 2,363,101.03 272,159.74 0.00 629.85 3,700.00 22.01 3.22 3,578.28 3,495.28 666.28 37.53 2,363,138.40 272,162.57 0.00 667.33 3,701.49 22.01 3.22 3,579.66 3,496.66 666.84 37.56 2,363,138.96 272,162.61 0.00 667.89 Start Dir 4°/100':3701.49'MD,3579.66'TVD 3/12/2015 6:17:49PM Page 3 COMPASS 5000.1 Build 73 • • Halliburton HA" LLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Actual:KBU 22-06Y @ 83.00usft Project: Kenai Gas Field MD Reference: Actual:KBU 22-06Y @ 83.00usft Site: KGF 14-6 Pad North Reference: True Well: KBU 22-06Y Survey Calculation Method: Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 3,507.00 3,712.66 22.45 3.43 3,590.00 3,507.00 671.06 37.81 2,363,143.17 272,162.93 4.00 672.12 Sterling 3,714.83 22.54 3.47 3,592.00 3,509.00 671.89 37.86 2,363,144.00 272,163.00 3.99 672.95 Start Dir 0.02°/100':3714.83'MD,3592'TVD 3,800.00 22.55 3.47 3,670.66 3,587.66 704.49 39.83 2,363,176.55 272,165.60 0.02 705.61 3,900.00 22.57 3.47 3,763.01 3,680.01 742.79 42.16 2,363,214.80 272,168.66 0.02 743.98 4,000.00 22.59 3.47 3,855.34 3,772.34 781.12 44.48 2,363,253.08 272,171.72 0.02 782.38 4,100.00 22.61 3.47 3,947.66 3,864.66 819.47 46.81 2,363,291.38 272,174.78 0.02 820.81 4,200.00 22.62 3.47 4,039.98 3,956.98 857.86 49.13 2,363,329.71 272,177.84 0.02 859.26 4,300.00 22.64 3.47 4,132.27 4,049.27 896.27 51.46 2,363,368.07 272,180.90 0.02 897.74 4,364.72 22.65 3.47 4,192.00 4,109.00 921.14 52.97 2,363,392.91 272,182.89 0.02 922.66 Sterling 5.2 4,400.00 22.66 3.47 4,224.56 4,141.56 934.71 53.79 2,363,406.46 272,183.97 0.02 936.26 4,500.00 22.68 3.47 4,316.84 4,233.84 973.18 56.12 2,363,444.87 272,187.04 0.02 974.79 4,600.00 22.69 3.47 4,409.10 4,326.10 1,011.68 58.46 2,363,483.32 272,190.11 0.02 1,013.36 4,685.53 22.71 3.47 4,488.00 4,405.00 1,044.62 60.45 2,363,516.22 272,192.74 0.02 1,046.37 Sterling Pool 6 4,700.00 22.71 3.47 4,501.35 4,418.35 1,050.20 60.79 2,363,521.79 272,193.18 0.02 1,051.96 4,800.00 22.73 3.47 4,593.59 4,510.59 1,088.75 63.13 2,363,560.29 272,196.26 0.02 1,090.58 4,900.00 22.75 3.47 4,685.82 4,602.82 1,127.34 65.47 2,363,598.82 272,199.33 0.02 1,129.23 4,959.84 22.76 3.47 4,741.00 4,658.00 1,150.43 66.87 2,363,621.88 272,201.17 0.02 1,152.37 Upper Beluga 5,000.00 22.76 3.47 4,778.04 4,695.04 1,165.94 67.80 2,363,637.37 272,202.41 0.02 1,167.91 5,100.00 22.78 3.47 4,870.24 4,787.24 1,204.58 70.15 2,363,675.96 272,205.49 0.02 1,206.62 5,200.00 22.80 3.47 4,962.43 4,879.43 1,243.25 72.49 2,363,714.57 272,208.58 0.02 1,245.36 5,300.00 22.82 3.47 5,054.61 4,971.61 1,281.94 74.83 2,363,753.21 272,211.66 0.02 1,284.12 5,400.00 22.83 3.47 5,146.78 5,063.78 1,320.66 77.18 2,363,791.87 272,214.75 0.02 1,322.91 5,500.00 22.85 3.47 5,238.94 5,155.94 1,359.41 79.53 2,363,830.57 272,217.84 0.02 1,361.73 5,600.00 22.87 3.47 5,331.09 5,248.09 1,398.19 81.87 2,363,869.29 272,220.93 0.02 1,400.58 5,644.40 22.88 3.47 5,372.00 5,289.00 1,415.41 82.92 2,363,886.50 272,222.30 0.02 1,417.84 Middle Beluga 5,700.00 22.89 3.47 5,423.22 5,340.22 1,436.99 84.22 2,363,908.04 272,224.02 0.02 1,439.46 5,800.00 22.90 3.47 5,515.34 5,432.34 1,475.82 86.58 2,363,946.82 272,227.12 0.02 1,478.36 5,900.00 22.92 3.47 5,607.45 5,524.45 1,514.69 88.93 2,363,985.63 272,230.22 0.02 1,517.29 6,000.00 22.94 3.47 5,699.55 5,616.55 1,553.58 91.28 2,364,024.47 272,233.32 0.02 1,556.25 6,100.00 22.96 3.47 5,791.64 5,708.64 1,592.49 93.64 2,364,063.33 272,236.42 0.02 1,595.24 6,200.00 22.97 3.46 5,883.71 5,800.71 1,631.44 96.00 2,364,102.22 272,239.52 0.02 1,634.26 6,300.00 22.99 3.46 5,975.77 5,892.77 1,670.41 98.36 2,364,141.14 272,242.63 0.02 1,673.30 6;326.32. 23.00 3.46 6,000.00 5,917.00 1,680.67 98.98 2,364,151.39 272,243.45 0.02 1,683.58 / 7 5/8" '\$,400.00 23.01 3.46 6,067.83 5,984.83 1,709.41 100.72 2,364,180.09 272,245.74 0.02 1,712.38 6,431.70 23.01 3.46 6,097.00 6,014.00 1,721.78 101.47 2,364,192.44 272,246.72 0.02 1,724.77 Lower Beluga 6,500.00 23.03 3.46 6,159.86 6,076.86 1,748.44 103.08 2,364,219.06 272,248.85 0.02 1,751.48 6,600.00 23.04 3.46 6,251.89 6,168.89 1,787.50 105.45 2,364,258.06 272,251.96 0.02 1,790.60 3/12/2015 6:17:49PM Page 4 COMPASS 5000.1 Build 73 • • Halliburton HALLIBURTOII Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Actual:KBU 22-06Y @ 83.00usft Project: Kenai Gas Field MD Reference: Actual:KBU 22-06Y @ 83.00usft Site: KGF 14-6 Pad North Reference: True Well: KBU 22-06Y Survey Calculation Method: Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +NI-5 +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 6,260.91 6,700.00 23.06 3.46 6,343.91 6,260.91 1,826.58 107.81 2,364,297.10 272,255.08 0.02 1,829.76 6,800.00 23.08 3.46 6,435.91 6,352.91 1,865.70 110.18 2,364,336.15 272,258.19 0.02 1,868.95 6,900.00 23.10 3.46 6,527.90 6,444.90 1,904.84 112.55 2,364,375.24 272,261.31 0.02 1,908.16 7,000.00 23.11 3.46 6,619.88 6,536.88 1,944.00 114.92 2,364,414.36 272,264.43 0.02 1,947.40 7,100.00 23.13 3.46 6,711.85 6,628.85 1,983.20 117.29 2,364,453.50 272,267.56 0.02 1,986.67 7,200.00 23.15 3.46 6,803.80 6,720.80 2,022.43 119.67 2,364,492.67 272,270.68 0.02 2,025.96 7,300.00 23.17 3.46 6,895.75 6,812.75 2,061.68 122.04 2,364,531.87 272,273.81 0.02 2,065.29 7,400.00 23.18 3.46 6,987.68 6,904.68 2,100.96 124.42 2,364,571.09 272,276.94 0.02 2,104.64 7,500.00 23.20 3.46 7,079.60 6,996.60 2,140.27 126.80 2,364,610.35 272,280.07 0.02 2,144.02 7,600.00 23.22 3.46 7,171.50 7,088.50 2,179.60 129.18 2,364,649.63 272,283.20 0.02 2,183.43 7,700.00 23.24 3.46 7,263.40 7,180.40 2,218.97 131.56 2,364,688.94 272,286.34 0.02 2,222.87 7,709.36 23.24 3.46 7,272.00 7,189.00 2,222.66 131.78 2,364,692.62 272,286.63 0.00 2,226.56 Upper Tyonek 7,800.00 23.25 3.46 7,355.28 7,272.28 2,258.36 133.94 2,364,728.28 272,289.48 0.02 2,262.33 7,900.00 23.27 3.46 7,447.15 7,364.15 2,297.78 136.33 2,364,767.64 272,292.62 0.02 2,301.82 8,000.00 23.29 3.46 7,539.01 7,456.01 2,337.23 138.71 2,364,807.04 272,295.76 0.02 2,341.34 8,100.00 23.30 3.46 7,630.86 7,547.86 2,376.71 141.10 2,364,846.46 272,298.90 0.02 2,380.89 8,200.00 23.32 3.46 7,722.70 7,639.70 2,416.21 143.49 2,364,885.91 272,302.05 0.02 2,420.47 8,300.00 23.34 3.46 7,814.52 7,731.52 2,455.74 145.88 2,364,925.38 272,305.20 0.02 2,460.07 8,400.00 23.36 3.46 7,906.33 7,823.33 2,495.30 148.27 2,364,964.89 272,308.35 0.02 2,499.70 8,500.00 23.37 3.46 7,998.13 7,915.13 2,534.89 150.67 2,365,004.42 272,311.50 0.02 2,539.36 8,600.00 23.39 3.46 8,089.92 8,006.92 2,574.51 153.06 2,365,043.98 272,314.65 0.02 2,579.05 8,700.00 23.41 3.46 8,181.69 8,098.69 2,614.15 155.46 2,365,083.57 272,317.81 0.02 2,618.77 8,800.00 23.43 3.46 8,273.45 8,190.45 2,653.82 157.86 2,365,123.19 272,320.97 0.02 2,658.51 8,900.00 23.44 3.46 8,365.21 8,282.21 2,693.52 160.26 2,365,162.83 272,324.13 0.02 2,698.28 9,000.00 23.46 3.46 8,456.94 8,373.94 2,733.25 162.66 2,365,202.50 272,327.29 0.02 2,738.08 9,100.00 23.48 3.46 8,548.67 8,465.67 2,773.00 165.06 2,365,242.20 272,330.46 0.02 2,777.91 9,200.00 23.50 3.46 8,640.38 8,557.38 2,812.79 167.47 2,365,281.93 272,333.62 0.02 2,817.77 9,300.00 23.51 3.46 8,732.09 8,649.09 2,852.60 169.87 2,365,321.69 272,336.79 0.02 2,857.65 9,347.89 23.52 3.46 8,776.00 8,693.00 2,871.67 171.03 2,365,340.74 272,338.31 0.02 2,876.76 Tyonek D1 9,400.00 23.53 3.46 8,823.78 8,740.78 2,892.43 172.28 2,365,361.47 272,339.96 0.02 2,897.56 9,500.00 23.55 3.46 8,915.46 8,832.46 2,932.30 174.69 2,365,401.28 272,343.14 0.02 2,937.50 9,514.78 23.55 3.46 8,929.00 8,846.00 2,938.19 175.05 2,365,407.17 272,343.60 0.02 2,943.40 Tyonek D2 9,600.00 23.57 3.46 9,007.12 8,924.12 2,972.20 177.10 2,365,441.12 272,346.31 0.02 2,977.47 9,700.00 23.58 3.46 9,098.77 9,015.77 3,012.12 179.51 2,365,480.99 272,349.49 0.02 3,017.46 9,800.00 23.60 3.46 9,190.42 9,107.42 3,052.07 181.93 2,365,520.88 272,352.67 0.02 3,057.49 9,867.21 23.61 3.46 9,252.00 9,169.00 3,078.93 183.55 2,365,547.71 272,354.81 0.02 3,084.40 Tyonek D3B 9,900.00 23.62 3.46 9,282.05 9,199.05 3,092.05 184.34 2,365,560.81 272,355.85 0.02 3,097.54 10,000.00 23.64 3.46 9,373.66 9,290.66 3,132.05 186.76 2,365,600.76 272,359.03 0.02 3,137.62 10,090.97 23.65 3.46 9,457.00 9,374.00 3,168.47 188.96 2,365,637.13 272,361.93 0.02 3,174.10 Tyonek D4A 3/12/2015 6:17:49PM Page 5 COMPASS 5000.1 Build 73 • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Actual:KBU 22-06Y @ 83.00usft Project: Kenai Gas Field MD Reference: Actual:KBU 22-06Y @ 83.00usft Site: KGF 14-6 Pad North Reference: True Well: KBU 22-06Y Survey Calculation Method: Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp3 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) 9,376.00 10,093.16 23.65 3.46 9,459.00 9,376.00 3,169.35 189.01 2,365,638.00 272,362.00 0.02 3,174.98 End Dir : 10093.16'MD,9459'TVD 10,100.00 23.65 3.46 9,465.27 9,382.27 3,172.09 189.18 2,365,640.74 272,362.22 0.00 3,177.72 10,199.99 23.65 3.46 9,556.86 9,473.86 3,212.13 191.60 2,365,680.72 272,365.40 0.00 3,217.84 Total Depth:10200'MD,9556.87'TVD-5" ' 10,200.00 23.65 3.46 9,556.87. 9,473.87 3,212.13 191.60 2,365,680.73 272,365.40 0.00 3,217.84 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +NI-S +E/-W Northing Easting -Shape (°) (°) (usft) (usft) (usft) (usft) (usft) KBU 22-06Y T2 wp3 0.00 0.00 9,459.00 3,169.35 189.01 2,365,638.00 272,362.00 -plan hits target center -Circle(radius 100.00) KBU 22-06Y T1 wp3 0.00 0.00 7,274.00 2,197.10 135.64 2,364,667.00 272,290.00 -plan misses target center by 24.61 usft at 7701.23usft MD(7264.53 TVD,2219.45 N, 131.59 E) -Circle(radius 100.00) KBU 22-06Y TO wp3 0.00 0.00 3,592.00 671.89 37.86 2,363,144.00 272,163.00 -plan hits target center -Circle(radius 100.00) Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name C') (") 1,500.00 1,500.00 10 3/4" 10-3/4 13-1/2 6,326.32 6,000.00 7 5/8" 7-5/8 9-7/8 10,199.99 9,556.86 5" 5 6-3/4 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (°) (°) 3,712.66 3,590.00 Sterling 0.00 9,347.89 8,776.00 Tyonek D1 0.00 4,959.84 4,741.00 Upper Beluga 0.00 9,514.78 8,929.00 Tyonek D2 0.00 7,709.36 7,272.00 Upper Tyonek 0.00 9,867.21 9,252.00 Tyonek D3B 0.00 4,364.72 4,192.00 Sterling 5.2 0.00 6,431.70 6,097.00 Lower Beluga 0.00 10,090.97 9,457.00 Tyonek D4A 0.00 4,685.53 4,488.00 Sterling Pool 6 0.00 5,644.40 5,372.00 Middle Beluga 0.00 3/12/2015 6:17:49PM Page 6 COMPASS 5000.1 Build 73 0 • Halliburton ALLIBURTDI J Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Actual:KBU 22-06Y @ 83.00usft Project: Kenai Gas Field MD Reference: Actual: KBU 22-06Y @ 83.00usft Site: KGF 14-6 Pad North Reference: True Well: KBU 22-06Y Survey Calculation Method: Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp3 Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/-S +E/-W (usft) (usft) (usft) (usft) Comment 1,600.00 1,600.00 0.00 0.00 Start Dir 3.4°/100': 1600'MD, 1600'TVD 2,247.50 2,231.68 122.68 6.91 End Dir :2247.5'MD,2231.68'TVD 3,701.49 3,579.66 666.84 37.56 Start Dir 4°/100':3701.49'MD,3579.66'TVD 3,714.83 3,592.00 671.89 37.86 Start Dir 0.02°/100':3714.83'MD,3592'TVD 10,093.16 9,459.00 3,169.35 189.01 End Dir : 10093.16'MD,9459'TVD 10,199.99 9,556.86 3,212.13 191.60 Total Depth: 10200'MD,9556.87'TVD 3/12/2015 6:17:49PM Page 7 COMPASS 5000.1 Build 73 4111 • Hilcorp Energy Company Kenai Gas Field KGF 14-6 Pad KBU 22-06Y KBU 22-06Y KBU 22-06Y wp3 Sperry Drilling Services Clearance Summary Anticollision Report 12 March,2015 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: KGF 14-6 Pad-KBU 22-06Y-KBU 22-06Y-KBU 22-06Y wp3 Well Coordinates: 2,362,472.99 N,272,112.27 E (60°27'38.27"N,151°15'45.10"W) Datum Height: Actual:KBU 22-06Y @ 83.00usft Scan Range: 0.00 to 10,200.00 usft.Measured Depth. Scan Radius is 1,218.20 usft. Clearance Factor cutoff is Unlimited. Max Ellipse Separation Is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 73 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 (11=101111111r VIIMM1111111111 HALLIBURTON Sperry Drilling Services l• • Hilcorp Energy Company HALLIBURTON Kenai Gas Field Anticollision Report for KBU 22-06Y - KBU 22-06Y wp3 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: KGF 14-6 Pad-KBU 22-06Y-KBU 22-06Y•KBU 22-06Y wp3 Scan Range: 0.00 to 10,200.00 usft.Measured Depth. Scan Radius is 1,218.20 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 18.00 139.06 18.00 137.66 21.99 99.049 Centre Distance Pass- KBU 11-07-KBU 11--07-KBU 11-07 1,100.00 140.68 1,100.00 130.07 1,109.69 13.252 Ellipse Separation Pass- KBU 11-07-KBU 11--07-KBU 11--07 1,350.00 157.50 1,350.00 144.10 1,347.04 11.749 Clearance Factor Pass- KBU 14-06Y-KBU 14-06Y-KBU 14-06Y 1,040.10 88.59 1,040.10 75.43 1,044.18 6.731 Centre Distance Pass- KBU 14-06Y-KBU 14-06Y-KBU 14-O6Y 1,050.00 88.60 1,050.00 75.40 1,053.95 6.711 Ellipse Separation Pass- KBU 14-06Y-KBU 14-06Y-KBU 14-06Y 1,075.00 88.68 1,075.00 75.45 1,078.62 6.703 Clearance Factor Pass- KBU 22-06-KBU 22-06-KBU 22-06 212.50 94.32 212.50 91.50 216.50 33.453 Centre Distance Pass- KBU 22-06-KBU 22-06-KBU 22-06 275.00 94.57 275.00 91.10 277.81 27.242 Ellipse Separation Pass- KBU 22-06-KBU 22-06-KBU 22-06 700.00 142.53 700.00 134.63 680.63 18.044 Clearance Factor Pass- KBU 23-07-KBU 23-07-KBU 23-07 1,307.43 110.89 1,307.43 96.25 1,311.98 7.573 Centre Distance Pass- KBU 23-07-KBU 23-07-KBU 23-07 1,350.00 111.01 1,350.00 96.15 1,353.90 7.470 Clearance Factor Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 2,105.57 60.42 2,105.57 42.54 2,145.80 3.380 Centre Distance Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 2,175.00 61.53 2,175.00 41.62 2,215.23 3.091 Ellipse Separation Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 6,875.00 392.97 6,875.00 228.59 6,950.00 2.391 Clearance Factor Pass- KBU 24-06-KBU 24-06-KBU 24-06 1,500.00 112.60 1,500.00 95.34 1,504.92 6.524 Clearance Factor Pass- KBU 24-06-KBU 24-06-KBU 24-06 1,620.65 112.01 1,620.65 95.28 1,626.27 6.698 Ellipse Separation Pass- KBU 24-06-KBU 24-O6RD-KBU 24-O6RD 1,500.00 112.60 1,500.00 95.34 1,504.92 6.524 Clearance Factor Pass- KBU 24-06-KBU 24-06RD-KBU 24-O6RD 1,620.65 112.01 1,620.65 95.54 1,626.27 6.801 Centre Distance Pass- KDU 1-KDU 1-KDU 1 1,600.00 208.97 1,600.00 24.56 1,607.00 1.133 Centre Distance Pass- KDU 1-KDU 1-KDU 1 1,900.00 225.01 1,900.00 2.60 1,905.42 1.012 Ellipse Separation Pass- KDU 1-KDU 1-KDU 1 2,075.00 252.40 2,075.00 2.62 2,075.74 1.010 Clearance Factor Pass- KDU 1-KDU 1 PB-KDU 1 PB 1,600.00 208.97 1,600.00 24.56 1,607.00 1.133 Centre Distance Pass- KDU 1-KDU 1 PB-KDU 1 PB 1,900.00 225.01 1,900.00 2.60 1,905.42 1.012 Ellipse Separation Pass- KDU 1-KDU 1 PB-KDU 1 PB 2,075.00 252.40 2,075.00 2.62 2,075.74 1.010 Clearance Factor Pass- KU 13-6-KU 13-6-KU 13-6 759.55 76.71 759.55 70.64 773.93 12.625 Centre Distance Pass- KU 13-6-KU 13-6-KU 13-6 775.00 76.79 775.00 70.59 788.95 12.397 Ellipse Separation Pass- KU 13-6-KU 13-6-KU 13-6 875.00 81.47 875,00 74.49 885.14 11.673 Clearance Factor Pass- KU 14X-6-KU 14X-6(KDU 8)-KU 14X-6 1,664.60 49.33 1,664.60 40.29 1,669.03 5.454 Centre Distance Pass- 12 March,2015- 18:12 Page 2 of 5 COMPASS • • Hilcorp Energy Company HALLIBURTON Kenai Gas Field Anticollision Report for KBU 22-06Y-KBU 22-06Y wp3 Closest Approach 3D Proximity Scan on Current Survey Data(North Reference) Reference Design: KGF 14.6 Pad-KBU 22-06Y-KBU 22-06Y-KBU 22-06Y wp3 Scan Range: 0.00 to 10,200.00 usft.Measured Depth. Scan Radius is 1,218.20 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 14X-6-KU 14X-6(KDU 8)-KU 14X-6 1,700.00 49.48 1,700.00 40.23 1,704.30 5.348 Ellipse Separation Pass- KU 14X-6-KU 14X-6(KDU 8)-KU 14X-6 1,750.00 50.33 1,750.00 40.79 1,754.02 5.275 Clearance Factor Pass- KU 21-7-KU 21-7-KU 21-7 1,344.91 158.46 1,344.91 151.29 1,355.95 22.106 Centre Distance Pass- KU 21-7-KU 21-7-KU 21-7 1,375.00 158.56 1,375.00 151.19 1,385.62 21.504 Ellipse Separation Pass- KU 21-7-KU 21-7-KU 21-7 1,650.00 170.24 1,650.00 161.26 1,654.78 18.960 Clearance Factor Pass- KU 21-7-KU 21-7PB-KU 21-7PB 937.11 146.83 937.11 140.47 951.47 23.092 Centre Distance Pass- KU 21-7-KU 21-7PB-KU 21-7PB 950.00 146.87 950.00 140.42 963.72 22.780 Ellipse Separation Pass- KU 21-7-KU 21-7PB-KU 21-7PB 1,200.00 159.04 1,200.00 151.07 1,206.00 19.958 Clearance Factor Pass- KU 21-7X-KU 21-7X-KU 21-7X 1,856.60 132.80 1,856.60 124.30 1,851.91 15.615 Ellipse Separation Pass- KU 21-7X-KU 21-7X-KU 21-7X 2,050.00 139.32 2,050.00 129.94 2,034.76 14.852 Clearance Factor Pass- KU 31-7X-KU 31-7X-KU 31-7X 175.52 168.26 175.52 165.75 179.52 66.935 Centre Distance Pass- KU 31-7X-KU 31-7X-KU 31-7X 525.00 170.22 525.00 163.66 526.94 25.958 Ellipse Separation Pass- KU 31-7X-KU 31-7X-KU 31-7X 1,200.00 226.85 1,200.00 211.81 1,170.83 15.078 Clearance Factor Pass- Survey tool oroaram From To Survey/Plan Survey Tool (usft) (usft) 18.00 2,499.00 KBU 22-06Y wp3 MWD+SC+sag 2,499.00 10,200.00 KBU 22-06Y wp3 MWD+SC+sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 12 March,2015-18:12 Page 3 of 5 COMPASS 411 • Hilcorp Energy Company HALLIBURTON Kenai Gas Field Anticollision Report for KBU 22-06Y - KBU 22-06Y wp3 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to Actual:KBU 22-06Y©83.00usft. Northing and Easting are relative to KBU 22-06Y. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150.00°,Grid Convergence at Surface is: -1.10°. Ladder Plot r____ r ___+ A___� - y y_.. I b i I e c ���� �� ,� LEGEND E1050— 1 , i - KBU 11-07,KBU 11-07,KBU 11-07 VO o r4 ►� ' < 4 1 - KBU 14-06Y,KBU 14-06Y,KBU 14-06Y V0 co ---1-------- ra -9- KBU22-06,KBU22-06,KBU22-06 VO E / i 4' i $ KBU23-07,KBU23-07,KBU23-07V0 p U% I .,/i 9i 'AI KBU23X-6,KBU23X-6,KBU23X-6W L 700— , as i -6- KBU2406,KBU24-06,KBU24-06V0 � It �1, ! KBU24-06,KBU2406RD,KBU24-06RDV0 (n I r, �il. � p�<� $ KDU1,KDU1,KDU1V0 2 -- :----- i f + 1 _.___._. �A ii ii �,l j� -P- KDUI,KDU1 PB,KDU1 PB VO I KU 13-6,KU 13-6,KU 13-6 VO 350- rm ,i � —4— KU 14X-6,KU14X-6(KDUB),KU14X-6V0 �. ..- ' / O / t 4 .- -8- KU21-7,KU21-7,KU21-7 VO i EL--) < �I�/ c' , KU 21-7,KU21-7PB,KU21-7PBV0 ----- ---- - -f- KU21-7X,KU21-7X,KU21-7XV0 U __N� °�' I -B- KU31-7X,KU31-7X,KU31-7XV0 -9- KBU22-06Ywp3 0 0 1500 3000 4500 6000 7500 Measured Depth(1500 usft/in) 12 March,2015-18:12 Page 4 of 5 COMPASS • . Hilcorp Energy Company HALLIBURTON Kenai Gas Field Anticollision Report for KBU 22-06Y - KBU 22-06Y wp3 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor 10.00 1--- - 4, \° 1 8.75— i 1 LEGEND _ r(,t .\ .4- KBU 11-07,KBU 11-07,KBU 11-07V0 7.50—. -___ -- KBU 14-06Y,KBU 14-06Y,KBU 14 06Y VO o _ 0,4 $ KBU22-06,KBU 22-06,KBU 22-06V0 O aD -e- KBU23-07,KBU 23-07,KBU23-07V0 6.25- __-_ ___.. ._.-._ _._. --..... o - -t- KBU23X-6 KBU23X-6 KBU 23X-6V0 mKBU24-06,KBU 24-06,KBU24-06 V0 O 5.00- -' - KBU 24-06,KBU 24-06RD,KBU24-06RDV0 _Ii $ KDU1,KDU1,KDU1V0 o _1 -♦- KDU1,KDU1 PB,KDU1 PB VO r U) 3.75- t L KU 13-6,KU 13-6,KU 13-6 VO -3- KU 14X8,KU 14X-6(KDU8),KU 14X-6V0 - 6' -. .4- KU21-7,KU21-7,KU21-7V0 2.50- .-..._ _.-.. ,-_ _._.__ __._.__-- -- _._ ___ ® $ KU 21-7,KU 21-7PB,KU21-7PBV0 �Collision Avoidance Rea, . KU21-7X,KU21-7X,KU21-7XV0 —14S.iOZone-Stop Drilling -9- KU31-7X,KU 31-7X,KU31-7XV0 1.25— _— _. m c w_ e _._... d - $ KBU 22-06Ywp3 000- 1 . . , 111 I1 1111IIII III H II III lIIII 1111 1111111iiili ' I 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 8250 9000 Measured Depth(1500lstt/n) 12 March,2015-18:12 Page 5 of 5 COMPASS • • TRANSMITTAL LETTER CHECKLIST WELL NAME: XB 22 -(1)6 )) ��� e ) PTD: s-- - U Y 7' Development Service _Exploratory Stratigraphic Test _Non-Conventional FIELD: � �/ S POOL: ( 671.-€4.=- Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application,the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(dX2XB) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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X 3, a. co a E. ca m 6 Y o a`)'. 6 c o' 0' 0 a', o a a 8. m. o y 3. o, .; �, 2' 2' 0, o as -o = O' O' -C o' °. a a)' ca; y; aaa)i, o; � a > z °- - D �; ' (I) 4_= 0' 0; aa0 �' Q0. o; `o0o' o; o' a •=; a — a' mm; os; e. 2 CI- 0cocoo r� O M d' U) CD W m O N M V U) (O 1� o m O N M U) CO I� CO O) `• _ EO �- N M U) O N. co O) .-- ,c1- �- .- �- N N N N N N N N N N M M M M 0) M M M M C) M C) U to cn e , N� o C '.' C r N ON C 0 O y� V O 0 CO 0 CD 0 O O N W O IC M C M M O tt �w _J t T E C ` o ` O w o E a p C a � o a 0 �7> a ¢ Q w a c7 Q 11001•••••••MMEMINIRIMMOMMIIIMINIIIIIIMMIMININI4 � Or Ty �wP I//7y;s THE STATE Alaska Oil and Gas o f /\nT L /� S J( /� Conservation Commission - == _ nJ �t-� z_ 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 O� 1�Q` Fax: 907.276.7542 ALAS www.aogcc.alaska.gov Monty M. Myers Drilling Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek and Tyonek Gas Pools, KBU 22-06Y Hilcorp Alaska, LLC Permit No: 215-044 Surface Location: 1207' FWL, 469' FSL, SEC. 6, T4N, R11 W, SM, AK Bottomhole Location: 1617' FNL, 1306' FWL, SEC. 6, T4N, Rl 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, Cathy P Foerster Chair AL DATED this GO day of March, 2015. • RECEIVED STATE OF ALASKA 0K OIL AND GAS CONSERVATION COMM N MAR 0 2 2015 PERMIT TO DRILL AOGCC 20 AAC 25.005 1 a.Type of Work: lb.Proposed Well Class: Development-Oil ❑ Service- Winj ❑ Single Zone Q • 1 c.Specify if well is proposed for: Drill •❑✓ Lateral ❑ Stratigraphic Test ❑ Development-Gas ❑✓ • Service-Supply ❑ Multiple Zone ❑ Coalbed Gas p Gas Hydrates ❑ Redrill ❑ Reentry ❑ Exploratory ❑ Service- WAG ❑ Service-Disp ❑ Geothermal ❑ Shale Gas ❑ 2.Operator Name: 5. Bond: Blanket ❑ Single Well ❑ 11.Well Name and Number: Hilcorp Alaska,LLC Bond No. 022035244 Kenai Beluga Unit(KBU)22-06Y • 3.Address: 6.Proposed Depth: 12.Field/Pool(s): 3800 Centerpoint Drive,Suite 1400 Anchorage AK 99503 MD: 10,200' . TVD: 9,563' • Kenai Gas Field 4a. Location of Well(Governmental Section): 7.Property Designation(Lease Number): Beluga/Upper Tyonek Gas Pool • Surface: 1207'FWL,469'FSL,Sec 6,T4N,R11 W,SM,AK • Unit Tract 26; Fee A028142 Tyonek Gas Pool 1 • Top of Productive Horizon: 8.Land Use Permit: 13.Approximate Spud Date: 1189'FSL, 1148'FWL,Sec 6,T4N, R11 W,SM,AK N/A 4/18/2015 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 1617'FNL, 1306'FWL,Sec 6,T4N,R11 W,SM,AK 2494.04 7,750'Unit Tract Boundary 4b.Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: 84 ft 15.Distance to Nearest Well Open Surface: x-272123.95 y- 2362521.75 . Zone-4 • GL Elevation above MSL: 65.5 ft • to Same Pool: 2604' 16.Deviated wells: Kickoff depth: 1,700 feet . 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) Maximum Hole Angle: 24 degrees • Downhole: 4207 psi • Surface: 3251 psi • 18.Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity,c.f.or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 13-1/2" 10-3/4" 45.5 L-80 Buttress 1,500' Surf Surf 1,500' • 1,500' . Lead-553 ft3/Tail-376.8 ft3 9-7/8" 7-5/8" 29.7 L-80 BTC 6,320' Surf Surf 6,320' . 6,000' Lead-752 ft3/Tail-Oeft3 3 6-3/4" 5" 18 L-80 DWC 10,200' Surf Surf 10,200' • 9,563' 730 ft3 t 5`? “ 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): Perforation Depth MD(ft): Perforation Depth TVD(ft): 20. Attachments: Property Plat Q BOP Sketch Q Drilling Program Time v.Depth Plot ❑✓ Shallow Hazard Analysis Diverter Sketch ❑✓ Seabed Report❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct. Contact Monty M Myers Email mmyers@hilcorp.com Printed Name M o ••4 7 M /\-1-er• s Title Drilling Engineer Signature 1 Phone 907-777-8431 Date 3 . 2 . 2d I c Commission Use Only Permit to Drill API Number: ^� j .� .ePermit Appr See cover letter for other Number: /.> 50- ,;!2.3.,,..7%:,:456., .. G�✓I IJV Date: 3 1•� requirements. Conditions of approval: If box is chef.cked,well may not be used to explore for,test,or produce coalbed methane,gas hydrate ,or gas contained in shales: Other: 3500/05e (� 7-j:51/...... Samples req'd: Yes❑ No( ,J Mud log req'd:Yes NoQ /��•T— +/� ( y ...eie HZS measures: Yes C aloe, .*2 Directional svy req'd:Yes v❑'Non "� ��� /"`�i ( �+ J Spacing exception req'd: Yes❑ No��'�Inclination-only svy req'd:Yes Nog Diur-��'�' Li)•,L)t Ct..1 a,it)C v✓ z , �-G 35( APPROVED BY 2 _ Approved by: ay....41.(_____ COMMISSIONER THE COMMISSION Date:3 2,3"--/.5-- ,,Ab- 3�/S ReLG1Nr :�•3' i‘ , Submit Form and Form 10-401(Revised 10/2012) Oh •• hs from the date of approval(20 AAC 25.005(g)) Attach in Dupr ate �ri' 111 . Monty Myers Hilcorp Alaska, LLC Drilling Engineer • 3800 Centerpoint Drive Suite 1400 Anchorage,AK 99503 Tel 907 777 8431 Hilcorp Alaska.LL,(; RECEIVED Email mmyers@hilcorp.com 03/02/2015 MAR 0 2 2015 AOGCC Commissioner Alaska Oil & Gas Conservation Commission 333 W. 7th Avenue Anchorage, Alaska 99501 Re: Permit to Drill KBU (Kenai Beluga Unit)22-06Y Dear Commissioner, • Enclosed for review and approval is the application for the Permit to Drill the KBU 22-06Y Development gas well. KBU 22-06Y is a 10,200' MD / 9,563' 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 —200 acre area of the Tyonek D- 3B sand and an 80 acre area LB/UT in the southwestern flank of the KGF structure. The reserves for this particular LB/UT location are booked, however, the primary objective (Tyonek D..-.3J3) is not booked and could have significant reserves/rate potential. Drilling operations are expected to commence approximately April 18th, 2015. The Saxon Rig# 169 will be used to drill and complete the wellbore. A separate 10-403 sundry will be submitted prior to completion operations. The 10-401 PTD covers all operations up to running and cementing the 5" long string. 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 Hileorp Alaska, LLC Kenai Beluga Unit KBU 22-06Y Drilling Program Kenai Field Revision 0 Feb 23rd, 2015 • KBU 22-06Y Drilling Procedure lcorp.Unskn,1J1 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"Production Casing 30 17.0 Cement 7-5/8"Cement Procedure 32 18.0 Drill 6-3/4"Hole Section 35 19.0 Run 5"Production Long String 41 20.0 Cement 5"Production Long String 44 21.0 RDMO 46 22.0 Perf and Frac 46 23.0 BOP Schematic 47 24.0 Wellhead Schematic 48 25.0 Days Vs Depth 49 26.0 Formation Tops 50 27.0 Anticipated Drilling Hazards 51 28.0 Saxon Rig 169 Layout 54 29.0 FIT Procedure 55 30.0 Choke Manifold Schematic 56 31.0 Casing Design Information 57 32.0 9-7/8"Hole Section MASP 58 33.0 6-3/4"Hole Section MASP 59 34.0 Spider Plot(NAD 27)(Governmental Sections) 60 35.0 Surface Plat(As Staked)(NAD 27) 61 36.0 Offset MW vs TVD Chart 62 37.0 Drill Pipe Information 63 V • • KBU 22-06Y Drilling Procedure mho,p tia-k..I.1C 1.0 Well Summary Well Kenai Beluga Unit(KBU)22-06Y Pad&Old Well Designation KBU 22-06Y is a grass roots well on the existing 14-6 pad Planned Completion Type 5"production tubing Target Reservoir(s) Tyonek/Beluga • Planned Well TD,MD/TVD 10,200' MD/9,563' TVD PBTD,MD/TVD 10,100' MD/9,472' TVD Surface Location(Governmental) 1207' FWL, 469' FSL, Sec 6, T4N, R11 W, SM,AK Surface Location(NAD 27) X=272123.95, Y=2362521.75 Surface Location(NAD 83) Top of Productive Horizon 1189'FSL, 1148'FWL, Sec 6, T4N,R11 W, SM,AK (Governmental) TPH Location(NAD 27) X=272163.22,Y=2363142.07 TPH Location(NAD 83) BHL (Governmental) 1617'FNL, 1306'FWL, Sec 6, T4N,R11 W, SM,AK BHL (NAD 27) X=272370.16,Y=2365708.17 BHL (NAD 83) Maximum Anticipated Pressure in 4207 psig psig(Downhole) Maximum Anticipated Pressure in 3251 psig psig(Surface) AFE Number 1510328D AFE Drilling Days 24 AFE Completion Days AFE Drilling Amount $4.3MM AFE Completion Amount Work String 4-1/2" 16.6#S-135 CDS-40(Rental Saxon String) KB Elevation above MSL 84.0 ft GL Elevation above MSL 65.5 ft BOP Equipment 11" 5M T3-Energy Annular BOP 11" 5M T3-Energy Double Ram 11" 5M T3-Energy Single Ram Page 2 Revision 0 Feb, 2015 w i KBU 22-06Y Drilling Procedure nilrorr�. 16-ku.1.cr 2.0 Management of Change Information Hilcorp Alaska. LLC Changes to Approved Permit to Drill Date: 2-24-2015 Subject: Changes to Approved Permit to Drill for KBU 22-06Y File#: KBU 22-06Y Drilling Program Any modifications to KBU 22-06Y Drilling Program will be documented and approved below_ Changes to an approved APD will be pomrnunicJtac#r6-the BLM and AOGCC. Sec Page Date Procedure Change Approved Approved By By Approval: Drilling Manager Date Prepared. Drilling Engineer Date Page 3 Revision 0 Feb, 2015 KBU 22-06Y Drilling Procedure Hil+•o 1.:t1a.1.a.LLC 3.0 Tubular Program: Hole OD(in) ID(in) Drift Conn Wt Grade Conn 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" 5" 4.276" 4.151" 5.563" 18 L-80 DWC/C 9910 10500 422 HT 4.0 Drill Pipe Information: Hole OD(in) ID(in) TJ ID TJ OD Wt Grade Conn Burst Collapse Tension Section (in) (in) (#/ft) (psi) (psi) (k-lbs) 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 Feb, 2015 I KBU 22-06Y Drilling Procedure tI...L .l.i t 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, 1ke1ler@hilcorp.com, &cdinger@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: Julieanna Orczewska: 0:907-777-8444 • Notify Drlg Manager&Drlg Engineer: 1. Paul Mazzolini: 0: 907-777-8369 C: 907-317-1275 2. Luke Keller: 0: 907-777-8395 C: 832-247-3785 3. 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 lkeller@hilcorp.com, mmyers@hilcorp.com & cdinger@hilcorp.com 5.5 Casing and Cmt report • Send casing and cement report for each string of casing to lkeller@hilcorp.com, mmyers@hilcorp.com &cdinger@hilcorp.com Page 5 Revision 0 Feb, 2015 • • KBU 22-06Y Drilling Procedure Nilnwp.tli.4 ,lit 6.0 Planned Wellbore Schematic CASING DETAIL T pe 'Nt Grade Conn. ID Top Btr,. ' NN"""".....,,.`V Conductor— 16' 1 16" Driven to Set 109 X-56 Weld 15" Surf 130' Depth " * 10-3/4" Surf.Csg 45.5 L-80 Buttress 9.95" Surf 1500' 16-3 4- ' ,. 7-5/8" Irterr?e^iate 21.7 L-80 BTC 6.875" Surf 6,320' 'UBING TOC=3000' fi �1 "�-kt 5" Productior 13 L-80 DWCJC HT 4.276" Surf 10,200' • •r✓" Hole Sectior Casirg (v"'4^., Wf ck5t.C1tg tet 13-1/2" 10-3/4" 8.8-9.3 ppg 4-1/2" 9.7/8,. 7-5/S" 9—9.5 ppg 4-1/2" 6-3/4' 5'' 10—11.5 ppg 4-1/2" J ELR.i'DETAIL t,:. Depth ID CD Item 1 18' 4.276" 11" Tubing Hanger 2 5,800' 4.276" 6.375" loft Swell Packer(WaterSwell;I Est. 2 J EXPECTED FLUID MM TVD(F7) Pressure i Sterimg gas/wet 3.706 3 59 s" 4- '.:,y„I Sterling 5.2 gas/wet 4.358 4.193 Sterrin. Poo/6 •as 4.679 4,489 Upper Beluga gas 4.952 4.742 I Middle Beluga gas 5-635 5.373' Lower Betuga gas 6.420 6.098 ' I Upper Tyonek gas 7.693 7.273 Tyonek D? gas 9,340 8.777 Tyonek D2 as 9.507 8.930 81.• -be Tyonek D3E gas 9,860 9,253 240 f Tyorek NA gas 10 084 9 458 701 Mr' 4 .4� PBTD=10,100'MD '9,472'TVD TD=10.200'MD 9,563'TVD Page 6 Revision 0 Feb. 2015 KBU 22-06Y Drilling Procedure ltilrorit t.I.3.3 7.0 Drilling / Completion Summary KBU 22-06Y is a 10,200' MD/9,563' 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—200 acre area of the Tyonek D-3B sand and an 80 acre area LB/UT in the southwestern flank of the KGF structure. The reserves for this particular LB/UT location are booked,however,the primary objective (Tyonek D-3B) is not booked and could have significant reserves/rate potential. — • The base plan is a directional wellbore with a kick off point at 1700' MD. Maximum hole angle will be 24 - deg. Vertical section will be 3176 ft. • Drilling operations are expected to commence approximately April 18th,2015. 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. 4. N/D conductor riser,N/U &test 11"x 5M T3-Energy BOP. 5. Drill 9-7/8" hole section to 6,320' 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 5" production casing. 7. N/D BOP,N/U tree, RDMO. Reservoir Data Acquisition Program: 13-1/2" Surface hole: Mud logging only, no LWD 9-7/8" Intermediate Hole: Mud logging+GR/Res/Den/Neu LWD, E-line RFT 6-3/4"Production Hole: Mud logging+ GR/Res/Den/Neu LWD , Page 7 Revision 0 Feb,2015 • S KBU 22-06Y Drilling Procedure NiIcor!.:11n,la.lit 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 KBU 22-06Y. • 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 5/5 min (annular to 50%rated WP, 2500 psi on the high test for initial and subsequent tests). Confirm that these test pressures match those specified on the APD. • If the BOP is used to shut in on the well in a well control situation, we must test all BOP components utilized for well control prior to the next trip into the wellbore. This pressure test will be charted same as the 14 day BOP test. • All AOGCC regulations within 20 AAC 25.033 "Primary well control for drilling: drilling fluid program and drilling fluid system". • All AOGCC regulations within 20 AAC 25.035 "Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements". • Ensure AOGCC approved drilling permit is posted on the rig floor and in Co Man office. AOGCC Regulation Variance Requests: • Diverter waiver request requested due to the recent drilling of KBU 32-08 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 KBU 22-06Y. Summary of BOP Equipment and Test Requirements Hole Section Equipment Test Pressure(psi) 13-1/2" • No diverter Installed N/A Page 8 Revision 0 Feb,2015 • S fitKBU 22-06Y Drilling Procedure nilrori. 11.-Lo.LLC • 11"x 5M T3-Energy(Model 7082)Annular BOP • 11"x 5M T3-Energy Double Ram Initial Test:250/3500 o Blind ram in btm cavity (Annular 2500 psi) • Mud cross 9-7/8"&6-3/4" • 11"x 5M T-3 Energy Single Ram • 3-1/8"5M Choke Line Subsequent Tests: • 2-1/16"x 5M Kill line 250/3500 • 3-1/8"x 2-1/16"5M Choke manifold (Annular 2500 psi) • Standpipe,floor valves,etc • Primary closing unit: Control Technologies accumulator unit, 5 station, 120 gallon (12 x 11 gal bottles). • Primary closing hydraulic pressure is provided by an electrically driven triplex pump. Emergency pressure is provided by bottled nitrogen. Required AOGCC Notifications: • Well control event(BOPS utilized to shut in the well to control influx of formation fluids). • 24 hours notice prior to spud. • 24 hours notice prior to testing BOPs. • 24 hours notice prior to casing running& cement operations. • Any other notifications required in APD. Regulatory Contact Information: AOGCC Jim Regg/AOGCC Inspector/(0): 907-793-1236/Email:jim.regg@alaska.gov Guy Schwartz/Petroleum Engineer/(0): 907-793-1226/(C): 907-301-4533 /Email:guy.schwartz@alaska.gov Victoria Loepp/Petroleum Engineer/(0): 907-793-1247/Email:victoria.loepp@alaska.gov Primary Contact for Opportunity to witness: AOGCC.Inspectors@alaska.gov Test/Inspection notification standardization format:http://doa.alaska.gov/ogc/forms/TestWitnessNotif.html Notification/Emergency Phone:907-793-1236 (During normal Business Hours) Notification/Emergency Phone: 907-659-2714 (Outside normal Business Hours) Page 9 Revision 0 Feb,2015 • ! KBU 22-06Y Drilling Procedure 1#flrnrp alx.kx.l.l.0 9.0 R/U and Preparatory Work 9.1 Set 16" conductor at a minimum of 111' 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. • TSM 1000 mud pumps are rated at 3633 psi (85%)/333 gpm (100%)with 5-1/2" liners. Page 10 Revision 0 Feb, 2015 • • HKBU 22-06Y Drilling Procedure !Mogi U:aLa.1.11. 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 up 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: KENAI GAS FIELD SECTION 6, T4N, R11 W, S.M., AK �N OR TH EOGEP .F•.•J . SCALE , 7 I TOP OF BERM TOP EDGE PA. 0 N 3 224 �0 / K.U. 21-7X E 1412069.33 . \ ��� � N 2362277.93 ----"I ® IL1, *,���'. ® E 1412^79.36 K.B.U. 11-7 (� N 2362291.62 ...e ' - '7 E 1412017.90 K,T.U.13-6 N 2362230.91 O+ K.U.14 . r;,-4 E 1412232.97 N K.D.U.-1EE141209$9L N N 2362219.39 0 WATER WELL K.B.U.31-7 E 1411864.73 9"CASING N 236220$.96 CO E 1412250.17 K.U,21-7 N 2362168,92 E 1411956.82 ®K.B.U.23-7 ®K.U.31-7X E 14112039.38 45) E 1412268.38 K.U.14-6 RD K.B.U.24-6 V. N 2362061.36 N 2362115.0? I2.3 E 1411904,54 K.B.U.23X-6 E 1412202.55 ® N 2362091.92 ----------x .,a�a. „.,. E 1412150,71 K.G.F. PAD 14-6 A CAL10311.Or.41.5 POI..MO ng.g., 4 A 30 cM.E PAD wa.+.,R...,.. Page 11 Revision 0 Feb,2015 • KBU 22-06Y Drilling Procedure ifileerp,tln..{.o,Id.c 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 Own OD Serial Number OD 6t Gauge Weigh Tom, t.e 19ttl Cumulative tom) fin) (in) OA C0006#00# fdq Length BD lel HDBS orictGRc 13450 3 COO 13.507 460.12 P 6-5+8'REG t.00 1.00 8•SperryDNM Lobe 45.5.3 slg... 8.0 0 5.000 ® 12 08 B 65«7'REG 31.83 32.83 _ Stablizer -__®_--- © 8"DsecBs0al Corer • IIIIIIIIIIIII 7.850 3.500 - 147.40 B 6-5.43-REG 8.86 MEM ups 8'Hirai Stabilizer#5 S)12 1 'pup 8.000 2 830 • 149.87 B6-5.8'REG 3.80 45.51 101 8'TM HOC(Pu19e0 8.150 4.500 _ 14520 136-516*REG 9.40 54.91 6 7.606 2.875 _ 132.48 B 6.543'REG 3000 84.91 ® 8'Non Mag Flex Collar 7.670 2 875 ENE��1�B 6-5.6".S'REG 30.C.3 114.91 0 X-06-518 Reg P X 4-111'IFB _® ®1lLTTCeAA=MI® 117.16 9 6.75'Non Mag Flex Cedar 8.730 Bug Egli 99.11 B 4..1,2IF 30:00 147.16 10 6.75'Non Mag Flex Collar 6.700 3.000 ® 96.06 6 4-1. IF 30.00 177.16 m X-0 4.177 IF P X CDS-40 B 6.520 2.750 _Emil B 4.5"CDS 40 2.75 179:91 ER 6Joints 4-11'7 HiSOPCDS-40 4.500 2.750 ® 41.00 185.00 364.91 11111 X.0 CDS-40 P X 4 t'2 IF B 6.520 2.750 _ 93.54 B 4-172'IF 2 367.66 ill 6 les'Wea4h.dord DAH Jar 6 250 on® 91.01 B 4.172•IF 32.00 39966 ® X-0 4-',T IF P X CDS-40 B ® 6.520 2.750 _ 93.54 B 4 S"CDS-40 2.75 402 41 18 13 Jahns 4.172•HWDP 0013.40 4.503 2.750 _ 41.00 400.00 80241 Twat; 60"1.41 BIT DATA Bit Number .• Noadee :1x14 3x16 Bit Site (m) : 13.530 TFA (e42) ;0.7394 Manufacturer facturer :14085 Dub Grade M Moder •OHC113RC 0611Grade Out • Serial Number MOTOR DATA Motor Number Bend (deg) 1.15 00(ed :8.000 Maude* (32nd) :0.0 Manufacturer ;Sperry Oribrg Avg 04B Press Model :SperryDril Cursed Cis Fire Serial Number . 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 Page 12 Revision 0 Feb, 2015 KBU 22-06Y 11 Drilling Procedure 11aulot,Ill 11.3 Primary bit will be the Security 13-1/2" QHC1GRC Milled Tooth Bit. These are available from Halliburton. 13-1/2" (343mm) QHC1GRC PRODUCT SPECIFICATIONS 1ADC Code 117W Total Tooth Count 64 Cage Rnw'Tooth Count Journal Angle Offset(1 16") Jet Nozzle Types Standard 111244 1 - Extended 311106 Center Jet (If Center knell)501813 Ti.Connection 6-51S"(AN Reg.) Recommended Make-Up Torque* 281100/32000 Ft*lbs. Bit Weight i Box ed 1 260 Lbs.tIISKgl flit Breaker thlatiVilLegacya) 11131771644911 111 PRODUCT FEATURES 44* • New patented Diamondrw Claw*tooth bit design. • Proprietary Iliammid TEC/12900m full tooth hardfacing on caning structure and gage. • Tungsten carbide'surf inserts in gage teeth for added gage protection. • Premium bearing and seal configuration suitable for both rotary and motor applications. sm_ • innovative mechanical pressure compensating system provides reliable pressure equalization and relict'for maximum bearing and seal life. • Raised tungsten carbide inserts and proprietary hardfaeing provides maximum arm protection in abrasive and directional applications while minimizing drill string toque. • QuadPaelet Plus Series incorporates its successfid*longevity" features and patented engineered hydraulics system for optimal cleaning efficiency. • Center jet feature to prevent bit balling pnablems Material#5,10030 iciatuiAtiom Nifatd onrecorrinictidatiurs from API and tool-joint manufacturm. 02014 Hal liburton.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 corn Page 13 Revision 0 Feb,2015 • KBU 22-06Y Drilling Procedure llihor1,:11,.1+9,lit 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. 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/ 1500' 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 Feb,2015 • • II KBU 22-06Y Drilling Procedure IIi14mr1.110.4o,Ile 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 80-1500' • 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 Feb,2015 • • KBU 22-06Y Drilling Procedure It''arp ANA*,111 12.0 Run 10-3/4" Surface Casing 12.1 R/U and pull 15.375"wearbushing. 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 Feb,2015 • • KBU 22-06Y Drilling Procedure i..n p:11fl.Lfl. MINN Tenaris Casing and Tubing Performance Data Choose pipe size,wall thickness and steel grade to view API connection options and performance data. Size "" Wall w Grade Connection ' Unit • Pipe Body Data GEOMETRY • Nominal OD 10.750 in Wall Thickness 0.400 in API Drift Diameter 9.794 in Nominal Weight 45.50lbsift Nominal ID 9.950 in Alternate Drift Diameter 9.875 in Plain End Weight 44.26 lbs/ft 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 1► _ Connection Data GEOMETRY Regular OD 11.750 in Threads Per Inch 5 Make-Up Thread Turns 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 TenarisHydrii Prertiittm Connections I Print ( Contact Us I 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 Feb,2015 I • KBU 22-06Y Drilling Procedure .wp %I.4.4,l_I i.1 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 Feb,2015 • • KBU 22-06Y Drilling Procedure Hung 11n44,1.11 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: 120' x .106 bpf= 12.7 71 16" Conductor x 10-3/4" 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 ad TAIL: (1500'-1000')x .065 bpf x 1.5 = 58.5 328 13-1/2" OH x 10-3/4" Casing annulus: TAIL: 90 x .096 bpf = 8.7 48.8 10-3/4" Shoe track: t 1, Total TAIL: 67.2 376.8 Page 19 Revision 0 Feb,2015 • • KBU 22-06Y Drilling Procedure ill 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 V 1.26 ft3/sk v` Mixed Water 14.437 gal/sk 5.76 gal/sk Mixed Fluid 14.417 gal/sk 5.76 gal/sk Expected 5 HR 3 HR Thickening 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 `/- 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 overdisplace by more than %2 shoe track volume. Total volume in shoe track is 8.7 bbls. Page 20 Revision 0 Feb, 2015 • • 111 KBU 22-06Y Drilling Procedure Meorp r%lnd.a,li 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 lkeller@hilcorp.com, mmyers@hilcorp.com &cdingerna,hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. Page 21 Revision 0 Feb,2015 S s KBU 22-06Y Drilling Procedure I-Moor MR,4.A,lit 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 T3-Energy BOP as follows: • BOP configuration from Top down: 11"x 5M T3-Energy annular BOP/11"x 5M T3-Energy Model 6011i double ram/11"x 5M mud cross/11"x 5M T3-Energy Model 601li 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). V.74)7 � • Test BOP to 250/35si for 5/5 min. Test annular to 250/2500 psi for 5/5 min. V • 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/EZ MUD/BDF-499 drilling fluid for 9-7/8"hole section. 14.8 Set 10"ID wearbushing 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. • TSM 1000 mud pumps are rated at 4250 psi (85%)/275 gpm (100%)with 5" liners. Page 22 Revision 0 Feb, 2015 i • II KBU 22-06Y Drilling Procedure Ilikorp nin.l.ai.I.I.f 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. 1 H08S IVW65 POC 811 6.003 2.500 9.875 79.63 P 4-1.T PEG 0.90 0.90 2 7'SPerryDr91 trite 7/8.6.0 419 7.000 4;952 93.13 8 4.412'IF 27.00 27,90 Statrlizsr 9.625 3 6 344'Non Meg Float Sub 6.500 2.875 90.96 B 4-417 IF 2.45 30.35 4 6 341"Integral Blade 9 57$'gauge 6.770 2.875 9,625 100.55 8 4-142'IF 7.00 37,35 5 6 314"DM Collar 6.690 3.125 103.40 B 4-1.2'IF 925 46.60 6 Bahr EWR•P4 Collar • 6.720 2.000 104.30 B 4=112'IF 14.00 60.60 7 63:4-DOB Collar • 6.780 1.920 97,80 P 4.1.2'IF 840 5900 B Inline Sla8Nlzer OLS) 6.750 3125 9.793 95.82 8 4-1 t2•IF 3.50 72.50 9 6 374'PWD Collor 6.730 1.805 9.30 B 44,,-2.IF 5 00 77.50 10 6 314"HCIM Collar 6.840 1.920 101.70 8 4-112•IF 7.00 54,50 11 6 374'TM Coltkr 6.893 3.250 103.80 8 4-1.2*it 9.80 94,30 12 6-3.74"5100 Meg Flex Collar 6.750 2.810 100 82 B 4-1,"2`IF 31:00 12530 13 6.314"Won Meg Flex Collor 6.750 2.810 100.82 B 4.101F31 DO 156.30 14 6-34"/440 Meg Flex Collar 6,750 2,610 100.62 8 4-112'IF ' 30 CO 186,30 15 6-3'4'Won Mail Fx3x Collar 6.750 2.810 100.82 8 4-112'IF 30:00 216.30 16 X-O 4.147 IF P X CDS-40 B 6.520 2.750 93,54 8 4.5"C0840 275 219.05 17 0 Joints 4-112" 1W0$COS-40 4.500 2.687 36.86 185.06 40466 18 X-0 CDS-40 P X 4 12 IF B 8.520 2750 93.54 8 4.1.2 IF 275 406.80 19 Fr 1I4"Weattrcrriprd tay11 Jar 6,250 2 250 91,01 8 4-112'IF 32.31 43911 20 X-O 4-112`IF P X CDS-40 B 6.520 2.750 93.54 B 4.5"CDS-40 215 441.86 21 13 Joints 4.172'HWDP COS-40 4.500 2 987 36.88 400.00 841 86 Twat. 841.86 BIT DATA Si Number Notzyas ;6503 Bit Size (hr) t 9.875 TFA (1n2) :0.7777 Itnartactrvar : P996 Dull Grade In :NEW Model : MM65 Dull Grade Out . Serial Number . 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. Page 23 Revision 0 Feb,2015 0 0 KBU 22-06Y IIDrilling Procedure Hamer Aliwka,1.1.1 15.6 Primary bit will be the Security 9-7/8"MM65. —- A 718" (251mm) MM65 PRODUCT SPECIFICATIONS to, . Cutter Type SelectCrviu3tte2; IADC Code Body Type MATRIX Total Cutter Count 46 Cutter Distribution IILIIIII Ai= P g 4 41 7 Face 0 211c4 i - , ''''''' . . Gauge 12 0 Up Drill 6 0 Number of Large Nozzles 6 Number of Medium Nozzles 0 or Number ofSmall Nozzles 0 Number of Micro Nozzles 0 * P 1i, .._ Number of Pres(Size/ 0 Number of Replaceable Ports(Size) 0 Junk Slot Area(4 hid 16.71 Normalrted Face Volinne 45,40% API Connection 4-112 REG.PIN 1, ;.',..,, , .,:4•&. 1 RecoininciakIl Make Up Torque. 12.A61—17,766 Fr , Nominal Dimensions.* Make-Up Face to Nose 10.81 in-275 nun (image Length 2.5 in-64 um Sleeve Length 0 in Shank Diameter 6 in-152 men Itrenk Out Plate1MatAtetracya) 181954144040 Approximate Shipping Weight 250Lbs.-I I3Kg. SPECIAL FEATURES Up-Drill Cutters on Gage Pads,1116"Relieved Gage Material#7711327 is a function of the hit W.and actual bit sub 0.D.utilized as nticeiirodin fA,LIR4P7G.,,Se.enit,to.n.Aill,.2..,,,,,,,,,,,nd rehr.d •••Blihr"sPesEncidfii'm7n7rau7s.carandetdtostirniaisaket.uanPdkvta:t7ears slightly on manuraesumit product liallthunon Drill Hits anti Seniors Product yeti ficatioris easy change without notice. C 2013 Halliburton.All rights reserved.Saks of Halliburton productsthesale.and services will beinaccord tinkly with the terms and conditions contained in the contract between Ha itiburton and the customeri that s applicable to Page 24 Revision 0 Feb, 2015 „/- • • II KBU 22-06Y Drilling Procedure Hilrsrrp,%1e4.e,lit 15.7 9-7/8"hole section hydraulic summary: Security DBS BIT HYDRAULIC PROGRAM 0 Prepared For-Hdcerp KBU 3248 Sy,.Mark Broulllat Dale prepared-119/11 Opereter:-")NIIC6rp I Well NarneMo:-KBU 32-00 7 0.1 Type:- PDC Contreetor;-, P County•Kenai Bit Diameter:- 9.875 in. SurwytAbsbact:-I 1 .-.... State(Country;•AK1USA :I ....__ M0CPC.'. ....__8100 R Mud WaigM:` 9.5 ppg _....... COMPONENTS 10(ME To 8881 1 1 PV 22 cp aging 9.05 1500 2 YP 25 RJ10001' _•, n Hole 9.6751 6400 3 ..__..._ Fluid Model ss'•-r•> ;:r-«9aaw1 cLr'' .,I 4 Prow Rate 500 Ilpm s S Mae.Pump Press90 6 Surface cool?. •....... '.i is 7 Motor Bypass', 8 TV07;: 5455116 9 a of Noule('10)t, s'4 rm,.+.00, 10 Min.TFA. 0.3134 In' Drill String 1205.38 pal 47.62% Total TFA 0 7777 In' Amildlnl'. 71.10 pal 2.54 Jel Velocity 206.37 Rh Surface! 77AS psi 2.66% Press.Drop 361.62 pm Speeder'. 905.06 pal 33.27% Rd Hyd,Power' 105.49 hp Batj 361:62 psi 13.3?5 H,S.I '3773 Morin' Impact Force507.37 IW ECD'I 9.78 ppp 1 TatnlISPP 2705.08 pal 100.00% 1 OD ID Tool Dant l.sn sh Cap. Pressure Lou DRILL STRING COMPONENTS 1 In, In 00 ID' 56 bbla Int Drill Pipe(SI(CDS 40 Connections 4.5 3.826 5.315 3.5,E 5503 70.65 593.35 IMIDP(CDS 40 connections,13 Its) 4.5 2.65 615 2,55 403 2.00 199.80 Weatherford Hyd Jar[CDS 40) 6 2.25 6 2.25. 31 0.15 32,50 HWDP(CDS 40 connections,.6 Jte) 4.5 2.68 6.25 2.55: 106 1,29 92.12 0-0 Sob LCOS 40 Bok 2 4-1l2"IF Pln) 6.5 2 7 6.5 2 75 4 0,03 1,74 4 Joints 6.3(4"NM Flex OrIK Collars 6.75 2.813 6.75 2,31.1 120 0.92 47.65 Integral BladeStabltizer(9:75'Gauge) 9.75 2.75 6.75 2.75 5 014 2.20 MWD TM HOC IPulser) 8.75 6.75 16 ••"•"""' 450.00 MWD HC1M Collar 8.75 1.42 8.75 142: 5 0.01 36.48 MWD-PWD Collar 4.75 1.42 6,75 1,42 51 0,01 38,40 MWD EWRP4 r Gamma Colter 6.75 1.42 6..75 1.42 22 0,04 141.24 MWD Directional Collar 6.75 1.42 6.76 142 9 0.02 89.23 Integral BladeStabllizer 19.75-Gauge) 8.75 2.75 6.75 2.75 5 0.04 2.20 Float Sub 6.75 2.75 6.75 2.75'.. 3 0.02 1.92 r Sperry0611 lobe 7183.9 Sig. 7 ...."...." 7 """" 26 '••'^^•"• 450.00 ANNULAR Hole 10 Pipe OD Length Cum. Cap. Mredat'. CrNIcaI Type of Pressure Lova SECTIONS. in. in.. ft Depth bI s..__ Ilfmin� Mein Flom PW Casing^, 9.95 4.51 15410 1500 114.75 15561, 303.43 L 16.62 Open Hole) 9.575 4.51 4055 5558 304.59 158.81 305.05 L 46.43 Open Hole 9.875: 4.51 403 5961 30.25 150.61: 305.05 L 4.61 Open Halm 9.575" 6.25 31 5992 1.76 209.66: 354.73 L 0.77 Open Hol 9.875: 4.5' 596 6171 13.96 158.61'. 305.05 L 2.13 Open Hoo 9.878) 6 5 4 6132 0.21 321.75 36416 L 8.11 Open Hole 9.8751 6.75 120 6302 6.06 235.89' 375.49 L. 4.00 Open Hole 9,475 5.75 5 6307 0 25 235.89. 37549 1. 0.17 Open Hole 1.975! 1.75 16 6323 0.81 235,89- 375.49 L 0.53 Open Hole 9.875`. 5.75 5 6328 0 2 235 89 37549 L 0.17 Open Hole 9.375 6.75 5 6331 0.25 235 WI 375.49 L 0.17 Open Hole 9.875 6.75 22 6355 1.11 235.09' 37510 L 9.73 Open Hole 9.675 6.75 9 6384 0.45 23519' 375.49 L 0.30 Open Hole'. 9.875 6.75 5 6360 0.25 235.89: 375.19 L 0.17 Open Hale' 9.375 6.75! 3 6372 0.15 235.19 375.49 L 0.10 Open tote 9.875 71 26 6400 1.32 25210x' 36717 L 1.10 Page 25 Revision 0 Feb,2015 • KBU 22-06Y Drilling Procedure 11,14„,,,,'h..ka.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%KC1/PHPA fresh water based drilling fluid. Properties: MD Mud Viscosity Yield Yield Point pH HPHT Weight'; Viscosity 1,500'-6,320', 9 0— 40-53 15-25 15-25 8.5-9.5 < 11.0 System Formulation: 6% KCL/EZ MUD/BDF-499 roduet 1111111 ,110. , SPH 41" 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(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 Feb, 2015 • S 111 KBU 22-06Y Drilling Procedure Hlir„rl, 11-4.1, 1 1 15.9 TIH, Conduct shallow hole test of MWD and confirm Gamma Ray LWD functioning properly. 15.10 Continue in hole and tag TOC. Note depth tagged on AM report. 15.11 Drill out plugs and shoe track. Clean out rat hole and drill an additional 20' of new formation. 15.12 CBU and condition mud for FIT. 15.13 Conduct FIT to 12 ppg EMW. 15.14 Drill 9-7/8"hole section to 6,320' MD/6,000' 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 is encountered. There are many stacked sands that are severely depleted that will be penetrated in the 9-7/8"hole section. Page 27 Revision 0 Feb,2015 ! I KBU 22-06Y Drilling Procedure iiia—l..11:i.R.t.III 15.15 Casing Point selection • KBU 23X-06 is the closest offset to use for correlation to pick casing point. Below is the annotated GR+ gas +resistivity log. • We want to set the 7-5/8" shoe 10 - 20' into the MB3CC. KBU 23X-06 '•" - KBU 23X.06 u k ._ -5,236 ---.:L.: -----57:-.. •_• KBU 22-06Y---- AS {: .�_.� -5,289 4 >7 > 07 �: I KBU 22-06Y Drilling Procedure IHfr.rp:lh.1.A. 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 29 Revision 0 Feb, 2015 i KBU 22-06Y Drilling Procedure 'wore :,• :,.t.�.r 16.0 Run 7-5/8" Production 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.V' • 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. 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 1550' 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 30 Revision 0 Feb, 2015 • i KBU 22-06Y Drilling Procedure Nilor1Alma. ,Ill 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/It Nominal ID 6.875 in Alternative Drift Diameter n.a. Plain End Weight 29.06 lbs/It 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 0D 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 31 Revision 0 Feb,2015 i 11110 KBU 22-06Y Drilling Procedure 1.1 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. • 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. 17.4 Pump remaining 35 bbls 10 ppg spacer and drop bottom plug. 17.5 Mix and pump slurry per below calculations: Section: Calculation: Vol (BBLS) Vol (ft3) LEAD: (5,820'- 3,000') x .038 bpf x 1.25 = 134 752 9-7/8" OH x 7-5/8" csg: Total Lead: 134 bbls 752 ft3 3`'1$x 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: )Z 5" }t- Total Tail: 28.1 bbls "941711t3 Page 32 Revision 0 Feb,2015 I • S KBU 22-06Y Drilling Procedure Hamel.tla.klk,LIS: Slurry Information Lead Tail System LiteCRETE Conventional Density 11 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 Ib/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: • 6,320' x .0459 bpf=229 bbls. • Displace with 10 ppg 6%KC1/Kla-Guard drilling fluid out of mud pits. 17.8 Monitor returns closely while displacing cement. Adjust pump rate if necessary. 17.9 Do not overdisplace by more than 1/2 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 33 Revision 0 Feb,2015 • • KBU 22-06Y Drilling Procedure I116rp 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 lkeller@hilcorp.com, mmyers@hilcorp.com & cdinger@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. Page 34 Revision 0 Feb,2015 • 111 KBU 22-06Y Drilling Procedure 111 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/Blind/Mud cross/VBR. p7% 18.2 Test BOPs on 4-1/2" and 5"test joints. 3 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 Run CBL on 7-5/8"casing only if cement job did not go according to plan and TOC is in question. 18.6 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. 18.7 Drift&caliper all components before M/U. Visually verify no debris inside components that cannot be drifted. 18.8 Ensure TF offset is measured accurately and entered correctly into the MWD software. 18.9 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 35 Revision 0 Feb,2015 i S KBU 22-06Y Drilling Procedure Iti.nrl, 11x.1,1,1.11 18.10 P/U below 6-3/4- directional drilling assy: COMPONENT DATA 'tern OD ID Gauge Wright Top Length Cumulative dcrr;crigltian $cnn€I Number lin) (inI (int 1810) Connection 1ftp Length fft) ill HDBS EM65D PDC bit 1111111111111111222111112115.750 47.67rli=la0.75 0 75 ® 5'Spern'Drill Lobe 67-6.0 st8 4.005 3.12.3 ® 48.00 EMI 24.•33 24,75 - Slatii,zer -__ 6.Sfi0 ® ®® 6.84 B3-1?2"IF 111111111111/1022/11 E viddt•,,i 9' 0,Stabilize, 4.840 2.400 6,500 52 00 8 3.1F2"IF 500 32,00 ® 4 1'4 DM Collar 4.730 1.250 47 00 B 3-1x2"IF 9.20 41,20 ® r,314'Slim Phase 4 Collar nu 1.2°50 ® 48.20 - 24.50 65.74 IIIII Inline S'.abil€zer(ILS;i 4.740 1.923 6.090 50.27 B 3-'.2"IF 3.50 69.20 Sill 4 314"At,.13 CollarEIIIIIII 4,754 1,253) M 45 50 B 3-172"IF 14.00 03;3.24 allSint;.N9seUr 5575 ®, 4 34"CTN Colla, • 4.750 1.25;1 50 50 B 3-117"IF 11.70 94 20 10 4 314"IND • 4.750 1.250 47.90 110131 9.20 103:40 Sal 4.14"TM HChs(Puller) 4.750 1.253 to 310 11.00 11.:40 Ell 4 3.'4"BAT Collar • IIIIIIIII 4.750 1.759 45 70 B NC 38 x5.42 IMINI IIIIIIIIIIIICEMIESIIIIIIII4 750 2.259 46 84 ICEMIN 31.0D 171 82 4 75"Flex Collar 4.750 2.250 46 84 B 3-117"IF 31.00 202.82 ® X-0 3-1,2'IF Pin X 4-11'CDS 40 Box a.2u° ® 00.22 B 4.5'CDS-40 2.751 205.57 Ell 6 Joints 4-112`HWDP 4.500 2.7750 41 00 MM. 185.04 390.57 ® X-0 4"lir CDS•44)1Pin X 3 132•IF box ',- "1.0 7,760 _llIE B 3-57'II 2 75 :393 32 MI 4 3x4"Weatherford Hyd Jar 4 750 2,250 ® 3003 NEM Ell X-0 3-112"IF Fin X 4-112"CDS-40 Brix 5.300 2.750 54 04 B 4 5 C Di --10 2.75 420.07 En 13 Joints 4-112'HO DP •4.500 2.753 41.00 400.00 826.07 Ts11al• 826.07 BIT DATA Bit Number Nozzles :6x10 Bit Size (In) : 6.750 TFA (In2) : 0.4602 Manufacturer : HOBS Dull Grade In Model ; EM65D Dull Grade Out Serial Number Page 36 Revision 0 Feb,2015 I S II KBU 22-06Y Drilling Procedure Hiker?Ainsl:a,lit 18.11 Hydraulics Summary: Security DBS BIT HYDRAULIC PROGRAM 0 Prepared Far-Hilcerp KBU 32.68 By Mark Broulilat CM.prepared!-1I9/14 Operator:-NOcorp Well tlsme1Ho:-160U 31-08 BB Type;- PDC. Contractor. County Kenai 1 Bit Dlsmeler.- : 8.75 in. Surveyytbet3act.-; StstelCountry.-lAK*USA E MO Out. One R Mud Weight 10.5 ppg COMPONENTS ID(In.t To{ft) 1 10„ PV 13 ep -.as ng 6.875:. 6400 2 10- YP.:. 19.tam 001et •;•.:n Hole 675 9350 3 10 Fluid Model Ill,, Vow€01.9 R 4 1U'... Flow Rate 275.gpm 5 10 Max.Pump Press,,, -,;100 pei 6 ... Surface equip.? 7 Stator bypass, a TVD41 7853 ft - 9 N ct Nozzle 0001:6 ,It jttsecc Ciactus(n •j 10 Min.TM 0.1974 fn} Drill String! 873.90 psi 35.40% Total TFA 0 460.2 Int Annulus 369.97 psi 14.99% Jet Velocity 191.82 Ns Surface! 29.19 psi 1.18% Press.Drop 345.31 psi Special.': 850.00 psi 34.44% Sit Hyd.Power 55.40 hp 9lI 345.31 psi 13.96% H.5,1 t 5497.hppn' Impact Force 286.59 Mt i ECD 1111 ppg TMat1SPP! 2458.37 psi 100.09% OD 10 Tool Joust 4angth Cap. Pressure Loss DRILL STRING COMPONENTS in. in. O0 ID ft bb's P. Drill Pipe(61(CDS 40 Connections 4.5 3..826 6.375 3.5 8517.5 120.53 319.99 I'YDP(CDS 40 connections,13 As) 4.5 2.68 6.25 2-55 403 2.80 88.47 4-374'Weathertord Hyd Jarwl X-0`s 5 2.25 5 2..251 95 0.17 12,43 IIWOP(CDS 46 connections,6 its) 4.5 2.68 6.25 2.55' 186 1.20 31.60 X-0 Sub ICDS 40 cox X 3-112"tF Pin) 4.7 2.5 5 2.31 4 0.02 0.92 2 Joints NM Flex DM Collars 4.75 2.5 4.75 2.51 I. 60 0.36 13.61 /AND IBat Sonic 415 1.25 4.75 135 26 0.04 11282 MWD/TM HOC{Pulsar) 4.75 •••'"` 4.75 •'""••'""•� 11 I 400.00 MWDIPWD 4.75 1.25 4.75 115, 9 0.01 39.05 MWDIALD-CTN(Nukesl 4.75 1.25 4.75 1.2511. 25 0.04 108,46 infuse Stabiliser(ILS 6"Gauge! 4.15 1.25 4.15 1.38, 3,5 0.01 15.19 MWD!Directionai/Slkm Phase 4 4.75 1.25 4.75 1.251 34 0.051 147.54 NM String Stabilizer(6.625Gauge) 4.75 2 4.75 2' 5.51 0.021 3.23 Float Sub 4.75 2,5 4.75 2.5 2.51 0.021 0.57 5"SperryOrill Lobe 6.17-6.0 slgIW ABti 5 5 ••""""" 28! •" "1 450.90 ANNULAR Hole ID Pipe 00 Length Cum. Cep. Annular CrNbesl Type o1 Pressure Loss SECTIONS` in.,........,__ in ft Depth ....._-bbis..__...__.,.,fetmin fetmen Flow pei Casing, � 6.875 4.5 6400 6400 167.96 249.491 310.59 L 242.12 Open Hole 6.75 4.5', 2111.5 8517.5 52.07 266.251 310.12 L 89,53 Open Hole 6.75 4.8' 403 8920.3 9.91 268.28... 316.12 L 17.07 Open Hole 6.75x:. 4.7: 35 8555.5 0.80 287.16` 325.86 L 1.77 Open Hole 6.15' 43 186 9141.5 4.57 266.28: 316.12 L 7.88 Open Hale 6.13, 4.7': 4 9145.5 0.09 287,16:. 325.86 L 020 Open Hole. 675"' 4.79: 60 9205.5 1.34 293.05 324.50 1, 3.18 Open Hots; 670 4.75 26 9231.5 0.54 29305: 328.50 L 1.38 Open Hots! 6.75 4,754 11 9242.5 0.25 293 05 328.50 L 0.58 Open Hole( 6 75 455, 9 9251.5 0.20 29305: 328.50 L 0.4$ Open Hole! 6.75 4.75' 25 9276,5 0.56 293.0511 328.50 L 1.32 Open Hole 6.751 4 75 3.5 9280 006 293 05 328.50 L 0,19 Open Hole 6.751 4.75. 34 9314 0.76 293.05 328.50 L 1.80 Open Hotel 6.75 4,15' 5.5 9309.5 0.12 293..051 328.50 L 0.29 Open Hole' 6.781 4.751 2.5 9322 0.06 293.051 328.50 L 0.13 Open Hole 6.75' 5 28 9150 0.56 327,79! 343.12 L 1.91 Page 37 Revision 0 Feb, 2015 KBU 22-06Y fl Drilling Procedure Meng.11n4.8. 18.12 Primary bit will be the Security EM65D. 6-3/4k' (171mm) EM65D PRODUCT SPECIFICATIONS Cutter Type X3-Extreme Drilling 444 IADC Code M323 Body Type MATRIX Total(*utter Count 33 4,4 - . Cutter Distribution .1.118111 lisam Face 4 13 Gauge 11 0 Up Drill 5 0 Number of Large Nozzles 0 Number of Medium Nozzks 0 v Number of Small Nozzles 4 Number of Micm Nonk 0 ;XIV Number of Poets(Size) 0 • Number or Reptaceable Porm{Size) 0 1 .4* X - Junk Slot Arca ail in) 8.68 Nurrnakeed Face Volume 34.69% sr # API Connection 3-la REG.PIN Recommenskil Make Up Torque* 5.173—7,665 Et*ths. ;14 Nominal Dimensions** Make-Up Face to Nose 9.42 us-239 mm Gauge Length 2m 61 nun Sleeve Length 0 in-0 mat Shank Diameter 4.3 in 114 mrn Break Out Plate(Mat.ttrlegacyn) 18195344030 Approximate Shipping Weight 90116.-41Kg. SPECIAL FEATURES Up-Drill Cutters on Gage Pads,1;16"Stepped Gage,Optimized Dual Row-ND"Feature Material 4761302 *Bit specific an tended rinilar-am torque is a Function of the bit f.D.and actual bit sub U.D.unlined us specified in API RPM Section AA2. "Deur dimensions are nominal and way vary slightly on manufactured misdates.Hulliburtun brill Bits and Services models are continuously reviewed and refined. Product VVVititzUhvet§may clianut without IINICV, 10 2013 Hal liburton.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 38 Revision 0 Feb,2015 • KBU 22-06Y Drilling Procedure 111,orp 11::.1..i I i 18.13 TIH to TOC. Shallow test MWD on trip in. Note depth TOC tagged at on AM report. 18.14 Conduct casing test to 3500 psi/ 30 min. 18.15 Drill out shoe track and additional 20' new formation. CBU and prep for FIT. 18.16 Drill 6-3/4"hole to 10,200' MD/9,563' TVD . • 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 39 Revision 0 Feb, 2015 • KBU 22-06Y Drilling Procedure Hili.,rp AiA kA,l i.f. 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/EZ MUD/BDF-499 fresh water based drilling fluid. Pro•erties: Plastie » x_ ViscosIty 6,320'- • X10-11.5 ppg 40-53 15-25 15-25 8.5-9.5 < 10.0 10,200' System Formulation: 6% KCL/EZ MUD/BDF-499 net 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 40 Revision 0 Feb, 2015 • ! KBU 22-06Y Drilling Procedure 1116•orir th.L. 1.1.i' 19.0 Run 5" Production Long String 19.1 R/U Weatherford 5" casing running equipment. • Ensure 5"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 to R/U Tesco or Weatherford CRT so that string can be rotated if necessary 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 5"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 solid body centralizers on every joint to 6,300' MD. Leave the centralizers free floating. • Ensure to install swell packer joint so that it is 500' from the 7-5/8" shoe when landed out. • Utilize a collar clamp until weight is sufficient to keep slips set properly. 5" DWC/C HT M/U torques Casing OD Minimum Maximum Yield Torque 5" 10,700 ft-lbs 12,100 ft-lbs 16,000 ft-lbs Page 41 Revision 0 Feb, 2015 • ~� KBU 22-06Y Drilling Procedure Technical Specifications Connection Type: Size(O.D.)/ Weight(Wan): Grade: D\mCIC-HTCauing 5 in 1Ol0lb/ft(l3G2in) L-80 4,«fimarriarl Material L8D Grade 80.000 MinimumYleldStrength(psi) 'U SA —' 95.000 Minimum Ultimate Strength(psi) VAM-L,SA Pipe Dimensions *u�vue�`*�mmnmmrpx��mm r4ctislon �mw1 5.000 Nomina|PipeBod �yD D�(in} pmz �3-479-xmm 4.276 Nominal Pipe Body 1.0.(in} Far.713-479-3234 0.362 Nominal Wall Thickness(in) eTriaitvpM 18.00 Nomina|VYeight(|bs/lt) 17.95 Plain End Weight(lbs/ft) 5.275 Nominal Pipe BodyArea( q in)Pipe Body Perfo 422.000 Minimum PiBodffield Strength(lbs) 10.490 Minimum Collapse Pressure(psi) 10,140 Minimum lnternalyield Pressure(psi: 9.300 HydrostaticTest Pressure(psi) Connection Dimensions ^ \' 5.563 Connection O.D.(in) 4.276 Connection i[l(in) 4.151 Connection Drift Diameter(in) 4.06 Make-up Loss(in) 5.275 Critical Area(sq in) 100.0 JoindBffidency(%) Connection Performance Properties 422,000 Joint Stre (Ibo) ~ ' 16.7E0 Reference String Length(ft) 1.4 Design Facto 457.000 API Joint 422,000 Compression Rating(I bs) 10.490 API Collape Pressure Rating(psi) 9.910 API Internal Pressure Resistance(psi) 73.3 Maximum Un i axial Bend Rating Idegrees/1 00 ft AppField End TorqueVoluon 10.700 Minimum Final Torque(ft-lbs; 12.100 Maximum Final Torqu (#bs) 16i000 ConnectionYleldTorque(ft-lbs) For d eta iled information on performance properties,refer to DWC Connection Data Notes on following page(s). Connect notice.Ceitan correction specifications are deperdent on the metharicA properti of the pipe.Mecharical properties of mril proprieary pipe grades were obtained from mill publications and are subject to thange.Properties of mill prcprietary grades stolid be cceirm ed wth the mill.Users are advised to obtan current correction specific,atiors and verify pipe mechanical properties for eacr application. Page 42 Revision 0 Feb, 2015 • 111 KBU 22-06Y Drilling Procedure liare.rp Aln..fl,Lit 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 43 Revision 0 Feb,2015 • KBU 22-06Y Drilling Procedure Iltleorp Alemk.,TAT 20.0 Cement 5" 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. 20.5 Pump remaining 15 bbls 12 ppg MUDPUSH II spacer. 20.6 Mix and pump 15.3 ppg class "G" cmt per below recipe. Ensure cmt is pumped at desigped weight. Job is designed to pump 100% OH excess. ' f' Section: Calculation: (BLS) Vol (ft3) 7-5/8"x 5" long string Overlap: 500' x 0.022= 11 61.8 6-3/4" OH x 5"Longstring: (10,200—6,320')x 0.020 x 1.5 = 117 657 Shoe Track: 90' x 0.019= 1.7 9.5 Total Volume: 130 bbls 730 ft3 Page 44 Revision 0 Feb,2015 • • KBU 22-06Y Drilling Procedure 11Whor1 1114.1,9,111 Slurry Information: Tad 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 Blend Thickening Code Description Concentration D046 Antifoam 0.2%BWOC D202 Dispersant 1.5% BWOC Gas Additives D400 0.8% BWOC 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%KCI. 10,100 ft x .01776= 179.4 bbls. 20.8 Do not overdisplace by more than '/z shoe track. Shoe track volume is 1,3,,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 45 Revision 0 Feb, 2015 • • KBU 22-06Y Drilling Procedure Hihvrrr 1.11 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 lkeller@hilcorp.com. This will be included with the EOW documentation that goes to the AOGCC. 21.0 RDMO 22.1 Install back pressure valve in hanger neck. N/D BOP. 22.2 N/U tree. 22.3 RDMO Saxon Rig#169. 22.4 After rig has departed, pull BPV& run CBL to determine TOC behind 5" production casing. 22.0 Perf and Frac 23.1 A separate Sundry will be submitted to the AOGCC that will cover the perf& frac operations for KBU 22-06Y. 23.2 Ensure to run a CBL across 5"to determine TOC after rig has departed. Expedite this to AOGCC ASAP"' • 23.3 Test 5"x 7-5/8" annulus to 2500 psi after swell packer has had sufficient time to inflate. Page 46 Revision 0 Feb,2015 • • KBU 22-06Y II Drilling Procedure Nikorp Ale.ka,tit 23.0 BOP Schematic Iii etre lit iii 1 if 1I T3 Energy. -J Saxon#169 , .,. 11"x5M i#t itl til mist T-3 Energy BOP T3-Enor Aad401041A1..... Manual Manual Manual CR 11,85' Valve Valve Valve ill##t IP If.' a IiI Km m .aJ Choke '-4.- A -441-Jiiiiir --fri 111,eii alt 71 ----- - T3-Energy Model 60111 - 11111 ' Grade Level 1111 Itt!111114111,1111 Ewer spoor1.95' 115MX115M III III will III 118. Al 1 Shnard•M65 s4tem y& 11114_o: 18 to3MX115M • i.} b • j_ _1+ I IIil ..r�..Iy ia.r.r�. !IJ 1f ii- 1 I11.11-ft.Tr 1—a.''411.(.7I. Page 47 Revision 0 Feb, 2015 • • KBU 22-06Y Drilling Procedure Ili6„rp.tix L>,,1,/i 24.0 Wellhead Schematic KBU 22-06Y . ?.'i) Ca - 3-1/16”14M r0 li i ■i11, ►■■ -1/16"10103-1/15""1.0M pW1 41140 tr1 si le'j3-1/15'10M � 4141 ' eel as Adapter,SM-E-2CLN _ €1'SM x 3-1/16"10M 'ImIMMiR ,scut,1Mt-t-=.....allll _ .lei t4 +x1 11.1 ! it t 3-I/2,1R Ii20 aol Oft . _. _. I X 3-1/2 ru*RD a"OP e 4 `I /•1 r sial tall , . 0 MP. 0 ii, �II � �� wt� C ll�C.', -22 Illit 11 x 7-5JP lea Mk 2—!It 94 w/ AL A'C'tYP Y TT 4......,....,„ ' .4 1. 10_3/4 im 1. ON CASIO;O.0031R, 0-22 •alpjoa eggis Yui° 2-1/14 54 4-3/4 x '0—.!/4 « 1 I `'. 3/13M w/twitli o-Y tit. w I 1 :IT' i,0 i 1e .—. ,�, ,,2-1/16 10,3/4 CASING-,..- S 7'.5.M CASW.-.,-r. 1 we 3-,/2 nsl~c_... 1 7a#OE MD i 3,020 pa Werlead&SPAM psi tree asst Isx1O Lx7-5Mx3-1/2 .., ..` fit; 771'U," gri.n ' .. P-14873 1 Page 48 Revision 0 Feb,2015 • • II KBU 22-06Y Drilling Procedure nib aria 1€n.1.1.Iii 25.0 Days Vs Depth Days Vs Depth oi - KBU 22-06Y --KBU 42-06Y 2000 . j 1 1 4000 ' 1 € _ t } i E .0 6000 ^ n to r 8000 I $ } ' I I { E 1 10000 I 1 1 1 d 12000 0 5 10 15 20 25 30 35 Days Page 49 Revision 0 Feb, 2015 . 111 KBU 22-06Y Drilling Procedure niI,0ry II:1.1.1t.LI.4 26.0 Formation Tops ANTICIPATED FORMATION TOPS&GEOHAZARDS EXPECTED FLUID MD TVD(FT) SUBSEA DEPTH -, ;rt. re i?C y Sterling gaslwet 3706 3.591 (3507) . 272163 236314- 1.338817128 Sterling 5.2 gashvet 4358 4.193 (4109) . 272184 2363393 6.879597865 Sterling Pool 6 gas 4679 4.489 (4405) ' 272194 2363516 0.856795243 Upper Beluga gas 4952 4,742 . (4658) 272203 2363620 3.649871849 Middle Beluga +as f ' 5635 .:.3'3 (5289) 8 272224 2363881 3.57914930 Lower Beluga # as ,. 6420 6.098 (6014) 272249 2364181 3.153619093 i Upper Tyonek as 1 3 7693 7,2 i (7189) 2504 272.90 2364667 6.610329036 Tyonek D1 9340 8.777 ! (8693) • ' 2001 272340 365336 4.382082541 Tyonek D2 9507 8.930 (8846) ' 800 272345 1965404 1.722801275 Tyonek D3B 9860 9.253 (9169) • 241+ 272356 2365547 4.987987264 s TyonekD4A 10084 9.458 (9374) 272362 ._....2365638 1.423296517 =Reservoir Objectives =Possible Geo Hazards DATA COLLECTION REQUIREMENTS: Page 50 Revision 0 Feb, 2015 • KBU 22-06Y Drilling Procedure .1t...k8.t.t.r 27.0 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. r 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 51 Revision 0 Feb,2015 • • KBU 22-06Y Drilling Procedure iftl.or1,aht461.rx,c 9-7/8" Hole Section: Lost Circulation: Ensure adequate amounts of LCM are available. BARACARB 5, 25, 50, 150, 400 & 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. Background concentrations of LCM (sized calcium carbonate) should be btwn 5 — 10 ppb while drilling this interval. There is a high probability of lost returns through the many stacked, depleted sands in this hole section. Hole Cleaning: Maintain rheology w/BARAZAN. 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 1ppb total of PAC L and 1 —2 ppb DEXTRID to maintain a thin/strong wall cake and keep HTHP filtrate below 11 ml/30 min. Maintain MW as necessary using additions of Barite. Maintain 4 ppb BDF-499 for shale/clay inhibition. Maintain 2—4 ppb BAROTROL and 2—4 ppb Soltex for • Shale/Coal stabilizer. Maintain 6%KCl 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 (BAROTROL, Soltex). • Increase fluid density as required to control a"running coal". • Emphasize good hole cleaning through hydraulics, ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb Asphasol Supreme pill • across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 52 Revision 0 Feb,2015 • s KBU 22-06Y Drilling Procedure x;�,•,,.�,>>ho..aa.Ia.c 6-3/4" Hole Section: Lost Circulation: ' Ensure adequate amounts of LCM are available. BARACARB 5, 25, 50, 150, 400 & 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. Background concentrations of LCM • (sized calcium carbonate) should be btwn 5— 10 ppb while drilling this interval. Hole Cleaning: Maintain rheology w/BARAZAN. 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 1ppb total of PAC L and 1 —2 ppb DEXTRID to maintain a thin/strong wall cake and keep HTHP filtrate below 10 ml/30 min. Maintain MW as necessary using additions of Barite. Maintain 4 ppb BDF-499 for shale/clay inhibition. Maintain 6%KCl 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 (BAROTROL, Soltex). • Increase fluid density as required to control a"running coal". • Emphasize good hole cleaning through hydraulics,ROP and system rheology. In the event that sloughing coal is encountered, consider spotting a 30 ppb BAROTROL pill across the coal seam. The pill can be safely "squeezed" into the coal by closing the bag and applying pressure not to exceed the total annular pressure loss. H2S: I H2S is not present in this hole section. No abnormal temperatures are present in this hole section. Page 53 Revision 0 Feb, 2015 • • KBU 22-06Y Drilling Procedure Hih orrr Ot-ka.Iii 28.0 Saxon Rig 169 Layout 123'-7" 1 36'-C" 55'-6" 3.0'_0" _ p@€-v C6 TAMS MT. VI :1g6 A@tS II.W..�.� --Ii-Z-‘ _� .- iii M rlllNr• s 1'ai o.-. iii i a'-"1, , i ,. •! I! C tram�nl. g a __mi.._ U ,1111111 ���I �mU..P - `f ow IR �,�7SL Ia- „�aa.. �jMI' �Ilg�dm,lr r, tii _�naiain'""" " IMINININIIINININININININCIININININIIIIIININININININNIN1111NINIIIIIIIIINININIIII:IINIIIIIIIIIIu1'1''1'111.1 urr-11111" lnal NININininNIIINIINi' �' MNININININI iNINININ}Ntfl IIIIMIIIII NNINI INIIIIII111I�INIIIIIII NININIINIIIIIINIIP'IIIti�iuEi�111111 111111iii� ININNI(NIININIIINll'ei U1 _ _IILIII( i —I�NgNNINIIl � SI Iail "1 r� ' {A, NImom � I illal ( IINININININNINI I�INININIII11 lINIIIIIININiNININIlI1NNINI" lolly haul ulii._ ..__ lIINIIINIIIIININIlIlILi .... ItIlglrlI I t IEjI IIMMI NININININI ININIMINI�IIIIIININININININIIIIIIui�li�lunm>♦N i iiIUINld fININN IIll l INIIN�NII IINININICN I o ._ . IIN1NINll II a — - _ • 11111111111M-117741 �� r•, Wel 4 VOW : ill E� 11 . lul 111MOM , jop !UI IHIMll�lt' i arAtRAT @ULLNG CAC" IS fh'AI"R TAwc/ R[YW 53'_..0" } 45"-O" L ti A5'-0" 85' 5" 170.-4" Page 54 Revision 0 Feb,2015 • • KBU 22-06Y Drilling Procedure >161;x.1.11 29.0 FIT Procedure Formation Integrity Test (FIT) and Leak-Off Test (LOT) Procedures Procedure for FIT: 1. Drill 20'of new formation below the casing shoe (this does not include rat hole below the shoe). 2. Circulate the hole to establish a uniform mud density throughout the system. P/U into the shoe. 3. Close the blowout preventer(ram or annular). 4. Pump down the drill stem at 1/4 to 1/2 bpm. 5. On a graph with the recent casing test already shown, plot the fluid pumped (volume or strokes) vs. drill pipe pressure until appropriate surface pressure is achieved for FIT at shoe. 6. Shut down at required surface pressure. Hold for a minimum 10 minutes or until the pressure stabilizes. Record time vs.pressure in 1-minute intervals. 7. Bleed the pressure off and record the fluid volume recovered. The pre-determined surface pressure for each formation integrity test is based on achieving an EMW at least 1.0 ppg higher than the estimated reservoir pressure, and allowing for an appropriate amount of kick tolerance in case well control measures are required. Where required, the LOT is performed in the same fashion as the formation integrity test. Instead of stopping at a pre-determined point, surface pressure is increased until the formation begins to take fluid; at this point the pressure will continue to rise, but at a slower rate. The system is shut in and pressure monitored as with an FIT. Page 55 Revision 0 Feb, 2015 0 • KBU 22-06Y II Drilling Procedure Iia.„gyp.11,4.1,1.u.c 30.0 Choke Manifold Schematic 4224 4362 4ata U 4 1 !t 1343 14.92 ^4.n 14,91 1343 i,.%.4(:):,..1:,r� -an n19 A ye.A av 314 '- .l. r 9 • • . II fb) }I3p; I�Ir'���I 9T Ilt73:°:::411. --I R-.:I 1.1 J � 0.,9.1 * . `1' =B af9J 0.19rw , ' AM 0' Mii 364 Ira19 •. .• I S• ! -//// lanai 5u^ a19J 1aN 4w1;:. 1.a,9� m 44 1,403 149T es►19�f lki,. rJj',,i L''- 1962 mM A nn ;,-11;111.11T .(P ES IL-Ville"' 1 m m Ta►R av mOJ �r9 h.- \ N 4360 It:Il'' I�' •1IL i , I ') II4I1 „„„„u, .! !�i-a,9 -- ® .2 CHM Mt ce(cme 0.19 -0.19 0.19149YK 1911 S 0.19 - 0.19 9PlR4AMR! 331 1492 14412 14.92 1491 311 //:�i}i'• '- - 4142 4192 J"'v,.,,,,%r4 92.24 1:1 CAD ..`.«. ..:w.y .. =. .... sat /,1;.K-C �_ 1,WWI'11111M R 9434119 S 3'' j.'' .4.14;6dil ^^41 '.�"""` 6.6.6s'.}-:" ` -✓' O :wr."!T w ...o.o... 1 Page 56 Revision 0 Feb, 2015 • • KBU 22-06Y Drilling Procedure Hilnvp Maas,11.1 31.0 Casing Design Information Calculation & Casing Design Factors Kenai Beluga Unit DATE:2-26-2015 WELL: KBU 22-06Y FIELD: Kenai Gas Field DESIGN BY:Monty M Myers Design Criteria: Hole Size 9-7/8" Mud Density: 9.5 ppg Hole Size 6-314" Mud Density: 11.5 ppg Hole Size Mud Density: Drilling Mode MASP(sec 1): 1254 psi(see attached MASP determination&calculation) MASP(sec 2& 3): 2167 psi(see attached MASP determination&calculation) Production Mode MASP: 3251 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" 5" Top(MD) 0 0 0 Top(TVD) 0 0 0 Bottom(MD) 1.500 6,320 10,200 Bottom(TVD) 1,500 6.000 9,563 Length 1,500 6.320 10.200 Weight(ppf) 45.5 29.7 18 Grade 1-80 L-80 L-80 Connection BTC BTC DWC/C NT Weight w/o Bouyancy Factor(lbs) 68,250 187.704 183.600 Tension at Top of Section(lbs) 68.250 187.704 183,600 Min strength Tension(1000 lbs) 1040 721 457 Worst Case Safety Factor(Tension) 15.24 3.84 2.49 Collapse Pressure at bottom (Psi) 741 2.964 4,973 Collapse Resistance wlo tension (Psi) 2,480 4,790 10.500 Worst Case Safety Factor(Collapse) 3.35 1.62 2.11 v MASP(psi) 1,254 2,167 3,251 Minimum Yield(psi) 5,210 6.890 9,910• Worst case safety factor(Burst) 4.15 3.18 3.05 v Page 57 Revision 0 Feb, 2015 • • KBU 22-06Y Drilling Procedure LI 32.0 9-7/8" Hole Section MASP 1 Maximum Anticipated Surface Pressure Calculation JI 9-7/8"Hole Section KBU 22-06Y Ninilchlk Unit MD TVD Planned Top: 1500 1500 Planned TD: 6320 6000 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Sterling 3,592 250 gas/wet 1.3 0.070 Sterling 5.2 4,194 1500 gas/wet 6.9 0.358 Sterling Pool 6 4,490 200 gas 0.9 0.045 Upper Beluga 4,743 900 gas 3.6 0.190 Middle Beluga 5,374 1000 gas 3.6 0.186 Offset Well Mud Densities Well MW range Top(TVD) Bottom(TVD) 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/1,500'TVD 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: 1500(ft)x 0.936(psi/ft)= 1404 psi 1404(psi)-(0.1(psi/ft)*1500(ft)]= 1254 psi MASP from pore pressure(unknown gas sand at TO,at 9.2 ppg(0.4784 psi/ft) 6,000(ft)x 0.4784(psi/ft)= 2870 psi 2870(psi)-(0.1(psi/ft)*6000(ft)]= 2270 psi Summary: 1. MASP while drilling 9-7/8"intermediate hole is governed by fracture gradient at the 10-3/4"casing shoe Page 58 Revision 0 Feb,2015 • • KBU 22-06Y Drilling Procedure 1111.29,alo.i,o.1.1,1 33.0 6-3/4" Hole Section MASP Maximum Anticipated Surface Pressure Calculation 6-3/4"Hole Section KBU 22-0er Cook Inlet,Alaska MD TVD Planned Top: 6320 6000 Planned TD: 10200 9563 Anticipated Formations and Pressures: Formation TVD Est Pressure Oil/Gas/Wet PPG Grad Lower Beluga 6,099 1000 gas 3.2 0.164 Upper Tyonek 7,274 2500 gas 6.6 0.344 Tyonek D1 8,778 2000 gas 4.4 0.228 Tyonek D2 8,931 800 gas 1.7 0.090 Tyonek D3B 9,254 2400 gas 5.0 0.259 Tyonek D4 9,459 700 gas 1.4 0.074 TD 9,563 4210 water 8.5 0.440 Offset Well Mud Densities Well Max Drlg MW Top(TVD) Bottom(TVD) Date KBU 11-17X 10.7 5,464 7,919 2009 KBU 14-08 10.3 5,432 7,746 2008 KBU 41-18X 11.6 5,391 8,651 2008 KBU 24-7X 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: 6000(ft)x 0.936(psi/ft)= 5616 psi 5,616(psi)-[0.1(psi/ft)"6,000(ft)]= 5016 psi Dr,ling Mode MASP MASP from pore pressure(2/3 wellbore evacuated to gas from"D"at.444 psi/ft) 9,563(ft)x 0.44(psi/ft)= 4207 psi 4,207(psi)-[[0.1(psi/ft)`9,563(ft)`2/3]+[0.44(psi/ft)"9,563(ft)'1/3]]= 2167 psi Production Mode MASP MAW from pore pressure(entire wellbore evacuated to gas from T : 9,563(ft)x 0.444(psi/ft)= 4207 psi -/j 4,207(psi)-[0.1(psi/ft)"9,563(ft)j= 3251 psi Summary: 1. MASP while drilling 6-3/4"production hole is governed by SIBHP minus 2/3 wellbore evacuated to gas from TD. 2. MASP during production mode is governed by SIBHP minus entire wellbore evacuated to gas from TD. Page 59 Revision 0 Feb,2015 • • IIKBU 22-06Y Drilling Procedure Likory th*La.1.1,1 34.0 Spider Plot (NAD 27) (Governmental Sections) ADL000593 , ._........_,.. KU 22-6X BHL I .KE3t:22-06Y 1311L1 * * , - 0 6 '610 0. 0 1.0 . KBU 22-06 BHL# * 444 0 44 44 - . « , -FEE AA093836 . . , KBU 42-6X EIHL, 1 . • 6 5 A 4 5 5 .. . • KBU 42-6 BHL , : • KU 13-C6 BH • ' KU 43-06 BHL ,,, • ,.. : ----- -74.-: ../31-11, 1 / , KU 43-06R3 BHL $ KTU 43-C6X BHL •• 1 .. • i • •,,,,' Eta g . , . Eta 6 ,1 1 KBL 33-06 SRL. , , , ,,, • : • '''' KBU 33-06X BR,. ''''',, •,, , '', , ,, : , ,i \ •., .„ , , ' Kerf1:2as Field Pad No.33-01 , 1 ,, •,.. \ \ ,,, „, \ \ \ , \ \ 1 t ___ \ KtU 24,66H BHL, \ ADL392670 KBU 22-06Y TPH i .; / -,,,,i, t ',,, ',. ',, i t fi • ,, / KOU 01 EEL- N, `. \/ I I 111 .,, /„.4_4_, SOCI4N012W SOO4N011W /' .1101.1 .: . 2'-Ony si IL KBU 24-06 Bik•,, 'Is,, % 1, I / A028142 KDU OB 4(L1"4X-f.,;SR.”- 0- -..'---'----/1.-- ',., ... (\0/ KENAI UNIT Kenai 1 / 14-05'' '-fiir 10.4 7 4 \ \1 /I , \ ,imr Kau 1 :Mt ,r, * i -.s Pielad. .. 4-06K-121.7X Blit, XBU 34-6 ---h--- •,ta,.,,4,$'i *- - ., ---....„ / 1 \ BHL- KBU;, Kenai Gat rii.4.;'ad NO.4r.,7, .,' .' \ .---'''' \-„, IS -; , \ KM 1u•,,,,1 7 0'c KW 09 BHL4"..---. \ I ! 1 L t,e ABU I`-e7 BHL • mu 31.07REyspc\- , f(LJ 31-07X8Hb' , / 1 A028143 4 I /1 / KTU 32-07HBHL--KBU31.437.113HL:,_ 1 ' i / 1 /KEN 42-07RD BK. , 7 . , ..- etalg5 , 633A7 KDU 04(KU 13-71 BHL'''' '• Legend , f . y Other Surface Well Locations _,,,, /, ', , Other Bottom Hole Locations —-- Well Paths . .' Well Pad , KDU 04_1131-0HL KBU 33-07 BI- .: 103U 04RD BHL----- ', , rzi Oil and Gas Unit Boundary F---------, j KU 43-12 BHL/ Kl3U 23-07 BHL L _ Hilcorp O&G Minerals KBU 43-07X BHL"r Kenai Unit Feet KBU 22-06Y 0 iocc 2.00.3 Naska State Plane Zone 4,NAD27 A ililowr¼t-& ,Ii i Map Date-2242015 A Page 60 Revision 0 Feb, 2015 • • iniKBU 22-06Y Drilling Procedure Hilt-oil,ths4 a.lit 35.0 Surface Plat (As Staked) (NAD 2r7) _ +w```Q F'A.t, +! ..< r 1.BASIS Cf HORIZONTAL COORDINATES NiE ALASKA STATE FLARE NA027 l w`' 1�,n,.•"•"{�',.�'! N ZONE A OFTERAINED SY A DOM If TO USC WS Tia STAA1IDRY HAVINC:A �43A/' ititi,_2�t PURL AHED Pk+31T1ON OF 6AT AY9:1hD 59r Atk+Kt 1SS•1SJ79t.r$ " r•°� N NAYA4SA7E 2i11SBSTS —*/49111 •;; N OR TN II EASE OF keERTICAt DATUM IS PAEAN S'�EA LEVEL yyy��p �� - 3,SOUTHWEST CORNER MC 6COOfiDPMMTE DETERMINED FRONT CIRECT „..—.71.217,..&&.4......—... ^ �•"T"""', •: '�'Yr``�.-- SURvEi,TIE TOTH>FTOE.71 TINGHLA+WCFORENWCONSE4RSEC:TAND s 5 STAx A.M... NE 2 -.(—,. WC A CORNER SECTION*6 A i RECO'/fRFD AND NOT TkE PROTRACTEO �/ tB] }S f .. SECT1CN CORNER VALUES. . t°. rrrll, K a SCALE E 2x ` 1 � I I I I I F'EE'T � a D- oAF.:�orogyvr / ems•- OCAITAOL VT.CP.1 • ( r ip;,CC tl1AV _r,� `.•.� N. ynn32man .C« KBU 22-06Y AS-STAKED NAD27" — --� .c"nez ****,* GRID N.2362521.75 ,� *µ""a. GRID E,272123.95 I/ LATITUDE:60'27'38.7481"N / LONGITUDE.151°15'44.8870'W ,..„. ELEV.:65.5 FT. `�`�� 1207y"VL{NTS) ".� al .. z V0', a;�nxie J \/\ • w- 'n11 KO F.PAr TA-i 461'FSL • 0 CELEVAT!ON-65 e«rA.S.L • I0) . /# --- f P.. . nAT r • 'V i•1 r tv-AE FAD IAJOIAAAr 1 CCMRLt M.CP.Y .a wt """ -,i 2174,7 in .41.94*.,.. - —�Ml /... 6 C.S1�SGi Ma1!, 'amu •Q i it I SW COR 1 ® 1 I N 2362069.27 I 1 • � 6 E 270908.10 *�«� 12 T ( l ,/ � A."'1, , .— / \. \ , / . / � , ,,D*A 0 HILCORP ALASKA LLC °ITS ,2,1V0 Canaw,ttsrg Inc KBU 22-06Y AS-STAKED now,etar A,- G... KENAI GAS FIELD PAD 14-6 ,,.+LE 16-1-0 SURFACE LOCATION DIAGRAM NAD27 +1rFCTIK , 114216G**Gi N/OPIG I1*11**NHD Y=SING ACOA MP • CC:(A1)VIDA211 fAA,AAA.MA-TM '.ItGT AA*121 1 s;Irra�cA'�I fliirnrp Marks,1.1A: S6 T4N R11W SEWARD MERIDIAN,ALASKA • *1°' 1 Page 61 Revision 0 Feb,2015 • • KBU 22-06Y Drilling Procedure IliIrwn:lln.ka.LLC 36.0 Offset MW vs TVD Chart MW vs TVD Offsets 0 KBU 32-OB 1000 -KBY 43-07Y 6. 2000 4 KBU 11-082 -KBU 23-05 611 3000 -KDU 10 KBU 42-06Y 4000 — 0--0 I (4,51k. 2_Z--06 47' q2ruT°S"1 5000 6000 k1 7000 I $ { 8000 111411illit 9000 10000 11000 1.2000 13000 6 7 8 9 10 11 12 13 14 Mud Weight(PPG) Page 62 Revision 0 Feb, 2015 • • II KBU 22-06Y Drilling Procedure IIII,4,rit 111.1.:. I I l' 37.0 Drill Pipe Information CINI 1IIIIIRY SIHY1US IL SizE: 4 1/2" COMM WEIGHT': 1 6.6 Las/FT GRADE: S-135 RANGE: 11(31.59 DRILL PIPE SPECS CONNECTION: CDS40 -- ] TUBE __,...- NEWPREMIUM IN MM IN MM OD 4.500 114.3 4.365 110_9 WALL THICKNESS 0.337 8.6 0,270 6.8 ID 3.826 97.2 3.826 97.2 FPLBS Ni Fr-LES NM TORSIONAL STRENGTH 55,453 75.200 43.451 58.900 80%TORSIONAL STRENGTH 44.362 60.200 34,761 47.100 LBS DAN LBS DAN TENSILE STRENGTH 595.004 265,300 468,297 208,800 PSI KPA PSI KPA INTERNAL PRESSURE CAPACITY 17,693 121,985 16,176 111,530 COLLAPSE CAPACITY 16.769 115.615 10,959 75.561 IN' WO IN2 MM' CROSS SECTIONAL AREA BODY 4.407 2844 3.469 2238 CROSS SECTIONAL AREA OD 15.904 10261 14,966 9655 CROSS SECTIONAL AREA ID 11.497 7417 11.497 7417 IN* MM* IN' MAI* SECTION MODULUS 4.271 69995 3.347 54845 POLAR SECTION MODULUS 8.543 139989! i.5. 94 109690 TOOL JOINT r NEW1 PREMIUM PSI KPA i PSI KPA YIELD STRENGTH 13C,000 896,3181 130,000 896,318 I IN MM I IN MM OD 52U0 133.4 5.1198 130.0 ID 26R75 68.3 2 6875 68.3 PIN LENGTH 11.0 279.4! 11.0 279.4 BOX LENGTH 14.0 355.6 14.0 355.6 Fr-LBS NM FT-LEIS NM TORSIONAL STRENGTH 35,400 48.000 34.700 47.100 MAX MAKE.LIP TORQUE 22,500 30.500 21.400 29.000 RECOMMENDED MAKE-UP TORQUE 21,200 28.800 20,800 28,200 MIN MAKE-UP TORQUE 19,600 26,600 19.300 26.200 LBS DAN LBS DAN TENSILE STRENGTH 824,400 367.600 804,900 358.900 Too'....JOINT/DRILL PIPE TORSIONAL RATIO, 064 0.80 ....,_„--..,.... DRILL PIPE ASSEMBLY WITH CONNECTION LBS/FT KG/M ADJUSTED WEIGHT 17.87 26 64 FT PA APPROXIMATE LENGtH 31.50 960 GAL/FT Nem FLUID DISPLACEMENT 0.273 0.003394 FLUID CAPACITY 0.577 0.007169 IN MM DRIFT SIZE 2.5625 65 Page 63 Revision 0 Feb, 2015 • • II KBU 22-06Y DrmngProcedure II.r m r COMBINED LOa CURVEFO R 4 1/2"913 16.6 LBS/ DRILL PIPE WITH CDS40 CONNECTIONS m : 1 a � / 004, J . . 2 - « ® - / § ° ^©^4e, ) aco.oca . . 4**. --,, % 3m } / \ y / `` . » / I m . . » / ° / . . . ! , \ < } , y ©2 ; . - a , : « : . . _ .. . . . . . . : . . , »»_ 2"e° »_ +mm ■ it �_!_+w __,m9 COMBINED LOAD 000 —� m._ m o __ �mm� >: _#a �»_na - YEs --BOX YIELD Page 64 Revision 0 Feb, 2015 • • Hilcorp Energy Company Kenai Gas Field KGF 14-6 Pad KBU 22-06Y KBU 22-06Y Plan: KBU 22-06Y wp2 m Standard Proposal Report ' 29 January, 2015 HALLIBURTON Sperry Drilling Services oject: Kenai Gas Field WELL DETAILS: -06Y NAD 1927(NADCON CONUS) Alaska Zone 04 HALLIBUPTON Site: KGF 14-6 Pad Ground Level: 67.00 Well: KBU 22-06Y +NI-S +E/-W Northing Fasting Latittude Longitude Slot s --v aril-Ong Wellbore: KBU 22-06Y 0.00 0.00 2362515.74 272132.73 60.4607474 -151.2624193 Plan: KBU 22-06Y wp2 REFERENCE INFORMATION Co-ordinate(N/E)Reference:Well KBU 22-06Y,True North Vertical(TVD)Reference:Plan:KBU 22-06Y @ 85.00usf(Saxon 169(67 GL+18 KB)) -500— Measured Depth Reference: Plan:KBU 22-O6Y t 85.00uslt(Saxon 169(67 GL+18 KB)) Calculation Method:Minimum Curvature 0- 500— 500 1000— 1000 1500— --' '1500 10 3/4" 2000— 2000 2500— 2500 3000 3000— _ 3500 3500--—Sterling KBU 22-06Y TO wp2 apo D 4000— 0 - Sterling 5.2 x500 N _ 4500--Sterling Pool 6 -Upper Beluga 000 d) - 0 5000- 55)c) Middle Beluga— 5500— tv 6000 6000— Lower Beluga- 6500 7 5/8" 6500— 1000 7000— 1500 r- Upper Tyonek - — 7500— 00 KBU 22-06Y T1 wp2 60 8000— 8500 9000 8500— r- Tyonek Dl— 00 9000— —Tyonek D2 —Tyonek D3B 00 9500 Tyonek D4A ,�1� 1p200 KBU 22-06Y T2 wp2 5 2 10000— ���22' 1 1 1 1 1 1 1 1 1 j 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 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 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 -2000 -1500 -1000 -500 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 Vertical Section at 3.10° (1250 usft/in) 11 lilcorp HALLIBURTCIN • Project: Kenai Gas Field , WELL DETAILS: KBU22-06Y Sperry Drilling®.rvio.. Site: KGF 14-6 Pad Ground Level: 67.00 Well: KBU 22-06Y +N/-S +E/-W Northing Easting Latittude Longitude Slot Wellbore: KBU 22-06Y 0.00 0.00 2362515.74 272132.73 60.4607474 -151.2624193 Plan: KBU 22-06Y wp2 REFERENCE INFORMATION Co-ordinate(N/E)Reference:Well KBU 22-06Y,True North Vertical(TVD)Reference:Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+18 KB)) 3750— Measured Depth Reference: Plan:KBU 22-06Y @ 85.00usft(Saxon 169(87 GL+18 KB)) Calculation Method:Minimum Curvature 3500— KBU 22-06Y wp2 _ - I I I 3250— 5 / ____TD at 10200.00 KBU 22-06Y T2 wp2,___-4ir --- ---- Start 113.84 hold at 10086.16 MD 3000— 50 9000 8750 2750- 8500 8250 2500— 8000 7750 2250— KBU 22-06YTI wp2 500 l 00 2000— S - 6750 a - 6500 0 1750— 6250 sn - 7 5/8"_ + ` '.000 y 1500— 5750 5500 5250 0 rn 1250- 5000 4750 1000— 4500 4250 4000 750— r KBU 22-06Y TO wp2--___ _Start DIS 0.02 TFO-8.26 CASING DETAILS II--- Start DIS 4.00 TFO 96.16 500— 3250 TVD TVDSS MD Size Name 1500.00 1415.00 1500.00 10-3/4 10 3/4" 3000 6000.00 5915.00 6319.35 7-5/8 7 5/8" 9563.28 9478.28 10200.00 5 5" 250— 2750 250.0 Start 1234.57 hold at 2453.79 MD 10 3/4" 2250 0— `` , 1500 Start Build 3.00 - T -250— A M Azimuths to True North /\ Magnetic North:16.62° Magnetic Field Strength:55327.2snT 500— Dip Angle:73.44° Date:3/31/2015 Model:BGGM2014 I l l I i I l I I I I I I I I I I I I I I I I I I I I I I I I I I I I I I l I { I i I I I I I I I I I I I I I I I I I I I I I l l i i i l l -1000 -750 -500 -250 0 250 500 750 1000 1250 1500 1750 2000 2250 2500 West(-)/East(+)(500 usft/in) II Hileorp • • Halliburton HALLIBURTON Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordina Well KBU 22-06Y Company: Hilcorp Energy CompanyTVD Reference: 's, ' i�Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1f Project: Kenai Gas Field MD Reference: Plan:KBU 22-06Y @ 85.O0usft(Saxon 169(67 GL+1f Site: KGF 14-6 Pad North Reference True Well: KBU 22-06Y Survey Calculatia ' hod. _ _Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp2 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 .' KGF 14-6 Pad Site Position: Northing: 2,362,394.10 usft Latitude: 60.4603760 From: Map Easting: 271,396.69usft Longitude: -151.2664830 Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -1.10 ° KBU 22-06Y i� ..»-,.- Wiz._ _ �atmo d. arl x,cnuIpipCpR 6Pt'fi t9p4q Well Position +N/-S 0.00 usft Northing: .Z-3L•ZSLZ s.'S1 sft Latitude: 60.4607474 +El-W 0.00 usft Easting: 2_72.(2 / 2'2,9.32r73-BT Longitude: -151.2624193 Position Uncertainty 0.00 usft Wellhead Elevation: ,(, 0.00 usft Ground Level: 67.00 usft .. Wellbore KBU 22-06Y Magnetics Model Name Sample Date Declination DipAngle Field Strength_ v d >> O 41116 ,4 1l(nn BGGM2014 3/31/2015 16.62 73.44 55,327 Design KBU 22-06Y wp2 Audit Notes: Version: Phase: PLAN Tie On Depth: 18.00 Vertical Section: Depth From(TVD) +NI-S +E1-W Direction (usft) (usft) (usft) (0) 18.00 0.00 0.00 3.10 Plan Sections Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/-S +El-W Rate Rate Rate Tool Face (usft) (°) (0) (usft) usft (usft) (usft) (°/100usft) (°1100usft) (°/100usft) (0) 18.00 0.00 0.00 18.00 -67.00 0.00 0.00 0.00 0.00 0.00 0.00 1,700.00 0.00 0.00 1,700.00 1,615.00 0.00 0.00 0.00 0.00 0.00 0.00 2,453.79 22.61 1.65 2,434.37 2,349.37 146.77 4.22 3.00 3.00 0.00 1.65 3,688.35 22.61 1.65 3,574.02 3,489.02 621.28 17.88 0.00 0.00 0.00 0.00 3,707.83 22.54 3.67 3,592.00 3,507.00 628.75 18.22 4.00 -0.36 10.38 96.16 10,086.16 23.65 3.27 9,459.00 9,374.00 3,126.21 169.38 0.02 0.02 -0.01 -8.26 10,200.00 23.65 3.27 9,563.28 9,478.28 3,171.80 171.99 0.00 0.00 0.00 0.00 1/29/2015 11:42:02AM Page 2 COMPASS 5000.1 Build 70 • • Halliburton HALLIBURTDNI Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1f Project: Kenai Gas Field MD Reference: Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1f Site: KGF 14-6 Pad North Reference; -,,-. .__:-.. True Well: , KBU 22-06Y Survey Calculation Method: Minimum Curvature Wellbore KBU 22-06Y Design e4,i KBU 22-06Y wp2 Planned Survey Measured Vertical ''' Map Map Depth Inclination Azimuth Depth TVDss' +N/-S +E/-W Northing Easting DLS Vert Section (usft) (°) (°) (usft) usft (usft) (usft) (usft) (usft) -67.00 ,,,H1H, 18.00 0.00 0.00 18.00 -67.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 100.00 0.00 0.00 100.00 15.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 200.00 0.00 0.00 200.00 115.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 300.00 0.00 0.00 300.00 215.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 400.00 0.00 0.00 400.00 315.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 500.00 0.00 0.00 500.00 415.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 600.00 0.00 0.00 600.00 515.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 700.00 0.00 0.00 700.00 615.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 800.00 0.00 0.00 800.00 715.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 900.00 0.00 0.00 900.00 815.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 1,000.00 0.00 0.00 1,000.00 915.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 1,100.00 0.00 0.00 1,100.00 1,015.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 1,200.00 0.00 0.00 1,200.00 1,115.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 1,300.00 0.00 0.00 1,300.00 1,215.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 1,400.00 0.00 0.00 1,400.00 1,315.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 1,500.00 0.00 0.00 1,500.00 1,415.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 10 3/4.. 1,600.00 0.00 0.00 1,600.00 1,515.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 1,700.00 0.00 0.00 1,700.00 1,615.00 0.00 0.00 2,362,515.74 272,132.73 0.00 0.00 1,800.00 3.00 1.65 1,799.95 1,714.95 2.62 0.08 2,362,518.35 272,132.86 3.00 2.62 1,900.00 6.00 1.65 1,899.63 1,814.63 10.46 0.30 2,362,526.19 272,133.23 3.00 10.46 2,000.00 9.00 1.65 1,998.77 1,913.77 23.50 0.68 2,362,539.23 272,133.86 3.00 23.51 2,100.00 12.00 1.65 2,097.08 2,012.08 41.72 1.20 2,362,557.43 272,134.73 3.00 41.72 2,200.00 15.00 1.65 2,194.31 2,109.31 65.05 1.87 2,362,580.74 272,135.85 3.00 65.06 2,300.00 18.00 1.65 2,290.18 2,205.18 93.44 2.69 2,362,609.10 272,137.21 3.00 93.45 2,400.00 21.00 1.65 2,384.43 2,299.43 126.80 3.65 2,362,642.44 272,138.81 3.00 126.81 2,453.79 22.61 1.65 2,434.37 2,349.37 146.77 4.22 2,362,662.40 272,139.77 3.00 146.78 2,500.00 22.61 1.65 2,477.03 2,392.03 164.53 4.73 2,362,680.15 272,140.62 0.00 164.55 2,600.00 22.61 1.65 2,569.34 2,484.34 202.97 5.84 2,362,718.55 272,142.46 0.00 202.99 2,700.00 22.61 1.65 2,661.65 2,576.65 241.40 6.95 2,362,756.96 272,144.30 0.00 241.43 2,800.00 22.61 1.65 2,753.96 2,668.96 279.84 8.05 2,362,795.36 272,146.14 0.00 279.87 2,900.00 22.61 1.65 2,846.28 2,761.28 318.28 9.16 2,362,833.77 272,147.99 0.00 318.30 3,000.00 22.61 1.65 2,938.59 2,853.59 356.71 10.26 2,362,872.17 272,149.83 0.00 356.74 3,100.00 22.61 1.65 3,030.90 2,945.90 395.15 11.37 2,362,910.58 272,151.67 0.00 395.18 3,200.00 22.61 1.65 3,123.21 3,038.21 433.58 12.47 2,362,948.99 272,153.51 0.00 433.62 3,300.00 22.61 1.65 3,215.52 3,130.52 472.02 13.58 2,362,987.39 272,155.36 0.00 472.06 3,400.00 22.61 1.65 3,307.84 3,222.84 510.45 14.69 2,363,025.80 272,157.20 0.00 510.50 3,500.00 22.61 1.65 3,400.15 3,315.15 548.89 15.79 2,363,064.20 272,159.04 0.00 548.94 3,600.00 22.61 1.65 3,492.46 3,407.46 587.32 16.90 2,363,102.61 272,160.88 0.00 587.38 3,688.35 22.61 1.65 3,574.02 3,489.02 621.28 17.88 2,363,136.54 272,162.51 0.00 621.34 3,700.00 22.57 2.86 3,584.77 3,499.77 625.75 18.05 2,363,141.01 272,162.77 4.00 625.81 3,707.83 22.54 3.67 3,592.00 3,507.00 628.75 18.22 2,363,144.00 272,163.00 4.00 628.81 Sterling 3,800.00 22.56 3.66 3,677.13 3,592.13 664.03 20.48 2,363,179.23 272,165.94 0.02 664.16 3,900.00 22.58 3.66 3,769.47 3,684.47 702.33 22.93 2,363,217.47 272,169.12 0.02 702.54 1/29/2015 11:42:02AM Page 3 COMPASS 5000.1 Build 70 Halliburton HALLl B U RTD N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1f Project: Kenai Gas Field MD Reference: Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1f Site: KGF 14-6 Pad North Reference: True Well: KBU 22-06Y Survey Calculation Method: Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp2 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/$ +Et W Northing Easting DLS Vert'Section (usft) (a) (°) (usft) usft (usft) (usft) (usft) (usft) 3,776.80 4,000.00 22.59 3.65 3,861.80 3,776.80 740.65 25.38 2,363,255.74 272,172.30 0.02 740.94 4,100.00 22.61 3.64 3,954.12 3,869.12 779.01 27.82 2,363,294.04 272,175.48 0.02 779.37 4,200.00 22.63 3.64 4,046.43 3,961.43 817.39 30.26 2,363,332.37 272,178.65 0.02 817.83 4,300.00 22.65 3.63 4,138.73 4,053.73 855.80 32.70 2,363,370.72 272,181.83 0.02 856.32 4,359.89 22.66 3.63 4,194.00 4,109.00 878.82 34.16 2,363,393.71 272,183.73 0.02 879.38 Sterling 5.2 4,400.00 22.66 3.62 4,231.01 4,146.01 894.24 35.14 2,363,409.11 272,185.00 0.02 894.83 4,500.00 22.68 3.62 4,323.28 4,238.28 932.71 37.57 2,363,447.52 272,188.17 0.02 933.38 4,600.00 22.70 3.61 4,415.54 4,330.54 971.21 40.00 2,363,485.96 272,191.34 0.02 971.95 4,680.71 22.71 3.60 4,490.00 4,405.00 1,002.30 41.96 2,363,517.01 272,193.90 0.02 1,003.10 Sterling Pool 6 4,700.00 22.71 3.60 4,507.79 4,422.79 1,009.73 42.43 2,363,524.43 272,194.51 0.02 1,010.55 4,800.00 22.73 3.60 4,600.03 4,515.03 1,048.28 44.86 2,363,562.93 272,197.67 0.02 1,049.17 4,900.00 22.75 3.59 4,692.26 4,607.26 1,086.86 47.28 2,363,601.45 272,200.83 0.02 1,087.83 4,955.02 22.76 3.59 4,743.00 4,658.00 1,108.10 48.61 2,363,622.66 272,202.57 0.02 1,109.11 Upper Beluga 5,000.00 22.77 3.58 4,784.47 4,699.47 1,125.47 49.70 2,363,640.01 272,203.99 0.02 1,126.51 5,100.00 22.78 3.58 4,876.68 4,791.68 1,164.11 52.12 2,363,678.59 272,207.15 0.02 1,165.22 5,200.00 22.80 3.57 4,968.87 4,883.87 1,202.77 54.53 2,363,717.20 272,210.31 0.02 1,203.96 5,300.00 22.82 3.56 5,061.05 4,976.05 1,241.47 56.95 2,363,755.84 272,213.46 0.02 1,242.73 5,400.00 22.84 3.56 5,153.21 5,068.21 1,280.19 59.36 2,363,794.50 272,216.61 0.02 1,281.52 5,500.00 22.85 3.55 5,245.37 5,160.37 1,318.94 61.76 2,363,833.20 272,219.76 0.02 1,320.35 5,600.00 22.87 3.55 5,337.51 5,252.51 1,357.71 64.17 2,363,871.92 272,222.91 0.02 1,359.20 5,639.60 22.88 3.54 5,374.00 5,289.00 1,373.08 65.12 2,363,887.26 272,224.16 0.02 1,374.59 Middle Beluga 5,700.00 22.89 3.54 5,429.65 5,344.65 1,396.52 66.57 2,363,910.67 272,226.06 0.02 1,398.08 5,800.00 22.91 3.53 5,521.77 5,436.77 1,435.35 68.97 2,363,949.45 272,229.20 0.02 1,436.98 5,900.00 22.92 3.53 5,613.88 5,528.88 1,474.21 71.37 2,363,988.26 272,232.34 0.02 1,475.92 6,000.00 22.94 3.52 5,705.97 5,620.97 1,513.10 73.76 2,364,027.09 272,235.48 0.02 1,514.88 6,100.00 22.96 3.51 5,798.06 5,713.06 1,552.02 76.15 2,364,065.95 272,238.62 0.02 1,553.87 6,200.00 22.98 3.51 5,890.13 5,805.13 1,590.97 78.54 2,364,104.85 272,241.75 0.02 1,592.89 6,300.00 22.99 3.50 5,982.19 5,897.19 1,629.94 80.93 2,364,143.77 272,244.89 0.02 1,631.93 6,319.35 23.00 3.50 6,000.00 5,915.00 1,637.49 81.39 2,364,151.30 272,245.49 0.02 1,639.49 7518' 6,400.00 23.01 3.49 6,074.24 5,989.24 1,668.95 83.32 2,364,182.71 272,248.02 0.02 1,671.01 6,426.90 23.01 3.49 6,099.00 6,014.00 1,679.44 83.96 2,364,193.19 272,248.86 0.02 1,681.52 Lower Beluga 6,500.00 23.03 3.49 6,166.28 6,081.28 1,707.98 85.70 2,364,221.69 272,251.15 0.02 1,710.11 6,600.00 23.04 3.48 6,258.31 6,173.31 1,747.03 88.08 2,364,260.69 272,254.27 0.02 1,749.24 6,700.00 23.06 3.48 6,350.32 6,265.32 1,786.12 90.45 2,364,299.73 272,257.40 0.02 1,788.40 6,800.00 23.08 3.47 6,442.32 6,357.32 1,825.24 92.83 2,364,338.79 272,260.52 0.02 1,827.58 6,900.00 23.10 3.46 6,534.31 6,449.31 1,864.38 95.20 2,364,377.87 272,263.64 0.02 1,866.80 7,000.00 23.11 3.46 6,626.29 6,541.29 1,903.55 97.57 2,364,416.99 272,266.76 0.02 1,906.04 7,100.00 23.13 3.45 6,718.26 6,633.26 1,942.75 99.93 2,364,456.14 272,269.88 0.02 1,945.31 7,200.00 23.15 3.44 6,810.21 6,725.21 1,981.97 102.30 2,364,495.31 272,272.99 0.02 1,984.61 1/29/2015 11:42:02AM Page 4 COMPASS 5000.1 Build 70 SHalliburton ALLIBURT N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA '41Well KBU 22-06Y Company: <Hilcorp Energy Company4 A _ i34Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1 f Project: Kenai Gas Field m -r Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1f Site: KGF 14-6 Pad r`i-- - True Shell: KBU 22-06Y Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp2 teIMEIN t It 1N1-10* Planned Survey', Measured Vertical � = Ma- -= -r-='''LlifilKill: 4i ' Depth Inclination Azimuth Depth TVDss +N1-S +' d 'r o (usft) (°) ("} (usft) usft (usttj (u$ftj�_„�,, ti itft} � 6,817.1; o 7,300.00 23.17 3.44 6,902.15 6,817.15 2,021.23 104.66 2,364,534.51 272,276.11 0.02 2,023.93 7,400.00 23.18 3.43 6,994.09 6,909.09 2,060.51 107.01 2,364,573.74 272,279.22 0.02 2,063.28 7,500.00 23.20 3.43 7,086.00 7,001.00 2,099.82 109.37 2,364,613.00 272,282.33 0.02 2,102.67 7,600.00 23.22 3.42 7,177.91 7,092.91 2,139.16 111.72 2,364,652.28 272,285.43 0.02 2,142.07 7,700.00 23.24 3.41 7,269.81 7,184.81 2,178.53 114.07 2,364,691.59 272,288.54 0.02 2,181.51 7,704.56 23.24 3.41 7,274.00 7,189.00 2,180.33 114.18 2,364,693.39 272,288.68 0.05 2,183.31 Upper Tyonek 7,800.00 23.25 3.41 7,361.69 7,276.69 2,217.93 116.42 2,364,730.94 272,291.64 0.02 2,220.98 7,900.00 23.27 3.40 7,453.56 7,368.56 2,257.35 118.77 2,364,770.31 272,294.74 0.02 2,260.47 8,000.00 23.29 3.39 7,545.42 7,460.42 2,296.80 121.11 222,:333666444,:877307900...739401 ,364,809.70 272,297.84 0.02 2,299.99 8,100.00 23.31 3.39 7,637.27 7,552.27 2,336.28 123.45 2,364,849.13 272,300.93 0.02 2,339.54 8,200.00 23.32 3.38 7,729.10 7,644.10 2,375.79 125.79 2,364,888.58 272,304.03 0.02 2,379.11 8,300.00 23.34 3.38 7,820.92 7,735.92 2,415.32 128.12 2,364,928.07 272,307.12 0.02 2,418.72 8,400.00 23.36 3.37 7,912.74 7,827.74 2,454.89 130.45 2,364,967.58 272,310.21 0.02 2,458.35 8,500.00 23.37 3.36 8,004.53 7,919.53 2,494.48 132.78 2,365,007.11 272,313.30 0.02 2,498.01 8,600.00 23.39 3.36 8,096.32 8,011.32 2,534.10 135.11 2,365,046.68 272,316.38 0.02 2,537.70 8,700.00 23.41 3.35 8,188.10 8,103.10 2,573.75 137.43 2,365,086.27 272,319.47 0.02 2,577.41 8,800.00 23.43 3.35 8,279.86 8,194.86 2,613.42 139.75 2,365,125.90 272,322.55 0.02 2,617.16 8,900.00 23.44 3.34 8,371.61 8,286.61 2,653.13 142.07 2,365,165.55 272,325.63 0.02 2,656.93 9,000.00 23.46 3.33 8,463.35 8,378.35 2,692.86 144.39 2,365,205.22 272,328.71 0.02 2,696.73 9,100.00 23.48 3.33 8,555.08 8,470.08 2,732.62 146.70 2,365,244.93 272,331.78 0.02 2,736.55 9,200.00 23.50 3.32 8,646.79 8,561.79 2,772.40 149.02 2,365,284.67 272,334.86 0.02 2,776.41 9,300.00 23.51 3.32 8,738.49 8,653.49 2,812.22 151.32 2,365,324.43 272,337.93 0.02 2,816.29 9,343.08 23.52 3.31 8,778.00 8,693.00 2,829.38 152.32 2,365,341.57 272,339.25 0.02 2,833.48 Tyonek D1 9,400.00 23.53 3.31 8,830.18 8,745.18 2,852.06 153.63 2,365,364.22 272,341.00 0.02 2,856.20 9,500.00 23.55 3.30 8,921.86 8,836.86 2,891.94 155.93 2,365,404.04 272,344.06 0.02 2,896.14 9,509.97 23.55 3.30 8,931.00 8,846.00 2,895.91 156.16 2,365,408.01 272,344.37 0.02 2,900.12 Tyonek D2 9,600.00 23.57 3.30 9,013.53 8,928.53 2,931.84 158.23 2,365,443.88 272,347.13 0.02 2,936.10 9,700.00 23.58 3.29 9,105.18 9,020.18 2,971.76 160.53 2,365,483.76 272,350.19 0.02 2,976.10 9,800.00 23.60 3.29 9,196.83 9,111.83 3,011.72 162.83 222,:333666555,:445284333...786668 ,365,523.66 272,353.25 0.02 3,016.12 9,862.40 23.61 3.28 9,254.00 9,169.00 3,036.66 164.26 2,365,548.57 272,355.16 0.02 3,041.10 Tyonek D3B 9,900.00 23.62 3.28 9,288.46 9,203.46 3,051.70 165.12 2,365,563.59 272,356.31 0.02 3,056.17 10,000.00 23.64 3.27 9,380.07 9,295.07 3,091.71 167.41 2,365,603.55 272,359.37 0.02 3,096.24 10,086.16 23.65 3.27 9,459.00 9,374.00 3,126.21 169.38 2,365,638.00 272,362.00 0.02 3,130.79 Tyonek D4A 10,100.00 23.65 3.27 9,471.68 9,386.68 3,131.75 169.70 2,365,643.54 272,362.42 0.00 3,136.35 10,200.00 23.65 3.27 9,563.28 9,478.28 3,171.80 171.99 2,365,683.53 272,365.48 0.00 3,176.46 COMPASS 5000.1 Build 70 1/29/2015 11:42:02AM Page 5 • 0 Halliburton HA LLI B U RTD N Standard Proposal Report Database: Sperry EDM-NORTH US+CANADA Local Co-ordinate Reference: Well KBU 22-06Y Company: Hilcorp Energy Company TVD Reference: Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1E'i' Project: Kenai Gas Field MD Reference: Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GL+1 E I' Site: KGF 14-6 Pad North Reference: True Well: KBU 22-06Y Survey Calculation Method: Minimum Curvature Wellbore: KBU 22-06Y Design: KBU 22-06Y wp2 Targets Target Name -hit/miss target Dip Angle Dip Dir. TVD +N/-S +E/-W Northing Easting -Shape (0) (°) (usft) (usft) (usft) (usft) (usft) KBU 22-06Y T1 wp2 0.00 0.00 7,274.00 2,153.97 116.01 2,364,667.00 272,290.00 -plan misses target center by 24.32usft at 7694.23usft MD(7264.50 TVD,2176.26 N,113.94 E) -Circle(radius 100.00) KBU 22-06Y T1 0.00 0.00 7,270.00 2,151.99 117.05 2,364,665.00 272,291.00 -plan misses target center by 24.68usft at 7689.80usft MD(7260.43 TVD,2174.51 N,113.83 E) -Point KBU 22-06Y TO wp2 0.00 0.00 3,592.00 628.75 18.22 2,363,144.00 272,163.00 -plan hits target center -Circle(radius 100.00) KBU 22-06Y T2 wp2 0.00 0.00 9,459.00 3,126.21 169.38 2,365,638.00 272,362.00 -plan hits target center -Circle(radius 100.00) KBU 22-06YT2 0.00 0.00 9,435.00 3,115.25 171.59 2,365,627.00 272,364.00 -plan misses target center by 2.85usft at 10059.83usft MD(9434.89 TVD,3115.67 N,168.78 E) -Point Casing Points Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name C') (") 1,500.00 1,500.00 10 3/4" 10-3/4 13-1/2 6,319.35 6,000.00 7 5/8" 7-5/8 9-7/8 10,200.00 9,563.28 5" 5 6-3/4 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology (0) (°) 6,426.90 6,099.00 Lower Beluga 0.00 9,862.40 9,254.00 Tyonek D3B 0.00 7,704.56 7,274.00 Upper Tyonek 0.00 3,707.83 3,592.00 Sterling 0.00 5,639.60 5,374.00 Middle Beluga 0.00 4,359.89 4,194.00 Sterling 5.2 0.00 4,680.71 4,490.00 Sterling Pool 6 0.00 10,086.16 9,459.00 Tyonek D4A 0.00 4,955.02 4,743.00 Upper Beluga 0.00 9,343.08 8,778.00 Tyonek D1 0.00 9,509.97 8,931.00 Tyonek D2 0.00 1/29/2015 11:42:02AM Page 6 COMPASS 5000.1 Build 70 • • Hilcorp Energy Company Kenai Gas Field KGF 14-6 Pad KBU 22-06Y II KBU 22-06Y KBU 22-06Y wp2 Sperry Drilling Services Clearance Summary Anticollision Report 29 January,2015 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: KGF 14-6 Pad-KBU 22-06Y-KBU 22-06Y-KBU 22-06Y wp2 ,_ Well Coordinates: 2,36Z 51574 N,272,132.73 E(60°27'38.69"N,151°15'44.71"W) Datum Height: Plan:KBU 22-06Y @ 85.00usft(Saxon 169(67 GLF18 KB)) Scan Range: 0.00 to 10,200.00 usft.Measured Depth. Scan Radius is 1,218.20 usft.Clearance Factor cutoff is Unlimited. Max Ellipse Separation is Unlimited Geodetic Scale Factor Applied Version: 5000.1 Build: 70 Scan Type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Scan Type: 25.00 R 1 1111 HALLIBURTON Sperry Drilling Services e • • Hilcorp Energy Company HALLIBURTON Kenai Gas Field Anticollision Report for KBU 22-06Y-KBU 22-06Y wp2 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: KGF 14-6 Pad-KBU 22-06Y-KBU 22-06Y-KBU 22-06Y wp2 Scan Range: 0.00 to 10,200.00 usk.Measured Depth. Scan Radius is 1,218.20 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-D7 25.00 145.37 25.00 143.93 26.96 100.591 Centre Distance Pass- KBU 11-07-KBU 11-07-KBU 11-07 225.00 146.50 225.00 143.37 225.31 46.712 Ellipse Separation Pass- KBU 11-07-KBU 11-07-KBU 11-07 1,350.00 196.97 1,350.00 183.92 1,333.18 15.093 Clearance Factor Pass- KBU 14-06Y-KBU 14-06Y-KBU 14-06Y 1,050.15 83.94 1,050.15 70.75 1,052.22 6.362 Ellipse Separation Pass- KBU 14-06Y-KBU 14-06Y-KBU 14-06Y 1,075.00 84.00 1,075.00 70.77 1,076.69 6.346 Clearance Factor Pass- KBU 22-06-KBU 22-06-KBU 22-06 260.49 57.64 260.49 54.32 262.50 17.366 Centre Distance Pass- KBU 22-06-KBU 22-06-KBU 22-06 300.00 57.83 300.00 54.12 301.43 15.577 Ellipse Separation Pass- KBU 22-06-KBU 22-06-KBU 22-06 575.00 78.36 575.00 71.70 568.79 11.778 Clearance Factor Pass- KBU 23-07-KBU 23-07-KBU 23-07 1,307.52 157.72 1,307.52 143.08 1,310.09 10775 Centre Distance Pass- KBU 23-07-KBU 23-07-KBU 23-07 1,350.00 157.85 1,350.00 142.99 1,351.58 10.625 Clearance Factor Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 2,211.85 49.15 2,211.85 28.29 2,259.05 2.356 Centre Distance Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 2,250.00 49.92 2,250.00 27.80 2,296.47 2.257 Ellipse Separation Pass- KBU 23X-6-KBU 23X-6-KBU 23X-6 2,275.00 51.20 2,275.00 28.33 2,320.95 2.238 Clearance Factor Pass- KBU 24-06-KBU 24-06-KBU 24-06 1,500.00 150.58 1,500.00 133.30 1,503.35 8.717 Clearance Factor Pass- KBU 24-06-KBU 24-06-KBU 24-06 1,747.53 147.40 1,747.53 130.92 1,753.62 8.943 Ellipse Separation Pass- KBU 24-06-KBU 24-O6RD-KBU 24-O6RD 1,500.00 150.58 1,500.00 133.30 1,503.35 8.717 Clearance Factor Pass- KBU 24-06-KBU 24-O6RD-KBU 24-O6RD 1,747.53 147.40 1,747.53 131.17 1,753.62 9.083 Ellipse Separation Pass- KDU 1-KDU 1-KDU 1 0.0osr-�y I 1,7011,704111 III " -77.6 F 0.762 - E KDU 1-KDU 1-KDU 1 C,r� �300.00 WH 341 2,300 ® -243.7 - ® 0.565 O11101.111111111.14111 KDU 1-KDU 1-KDU 1 4,775 00 IIIF', 1,213.87 4,775U ® -862.05 , 0.585 Ellipse Separation KDU 1-KDU 1 PB-KDU 1 PB wi' 1,700.00 1 249.45 1111111,7ooll III -77.82 1 II 0.762 Centre Distance FAIL- KDU 1-KDU 1 PB-KDU 1 PB hia,300.00 WIWIN6.52 =WIN MENEM ilali ® 0.565 Clearance Factor FAIL- KDU 1-KDU 1 PB-KDU 1 PB 1.1175.0Q M.k.87 - I, 0.585 Ellipse Separation FAIL- KU 13-6-KU 13-6-KU 13-6 849.88 34.71 849.88 27.83 864.45 5.047 Centre Distance Pass- KU 13-6-KU 13-6-KU 13-6 650.00 34.71 850.00 27.83 864.57 5.046 Ellipse Separation Pass- KU 13-6-KU 13-6-KU 13-6 675.00 35.25 875.00 28.16 888.75 4.977 Clearance Factor Pass- KU 14X-6-KU 14X-6(KDU 6)-KU 14X-6 25.00 82.71 25.00 81.56 26.99 71.624 Centre Distance Pass- KU 14X-6-KU 14X-6(KDU 8)-KU 14X-6 1,725.00 84.51 1,725.00 75.11 1,727.09 8.996 Ellipse Separation Pass- 29 January,2015-12:24 Page 2 of 5 COMPASS • • Hilcorp Energy Company HALLIBURTON Kenai Gas Field Anticollision Report for KBU 22-O6Y-KBU 22-O6Y wp2 Closest Approach 3D Proximity Scan on Current Survey Data(Highside Reference) Reference Design: KGF 14-6 Pad-KBU 22-06Y-KBU 22-06Y-KBU 22-O6Y wp2 Scan Range: 0.00 to 10,200.00 usft.Measured Depth. Scan Radius is 1,218.20 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 14X-6-KU 14X-6(KDU 8)-KU 14X-6 1,825.00 87.16 1,825.00 77.19 1,826.67 8.742 Clearance Factor Pass- KU 21-7-KU 21-7-KU 21-7 1,290.25 204.60 1,290.25 197.84 1,297.87 30.230 Centre Distance Pass- KU 21-7-KU 21-7-KU 21-7 1,325.00 204.75 1,325.00 197.74 1,331.97 29.219 Ellipse Separation Pass- KU 21-7-KU 21-7-KU 21-7 1,775.00 227.85 1,775.00 218.12 1,772.54 23.402 Clearance Factor Pass- KU 21-7-KU 21-7PB-KU 21-7PB 930.29 194.11 930.29 187.81 942.42 30.812 Centre Distance Pass- KU 21-7-KU 21-7PB-KU 21-7PB 950.00 194.20 950.00 187.76 961.00 30.164 Ellipse Separation Pass- KU 21-7-KU 21-7PB-KU 21-7PB 1,200.00 204.58 1,200.00 196.50 1,204.45 25.314 Clearance Factor Pass- KU 21-7X-KU 21-7X-KU 21-7X 1,758.61 105.33 1,758.61 97.22 1,760.29 12.992 Centre Distance Pass- KU 21-7X-KU 21-7X-KU 21-7X 1,775.00 105.36 1,775.00 97.19 1,776.08 12.887 Ellipse Separation Pass- KU 21-7X-KU 21-7X-KU 21-7X 1,875.00 108.00 1,875.00 99.41 1,871.00 12.580 Clearance Factor Pass- KU 31-7X-KU 31-7X-KU 31-7X 200.22 183.00 200.22 180.25 202.22 66.385 Centre Distance Pass- KU 31-7X-KU 31-7X-KU 31-7X 700.00 185.25 700.00 176.48 700.00 21.107 Ellipse Separation Pass- KU 31-7X-KU 31-7X-KU 31-7X 1,300.00 236.95 1,300.00 220.32 1,270.32 14.247 Clearance Factor Pass- Survey tool program From To Survey/Plan Survey Tool (usft) (usft) 18.00 2,501.00 KBU 22-O6Ywp2 MWD+SC+sag 2,501.00 10,199.60 KBU 22-O6Ywp2 MWD+SC+sag Ellipse error terms are correlated across survey tool tie-on points. Calculated ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Distance Between centres is the straight line distance between wellbore centres. Clearance Factor=Distance Between Profiles/(Distance Between Profiles-Ellipse Separation). All station coordinates were calculated using the Minimum Curvature method. 29 January,2015-12:24 Page 3 of 5 COMPASS • • Hilcorp Energy Company HALLIBURTON Kenai Gas Field Anticollision Report for KBU 22-06Y-KBU 22-06Y wp2 Direction and Coordinates are relative to True North Reference. Vertical Depths are relative to Plan:KBU 22-06Y @ 85.0ousft(Saxon 169(67 GL+18 KB)). Northing and Easting are relative to KBU 22-06Y. Coordinate System is US State Plane 1927(Exact solution),Alaska Zone 04. Central Meridian is-150.00",Grid Convergence at Surface is:-1.10°. Ladder Plot r--- -----r---- r - -----+ r i , •c ; VI ; � LEGEND I FA X10 1 .,� mir o ; rI II!i !- -let- KBU 11-07,KBU11--07,KBU 11-07 V0 1 i�. KBU 14-06Y,KBU 14-06Y,KBU 14-06Y V0 co -----, ---- Ir i� � ,fr � --------i ----'---- $ KBU 22-06,KBU22-06,KBU22-06 V0 r y -e- KBU23-07,KBU23-07,KBU23-07V0 O '� I p i �/ � -I-KBU 23X-6,KBU 23X-6,KBU 23X-6 V0 700 I n II! C6 7 KI ii, / •-6- KBU 24-06,KBU 24-06,KBU24-06 V0 ,� ` , 1 i -4- KBU 24-06,KBU 24-06RD,KBU 24-06RDV0 CO !%'< r! ./ / i $ KDU1,KDU1,KDU1V0 �� p! r �:� I -A- KDU1,KDU1PB,KDU1PBVO --�-- KU 13-6,KU 13-6,KU 13-6 VO o 350 r. !s` KU 14X-6,KU 14X-6(KDU 8),KU 14X-6 VO art `� -A- KU21-7,KU21-7,KU21-7V0 2 T' � wii 4�, • .---1 i I -�(- KU21-7,KU21-7PB,KU21-7PBVO .a a - C ;,_ `s w - - ---- ---- KU 21-7X,KU 21-7X,KU 21-7X VO a) U •_w.m;.ypar.o., ..�., $KU 31-7X,KU 31-7X,KU 31-7X V0 $KBU22-06Ywp2 0 1500 3000 4500 6000 7500 Measured Depth(1500 usft/in) 29 January,2015- 12:24 Page 4 of 5 COMPASS • • Hilcorp Energy Company HALLIBURTON Kenai Gas Field Anticollision Report for KBU 22-06Y-KBU 22-06Y wp2 Clearance Factor Plot: Measured Depth versus Separation(Clearance)Factor 10.00- ._. _ _ _ _. ,-_. ,. •I P� 6.75- :...1 _. ---• - .---.... . .._.. LEGEND 7.50 I - .>dKBU 11-07,KBU 11--07,KBU 11-07 VO _ • i -- 44- KBU 14-06Y,KBU 14-06Y,KBU 14-06YVO -9- KBU 22-06,KBU 22-06,KBU 22-06V0 N - -e- KBU23-07,KBU23-07,KBU23-07V0 - 6.25 o - . I 1 -4- KBU23X-6,KBU23X-6,KBU23X-6V0 _ . ._. ., + .. -6- KBU 24-06,KBU 24-06,KBU 24-06 V0 cc• 5.00 (1�. -,- KBU 24-06,KBU 24-06RD,KBU 24-06RD VO 'm __. _,,,, -e- KDU1,KDU1,KDU1V0 co '' $ KDU1,KDU1PB,KDU1PBV0 in 3.75 -1i- KU 13-6,KU13-6,KU 13-6 VO .td - - I -1'- KU14X-6,KU14X-6(KDU8),KU14X-6V0 -4- KU 21-7,KU21 7,KU21-7 VO 2.50 \t t 4(- KU21-7,KU21-7PB,KU21-7PBV0 --`Collision Avoidance Reg i. ! ( 4E KU21-7X,KU21-7X,KU21-7XVO Zone Stop Drilling, 1.25-- . ... ....... ........ — --. 11 ..— - .. ___:.__ $ KU31-7X,KU31-7X,KU31-7X V0 $ KBU22-06 Y 2 ,e �...� �..F i 0.00 1 I i 11 I I I I 1 1 1 1 � I I 1 II I I I I I I I I II 1111� 11 1 1 1 1 1 1 1 IIID 0 750 1500 2250 3000 3750 4500 5250 6000 6750 7500 6250 9000 Measued Depth(1500 usft/iin) 29 January,2015- 12:24 Page 5 of 5 COMPASS • • SH33a7 171:1` g ,► 1 1 ii o 1 0 W3 It 1r, N 3 ----- 0.4 _ .�-1 aa. <- - T N O O M N .0 .O 1 -. 0' .4 -4 N ( S Os. d a 0 N ra kr, N- u1 N to' .-I 0 �( -4 •-+ N u, _ t Rr; r N M I kr, CO r4 N N cam+, .40 u, W N a� O = O[-t < I T --- 1 Q O ~ r I mO0 W • Y U ill z 1 _--1tO tv‘f�- 1 - — p= W u < z '00 1 .00 C \ N' 0 0 I 0 cceN v-, Com -4 N I N N 'CO � .4 U c O r-1 c•, u, CO h 0• cr, 0• CO -N CCI N '0 CO 0 CD 0 z .-'1 N c'r1 u, N as 4-4 M Co N •O N •O u, r-I r-1 rl N N cr, rV .4 y- i ! 1 W Y I _r'._.�_ Or1 re } N Woi m a 01 Z 1,14o r –7 o .2 U O N U z� J R W Z s 0 U — _ 1 < i � I I I - — -- — ---+---- _.-_ a+ =) it o . —1 i _T I T -1 � z `� ; --T w wj w1 w gel wI r: w�w1 w w1 wT w w w 1 PA w :2;„o — I ---1 - H • Q 5 < co mI u, 0` � u, rn ,—I ce, a, at.1 N N- •0 -4 1 .4 .O H $ N N -4 u, u\ .O \O .O I .O .O •0 .O •0 I \O •D •O LU• .-• I Ce 8 z H.44 W ' 1-� ` _ j ►s Z-. f'i .7r 1�i `r FZ rz f-. it I Z+ Fi Z Z .Z. Zr .fie Z 03 ft., c H t2 w z i m[� 1=c1.301 C0O• ON 1c . .0, tN 2 Cr-1O ! uc ra`1 Ou,I N--l 1,4-..‘i 1] �O--I M� A�CrOl Q @ a ►>4 00 .-1 .-1 N N N I - r-1 QC I cr,1 .O m e mC- 1 a+ SrUz - o ( 1 N . N-` c� - ul _.1- .4U_ ,� 0` � a Z rm. F O O m` N�! O 0` N nOI1 � � V I JNOCNIo < � CN c .--1 01 cr.1 a• 0 r-+ Co tel u,-f 0•, 0 ' o a• •o to o •-4 0 0• it... -1 w i o 0 0, N '0 a• CV r-I N 1 c",1 r-I 1 M -4 0• ir, CO Cr, -4 0• <4 P 1 0 0 r-4( .-4 r-1 cn .4 to '. C^ 0\ 0 r, v0 tqO} 4-44-4 c1 N- . . et J u-• u1 u1 u1uti uuv v it1� O uv( u'1 u1 .0 .0 •O •0 •0 N N N • o r., 1 I ( . iiI ' IIl 0 C~ � O 1 _T—, O u — 0 R. 1o 0 03 01 u\ o� 01 01 u, u, � 0 0 - u\ u, u\ 0 0 u,11 HI ti2 1 cn 0 e-1 00 N, .4 M [r, e-1 r^1 .4r^ M r-I .1 rA 0 N r,1u, o• r-1 r,I u,I co 0 r-1 -3 -4 � N vw f i. o r-i 4--1 1f--1 1 r-I N N N N N N-1TN _.NN r <C -it el 1 - , . __ . L,.f r •1 . J . , O a. O r-i N r-i N 1 N I O 1 r-1 a. N sO O .3 u1 07 GP. -4 t 0 W i i O a• r .•O 0• cr, N i cam, I u, I M u1 CO ,(721 N .4 CT N .-1.., O U ; o o ra r-1 r-1 c*, 1 u\ CQ 0' o -4 N 0' N O _ '� ut u•,j u\, uN u, u,) ur, u\ I u1 u, .0 •O •0 •0 .O N N tO • o • 0 a . 0 0 0 o0 At . 0 KBU 22-06Y SHL KBU 11-07 KBU 14-6/(/ , KU 21-7X KBU 22-06Y Sec.4 KU 13 06 * KDU 01 1.KDU 08(KU 14X-6) KU 14-06 BHL KBU 31-07 KBU 31-07RD 'KU 21-07 4- 0 KBU 23-07 . . S004N011 W 04 a KBU 24-06 KBU23X-06 KBU 24-06RD te KU 14-06 Kenai Gas Field Pad No. 14-06 °'''' ,4?sl, r , rA KU 43-12 R".. Ali ♦ KBU 14-6Y BHL' thrialli1/4 iaa. i I, 1 fire's"' : i Ark, la.a. 'A�rt� rrrrrgq . ~ a. 1 I Legend s. 1 0 KBU 22-06Y SHL 4 Other Surface Well Locations • Other Bottom Hole Locations „,.:: ,, w �±500 ft radius from KBU 22-06Y SHL Well Pad I i Oil and Gas Unit Boundary 0 100 200 300 Kenai Unit Feet KBU 22-06Y N Alaska State Plane Zone 4,NAD27 Hilexorp Alaska,LLC Map Date:3/16/2015 • • KBU 22-06Y Offset wells Well Name Hole Size Casing Size TMD TVD FIT KBU 22-6 16 13-3/8 1668 1502 16.3 KU 14X-6 17-1/2 13-3/8 2566 2566 16.9 KDU 1 17-1/2 13-3/8 1209 1209 KBU 23-7 16 13-3/8 1395 1395 KBU 23X-06 17-1/2 13-3/8 2532 2532 13 KBU 24-6 17-1/2 13-3/8 1518 1518 KBU 31-7 17-1/2 13-3/8 2526 16.9 KU 13-6 17-1/2 13-3/8 2008 KU 21-7X 12-1/4 9-5/8 1525 1525 KBU 43-7X 16 13-3/8 1510 1469 KBU 42-7 17-1/2 13-3/8 1099 1093 KBU 24-6 17-1/2 13-3/8 1518 1518 KBU 11-8X 16 13-3/8 1517 1507 KBU 42-6 16 13-3/8 1525 1525 KBU 11-07 16 13-3/8 1717 1680 15.2 KBU 14-6Y 16 13-3/8 1504 1503 KU 43-12 16 13-3/8 1197 1197 Average Depth 1678.5 1582.6 TMD TVD • • Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday, March 17, 2015 3:01 PM To: Schwartz, Guy L(DOA) �7 ,�— Q 4411 Subject: FW: KBU 22-06Y WP3 PrD �6 As per our conversation,this is how Cary explains it. I will plan on getting a Gyro run on KDU 1 to clean up the data even more. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Cary Taylor [mailto:Cary.Taylor@Halliburton.com] Sent: Tuesday, March 17, 2015 2:38 PM To: Monty Myers Subject: RE: KBU 22-06Y WP3 Monty, Taking a look at KBU 22-06Y I am seeing that the AC did improve slightly but we are just squeaking by the ellipses on the KDU-1 well. 1 • • j ifiIiii Wir - waa[ # ut ktz el + acIISIQ QIeI %I_ Q Plan: KBU 22-06Y wp3 (Plan:KBU 22-06Y/KBI -69 60 330 60 5050---____ 40 �. 4 3004„,.1/4S.4':,,:„.....:\N =30 _ -_.4 .**, ------'---r-- ' ,„ 20 _ s 10 44011iXNN44kkNNV.\ --- 10 \ ikkil41111/4Nirk, . • ,... N •.\\':.:::::,:.1... , , l IA., . . ti 0 270 ,. >'. . 44411k . 10 • "Nk. .'::$01.40:::':,.::::idigik . .. IIIN--TA'N. ,..k iihre. ::!:•,t-z.-:=3,-.-•:..!.i:..„,..4.0,1/4. • • \ .a NNii !,• s 1,**.--.4ez*AN11* ' . NNik• ' •• •!:',..-:...\ V.,Nit,47,4*-0444VA .. ..„ , ,.„ . •• Nii.._ N.., V: ... 20 41.0-- NT Ni...4#4 hL 111044kk . ''SA44‘:\ \ NO4LittS'*'.4'*IN Ili( \\I\ .\. • ''''.' 16.4.10 ..„4403,10, . 0 )11,, . .. .., Nlit4k‘‘MirN14 . . \41/k \ \ 30 240 TRa,444Atiklik• �'� 40 ,,- 1frAik )44,Nilik. . 'I lb\ -`lik'Ik• 0441644S114( '� t ,..s tiON.46 itA74tArv,"11,11"74,10:04ko, J OI I VIP I triWal k*4T 7* -0 , ti * Ikli'4 60 21 I r , ‘ '1111%-- WIti.lk °. ' } 4 I 11 I I I lkiVki I Its - 2 • I looks like we are kicking off 100' shallower with a 3.4°/100 DLS instead of a 3°/100 DLS. As-Built survey updated the location and the RKB to 83' (65'GL+18'KB) Formations all match the TVDSS of Geoprog rev2 Targets matches X,Y from Geoprog rev2 for the Sterling target and the Tyonek D4A target. The T1 target appears to be not exactly in line with the other two targets so we don't hit it dead center. All three targets upon closer inspection are 2' deeper in TVDSS than the targets listed in the GeoProg and will be corrected upon review by the Geologist. Cary L. Taylor Technical Professional -Well Design, Ld. Halliburton Energy Services 6900 Arctic Blvd Anchorage, AK 99518 Office:907-273-3529 VolP: 88-245-3529 Ce11:907-748-3920 Fax:907-273-3535 From: Monty Myers [mailto:mmyers@hilcorp.com] Sent: Tuesday, March 17, 2015 10:01 AM To: Cary Taylor Subject: [EXTERNAL] KBU 22-06Y WP3 Cary, I found WP3 in the directional folder, but don't remember requesting it? I am sure it was the update to surface location but I can't find that email anywhere? It looks like the KOP changed between WP2 and WP3. Is that all? Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 This e-mail, including any attached files, may contain confidential and privileged information for the sole use of the intended recipient. Any review, use, distribution, or disclosure by others is strictly prohibited. If you are not the intended recipient(or authorized to receive information for the intended recipient), please contact the sender by reply e-mail and delete all copies of this message. 3 • • Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Tuesday, March 17, 2015 2:08 PM To: Schwartz, Guy L(DOA) Cc: Davies, Stephen F (DOA) Subject: RE: Surf Depth and AC issues for Diverter Waiver on KBU 22-06Y Attachments: KBU 22-06Y wp3 - Proposal Report.pdf; 157003 KBU 22-06Y 14-6 PAD AS BUILT NAD 27.pdf Good afternoon Guy. It isn't readily possible to get a gyro because gyrodata has shipped their tools out of cook inlet for a while because we didn't have any work coming up. We could make a request to get tools here, it would just take some time. However, I had Halliburton update the directional after we received the"As Built" surface location diagram, and upon review of the KDU 1 AC issues they have now become a "Pass" on their parameters for AC concerns. I have a call into our Halliburton directional planner asking him what has changed. The only thing I can find so far is that the surface location now matches the actual location and the KOP has moved up to 1600'from 1700'. I believe this packet was sent to you already, showing the new as-built, but I am attaching for your reference if needed. Thank you Guy! Please let me know if this will suffice or if I need to provide additional detail. Monty M Myers Drilling Engineer Hilcorp Alaska Office:907.777.8431 Cell: 907.538.1168 From: Schwartz, Guy L (DOA) [mailto:guy.schwartz@ alaska.gov] Sent: Monday, March 16, 2015 3:50 PM To: Monty Myers Cc: Davies, Stephen F(DOA) Subject: RE: Surf Depth and AC issues for Diverter Waiver on KBU 22-06Y Monty, Thanks for the info... is it possible to get a gyro survey on the well KDU 1 ? Seems like someone would have done that by now if it was possible to access the wellbore. Guy Schwartz Senior Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE:This e-mail message,including any attachments,contains information from the Alaska Oil and Gas Conservation Commission (AOGCC),State of Alaska and is for the sole use of the intended recipient(s).It may contain confidential and/or privileged information.The unauthorized review,use or disclosure of such information may violate state or federal law.If you are an unintended 1 11 recipient of this e-mail,please delete it,wi out first saving or forwarding it,and,so that the AOGCC is aware of the mistake in sending it to you,contact Guy Schwartz at(907-793-1226) or(Guv.schwartz@alaska.gov). From: Monty Myers [nailto:mmyers@ hilcorp.com] Sent: Monday, March 16, 2015 3:40 PM To: Schwartz, Guy L(DOA) Subject: Surf Depth and AC issues for Diverter Waiver on KBU 22-06Y Guy, As per our conversation.The tool codes used on KDU 1 AC issues are listed below. Blind tool codes to 5000' because the well is assumed vertical to 5000' and no surveys exist(see attached survey sheet) After 5000'we have surveys but applied a generic Magnetic survey,which are pretty poor also. As far as the surface casing depths for offset wells, please see attached zoomed in spider plot and the list of wells with surface depths. If you need anything else, please let me know! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Cary Taylor [mailto:Cary.Taylor@Halliburton.com] Sent: Monday, March 16, 2015 2:44 PM To: Monty Myers Subject: RE: AC on KBU 22-06Y The well that is an issue I believe is KDU 1 which has blind tool codes down to 5000'and CB-Magnetic surveys to TD which are pretty poor too! What's the status of KDU 1? Cary L.Taylor Technical Professional -Well Design, Ld. Halliburton Energy Services 6900 Arctic Blvd Anchorage, AK 99518 Office:907-273-3529 VolP: 88-245-3529 Ce11:907-748-3920 Fax:907-273-3535 Fax:907-273-3535 From: Monty Myers [mailto:mmvers@hilcoro.com] Sent: Monday, March 16, 2015 1:27 PM To: Cary Taylor Subject: [EXTERNAL] AC on KBU 22-06Y Cary, Can you tell me what tool codes were applied to the KDU 10 in reference to the AC for KBU 22-06Y? 2 • The AOGCC is just askingwhat the main difference are in this well compared to some of the others for AC. J p Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office:907.777.8431 Cell:907.538.1168 This e-mail, including any attached files, may contain confidential and privileged information for the sole use of the intended recipient. Any review,use, distribution, or disclosure by others is strictly prohibited. If you are not the intended recipient(or authorized to receive information for the intended recipient),please contact the sender by reply e-mail and delete all copies of this message. 3 0 • OF q 1.BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD27 4► � - -•.!9s It \ , ZONE 4 DETERMINED BY A DIRECT TIE TO USC&GS TRI STA AUDRY HAVING A ._ 'f- 10 PUBLISHED POSITION OF LAT.60°30'50.559"N LONG.151°16'37.445'W �' 7. N:2382045.42 E:269866.75 '* 49 *- NOR TH 2)BASIS OF VERTICAL DATUM IS MEAN SEA LEVEL. 3)SOUTHWEST CORNER SEC.6 COORDINATE DETERMINED FROM DIRECT 4, STAN A. McLANE. aff i "I'illfl'�III IIIW ullllllllir l'Ij' SURVEY TIE TO THE TO EXISTING BLM WC FORE NW CORNER SEC.7 AND P a637-S �'8� WC Y4 CORNER SECTIONS 6&7 RECOVERED AND NOT THE PROTRACTED i/,"-,k MARCH 16.' 5,_ SECTION CORNER VALUES. litv0;.• ION••.,,'�,� SCALE 4'Ilt‘‘‘s• 0 100 200 J I I I FEET EDGE PA_p FOOTPRINT BERM CONTROL PT,CP-3 -___ ------__X=271,632.56 ® / \ Y;2.362.592.02 WELL"A" KBU 22-06Y AS-BUILT NAD27-------- X=271.90707 \EV.=622,' r=2.362,654.96 GRID N:2362472.99 \ TOP 6"PIPE EL=62.52' GROUND 2ND EL.EL28 GRID E: 272112.27 TOP 2"PIPE EL=62<'. \ LATITUDE: 60°27'38.2658"N \� '� / LONGITUDE: 151°15'45.1013"W (___, \ \ ELEV.: 65.0 FT. NAVD88 \__N l ''' \ \ ,---- 1196' FWL \ O K.B.0 22"6J 420' FSL • O • 0,.O �Ry B'DIWELL CELLAR g\ %, i '' z-i89.66 rss8'DIEL WELL C ,. vii2s.250 6 ;AK,T.U.13-6 9Q fnA '0 PRODUCTION WELLy %q\ K.U. CIli'1196' o NTS) IS. .. <5272,204.41 WELLHOUSE *41)) 1=2,362,476.36 °oa PRODUCTION WELL ‘e. WATER WELL WELL HOUSE 1 01 S. K.D.U.-'' 8'CASING X=272,06287 N 14.5'0 SILO 18.0'X18.0'THREE SIDED 0 V:2,382 471.46 WELL HOUSE N- ,- \ VALVE X=27R 836.34 X=272, 221.84 (e BLDG. 10 T Y52,362,462.91 • V=2,362,453.56 '"�• K.U.21-7 10'0 SILO K.B.U.24-6 X:2]1.928,94 WELL HOUSE I'^ 10'0 PIPE ". V:2,362,414.06 O X=272.174.29 • V, PIPELINE OLD JUMP V=2.362.360.6] ��' MILEPOST SIGN K.B.U.23-7 _. 41' \ MILE'0' ❑OVER BLDG. • Z \ 1' K.B.U.23X-06 I PRODUCTION WELL 14 r //-- ® fi'0 PIPE WELL HOUSE n❑ W / VALVE W' X=272.122.20' • Z 3.6'X3.6'GUARD PIPE Y52.362.337.41 J K.U.14-6 O,02,11WELL HOUSE Z X271 876.24 O V=2 30.9055C B.U'XE.1 CONC.PADS I- _ K.G.F.PAD 14-6 • U [ , 'X• 3.0'HUNGS ELEVATION=65.6'M.S.L. 420'FSL I ''W^^ E '` ate/I1EAT EXCHANGER `LCL )k`,_D ` VJ /J[ 1.2 X5.2'METAL COVER PLATE • - \ -- 8.2756' EDGE PAD FOOTPRINT PE RACK OKU. SILO QONL . A.P.L.AS -,00 Q.H. 14.5 0 S81 E II CONTROL PT.CP-2 RE-BOILER PIPES X=271,888.18 PAG • 5 GLO BLDG. T.B.M.EL E63 0=2,382.224,53 X=272,169,16 T4N W.C. SPIKE IN P P V=2,362,213.75 Sl 36 m4ALVE METER JCONC. 3"O GUARD OLJ ELEV.=65.BT I S72I S7 8.0'X12.0' ' BUILDING PAD 40'X4.0' PIPE R12W R11W UTILITY \ _ Illli Q.H.P,W �/ 3.0'X5.1' GAL HEATER 1921 BLDG 4 8.0'X8.0'FIRE COVER" TE �I "❑ 4..Q ry B (HOSE BLDG. Q.H.PIPE 12.0'X9.0' 4 --I'..d'X123' QONQ.PAD COVER MAT, HEATER CONTROL ,I 1 SWITCH GEAR 260 mid wwww COVERPLATE W 1112111 ®tt BLDG. BLDG. J ROOM / \� II VALVE W/ /le a �_ CENTAUR E �G lig \ WWATERASTE GUARDPIPE PIPEGUARD �. tr.gBODG.RESSOR N HiI o °; SW COR ].4'X8.0 I� 1i'0 E UTILIITV 1n 3SIDED 3'X3' $�.1 D OH/ BLDG. GUARD%PE Z. N 2362069.27 0 , E" AIR 5]4'_ I 1 6 E 270908.10 1 0 FILTERS a„ ':LVE �Ir,E SUPPORTS O ' 3'00N 5C 12I 7 _� GENE - - . . . CONCRE'': / , ROOM 67'X8.0' J 3.0'X5.0'META,. /� DIESEL It' v - ` •' VALVE COVER PLATE \ / \ TANK 9 T . ._. ®BLDG / ��- SATURN \ \ \ ii COMPRESSOR ' OFFICE SHOP R BLDG BLDG 03 SATURN VENT BLOW DOWN\ // \ A82 PAD PROTECTING DPIPED \ \ \ T FILTERS PIPEEN,CONTINUING \ i 11:11PROJECT REVISION: 0 HILCORP ALASKA LLC DATE: 310115 Consulting Inc KBU 22-06Y AS-BUILT DRAWN BY: ICB M� CLAN KENAI GAS FIELD PAD 14-6 SCALE: 1'=1Do• `�► SURFACE LOCATION DIAGRAM NAD27 PROJECTNO. 157003 ENGINEERING I MAPPING/SURVEYING/TESTING BOOK NO. 14-27 P.O.BOX 468 SOLDOTNA,AK 99869 LOCATION VOICE:(907)283-4218 FAX:(907)283-3265 SHEET EMAIL:SAMCLANEEMCLANECG.COM Hilcorp Alaska, LLC S6 T4N R11 W SEWARD MERIDIAN,ALASKA 1 OF 1 • • Schwartz, Guy L (DOA) From: Monty Myers <mmyers@hilcorp.com> Sent: Monday, March 16, 2015 3:40 PM To: Schwartz, Guy L(DOA) Subject: Surf Depth and AC issues for Diverter Waiver on KBU 22-06Y Attachments: KDU 1 Surveys.pdf; KBU_22_06Y_wp01_NAD27_v03_MontysMap.pdf Guy, As per our conversation.The tool codes used on KDU 1 AC issues are listed below. Blind tool codes to 5000' because the well is assumed vertical to 5000' and no surveys exist(see attached survey sheet) After 5000' we have surveys but applied a generic Magnetic survey, which are pretty poor also. As far as the surface casing depths for offset wells, please see attached zoomed in spider plot and the list of wells with surface depths. If you need anything else, please let me know! Monty M Myers Drilling Engineer Hilcorp Alaska Office: 907.777.8431 Cell: 907.538.1168 From: Cary Taylor [mailto:Carv.Taylor@ Halliburton.com] Sent: Monday, March 16, 2015 2:44 PM To: Monty Myers Subject: RE: AC on KBU 22-06Y The well that is an issue I believe is KDU 1 which has blind tool codes down to 5000' and CB-Magnetic surveys to TD which are pretty poor too! What's the status of KDU 1? Cary L. Taylor Technical Professional -Well Design, Ld. Halliburton Energy Services 6900 Arctic Blvd Anchorage, AK 99518 Office:907-273-3529 VolP: 88-245-3529 Cel1:907-748-3920 Fax:907-273-3535 Fax:907-273-3535 From: Monty Myers [mailto:mmyers@hilcorp.com] Sent: Monday, March 16, 2015 1:27 PM To: Cary Taylor Subject: [EXTERNAL] AC on KBU 22-06Y Cary, 1 • • Can you tell me what tool codes were applied to the KDU 10 in reference to the AC for KBU 22-06Y? The AOGCC is just asking what the main difference are in this well compared to some of the others for AC. Thank you! Monty M Myers Drilling Engineer Hilcorp Alaska Office:907.777.8431 Cell:907.538.1168 This e-mail, including any attached files,may contain confidential and privileged information for the sole use of the intended recipient. Any review,use, distribution, or disclosure by others is strictly prohibited. If you are not the intended recipient(or authorized to receive information for the intended recipient),please contact the sender by reply e-mail and delete all copies of this message. 2 • • OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. • TRANSMITTAL LETTER CHECKLIST WELL NAME: kc',t,c '.-e • ksof /%G%..0 –66 PTD: Z-LS '041(7 /Development Service lo ment Ex lorato Stratigraphic Test Non-Conventional P —Exploratory FIELD: POOL: Check Box for Appropriate Letter/Paragraphs to be Included in Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - . (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - ) from records, data and logs acquired for well (name on permit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10'sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non-Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a)authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name)in the attached application,the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(dX2XB) 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 • • [ I , , T, a) Q , o 7 , N, cc , . a, 0. , , a o w' E o. v, a Y a o U. 3, w c4 O, O) •-, 0, c, ' E' 7. 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N N N N N N N N N N M M CI) F) M M M M M M U H Lo u-) w • a)) 0 a) O a) �O U C E. O C CO N CZ N f6 N O Ce V I" 0 M a) 0 0 M O N dT) _ M 'L M M N J N y a) a) p o .:� FE Q p c 0 oa Qu UwQE � JCLQ Q w Q . • • Well History File APPENDIX Information of detailed nature that is not particularly germane to the Well Permitting Process but is part of the history file. To improve the readability of the Well History file and to simpirfy finding information, information of this nature is accumulated at the end of the file under APPENDIX. No special effort has been made to chronologically organize this category of information. Technical Report Title Date Client: Hilcorp Alaska, LLC Field: Kenai Beluga Unit Rig: Saxon 169 Date: May 22, 2015 Surface Data Logging End of Well Report KBU 22-06Y TABLE OF CONTENTS 1. General Information 2. Daily Summary 3. Days vs. Depth 4. After Action Review 5. Mud Record 6. Bit Record 7. Morning Reports 8. Survey Report Digital Data to include: Final Log Files Final End of Well Report Final LAS Exports Halliburton Log Viewer EMF Log Viewer GENERAL WELL INFORMATION Company: Hilcorp Alaska, LLC Rig: Saxon 169 Well: KBU 22-06Y Field: Kenai Gas Unit Borough: Kenai Peninsula Borough State: Alaska Country: United States API Number: 50-133-20650-00-00 Sperry Job Number: AK-XX-0902299672 Job Start Date: 07 April 2015 Spud Date: 07 April 2015 Total Depth: 10200’ MD, 9697’ TVD North Reference: True Declination: 16.618° Dip Angle: 73.442° Total Field Strength: 55327 nT Date Of Magnetic Data: 7 April 2015 Wellhead Coordinates N: North 60° 27’ 38.266” Wellhead Coordinates W: West 151° 15’ 45.101“ Drill Floor Elevation 83.0’ Ground Elevation: 65.0’ Permanent Datum: Mean Sea Level SDL Engineers: Autumn Gould, Jacob Robertson, Jeremy Tiegs, Eric Andrews SDL Sample Catchers: Kruz Kleewein, Michael Frazier, Matthew Wavra, Nathan Conway Company Geologist: Jacob Dunston Company Representatives: Shane Barber, Doug Yessak, Rance Pederson, Lenward Toussant SSDS Unit Number: 117 DAILY SUMMARY 04/07/2015 Spudded well and continued to drill ahead. Gas: 0 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: The samples have been predominantly translucent to clear, occasionally white, very fine to fine grained, sub spherical, moderately to well-sorted sandstone with trace amounts of siltstone. 04/08/2015 Drilled surface hole to 1530’ MD, ran sweep, and circulated hole clean. Began rigging up casing equipment to run down hole. Gas equipment was down and is now fixed and running. Gas: N/A Fluids: There was 0 barrels of water based mud lost down hole. Geology: 40% Sand: black, light-gray, translucent, white to cream, fine grained, silty, poorly sorted, unconsolidated, occasional sandstone, sub angular, firm to hard; 60% Siltstone: light gray-gray, soft-firm, silty, non-calcareous, trace black lithic. 04/09/2015 Rigged up surface casing and ran 10.75” casing to 1499’ MD. Rigged up cement and bumped plug without seeing cement to surface. Decision was made to nipple down the stack and nipple up the BOP to finish getting cement to surface; currently nippling up BOP. Gas: N/A Fluids: There was 0 barrels of water based mud lost down hole. Geology: 40% Sand: black, light-gray, translucent, white to cream, fine grained, silty, poorly sorted, unconsolidated, occasional sandstone, sub angular, firm to hard; 60% Siltstone: light gray-gray, soft-firm, silty, non-calcareous, trace black lithic. 04/10/2015 Nippled up BOP and ran top job with good cement returns to surface. Cement job was finished and nippled up BOP; currently testing BOP. Gas: 0 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: 40% Sand: black, light-gray, translucent, white to cream, fine grained, silty, poorly sorted, unconsolidated, occasional sandstone, sub angular, firm to hard; 60% Siltstone: light gray-gray, soft-firm, silty, non-calcareous, trace black lithic. 04/11/2015 Finished testing BOP and testing casing and started to pick up singles and racked back drill pipe for intermediate section; currently picking up BHA with tools and motor. Gas: 0 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: 40% Sand: black, light-gray, translucent, white to cream, fine grained, silty, poorly sorted, unconsolidated, occasional sandstone, sub angular, firm to hard; 60% Siltstone: light gray-gray, soft-firm, silty, non-calcareous, trace black lithic. 04/12/2015 Picked up and made up BHA. Drilling ahead in the intermediate section w/ current hole depth of 3150' MD. Gas: 84 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: 60% Sandstone: white, translucent to clear, gray to black, earthy texture, sub- rounded, sub angular, medium grained, unconsolidated, abundant Glauconite. 20% Siltstone: light gray to gray, brown, soft-firm, shaly to silty, non-calcareous, occasional black lithic, argillaceous mixture 20% Coal. 04/13/2015 Current hole depth is 4190’ MD with a bit depth of 3628’ MD. Fluid losses were encountered at 3765' of 45 bbls. Drilled to 4190' MD, circulated and built mud volume. Reamed out of hole to 3062' MD and built and pumped walnut sweep to clean out BHA. Formation gas has been approximately 100 units. Gas: 557 gas units Fluids: There was 843 barrels of water based mud lost down hole. Geology: 60% Sand: black, light gray-gray, translucent-white-cream, green, fine grained, silty, poorly sorted, unconsolidated, sub angular, firm-hard, trace consolidated sandstone 30% Siltstone: light gray to gray, brown, soft-firm, shaly to silty, non-calcareous, occasional black lithic, argillaceous mixture 10% Coal 04/14/2015 Pumped walnut sweep to clean BHA and then started to drill ahead with losses increasing to 50 barrels bph. Pulled out of the hole for wiper trip at 5198’ MD; the average daily gas while drilling was approximately 140 units. Gas: 768 gas units Fluids: There was 1549 barrels of water based mud lost down hole cumulative. Geology: 90% Sand: black, light gray-gray, translucent-white, fine grained, silty, argillaceous, moderately sorted, unconsolidated, sub angular, firm-hard, trace consolidated sandstone 10% Siltstone: light gray to gray, brown, soft-firm, silty, non-calcareous, occasional black lithic, argillaceous mixture 04/15/2015 Drilled ahead to 6181' MD and then pumped a high-vis sweep and circulated the hole clean. Gas has been approximately 50 units. Gas: 729 gas units Fluids: There was 578 barrels of water based mud lost down hole cumulative. Geology 80% Siltstone: light gray to gray, brown, soft-firm, silty, non-calcareous, occasional black lithic, argillaceous mixture 10% Sand: black, light gray-gray, translucent-white, fine grained, silty, argillaceous, moderately sorted, unconsolidated, sub angular, firm-hard, trace Coal, 10% Clay 04/16/2015 Ran Wiper trip and had tight spots. POOH to 1468' MD and conducted a rig service. RIH and drilled ahead. Current bit depth of 6585’ MD. Gas units were around 20-40 units. Gas: 729 gas units Fluids: There was 130 barrels of water based mud lost down hole. Geology 70% Siltstone: light gray to gray, light brown, soft-firm, bulky, earthy, amorphous, non- calcareous, occasional black lithic, 30% Sand: light gray-gray, translucent-white, fine grained, silty, poorly sorted, consolidated sandstone, cemented, sub rounded, firm-hard, occasional Coal, 04/17/2015 Drilled ahead to 6,760' MD and then pumped a sweep. Continued drilling to 7174' MD and pumped another sweep and circulated hole clean. Wiper tripped to 5,559' MD and ran a rig service. Currently TIH w/ a hole depth of 7174' MD. Gas units are approximately 30 units. Gas: 440 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: 90% Siltstone: light gray to gray, light brown, soft-firm, bulky, earthy, amorphous, non-calcareous, occasional black lithic, 10% Coal, 04/18/2015 Drilled ahead to 7,212' MD and pumped a sweep and then continued to drill ahead to 7,547' and pumped another sweep. Currently drilling ahead with a bit depth of 7,855' MD; gas is approximately 40 units. Gas: 1115 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: 60% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non- calcareous, argillaceous, abundant black lithic, 30% Sand: light gray-gray, translucent-white, fine grained, silty, moderately well sorted, unconsolidated, sub-rounded, firm-hard 10% Coal, 04/19/2015 Drilled ahead to an Intermediate TD of 8,028' MD and then pumped a sweep and began wiper trip. Washed and reamed to 5,040’ MD and tripped in the hole. Once back on the bottom, gas reached 9,522 units and decision was made to weigh up mud to a 9.9 ppg. Current background gas is approximately 150 units. Gas: 9522 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: 90% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non- calcareous, argillaceous, abundant black lithic, 10% Coal, 04/20/2015 Pulled out of the hole from 6050' with BHA and then rigged up for wireline. Ran in to the hole and are currently logging with wireline logs. Sample catcher left site yesterday. Gas: N/A Fluids: There was 0 barrels of water based mud lost down hole. Geology: 90% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non- calcareous, argillaceous, abundant black lithic, 10% Coal, 04/21/2015 Slipped and cut drill line. Continued to wash and ream down through tight spots from 6,520' to bottom of hole. Pumped sweep and circulating shakers clean; currently preparing to pull out of the hole. Gas: 4920 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: 90% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non- calcareous, argillaceous, abundant black lithic, 10% Coal, 04/22/2015 Pulled out of the hole and rigged up for casing run. Currently running casing with a bit depth of 1,645' MD. Gas: 81 gas units Fluids: There was 0 barrels of water based mud lost down hole. Geology: 90% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non- calcareous, argillaceous, abundant black lithic, 10% Coal, 04/23/2015 Ran 7 5/8" casing down hole and then attempted to circulate bottoms up. All returns were lost at 4,053' MD. Filled backside every 5 joints and landed hanger but could not establish circulation. Decision was made to pump cement job. Rigged up test equipment and currently testing BOPE. Gas: N/A Fluids: There was 1191 barrels of water based mud lost down hole. Geology: 90% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non- calcareous, argillaceous, abundant black lithic, 10% Coal, 04/24/2015 Tested BOPE and ran into the hole to 2,992' MD. Picked up singles of drill pipe from 2,992'- 4,765' MD and then continued run into the hole to 7,871' MD and tested casing at 3500 psi. Currently running in the hole to bottom with a hole depth of 8,028' MD. Gas: 9u Fluids: There was 0 barrels of water based mud lost down hole. Geology: 90% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non- calcareous, argillaceous, abundant black lithic, 10% Coal, 04/25/2015 Running into the hole and drilled 20' to 8,048' MD. Circulated and FIT tested. Currently drilling ahead with a hole depth of 8,795' MD. Background gas is approximately 100-200 units with a max gas of 8624 units at the 8,613' connection. Gas: 8624u Fluids: There was 0 barrels of water based mud lost down hole. Geology: 60% Sand: clear-translucent, gray-black, unconsolidated, silty, very fine to fine grained, sub angular to sub rounded, sucrosic, moderately sorted, trace Glauconite 20% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non-calcareous, argillaceous, abundant black lithic, 20% Coal, 04/26/2015 Drilled ahead to 8,984' MD and increased MW to 10.5 ppg to decrease background gas. Gas didn't drop and decision was made to slowly drill to 9,107' MD while weighing up mud to 10.9 ppg. Gas maxed at 9,714 units. Ran wiper trip to 8,172' MD and flow went from 31-63% so the well was shut in. Circulated gas through choke and weighing up mud to 11.1 ppg. Continued circulating until background gas dropped. Ran into the hole to bottom and continued drilling ahead. Current hole depth is 9,176' MD with background gas of approximately 90 units. Gas: 9714u Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: clear-translucent, gray-black, consolidated, silty, very fine to fine grained, sub rounded, moderately sorted 80% Siltstone: light gray to gray, brown, soft-firm, earthy, amorphous, cemented, non-calcareous, abundant black lithic, 10% Coal, 04/27/2015 Continued drilling ahead to 9,200' MD and performed a rig service to repair mud saver on the top drive. Currently drilling ahead with a bit depth of 10,035' MD; background gas is approximately 40 units and a 24 hour max of 9,885 units. Gas: 9885u Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal, 04/28/2015 TD'd the well @ 10,200' MD. Circulated, pumped high vis sweep, and weighed up mud weight to 11.4 ppg. Pulled out of the hole to 8,156' MD then washed and reamed to 8,012' MD. Background gas while tripping began rising to a max gas of 2952 units. Circulated bottoms up and monitored well while building weighed well cap. Pulled out of the hole and conducted a flow check but no flow. Decision was made to monitor well. Gas: 9480u Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal, 04/29/2015 Monitored well for gas and rigged up wire line to run CBL logs. Run into hole to 7,890' MD and circulated. Current background gas is 60 units with a max trip gas of 820 units. Gas: 820u Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal, 04/30/2015 Finished circulated bottoms up at shoe. Slip and cut drill line and continued rig in hole. At 9,150' MD began circulating well and flow went from 25% to 56%, shut in well. Gas went from 200 units to 4084 units within 3 minutes. Circulated gas out through choke and opened well to monitor. Pumped and reamed from 9,150' to bottom of hole. Began picking up out of hole to 7,994' MD and had gas reach 9579 units. Continued to circulate until gas dropped out and continued picking up out of hole. Gas: 9579u Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal, 05/01/2015 Picked up out of hole to 3,102' MD and the well starting flowing. Shut down well and tried to circulate on well but couldn’t pump by mud dog wiper. Ran up wireline and fished out mud dog wiper. Circulated gas out that reached 1591 units. Weighted up mud to 13 ppg and continued to lay down drill pipe. Currently testing blow out preventers. Gas: 1591u Fluids: There was 10 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal, 05/02/2015 Ran in hole with 5" casing to 5061' MD and the circulated bottoms up. Continued tripping in the hole to 7,825' MD and gas chromatograph needed to be replaced and recalibrated. Max gas was 8,565 units at this time. Gas chromatograph is now working properly. Ran in hole to bottom of hole with casing liner and circulated. Gas reached 4,865 units. Continued to circulate and build mud. Currently rigging up cementers. Gas: 8565u Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal, 05/03/2015 Finished rigging up cementers and began cementing but were unable to establish returns to the surface. Decision was made to drill out plugs and cement. Tested BOP. Currently running in hole. Mudloggers are standing by. Gas: N/A Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal, 05/04/2015 Ran in hole with a 2 7/8" clean out assembly to 3,740' MD and began seeing cement at shakers. Washed and reamed to 4,589' MD. Pick up and milling ahead with a current bit depth of 5114' MD. No gas being monitored while milling through cased hole. Mudloggers are on standby. Gas: N/A Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal, 05/05/2015 Milled ahead to 5,578' MD and decision was made to POOH. At 2,738' MD gas bubbles began breaking out of the water on the rig floor. The gas equipment was turned on and had a high of 168u. The gas leak was identified as it was coming from the pack off. After troubleshooting lock downs were tightened and pressure was established. Currently continuing to POOH with a bit depth of 316' MD. SDL was released shortly after while cement was being drilled out. Gas: N/A Fluids: There was 0 barrels of water based mud lost down hole. Geology: 10% Sand: white, clear-translucent, consolidated, silty cemented, fine grained, sub angular to sub rounded, moderately sorted, black laminations 90% Siltstone: light gray, brown, soft-firm, earthy, amorphous, waxy, argillaceous mixture, occasional black lithics, 10% Coal 05/16/2015 SDL was brought back onto location to monitor gas and fluids. Drilled ahead to 10,098' and circulated bottoms up; no rubber seen. Displaced the wellbore to 11.7 pounds per gallon drilling mud and continued drilling cement to 10,104'. Washed down to 10,186' and tagged shoe. Circulated bottoms up, closed bags, and lined up to pump through drill string back up through the IA and choke lines to the degasser to try and establish communication with the well and keep background gas down with 11.7+ pounds per gallon mud. Communications were established Gas: 3178u Fluids: There was 0 barrels of water based mud lost down hole. 05/17/2015 Continued circulating and monitoring the well, Conducted 30 minute flow-check; no flow, and Circulated bottoms up: max 244 units gas. Decision was made to pull out of the hole and run in hole with e-line for a 4" gauge run. Pulled back out of the hole, made up 5' retainer plug, and then ran back in hole to 10,065'. Set plug, pulled out of hole and rigged down e-line. Making up pack off assembly at time of report Fluids: There was 0 barrels of water based mud lost down hole. 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 0 5 10 15 20 25 30 35 Me a s u r e d D e p t h Rig Days Prognosed Actual WELL NAME: KBU 22-06Y OPERATOR: Hilcorp Alaska, LLC MUD CO: RIG: Saxon 169 SPERRY JOB: AK-AM-0902299672 Days vs. Depth 04 April 2013 Sperry SDL Arrived on Location LOCATION: Kenai Gas Field AREA: Kenai Peninsula Borough STATE: Alaska SPUD: 04/07/2015 TD: WELL NAME: KBU 22-06Y OPERATOR: Hilcorp Alaska, LLC MUD CO: Baroid RIG: Saxon 169 SPERRY JOB: AK-XX-0902299672 Days vs. Depth 07 April 2015 Sperry SDL Arrived on Location LOCATION: Kenai Beluga Unit AREA: Kenai Peninsula Borough STATE: Alaska SPUD: 7-Apr-2015 TD: 28-Apr-2015 Landed 7.625" Casing 8012' MD, 7657' TVD 24 April 2015 POOH Wiper Trip 26 April 2015 Commenced 13.5" Surface Hole Section On Bot: 18:19 07 April 2015 TD Surface Hole Section 1530' MD, 1530' TVD Off Bot: 14:57 08 April 2015 Landed 10.75" Casing 1499' MD, 1499' TVD 09 April 2015 Commenced 9.825" Intermediate Hole Section On Bot: 07:02 12 April 2015 POOH Wiper Trip 16 April 2015 TD Intermediate Hole Section 8028' MD, 7658' TVD Off Bot: 05:53 19 April 2015 Commenced 6.75" Production Hole Section On Bot: 04:48 25 April 2015 TD Production Hole Section 10200' MD, 9697' TVD Off Bot: 05:24 28 April 2015 Landed 5" Casing 10186' MD, 9685' TVD 02 May 2015 WELL NAME:LOCATION:Kenai Beluga Unit OPERATOR:AREA:Kenai Peninsula Borough SPERRY JOB:STATE:Alaska RIG:Saxon 169 HOLE SECTION Intermediate EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 Hilcorp Alaska, LLC AK-XX-09012299672 Autumn Gould 13-Apr-2015 KBU 22-06Y What went as, or better than, planned: The first difficulty experienced was that the company man forgot to call us out to the rig so we arrived with very little time to rig up before drilling. This caused us to not start collecting data until 350' MD. The next problem to occur was our gas trap assembly failed and became completely unusable. There was no backup gas trap assembly on location. The vibration caused the bolt hangers to fall off the welding seam, making the canister completely useless. A new assembly was sent from Anchorage, but the section had already TD'd by the time it got to location. No gas data was collected for the entire section. Recommendations: Innovations and/or cost savings: Despite the initial hardship with rigging up and the gas trap assembly failure, everything else ran smoothly. Difficulties experienced: Always have a backup gas trap assembly on location. Put different latches on to the gas trap assembly which latch tighter and not vibrate apart. N/A Surface Data Logging After Action Review WELL NAME:LOCATION:Kenai Beluga Unit OPERATOR:AREA:Kenai Peninsula Borough SPERRY JOB:STATE:Alaska RIG:Saxon 169 HOLE SECTION Intermediate EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 What went as, or better than, planned: We have had an issue with the clocks randomly changing on the computers. There doesn’t seem to be any consistency on what day it happens on. We also had an agitator blade break off its threads into the brass piece attached to the motor. We were able to switch out this piece quickly and minimal data was lost. The motorman was able to help us remove the broken threads so we can reuse the brass piece in the future. Recommendations: Innovations and/or cost savings: Everything went smoothly; there were minimal issues with the gas equipment and Insite. Difficulties experienced: Always have backup pieces for the gas trap on location so they can be changed out in a timely fashion. N/A Hilcorp Alaska, LLC AK-XX-09012299672 Autumn Gould 20-Apr-2015 KBU 22-06Y Surface Data Logging After Action Review WELL NAME:LOCATION:Kenai Beluga Unit OPERATOR:AREA:Kenai Peninsula Borough SPERRY JOB:STATE:Alaska RIG:Saxon 169 HOLE SECTION Production EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 Hilcorp Alaska, LLC AK-XX-09012299672 Autumn Gould 28-Apr-2015 KBU 22-06Y What went as, or better than, planned: We are still experiencing difficulties with the clocks jumping around on the computers. Halliburton IT has been contacting and is helping to fix the issue. Recommendations: Innovations and/or cost savings: Everything went smoothly; all of our equipment worked flawlessly during this section. Difficulties experienced: Keep a close eye on the clocks so that minimal data is lost; it is easy to fix the clocks if it is caught right away. N/A Surface Data Logging After Action Review KBU 22-06Y Hilcorp Alaska LLC Baroid Saxon 169 AK-XX-0902299672 Date Depth Wt Vis PV YP Gels Filt R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Sd Pm pH MBT Pf/Mf Chlor Hard ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%%ppb Eqv mg/l Ca++ 7-Apr 407 9.00 120 30 42 13/35/44 9.2 102/72/59/43/20/16 2/0 4.7 0/95.1 1.50 0.30 9.3 116.0 .15/.45 450 -Drilling Surface interval 8-Apr 1530 8.95 52 21 18 5/9/13 9.5 60/39/31/20/6/5 2/0 4.6 0/95.2 0.35 0.05 8.4 16.0 .1/.45 300 20 R/U to run Surface casing 9-Apr 1530 8.95 49 18 11 3/5/9 9.5 47/29/22/14/4/3 2/0 4.6 0/95.2 0.35 -8.0 16.0 .05/.35 300 20 N/D Stack and N/U BOPs 10-Apr 1530 9.15 39 39 12 3/5/6 7.0 22/17/14/10/3/2 1/2 3.0 0/93.9 0.10 0.55 9.7 2.0 .5/3.2 36000 80 Testing BOPs 11-Apr 1530 9.30 38 7 10 3/5/7 7.4 24/17/15/11/4/3 1/2 4.6 0/93 0.10 0.45 9.5 2.8 .5/3.2 29500 80 Changing Drill Line 12-Apr 2942 9.25 55 11 19 6/8/10 4.9 41/30/25/18/7/5 1/2 4.4 0/93.1 0.35 0.95 9.9 2.0 .9/3.3 30500 100 Drilling Intermediate section 13-Apr 4190 9.15 58 12 17 4/5/7 4.0 41/29/23/16/4/3 1/2 3.8 0/93.9 0.15 0.40 9.2 2.0 .25/1.2 28500 160 RIH Wiper Trip 14-Apr 5189 9.35 56 13 16 4/6/8 3.6 42/29/23/16/5/4 1/2 5.0 0/92.4 0.35 0.20 9.1 2.0 .15/.85 32500 200 Wiper Trip 15-Apr 6120 9.40 60 15 20 5/8/10 3.5 50/35/28/19/6/4 1/2 5.4 0/92 0.15 0.30 9.1 2.0 .1/.8 32500 100 Circulating Sweep 16-Apr 6568 9.50 58 15 20 6/8/12 3.4 50/35/29/20/6/5 1/2 6.3 0/91.2 0.25 0.30 8.9 2.8 .2/.85 31000 160 Drilling Intermediate section 17-Apr 7174 9.35 48 13 19 6/9/14 3.6 45/32/27/19/6/4 1/2 5.2 0.2/92.2 0.10 0.30 9.2 2.8 .15/.9 30500 60 RIH Wiper Trip 18-Apr 7810 9.45 50 13 19 4/8/12 3.8 45/32/26/18/5/4 1/2 6.1 0./91.3 0.10 0.30 9.3 3.0 .2/1.1 29500 100 Drilling Intermediate section 19-Apr 8028 9.50 55 13 20 5/9/16 3.8 46/33/27/19/6/4 1/2 6.2 0.1/91.2 0.10 0.60 10.2 3.5 .4/1.2 31000 160 Circulate and condition mud 20-Apr 8028 9.90 53 15 20 6/10/16 3.6 50/35/29/21/6/5 1/2 7.9 0.1/89.7 0.10 0.60 10.0 3.8 .3/1.25 29500 60 RIH with E-line RFT Log 21-Apr 8028 9.90 48 13 18 5/9/15 3.9 44/31/26/18/5/4 1/2 8.1 0/89.5 0.10 0.60 9.9 3.8 .45/1.3 31000 40 Circulate and condition mud 22-Apr 8028 9.95 54 14 19 6/10/16 3.9 47/33/27/19/6/4 1/2 8.3 0/89.3 0.10 0.30 9.2 4.0 .25/1.4 31000 60 RIH with Intermediate casing 23-Apr 8028 9.85 48 10 16 5/7/9 4.6 36/26/21/15/5/4 1/2 6.6 0/91.1 0.10 0.10 7.2 2.0 .05/1.7 28500 260 Testing BOPs 24-Apr 8028 9.95 45 9 17 7/9/11 5.4 35/26/22/16/7/5 1/2 6.4 0/91.1 0.10 0.05 7.2 1.8 0/1 31000 240 RIH to drill out cement 25-Apr 8749 10.10 49 12 18 6/8/11 5.0 42/30/25/19/7/5 1/2 6.8 0/90.7 0.15 0.30 9.6 1.8 .25/1.8 31000 100 Drilling Production section 26-Apr 9122 11.10 53 16 19 5/7/10 4.8 51/35/28/20/6/5 1/2 10.3 0/87.3 0.30 0.55 9.7 3.0 .4/2 31000 80 Drilling Production section 27-Apr 9933 11.20 46 19 19 4/6/9 4.0 57/38/31/22/5/4 1/2 11.6 0/86 0.15 0.70 9.6 3.0 .6/3.1 32000 60 Drilling Production section 28-Apr 10200 11.45 47 19 20 4/6/10 3.9 58/39/31/21/5/3 1/2 12.9 0/84.8 0.10 0.35 8.9 3.8 .25/2.8 31500 100 TOOH 29-Apr 10200 11.39 56 17 20 4/7/10 4.0 54/37/29/20/5/3 1/2 12.6 0/85.0 0.10 0.90 10.1 4.0 .75/3.1 33000 80 Circulate and condition mud 30-Apr 10200 11.40 46 13 16 4/5/7 4.7 42/29/23/16/4/3 1/2 13.1 0/84.8 0.10 1.20 9.8 4.5 .95/4.5 29000 80 POOH sideways 1-May 10200 13.10 50 21 21 4/7/11 4.9 63/42/33/23/5/4 1/2 19.8 0/78.3 0.10 1.60 10.0 4.5 1.2/5.5 28500 60 Testing BOPs 2-May 10200 11.75 46 15 18 4/6/10 5.1 48/33/26/18/4/3 1/2 14.3 0/83.6 0.10 1.40 9.7 4.3 1.1/6 29000 80 R/U cementers and circulate 3-May 10200 8.40 27 ---------------RIH w/ work string 4-May 10200 8.40 26 ---------------Drill cement out of casing 5-May 10200 8.40 26 ----------10.8 --200 1800 POOH 16-May 10200 11.75 50 16 16 4/9/12 7.3 48.0/32.0/26.0/18.0 1/0 14.3 0/84.3 0.10 0.40 9.2 43.0 0.25/3.00 30000 160 Circulate and condition mud 17-May 10200 11.9 50 15 17 4/7/2010 6.4 47.0/32.0/26.0/18.0 Jan-00 15.2 0/83.6 0.10 0.65 9.6 4.5 0.50/5.00 24500 160 R/U pack off assembly Casing Record WELL NAME:LOCATION:Kenai Beluga Unit OPERATOR:AREA:Kenai Peninsula Borough MUD CO:STATE:Alaska RIG:SPUD:7-Apr-2015 SPERRY JOB:TD:28-Apr-2015 Remarks 16" Conductor @ 130' MD, 130' TVD 10.75" Casing @ 1499' MD, 1499'TVD 7.625" Casing @ 8012' MD, 7657'TVD W a t e r a n d O i l B a s e d M u d R e c o r d BHA#SDL RUN #Bit #Bit Type Bit Size Depth In Depth Out Footage Bit Hours TFA AVG ROP WOB (max) RPM (max) SPP (max) FLOW GPM (max)Bit Grade Comments 1 1 1 Varel DT1GJMRS 13.5"130'1530'1400'18.00 0.739 129.0 12 80 1540 480 1-1-WT-A-E-I-NO-TD TD Surface Hole Section 2 2 2 HDBS MM65 PDC 9.875"1530'8030'6500'149.00 0.778 69.0 10 80 2390 500 1-3-CT-G-X-IN-LM-TD TD Internediate Hole Section 4 3 3 Varel V613 PDUX 6.75"8030'10200'2188'70.89 0.460 53.0 10 90 2880 305 1-2-CT-T-X-I-NO-TD TD Production Hole Section Alaska RIG:Saxon 169 SPUD:7-Apr-2015 WELL NAME:KBU 22-06Y LOCATION:Kenai Beluga Unit OPERATOR:Hilcorp Alaska LLC AREA:Kenai Peninsula Borough MUD CO: SPERRY JOB:AK-XX-0902299672 TD:28-Apr-2015 Baroid STATE: B i t R e c o r d . . * 24 hr Recap:Spud well and drilling ahead in surfaces section. Zero gas units Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 450 - 7-Apr-2015 23:59 Current Pump & Flow Data: 1200 Max ROP ROP (ft/hr) 3.07 @ Mud Data Depth Morning Report Report # 1 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 4.7 13.5 9.00 Tricone 9.00 Size 2 Geology: 0 Fluids: 0 Max Gas: 0 100% Gas In Air=10,000 Units-Connection - Tools N/A API FL Chromatograph (ppm) -0' - WOB N/A9.20 Avg Min Comments RPM ECD (ppg) ml/30min 0Background (max)Trip Average - Mud Type Lst Type - Spud 9.2407'42 Depth in / out YP (lb/100ft2) 9.30 --- -- CementChtSd C-4i C-4n 24 hr Max Weight - Hours C-3 Sst (ppb Eq) C-1 C-5i - N/A N/A Drilling Surface PV - Footage - S, Barber/ D. Yessak ShClyst TuffGvlCoal cP 30 Gas Summary - -- (current) Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) N/A 405' 405' Max @ ft Current -60.0 Date: Time: 0 in 0 -Minimum Depth C-5n - 80.0 C-2 0 SPP (psi) Gallons/stroke TFABit Type Depth 16.0120 MBT - pH 0.739 - - - Siltst 243 83 Units* Casing Summary Lithology (%) -- - 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize Grade (max)(current) - - Cly - . . * 24 hr Recap:Drilled surface hole to a depth of 1530' MD. Ran pump sweeps and circulated hole clean. Began rigging up casing Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 300 - 8-Apr-2015 23:59 Current Pump & Flow Data: - Max ROP ROP (ft/hr) -@ Mud Data Depth Morning Report Report # 2 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 4.6 13.5 8.95 Tricone 8.95 Size 2 Geology: 40% Sand, 60% Siltstone Fluids: 0 Max Gas: 0 100% Gas In Air=10,000 Units-Connection - Tools N/A API FL Chromatograph (ppm) -0' - WOB N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min N/ABackground (max)Trip Average - Mud Type Lst Type - Spud 9.51530'18 Depth in / out YP (lb/100ft2) 8.40 --- -- CementChtSd C-4i C-4n 24 hr Max Weight - Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Rig up casing PV - Footage - S. Barber/ D. Yessak ShClyst TuffGvlCoal cP 21 Gas Summary - -- (current) Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: 308.0 Flow In (gpm) Flow In (spm) 405' 1530' 1125' Max @ ft Current 444'155.0 Date: Time: equipment. Gas equipment failure, now running and fixed. N/A in N/A -Minimum Depth C-5n - - C-2 N/A SPP (psi) Gallons/stroke TFABit Type Depth 16.052 MBT - pH 0.739 - - - Siltst - - Units* Casing Summary Lithology (%) - 60 - - 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize Grade (max)(current) - - Cly - 40 . . * 24 hr Recap: (max)(current) - - Cly - 40 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 60 - - - - Units* Casing Summary Lithology (%) - MBT - pH 0.739 - - - Siltst SPP (psi) Gallons/stroke TFABit Type Depth 16.049 C-5n - - C-2 N/A in N/A -Minimum Depth Time: plug without seeing cement to surface. N/D stack and N/U BOP to finish getting cement to surface. Currently N/U BOP. N/A 1530' 1530' 0' Max @ ft Current -- Date: Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Gas Summary - -- (current) S. Barber/ D. Yessak ShClyst TuffGvlCoal cP 18 - Footage - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A N/U BOP PV 24 hr Max Weight - Hours C-3 -- CementChtSd C-4i C-4n YP (lb/100ft2) 8.00 --- - Spud 9.51530'11 Depth in / out Mud Type Lst Type Average -N/ABackground (max)Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools N/A API FL Chromatograph (ppm) -0' - WOB Surface Casing 100% Gas In Air=10,000 Units-Connection - 2 Geology: 40% Sand, 60% Siltstone Fluids: 0 Max Gas: 0 1530' Condition - Bit # 1 4.6 13.5 8.95 Tricone 8.95 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 3 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field ROP ROP (ft/hr) -@ Mud Data Depth 9-Apr-2015 23:59 Current Pump & Flow Data: - Max - Chlorides mg/l 300 R/U surface casing and ran 10.75" casing T/1499' MD. R/ U cement and pressure test lines T/3500 psi. Bumped Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:N/U BOP and ran top job with good cement returns to surface. Finished cement job and N/U BOP. Currently Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 36000 - 10-Apr-2015 23:59 Current Pump & Flow Data: - Max ROP ROP (ft/hr) -@ Mud Data Depth Morning Report Report # 4 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 3.1 13.5 9.15 Tricone 9.15 Size 2 Geology: 40% Sand, 60% Siltstone Fluids: 0 Max Gas: 0 1530' 100% Gas In Air=10,000 Units-Connection - Tools N/A API FL Chromatograph (ppm) -0' - WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min N/ABackground (max)Trip Average - Mud Type Lst Type - KCI/Polymer 7.01530'12 Depth in / out YP (lb/100ft2) 9.70 --- -- CementChtSd C-4i C-4n 24 hr Max Weight - Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A BOP testing PV - Footage - S. Barber/ D. Yessak ShClyst TuffGvlCoal cP 5 Gas Summary - -- (current) Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 1530' 1530' 0' Max @ ft Current -- Date: Time: testing BOP to TIH and drill intermediate section. N/A in N/A -Minimum Depth C-5n - - C-2 N/A SPP (psi) Gallons/stroke TFABit Type Depth 2.039 MBT - pH 0.739 - - - Siltst - - Units* Casing Summary Lithology (%) - 60 - - 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) - - Cly - 40 . . * 24 hr Recap:P/U singles back in hole with drill pipe. POOH stand in derrick. P/U and M/U BHA. Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 29500 - 11-Apr-2015 23:59 Current Pump & Flow Data: - Max - ROP ROP (ft/hr) -@ Mud Data Depth Morning Report Report # 5 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 4.6 13.5 9.30 Tricone 9.30 Size 2 Geology: 40% Sand, 60% Siltstone Fluids: 0 Max Gas: 0 1530' 100% Gas In Air=10,000 Units-Connection - Tools N/A API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min N/ABackground (max)Trip Average - Mud Type Lst Type - - PDC KCI/Polymer 7.4 1530' 1530'10 - Depth in / out YP (lb/100ft2) 9.50 --- -- CementChtSd C-4i C-4n 24 hr Max Weight - Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A M/U BHA and TIH PV 1530' 6 - Footage -- - S. Barber/ D. Yessak ShClyst TuffGvlCoal cP 7 Gas Summary - -- (current) Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 1530' 1530' 0' Max @ ft Current -- Date: Time: N/A in N/A -Minimum Depth C-5n - - C-2 N/A SPP (psi) Gallons/stroke TFABit Type Depth 2.838 MBT - pH 0.739 - - - Siltst - - Units* Casing Summary Lithology (%) - 60 - - 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) - - Cly - 40 . . * 24 hr Recap: (max)(current) 0 0 Cly 15621 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 20 1721 0 492 170 Units* Casing Summary Lithology (%) 0 MBT - pH 0.739 0 0 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 2.055 C-5n 1533' 186.0 C-2 84 in 0 3020'Minimum Depth Time: 17 1530' 3145' 1615' Max @ ft Current 2527'187.0 Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 309.0 Flow In (gpm) Flow In (spm) Gas Summary 0 0 0 (current) S. Barber/ D. Yessak ShClyst 20 TuffGvlCoal cP 11 1530' 6 0..778 Footage -- - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Drilling Ahead PV 24 hr Max Weight 0 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 9.90 000 233 - PDC KCI/Polymer 4.9 1530' 2942'19 - Depth in / out Mud Type Lst 60 Type Average 10Background (max)Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 Units77Connection 0 2 Geology: 60% Sandstone, 20% Siltstone, 20% Coal Fluids: 0 Max Gas: 84u 1530' Condition - Bit # 1 4.4 13.5 9.25 Tricone 9.25 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 6 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) 2.94 @ Mud Data Depth 12-Apr-2015 23:59 Current Pump & Flow Data: 1300 Max 0 Chlorides mg/l 30500 P/U and M/U BHA. Drilling ahead w/ current hole depth of 3150' MD. Gas around 15 units on average. Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: (max)(current) 47 0 Cly 72040 60 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 30 16677 4259 451 154 Units* Casing Summary Lithology (%) 0 MBT - pH 0.739 0 0 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 2.058 C-5n 3994' 0.0 C-2 557 in 4 3205'Minimum Depth Time: hole to 3062' MD. Build and pump walnut sweep to clean BHA. Formation gas has been around 100 units. 128 3145' 4190' 1045' Max @ ft Current 3351'145.0 Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 229.0 Flow In (gpm) Flow In (spm) Gas Summary 0 0 0 (current) S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 12 1530' 6 0..778 Footage -- - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Pump Sweep PV 24 hr Max Weight 9 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 9.20 000 233 - PDC KCI/Polymer 4.0 1530' 4190'17 - Depth in / out Mud Type Lst Type Average 2115Background (max)Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 UnitsN/AConnection 0 2 Geology: 60% Sandstone, 20% Siltstone, 20% Coal Fluids: 843 bbls Max Gas: 557u 1530' Condition - Bit # 1 3.8 13.5 9.15 Tricone 9.15 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 7 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) 2.94 @ Mud Data Depth 13-Apr-2015 23:59 Current Pump & Flow Data: 1300 Max 0 Chlorides mg/l 28500 Incountered fluid losses @ 3765' of 45 bbls. Drilled to 4190' MD, circulated and built mud volume. Reamed out of Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Pumped walnut sweep to clean BHA. Drilled ahead with losses increasing to 50 bph. P.O.O.H for wiper trip at Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 32500 0 14-Apr-2015 23:59 Current Pump & Flow Data: 1470 Max - ROP ROP (ft/hr) 2.94 @ Mud Data Depth Morning Report Report # 8 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 5.0 13.5 9.35 Tricone 9.35 Size 2 Geology: 90% Sand, 10% Siltstone Fluids: 1549 bbls lost Max Gas: 768u 1530' 100% Gas In Air=10,000 UnitsN/AConnection 0 Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 15Background (max)Trip Average 11 Mud Type Lst Type 233 - PDC KCI/Polymer 3.6 1530' 5189'16 - Depth in / out YP (lb/100ft2) 9.10 000 00 CementChtSd C-4i C-4n 24 hr Max Weight 11 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Wiper Trip PV 1530' 6 0..778 Footage -- - S. Barber/ D. Yessak ShClyst TuffGvlCoal cP 13 Gas Summary 0 0 0 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 147.0 Flow In (gpm) Flow In (spm) 4190' 5189' 999' Max @ ft Current 4466'84.0 Date: Time: 5198' MD 140 in 2 4843'Minimum Depth C-5n 5169' 0.0 C-2 768 SPP (psi) Gallons/stroke TFABit Type Depth 2.056 MBT - pH 0.739 0 0 0 Siltst 457 156 Units* Casing Summary Lithology (%) 0 10 20393 4175 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) 54 0 Cly 96463 90 . . * 24 hr Recap:Drilled ahead to 6181' MD. Pumping high vis sweep and circulating hole clean. Gas has been around 50 units. Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 32500 0 15-Apr-2015 23:59 Current Pump & Flow Data: 1780 Max - ROP ROP (ft/hr) 2.94 @ Mud Data Depth Morning Report Report # 9 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 5.4 13.5 9.40 Tricone 9.40 Size 2 Geology: 40% Sand, 60% Siltstone Fluids: 578 bbls lost Max Gas: 729u 1530' 100% Gas In Air=10,000 UnitsN/AConnection 0 Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 15Background (max)Trip Average 188 Mud Type Lst Type 233 - PDC KCI/Polymer 3.5 1530' 6120'20 - Depth in / out YP (lb/100ft2) 9.10 000 00 CementChtSd C-4i C-4n 24 hr Max Weight 10 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Pump Sweep PV 1530' 6 0..778 Footage -- - S. Barber/ D. Yessak ShClyst TuffGvlCoal cP 15 Gas Summary 0 0 0 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 150.0 Flow In (gpm) Flow In (spm) 5189' 6181' 992' Max @ ft Current 5595'75.0 Date: Time: 148 in 20 5857'Minimum Depth C-5n 5430' 0.0 C-2 729 SPP (psi) Gallons/stroke TFABit Type Depth 2.060 MBT - pH 0.739 0 0 0 Siltst 475 162 Units* Casing Summary Lithology (%) 0 90 17764 221 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) 45 0 Cly 91005 10 . . * 24 hr Recap: (max)(current) 20 0 Cly 40703 30 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 70 14518 3015 490 167 Units* Casing Summary Lithology (%) 0 MBT - pH 0.739 0 0 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 2.858 C-5n 6391' 10.0 C-2 325 in 14 6187'Minimum Depth Time: current bit depth is 6585' MD. Gas has been around 20-40 units. 107 6181' 6583' 402' Max @ ft Current 6344'73.5 Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 123.0 Flow In (gpm) Flow In (spm) Gas Summary 0 0 0 (current) S. Barber/ D. Yessak ShClyst TuffGvlCoal cP 15 1530' 6 0..778 Footage -- - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Drilling Ahead PV 24 hr Max Weight 8 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 8.90 000 233 - PDC KCI/Polymer 3.4 1530' 6568'20 - Depth in / out Mud Type Lst Type Average 3730Background (max)Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 Units207Connection 6 2 Geology: 30% Sand, 70% Siltstone Fluids: 130 bbls lost Max Gas: 325u 1530' Condition - Bit # 1 6.3 13.5 9.50 Tricone 9.50 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 10 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) 2.94 @ Mud Data Depth 16-Apr-2015 23:59 Current Pump & Flow Data: 1665 Max 0 Chlorides mg/l 31000 Ran Wiper trip and had tight spots. POOH to 1468' MD and conducted a rig service. RIH and drillied ahead. The Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Drilled ahead to 6,760' MD and pumped sweep. Continued drilling to 7174' MD and pumped another sweep and Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 30500 0 17-Apr-2015 23:59 Current Pump & Flow Data: 2060 Max - ROP ROP (ft/hr) 2.94 @ Mud Data Depth Morning Report Report # 11 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 5.2 13.5 9.35 Tricone 9.35 Size 2 Geology: 90% Siltstone, 10% Coal Fluids: 0 bbls lost Max Gas: 440u currently 30 units 1530' 100% Gas In Air=10,000 Units135Connection 7 Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 30Background (max)Trip Average 30 Mud Type Lst Type 233 - PDC KCI/Polymer 3.6 1530' 7174'19 - Depth in / out YP (lb/100ft2) 9.20 000 00 CementChtSd C-4i C-4n 24 hr Max Weight 12 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A TIH PV 1530' 6 0..778 Footage -- - S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 13 Gas Summary 0 0 0 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 145.0 Flow In (gpm) Flow In (spm) 6583' 7174' 591' Max @ ft Current 6818'73.5 Date: Time: circulated hole clean. Wiper tripped to 5,559' MD and ran a rig service. Currently TIH w/ a hole depth of 7174' MD. Gas units 180 in 11 6700'Minimum Depth C-5n 7021' 0.0 C-2 440 SPP (psi) Gallons/stroke TFABit Type Depth 2.848 MBT - pH 0.739 0 0 0 Siltst 513 175 Units* Casing Summary Lithology (%) 0 90 18444 5120 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) 33 0 Cly 54872 . . * 24 hr Recap: (max)(current) 81 0 Cly 137967 30 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 60 36041 134 507 173 Units* Casing Summary Lithology (%) 0 MBT - pH 0.739 0 6 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 3.050 C-5n 7279' 19.9 C-2 1115 in 3 7816'Minimum Depth Time: drilling ahead with a bit depth of 7,855' MD. Gas around 40 units. 293 7174' 7823' 649' Max @ ft Current 7259'68.0 Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 142.0 Flow In (gpm) Flow In (spm) Gas Summary 0 0 0 (current) S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 13 1530' 6 0..778 Footage -- - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Drilling Ahead PV 24 hr Max Weight 21 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 9.30 000 233 - PDC KCI/Polymer 3.8 1530' 7810'19 - Depth in / out Mud Type Lst Type Average N/A37Background (max)Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 UnitsN/AConnection 19 2 Geology: 60% Siltstone, 30% Sand, 10% Coal Fluids: 0 bbls lost Max Gas: 1115u 1530' Condition - Bit # 1 6.1 13.5 9.45 Tricone 9.45 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 12 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) 2.94 @ Mud Data Depth 18-Apr-2015 23:59 Current Pump & Flow Data: 2010 Max 8 Chlorides mg/l 29500 Drilled ahead to 7,212' MD and pumped sweep. Drilled ahead to 7,547' and pumped another sweep. Currently Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Drilled ahead to the Intermediate TD of 8,028' MD. Pumped a sweep and began wiper trip. Washed and reamed to Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 31000 12 19-Apr-2015 23:59 Current Pump & Flow Data: 1776 Max - ROP ROP (ft/hr) 2.94 @ Mud Data Depth Morning Report Report # 13 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 6.2 13.5 9.50 Tricone 9.50 Size 2 Geology: 90% Siltstone,10% Coal Fluids: 0 bbls lost Max Gas: 9522u 1530' 100% Gas In Air=10,000 UnitsN/AConnection 336 Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 215Background (max)Trip Average 9522 Mud Type Lst Type 233 - PDC KCI/Polymer 3.8 1530' 8028'20 - Depth in / out YP (lb/100ft2) 10.20 000 00 CementChtSd C-4i C-4n 24 hr Max Weight 39 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A TIH; Circulate PV 1530' 6 0..778 Footage -- - S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 13 Gas Summary 0 16 0 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 156.0 Flow In (gpm) Flow In (spm) 7823' 8028' 205' Max @ ft Current 8013'82.0 Date: Time: 5,040' MD and TIH. Back on bottom gas reached 9,522 units and decision was made to weight up to a 9.9 ppg MW. 605 in 2 -Minimum Depth C-5n - OFF C-2 9522 SPP (psi) Gallons/stroke TFABit Type Depth 3.555 MBT - pH 0.739 0 57 0 Siltst 413 141 Units* Casing Summary Lithology (%) 0 90 65967 232 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) 594 0 Cly 743109 . . * 24 hr Recap: (max)(current) - - Cly - Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 90 - - N/A N/A Units* Casing Summary Lithology (%) - MBT - pH 0.739 - - - Siltst SPP (psi) Gallons/stroke TFABit Type Depth 3.853 C-5n - N/A C-2 - in --Minimum Depth Time: - 8028' 8028' 0' Max @ ft Current -- Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Gas Summary - -- (current) S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 15 1530' 6 0..778 Footage -- - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Logging w/ wireline PV 24 hr Max Weight - Hours C-3 -- CementChtSd C-4i C-4n YP (lb/100ft2) 10.00 --- 233 - PDC KCI/Polymer 3.6 1530' 8028'20 - Depth in / out Mud Type Lst Type Average --Background (max)Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 Units-Connection - 2 Geology: 90% Siltstone,10% Coal Fluids: 0 bbls lost Max Gas: N/A 1530' Condition - Bit # 1 7.9 13.5 9.89 Tricone 9.89 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 14 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) 2.94 @ Mud Data Depth 20-Apr-2015 23:59 Current Pump & Flow Data: N/A Max - Chlorides mg/l 29500 P.O.O.H. from 6050' with BHA. Prepared and rigged up wireline. Ran in hole and logging with wireline. Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Slipped and cut drill line. Continued to wash and ream down through tight spots from 6,520' to bottom of hole. Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 31000 0 21-Apr-2015 23:59 Current Pump & Flow Data: 1560 Max - ROP ROP (ft/hr) 2.94 @ Mud Data Depth Morning Report Report # 15 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 8.1 13.5 9.90 Tricone 9.90 Size 2 Geology: 90% Siltstone,10% Coal Fluids: 0 bbls lost Max Gas: 4920u 1530' 100% Gas In Air=10,000 UnitsN/AConnection 85 Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 80Background (max)Trip Average 4920 Mud Type Lst Type 233 - PDC KCI/Polymer 3.9 1530' 8028'18 - Depth in / out YP (lb/100ft2) 9.90 000 00 CementChtSd C-4i C-4n 24 hr Max Weight 0 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Pump Sweep/ Circulate out PV 1530' 6 0..778 Footage -- - S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 13 Gas Summary 0 0 0 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 8028' 8028' 0' Max @ ft Current -- Date: Time: Pumped sweep and circulating shakers clean. Currently preparing to POOH. 111 in 1 -Minimum Depth C-5n - N/A C-2 4920 SPP (psi) Gallons/stroke TFABit Type Depth 3.848 MBT - pH 0.739 0 10 0 Siltst 495 169 Units* Casing Summary Lithology (%) 0 90 100 93 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) 235 0 Cly 526030 . . * 24 hr Recap: (max)(current) 0 0 Cly 8679 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 90 0 0 - - Units* Casing Summary Lithology (%) 0 MBT - pH 0.739 0 0 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 4.054 C-5n - N/A C-2 81 in --Minimum Depth Time: - 8028' 8028' 0' Max @ ft Current -- Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Gas Summary 0 0 0 (current) S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 14 1530' 6 0..778 Footage -- - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A TIH w/ Casing PV 24 hr Max Weight 0 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 9.20 000 233 - PDC KCI/Polymer 3.9 1530' 8028'19 - Depth in / out Mud Type Lst Type Average 81N/ABackground (max)Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 UnitsN/AConnection 0 2 Geology: 90% Siltstone,10% Coal Fluids: 0 bbls lost Max Gas: 81u 1530' Condition - Bit # 1 8.3 13.5 9.95 Tricone 9.95 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 16 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) -@ Mud Data Depth 22-Apr-2015 23:59 Current Pump & Flow Data: - Max 0 Chlorides mg/l 31000 POOH and R/U for casing run. Currently running casing with a bit depth of 1,645' MD. Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Ran 7 5/8" casing down hole. Attempted to circulate bottoms up and lost all returns at 4,053' MD. Filled backside Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 28500 - 23-Apr-2015 23:59 Current Pump & Flow Data: - Max - ROP ROP (ft/hr) -@ Mud Data Depth Morning Report Report # 17 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 6.6 13.5 9.85 Tricone 9.85 Size 2 Geology: 90% Siltstone,10% Coal Fluids: 1191 bbls lost Max Gas: 9u and currently testing BOPE. 8013' 1530' 100% Gas In Air=10,000 Units-Connection - Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min -Background (max)Trip Average - Mud Type Lst Type 233 - PDC KCI/Polymer 4.6 1530' 8028'16 - Depth in / out YP (lb/100ft2) 7.20 --- -- CementChtSd C-4i C-4n 24 hr Max Weight - Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Cementing; Test BOPE PV 1530' 6 0..778 Footage -- - S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 10 Gas Summary - -- (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 8028' 8028' 0' Max @ ft Current -- Date: Time: every 5 joints and landed hanger but could not establish circulation. Decision was made to pump cement job. R/U test equipment - in --Minimum Depth C-5n - N/A C-2 - SPP (psi) Gallons/stroke TFABit Type Depth 2.048 MBT - pH 0.739 - - - Siltst 7.63'' - - Units* Casing Summary Lithology (%) - 90 - - 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) Intermediate Casing - - Cly - . . * 24 hr Recap: (max)(current) Intermediate Casing 0 0 Cly 841 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 90 60 36 7.63'' - - Units* Casing Summary Lithology (%) 0 L-80 MBT - pH 0.739 0 0 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 1.845 C-5n - N/A C-2 9 in 1 -Minimum Depth Time: Continued RIH to 7,871' MD and tested casing at 3500 psi. Currently RIH to bottom with a hole depth of 8,028' MD. 2 8028' 8028' 0' Max @ ft Current -- Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Gas Summary 0 0 0 (current) S. Barber/ D. Yessak ShClyst 10 TuffGvlCoal cP 9 1530' 6 0..778 Footage -- - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A TIH to drill production PV 24 hr Max 29.7 Weight 0 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 7.20 000 233 - PDC KCI/Polymer 5.4 1530' 8028'17 - Depth in / out Mud Type Lst Type Average 92Background (max) Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 UnitsN/AConnection 0 2 Geology: 90% Siltstone,10% Coal Fluids: 0 bbls lost Max Gas: 9u 8013' 1530' Condition - Bit # 1 6.4 13.5 9.95 Tricone 9.95 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 18 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) -@ Mud Data Depth 24-Apr-2015 23:59 Current Pump & Flow Data: - Max 0 Chlorides mg/l 31000 Tested BOPE and RIH out of the derrick to 2,992' MD. P/U drill pipe singles for TD from 2,992'-4,765' MD. Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:RIH and drilled 20' to 8,048' MD. Circulated and FIT tested. Currently drilling ahead with a hole depth of 8,795' MD. Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 31000 54 25-Apr-2015 23:59 Current Pump & Flow Data: 2080 Max - ROP ROP (ft/hr) 2.93 @ Mud Data Depth Morning Report Report # 19 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 6.8 13.5 10.10 Tricone 10.10 Size 2 Geology: 60% Sand, 20% Siltstone,20% Coal Fluids: 0 bbls lost Max Gas: 8624u 8013' 1530' 100% Gas In Air=10,000 Units8624Connection 167 Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 100Background (max) Trip Average N/A Mud Type Lst Type 233 - PDC KCI/Polymer 5.0 1530' 8749'18 - Depth in / out YP (lb/100ft2) 9.60 000 00 CementChtSd C-4i C-4n 24 hr Max 29.7 Weight 85 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Drilling ahead PV 1530' 6 0..778 Footage -- - R. Pederson/ L. Tousant ShClyst 20 TuffGvlCoal cP 12 Gas Summary 0 6 0 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 178.0 Flow In (gpm) Flow In (spm) 8028' 8795' 767' Max @ ft Current 8137'79.0 Date: Time: Background gas is around 100-200 units with a max gas of 8624 units at the 8,613' connection. 732 in 2 8452'Minimum Depth C-5n 8613' 87.0 C-2 8624 SPP (psi) Gallons/stroke TFABit Type Depth 1.849 L-80 MBT - pH 0.739 0 27 0 Siltst 7.63'' 293 100 Units* Casing Summary Lithology (%) 9 20 98809 416 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) Intermediate Casing 339 0 Cly 440628 60 . . * 24 hr Recap: (max)(current) Intermediate Casing 834 0 Cly 981604 10 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 80 126749 272 7.63'' 293 100 Units* Casing Summary Lithology (%) 13 L-80 MBT - pH 0.739 0 85 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 3.053 C-5n 9001' 0.0 C-2 9714 in 1 9033'Minimum Depth Time: decision was made to slowly drill to 9,107' MD while weighting up to 10.9 ppg. Gas maxed at 9,714 units. Ran wiper trip to 1214 8795' 9171' 376' Max @ ft Current 8924'66.0 Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 129.0 Flow In (gpm) Flow In (spm) Gas Summary 0 0 0 (current) R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP 16 1530' 6 0..778 Footage -- - Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Drilling ahead PV 24 hr Max 29.7 Weight 125 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 9.70 040 233 - PDC KCI/Polymer 4.8 1530' 9122'19 - Depth in / out Mud Type Lst Type Average 9476150Background (max) Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 Units5874Connection 452 2 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost Max Gas: 9714u with background gas around 90 units. Continued circulating until background gas dropped. RIH to bottom and continued drilling ahead. Current hole depth is 9,176' MD 8,172' MD and flow went from 31-63% so well was shut in. Circulated gas through choke and weighting up mud to 11.1 ppg. 8013' 1530' Condition - Bit # 1 10.3 13.5 11.10 Tricone 11.10 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 20 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) 2.93 @ Mud Data Depth 26-Apr-2015 23:59 Current Pump & Flow Data: 2365 Max 71 Chlorides mg/l 31000 Drilled ahead to 8,984' MD and increase MW to 10.5 ppg to decrease background gas. Gas didn't drop and Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Continued drilling ahead to 9,200' MD and performed a rig service to repair mud saver on the top drive. Currently Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 32000 15 27-Apr-2015 23:59 Current Pump & Flow Data: 2365 Max - ROP ROP (ft/hr) 2.93 @ Mud Data Depth Morning Report Report # 21 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 11.6 13.5 11.20 Tricone 11.20 Size 2 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost Max Gas: 9885u 8013' 1530' 100% Gas In Air=10,000 Units3869Connection 526 Tools Gamma, Resistivity API FL Chromatograph (ppm) 3450 -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 80Background (max)Trip Average N/A Mud Type Lst Type 233 - PDC KCI/Polymer 4.0 1530' 9933'19 - Depth in / out YP (lb/100ft2) 9.60 000 00 CementChtSd C-4i C-4n 24 hr Max 29.7 Weight 28 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Drilling ahead PV 1530' 6 0..778 Footage -- - R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP 19 Gas Summary 0 28 44 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 127.0 Flow In (gpm) Flow In (spm) 9171' 10001' 830' Max @ ft Current 9433'68.0 Date: Time: drilling ahead with a bit depth of 10,035' MD. Background gas around 40 units with a 24 hour max of 9,885 units. 303 in 1 9249'Minimum Depth C-5n 9198' 64.0 C-2 9885 SPP (psi) Gallons/stroke TFABit Type Depth 3.046 L-80 MBT - pH 0.739 0 95 0 Siltst 7.63'' 293 100 Units* Casing Summary Lithology (%) 0 80 25571 89 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) Intermediate Casing 1067 0 Cly 800251 10 . . * 24 hr Recap: 3450 233 -PDC 9.8752 0..778 -1530' (max)(current) Intermediate Casing 1109 0 Cly 785877 10 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 80 36937 60 7.63'' - - Units* Casing Summary Lithology (%) 0 L-80 MBT 10200' pH 0.739 0 74 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 3.847 C-5n - - C-2 9480 in 1 -Minimum Depth Time: 8,156' MD then washed and reamed to 8,012' MD. Background gas while tripping began rising to a max gas of 2952 units. 346 10001' 10200' 199' Max @ ft Current 10058'70.0 Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: 109.0 Flow In (gpm) Flow In (spm) Gas Summary 0 20 24 (current) R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP 19 1530' 6.75 0.460 Footage -2188' - 8012' 6482' Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A POOH; Monitoring well PV 24 hr Max 29.7 Weight 44 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 8.90 000 - - PDC KCI/Polymer 3.9 8012' 10200'20 10200' Depth in / out Mud Type Lst Type Average 94803Background (max) Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 UnitsN/AConnection 493 3 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost Max Gas: 9480u Decision was made to monitor well. Circulated bottoms up and monitored well while building weighted well cap. POOH and conducted a flow check but no flow. 8013' 1530' Condition - Bit # 1 12.9 13.5 11.45 Tricone 11.45 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 22 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) -@ Mud Data Depth 28-Apr-2015 23:59 Current Pump & Flow Data: - Max 12 Chlorides mg/l 31500 TD'd the well @ 10,200' MD. Circulated, pumped high vis sweep, and weighted up to an 11.4 ppg. P.O.O.H. to Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Monitored well for gas and R/U wire line to run CBL logs. RIH to 7,890' MD and currently circulating. Current Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 33000 46 29-Apr-2015 23:59 Current Pump & Flow Data: - Max - ROP ROP (ft/hr) 2.93 @ Mud Data Depth Morning Report Report # 23 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 12.6 13.5 11.39 Tricone 11.39 Size 3 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost Max Gas: 820u 8013' 1530' 100% Gas In Air=10,000 UnitsN/AConnection 58 Tools Gamma, Resistivity API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 692Background (max) Trip Average 820 Mud Type Lst Type - - PDC KCI/Polymer 4.0 8012' 10200'20 10200' Depth in / out YP (lb/100ft2) 10.10 000 00 CementChtSd C-4i C-4n 24 hr Max 29.7 Weight 101 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A RIH; Circulate PV 1530' 6.75 0.460 Footage -2188' - 8012' 6482' R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP 17 Gas Summary 0 0 0 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 10200' 10200' 0' Max @ ft Current -- Date: Time: background gas is 60 units with a max trip gas of 820 units. 81 in 1 -Minimum Depth C-5n - - C-2 820 SPP (psi) Gallons/stroke TFABit Type Depth 4.056 L-80 MBT 10200' pH 0.739 0 9 0 Siltst 7.63'' 135 46 Units* Casing Summary Lithology (%) 7 80 71352 48 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) Intermediate Casing 137 0 Cly 114746 10 3450 233 -PDC 9.8752 0..778 -1530' . . * 24 hr Recap: 3450 233 -PDC 9.8752 0..778 -1530' (max)(current) Intermediate Casing 1939 0 Cly 785642 10 Set AtSize 45.5 L-80 Grade 10.75'' 907-283-1309Unit Phone: 14 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 80 713191 64 7.63'' - - Units* Casing Summary Lithology (%) 106 L-80 MBT 10200' pH 0.739 0 230 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 4.546 C-5n - - C-2 9579 in 1 -Minimum Depth Time: from 25% to 56% and shut in well. Gas went from 200 units to 4084 units within 3 minutes. Circulated gas out through choke and 907 10200' 10200' 0' Max @ ft Current -- Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Gas Summary 0 69 97 (current) R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP 13 1530' 6.75 0.460 Footage -2188' - 8012' 6482' Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A POOH PV 24 hr Max 29.7 Weight 1038 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 9.80 02737 - - PDC KCI/Polymer 4.7 8012' 10200'16 10200' Depth in / out Mud Type Lst Type Average 95793Background (max) Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 UnitsN/AConnection 1182 3 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost Max Gas: 9579u gas of 15 units. 9579 units. Continued to circulate until gas dropped out and continued POOH. Current bit depth is 2,791' MD with a background opened well to monitor. Pumped and reamed from 9,150' to bottom of hole. Began POOH to 7,994' MD and had gas reach 8013' 1530' Condition - Bit # 1 13.1 13.5 11.40 Tricone 11.40 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 24 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) -@ Mud Data Depth 30-Apr-2015 23:59 Current Pump & Flow Data: - Max 579 Chlorides mg/l 29000 Finished CBU at shoe. Slip and cut drill line and continued RIH. At 9,150' MD began circulating well and flow went Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:POOH to 3,102' MD when well starting flowing. Shut down well and tried to circulate on well but couldn't pump by Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 28500 20 1-May-2015 23:59 Current Pump & Flow Data: - Max - ROP ROP (ft/hr) -@ Mud Data Depth Morning Report Report # 25 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 19.8 13.5 13.10 Tricone 13.10 Size 3 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 10 bbls lost Max Gas: 1591u and continued to L/D DP. Currently testing BOP's. 8013' 1530' 100% Gas In Air=10,000 UnitsN/AConnection 153 Tools Gamma, Resistivity API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 0Background (max) Trip Average 1591 Mud Type Lst Type - - PDC KCI/Polymer 4.9 8012' 10200'21 10200' Depth in / out YP (lb/100ft2) 10.00 000 00 CementChtSd C-4i C-4n 24 hr Max 29.7 Weight 32 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Testing BOP PV 1530' 6.75 0.460 Footage -2188' - 8012' 6482' R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP 21 Gas Summary 0 14 28 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 10200' 10200' 0' Max @ ft Current -- Date: Time: mud dog wiper. R/U wireline and fished out mud dog wiper. Circulated gas out which reached 1591 units. Weighted up to 13 ppg 370 in 1 -Minimum Depth C-5n - - C-2 1591 SPP (psi) Gallons/stroke TFABit Type Depth 4.550 L-80 MBT 10200' pH 0.739 0 39 0 Siltst 7.63'' - - Units* Casing Summary Lithology (%) 0 80 21593 28 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) Intermediate Casing 298 0 Cly 213848 10 3450 233 -PDC 9.8752 0..778 -1530' . . * 24 hr Recap:RIH from 1,300'-5061' MD and the circulated bottoms up. RIH to 7,825' MD and gas chromatograph needed to be Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 29000 N/A 2-May-2015 23:59 Current Pump & Flow Data: - Max - ROP ROP (ft/hr) 2.93 @ Mud Data Depth Morning Report Report # 26 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 14.3 13.5 11.75 Tricone 11.75 Size 3 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost Max Gas: 8565u UPDATE: While cementing, we were unable to establish cement returns to the surface. Currently, the cement is inside the casing hole and circulated. Gas reached 4.865 units.Continued to circulate and build mud. Currently R/U cementers. 8013' 1530' 100% Gas In Air=10,000 UnitsN/AConnection N/A Tools Gamma, Resistivity API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 120Background (max) Trip Average 8565 Mud Type Lst Type - - PDC KCI/Polymer 5.1 8012' 10200'18 10200' Depth in / out YP (lb/100ft2) 9.70 N/AN/A N/A 00 CementChtSd C-4i C-4n 24 hr Max 29.7 Weight N/A Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 - - R/U cementers PV 1530' 6.75 0.460 Footage -2188' - 8012' 6482' R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP 15 Gas Summary 0 N/A N/A (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 10200' 10200' 0' Max @ ft Current -- Date: Time: replaced and recalibrated. Max gas was 8,565 units at this time. Gas chromatograph is now working properly. RIH to bottom of 428 and unable to flow up the backside. Mudloggers are standing by. in 1 -Minimum Depth C-5n - - C-2 8565 SPP (psi) Gallons/stroke TFABit Type Depth 4.346 L-80 MBT 10200' pH 0.739 0 N/A 0 Siltst 7.63'' 255 87 Units* Casing Summary Lithology (%) N/A 80 N/A 76 907-283-1309Unit Phone: N/A Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade 10.75'' (max)(current) Intermediate Casing N/A 0 Cly N/A 10 3450 233 -PDC 9.8752 0..778 -1530' . . * 24 hr Recap:Finished rigging up cementers and began cementing but were unable to establish returns to the surface. Decision Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l - - 3-May-2015 23:59 Current Pump & Flow Data: - Max - ROP ROP (ft/hr) -@ Mud Data Depth Morning Report Report # 27 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 - 13.5 8.40 Tricone 8.40 Size 3 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost downhole Max Gas: N/A 8013' 1530' 100% Gas In Air=10,000 Units-Connection - Tools Gamma, Resistivity API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min -Background (max)Trip Average - Mud Type Lst Production Casing Type - - PDC Fresh Water - 8012' 10200'- 10200' Depth in / out YP (lb/100ft2) - --- -- CementChtSd C-4i C-4n 24 hr Max 29.7 Weight - Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A RIH PV 1530' 6.75 0.460 Footage -2188' - 8012' 6482' R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP - 18.0 Gas Summary - -- (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 10200' 10200' 0' Max @ ft Current -- Date: Time: was made to drill out plugs and cement. Tested BOP. Currently running in hole. Mudloggers are standing by. - in --Minimum Depth C-5n - - C-2 - SPP (psi) Gallons/stroke TFABit Type Depth -27 L-80 MBT 10200' pH 0.739 - - - Siltst 7.63'' - - Units* Casing Summary Lithology (%) - 80 - - 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade L-8010200' 10.75'' 5.00'' (max)(current) Intermediate Casing - - Cly - 10 3450 233 -PDC 9.8752 0..778 -1530' . . * 24 hr Recap: 3450 233 -PDC 9.8752 0..778 -1530' (max)(current) Intermediate Casing - - Cly - 10 Set AtSize 45.5 L-80 Grade L-8010200' 10.75'' 5.00'' 907-283-1309Unit Phone: - Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson 80 - - 7.63'' - - Units* Casing Summary Lithology (%) - L-80 MBT 10200' pH 0.739 - - - Siltst SPP (psi) Gallons/stroke TFABit Type Depth -26 C-5n - - C-2 - in --Minimum Depth Time: reamed to 4,589' MD. Pick up and milling ahead with a current bit depth of 5114' MD. No gas monitored while milling through - 10200' 10200' 0' Max @ ft Current -- Date: Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 18.0 Gas Summary - -- (current) R. Pederson/ L. Tousant ShClyst 10 TuffGvlCoal cP - 1530' 6.75 0.460 Footage -2188' - 8012' 6482' Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A Milling ahead PV 24 hr Max 29.7 Weight - Hours C-3 -- CementChtSd C-4i C-4n YP (lb/100ft2) - --- - - PDC Fresh Water - 8012' 10200'- 10200' Depth in / out Mud Type Lst Production Casing Type Average --Background (max)Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools Gamma, Resistivity API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 Units-Connection - 3 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost downhole Max Gas: N/A cased hole. Mudloggers are on standby. 8013' 1530' Condition - Bit # 1 - 13.5 8.40 Tricone 8.40 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 28 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) -@ Mud Data Depth 4-May-2015 23:59 Current Pump & Flow Data: - Max - Chlorides mg/l - Ran in hole with a 2 7/8" clean out assembly to 3,740' MD and began seeing cement at shakers. Washed and Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Milled ahead to 5,578' MD and decision was made to POOH. At 2,738' MD gas bubbles began breaking out of the Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 200 0 5-May-2015 23:59 Current Pump & Flow Data: - Max - ROP ROP (ft/hr) -@ Mud Data Depth Morning Report Report # 29 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 - 13.5 8.40 Tricone 8.40 Size 3 Geology: 10% Sand, 80% Siltstone, 10% Coal Fluids: 0 bbls lost downhole Max Gas: 168u a bit depth of 316' MD. the pack off. After troubleshooting lock downs were tighted and pressure was established. Currently continuing to POOH with 8013' 1530' 100% Gas In Air=10,000 UnitsN/AConnection 0 Tools Gamma, Resistivity API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min N/ABackground (max)Trip Average 168 Mud Type Lst Production Casing Type - - PDC Fresh Water - 8012' 10200'- 10200' Depth in / out YP (lb/100ft2) 10.80 000 00 CementChtSd C-4i C-4n 24 hr Max 29.7 Weight 0 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 N/A N/A POOH PV 1530' 6.75 0.460 Footage -2188' - 8012' 6482' S. Barber, D. Yessak ShClyst 10 TuffGvlCoal cP - 18.0 Gas Summary 0 0 0 (current) Avg to1530' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 10200' 10200' 0' Max @ ft Current -- Date: Time: water on the rig floor. Gas equipment was turned on and had a high of 168u. The gas leak was identified as it was coming from 4 in 0 -Minimum Depth C-5n - - C-2 168 SPP (psi) Gallons/stroke TFABit Type Depth -26 L-80 MBT 10200' pH 0.739 0 0 0 Siltst 7.63'' - - Units* Casing Summary Lithology (%) 0 80 4051 0 907-283-1309Unit Phone: 0 Jacob Robertson Maximum Report By:Logging Engineers:Autum Gould, Jacob Robertson Set AtSize 45.5 L-80 Grade L-8010200' 10.75'' 5.00'' (max)(current) Intermediate Casing 0 0 Cly 24351 10 3450 233 -PDC 9.8752 0..778 -1530' . . * 24 hr Recap: 3450 233 -PDC 9.8752 0..778 -1530' (max)(current) Intermediate Casing 5011 0 Cly 350160 Set AtSize 45.5 L-80 Grade L-8010200' 10.75'' 5.00'' 907-283-1309Unit Phone: 1006 Eric Andrews Maximum Report By:Logging Engineers:Jeremy Tiegs, Eric Andrews 35642 0 7.63'' - - Units* Casing Summary Lithology (%) 7 L-80 MBT pH 0.739 0 2475 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 4.350 C-5n 10183' - C-2 3178 in 4 10183'Minimum Depth Time: gallon drilling mud and continued drilling cement to 10,104'. Washed down to 10,186' and tagged shoe. Circulated bottoms up, 284 10186' 10186' 0' Max @ ft Current -- Date: Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 18.0 Gas Summary 0 2537 1001 (current) Rance Pederson ShClyst TuffGvlCoal cP 16 1530' 6.75 0.460 Footage -2188' - 8012' 6482' Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 Circulating PV 24 hr Max 29.7 Weight 5 Hours C-3 00 CementChtSd C-4i C-4n YP (lb/100ft2) 9.20 146 - - PDC Fresh Water 36526.0 8012' 10200'16 10200' Depth in / out Mud Type Lst Production Casing Type Average N/A1170Background (max) Trip N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min Tools API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing 100% Gas In Air=10,000 UnitsN/AConnection 2500 3 Geology: No samples collected Fluids: 0 bbls lost downhole Max Gas: 3178u after 2000 strokes/70 bbls. Continued circulating and monitoring well at time of report communication with the well and keep background gas down with 11.7+ pounds per gallon mud. Communications were established closed bags, and lined up to pump through drill string back up through the IA and choke lines to the degasser to try and establish 8013' 1530' Condition - Bit # 1 14.3 13.5 11.75 Tricone 11.80 Size Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Morning Report Report # 30 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field - ROP ROP (ft/hr) -@ Mud Data Depth 16-May-2015 23:59 Current Pump & Flow Data: - Max 22 Chlorides mg/l 30000 Drilled ahead to 10,098' and circulated bottoms up; no rubber seen. Displaced the wellbore to 11.7 pounds per Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Continued circulating and monitoring the well, Conducted 30 minute flow-check; no flow, and Circulated bottoms up: Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 24000 11 17-May-2015 23:59 Current Pump & Flow Data: - Max - ROP ROP (ft/hr) - @ Mud Data Depth Morning Report Report # 31 Customer: Well: Area: Location: Rig: KBU 22-06Y Hilcorp Alaska LLC Kenai Peninsula Kenai Gas Field Job No.: Daily Charges: Total Charges: MWD Summary 95% Rig Activity: N/A Saxon 169 Report For: Condition - Bit # 1 15.2 13.5 11.90 Tricone 11.88 Size 3 Geology: No samples collected. Fluids: 0 bbls lost downhole. Max Gas: 4228u pack off assembly at time of report. hole, made up 5' retainer plug, and then ran back in hole to 10,065'. Set plug, pulled out of hole and rigged down e-line. Making 8013' 1530' 100% Gas In Air=10,000 UnitsN/AConnection 158 Tools API FL Chromatograph (ppm) - -0' 1530' WOB Surface Casing N/AN/A Avg Min Comments RPM ECD (ppg) ml/30min 1170Background (max) Trip Average 31 Mud Type Lst Production Casing Type - - PDC Fresh Water 6.4 8012' 10200'17 10200' Depth in / out YP (lb/100ft2) 9.60 001 00 CementCht Sd C-4i C-4n 24 hr Max 29.7 W eight 0 Hours C-3 Sst (ppb Eq) C-1 C-5i AK-AM-0902299672 M/U Pack off assembly PV 1530' 6.75 0.460 Footage -2188' - 8012' 6482' R. Pederson / J. Lott ShClyst TuffGvlCoal cP 15 18.0 Gas Summary 0 11 24 (current) Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 10186' 10186' 0' Max @ ft Current -- Date: Time: max 244 units gas. Decision was made to pull out of the hole and run in hole with e-line for a 4" gauge run. Pulled back out of the 284 in 5 10186'Minimum Depth C-5n 10186' - C-2 4228 SPP (psi) Gallons/stroke TFABit Type Depth 4.550 L-80 MBT pH 0.739 0 35 0 Siltst 7.63'' - - Units* Casing Summary Lithology (%) 223505 0 907-283-1309Unit Phone: 0 Eric Andrews Maximum Report By:Logging Engineers:Jeremy Tiegs, Eric Andrews Set AtSize 45.5 L-80 Grade L-8010200' 10.75'' 5.00'' (max)(current) Intermediate Casing 0 0 Cly 432763 3450 233 -PDC 9.8752 0..778 - 1530'
