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218-083
MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Wednesday, October 8, 2025 SUBJECT:Mechanical Integrity Tests TO: FROM:Josh Hunt P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Cook Inlet Energy, LLC. 6A REDOUBT UNIT 6A Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 10/08/2025 6A 50-733-20519-01-00 218-083-0 W SPT 11752 2180830 2938 4992 4992 4992 4992 130 130 130 130 4YRTST P Josh Hunt 8/14/2025 Very solid test. 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:REDOUBT UNIT 6A Inspection Date: Tubing OA Packer Depth 2494 3302 3299 3299IA 45 Min 60 Min Rel Insp Num: Insp Num:mitJDH250814202717 BBL Pumped:2.2 BBL Returned:2.2 Wednesday, October 8, 2025 Page 1 of 1 MEMORANDUM TO: Jim Regg 1� P.I. Supervisor I�`� PRONI: Adam Earl Petroleum Inspector Well Name REDOUBT UNIT 6A Insp Num: mitAGE210816121146 Rel Insp Num: NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, August 25, 2021 SUBJECT: Mechanical Integrity Tests Cook Inlet EnerLy, LLC. 6A REDOUBT UNIT 6A Sre: Inspector Reviewed By: P. 1. Supry -, 1�i Comm API Well Number 50-733-20519-01-00 Inspector Name: Adan, Earl Permit Number: 218-083-0 Inspection Date: 8/14/2021 Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min 11752 Tubing 0 0 0 0 2938 IA 226 3300 3290 ' 3285 8.8 ' OA o 10 10 10 1 ✓ Wednesday, August 25, 2021 Page I of I Packer Well 6A Type Inj N TVD PTD 2180830 ' Type Test SPT- Test psi BBL Pumped: 9 ` BBL Returned: Interval OTHER P/F Notes: Required pre-injection for start-up / Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min 11752 Tubing 0 0 0 0 2938 IA 226 3300 3290 ' 3285 8.8 ' OA o 10 10 10 1 ✓ Wednesday, August 25, 2021 Page I of I STATE OF ALASKA RECEIVED ALAS DIL AND GAS CONSERVATION COMMIS J REPORT OF SUNDRY WELL OPERATIONS FEB 0 6 2Q20 1. Operations Abandon Ll Plug Perforations LJ Fracture Stim ulateLJ Pull TubingshutdownLl Performed: Suspend 11Perforate ❑� Other Stimulate❑ Alter Casing E]Ae �rogram ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Wel❑ Re-enter Susp Well ❑ Other: StimTubes 0 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: COOK INLET ENERGY LLC Development ❑ Exploratory ❑ 218-083 3. Address: 188 W Northern Lights Blvd, Suite 510 Stratigraphic ❑ Service 0 6. API Number: Anchorage, AK 99503 50-733-20519-01-00 7, Property Designation (Lease Number): 8. Well Name and Number: ADL 381203 (surface), ADL 374002 (TD) REDOUBT Unit #BA 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 110. Field/Pool(s): BT SHOAL UNDEFINED, UNDEFINED OIL 11. Present Well Condition Summary: Total Depth measured 17450' feet Plugs measured none feet true vertical 12433' feet Junk measured none feet Effective Depth measured 17361' feet Packer measured see schematic feet true vertical 12433' feet true vertical see schematic feet Casing Length Size MD TVD Burst Collapse Structural 200' 30" 200' 200' N/A NIA Conductor Surface 3840' 13-3/8' 3840' 3243' 5020' 2260' Intermediate 10608' 9-518" Window. 13641' 10608' 6870' 4750' Production 2938' 7" 16200' 11907' 9960' 6230' Liner 1538' 4-i/2" 17450' 12433' 8430' 7500' Perforation depth Measured depth see schematic feet True Vertical depth see schematic feel Tubing (size, grade, measured and true vertical depth) Packer; and SSSV (type, measured and true vertical depth) 4-1/2" L-80 4 112" x 7" HES Liner Top Packer 12. Stimulation or cement squeeze summary: Intervals treated (measured): See attached for StimTube intervals descriptions including volumes used and final pressure: 15823' MD 111745' TVD Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 980 294 4354 Subsequent to operation: 0 0 965 312 4357 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations 2 Exploratory ❑ Development ❑ Service Q Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ IGSTOR ❑ WINJ Q WAG ❑ GINJ ❑ SUSP❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or NIA if C.O. Exempt: 319-571 Name: Stephen Ratcliff Contact Name: Stephen Ratcliff Title: VP of Date: 2 l 4 1W Form 1004 Revised 412017 �j „ /D / RBDMs L9 / FEB 10 2020a� Contact Email: sratcltff@glacieroil.com Contact Phone: 907-433-3808 Submit Original Only GLACIER RU -6A Daily Summary API: 50-733-20519-01-00 Permit #: 218-083 Date Activity 16 January 2020 Rig up Eline. 17 January 2020 Finish rig up Eline. Pressure test lubricator to 4500 psi. RIH with 3.4" GR on rollers to 16520', POH. 18 January 2020 RIH with Perf Gun #1(20', 3-1/8", 6 spf, 60deg) and perforate new interval 16990'— 17010' MD. POH and confirm all shots fired. RIH with Perf Gun #2 (20', 3-1/8", 6 spf, 60deg) and reperforate 16800'— 16820' MD. POH and confirm all shots fired. 19 January 2020 RIH with Perf Gun #3 (20', 3-1/8", 6 spf, 60deg) and reperforate 16660' — 16680' MD. POH and confirm all shots fired. RIH with Perf Gun #4 (20', 3- 1/8", 6 spf, 60deg) and reperforate 16610'— 16630' MD. POH and confirm all shots fired. RIH with Perf Gun #5 (20', 3-1/8", 6 spf, 60deg) and reperforate 16510'— 16530' MD. POH and confirm all shots fired. 20 January 2020 RIH with StimGun #1 (6' long, 3" OD) and reperforate 16510'— 16516' MD. PON and confirm tool fired. RIH with StimGun #2 (6' long, 3" OD) and reperforate 16524'— 16530' MD. POH and confirm tool fired. RIH with StimGun #3 (6' long, 3" OD) and reperforate 16610'— 16616' MD. POH and confirm tool fired. 21 January 2020 RIH with StimGun #4 (6' long, 3" OD) and reperforate 16624' —16630' MD. POH and confirm tool fired. RIH with StimGun #5 (6' long, 3" OD) and reperforate 16660'— 16666' MD. POH and confirm tool fired. RIH with StimGun #6 (6' long, 3" OD) and reperforate 16674'— 16680' MD. POH and confirm tool fired. RIH with StimGun #7 (5' long, 3" OD) and reperforate 16692'— 16697' MD. POH and confirm tool fired. 22 January 2020 RIH with StimGun #8 (6' long, 3" OD) and reperforate 16804'— 16810' MD. POH and confirm tool fired. RIH with StimGun #9 (6' long, 3" OD) and reperforate 16810'— 16816' MD. POH and confirm tool fired. RIH with StimGun #10 (6' long, 3" OD) and reperforate 16990'— 16996' MD. POH and confirm tool fired. RIH with StimGun #11(6' long, 3" OD) and reperforate 17004'— 17010' MD. POH and confirm tool fired. 23 January 2020 Rig down Eline. Turn well over to injection. GLACIER RU -6A — Perf Intervals Run # Top MD Base MD Top TVD Base TVD Notes 5 16510 16530 12027 12035 Re-perf 4 16610 16630 12066 12074 Re-perf 3 16660 16680 12085 12093 Re-perf 2 16800 16820 12140 12148 Re-perf 1 16990 17010 T 12224 12233 New Interval RU -6A — Stim Intervals Run # Top MD Base MD Top TVD Base TVD Notes 1 2 16510 16524 16516 16530 12027 12033 12029 12035 Re-perf Re-perf 3 4 5 16610 16624 16660 16616 16630 16666 12066 12072 12085 12069 12074 12088 Re-perf Re-perf Re-perf 6 16674 16680 12091 12093 Re -pert 7 16692 16697 12098 12100 Re-perf 8 16804 16810 12141 12144 Re-perf 9 16810 16816 12144 12146 Re-perf 10 16990 16996 12224 12227 Re-perf 11 1 17004 17010 1 12230 12233 Re-perf RU -06)' 'tual Completion Schematic GLACIER Calc TOC @ 11000' MD 7" TOL @13262' MD110310' TVD KOP @ 13641' MDl10608' TVD CBL TOC @ 14740' MD 4.5" TOL @ 15823' MD111745' TVD TCP Perforations (3-118", 6spf, 60 phase): Top -Bottom MD 1 Top -Bottom TVD 16200'-16240' MD 111902'-11916' TVD 16265'-16290' MD 111928'-11939' TVD 16440'-16465' MD 111999'-12009' TVD 16500'-16845' MD 112023'-12158' TVD 16990'-17010' MD 112224'-12233' TVD 17020'-17090' MO 112237'-12269' TVD 17150'-17285' MD 112296'-12355' TVD Total = 640ft "Specific Intervals reperf using guns & 3.5' OD Eline bullnose 6.25" long on top of CIE Left in hale on 10123/2019 PBTDICIBP @ 17361' MD Version: Final February 6, 2020 4-112" tubing hanger wIPH6xDWC1CHT crossover Set w13.45ft of compression/20k down on ratch-latch seal assy 30" 1 150# A-36 200' MD A-36 1 200' TVD 13 318" 1 88# L-80 3,480' MD ID - 112A115"I BTC 2,975' TVD 4-112" 12.6# L80 DWCIC-HT Tubing - ID 3.958'YDdit = 3.933" Whipstock Window 9W8- 1 47# L-80 13641' MD Inc - 3a ID - 8.681" 1 BTC 10608' TVD I Azm -107 8.112" Hole - Sidetrack 7' 26# P710 16200' MD Inc .65 ]D=6.194 DWCIC 11907' TVD Azm - 73 6" Hole - Sidetrack 4.5" 1 12.69 L80 17450' MO Inc -62 ID - 3.95$ 1 DWCIC-HT 12432' TVD Azm - 60 GLACIER February 6th, 2020 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Report of Sundry Cook Inlet Energy, LLC: Redoubt Unit 06A API No: 50-733-20519-01-00 Dear Commissioner, Cook Inlet Energy, LLC, hereby submits a Report of Sundry Well Operations for RU -6A. The work performed was covered under Approved Sundry 319-571. If you have any questions, please contact me at (907) 433-3808. Sincerely, t��C�— \ Stephen Ratcliff Vice President of Drilling Cook Inlet Energy, LLC (a Glacier Oil & Gas Corp. owned company) 188 W. Northern Lights Blvd, Suite 510 Anchorage, AK 99503 DATA SUBMITTAL COMPLIANCE REPORT 113/2020 Permit to Drill 2180830 Well NamelNo. REDOUBT UNIT 6A MD 17450 TVD 12433 Completion Date 9/4/2019 REQUIRED INFORMATION Mud Log No/ DATA INFORMATION List of Logs Obtained: GR, Res, Cmt Eval Well Log Information: Logl Electr Data Digital Dataset Type MedlFrmt Number Name ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data ED C 31284 Digital Data Log Electronic File: RU -06A LWD Final MD.tif 31284 Log Header Scans Well Cores/Samples Information: Name Operator Cook Inlet Energy, LLC. API No. 50-733-20519-01-00 Completion Status 1WINJ Current Status 1WINJ UIC Yes Samples No I/ Directional Survey Yes V (from Master Well Data/Logs) Log Log Run Interval OH 1 Scale Media No Start Stop CH Received Comments 13828 17450 10/2/2019 Electronic Data Set, Filename: RU -06A LWD Final.las 10/2/2019 Electronic File: RU -6A 71NCH SCBL RAW.pdf 10/2/2019 Electronic File: RU -06A LWD Final MD.cgm 10/2/2019 Electronic File: RU -06A LWD Final TVD.cgm 1012!2019 Electronic File: RU#6A Definitive Survey Report. pdf 1012!2019 Electronic File: RU#6A_DSR.t d 1002019 Electronic File: RU#6A_GIS.txt 10/2/2019 Electronic File: RU -06A LWD Final MD.emf 10/2/2019 Electronic File: RU -DBA LWD Final TVD.emf 10/212019 Electronic File: RU -06A LWD Final MD.pdf 10/2/2019 Electronic File: RU -06A LWD Final TVD.pdf 10/2/2019 Electronic File: RU -06A LWD Final MD.tif 10/212019 Electronic File: RU -06A LWD Final TVD.tif 10/2/2019 Electronic File: EMFView3_1.zip 10/212019 Electronic File: Readme.txt 0 0 2180830 REDOUBT UNIT 6A LOG HEADERS Sample Interval Set Start Stop Sent Received Number Comments AOGCC Page 1 of 2 Friday, January 3, 2020 DATA SUBMITTAL COMPLIANCE REPORT 113/2020 Permit to Drill 2180830 Well Name/No. REDOUBT UNIT 6A Operator Cook Inlet Energy, LLC. MD 17450 TVD 12433 Completion Date 9/4/2019 Completion Status 1WINJ Current Status 1WINJ INFORMATION RECEIVED Completion Report lY Production Test Information Y /(!Y Geologic Markers/Tops 0 COMPLIANCE HISTORY Completion Date: 9/4/2019 Release Date: 7/26/2018 Description API No. 50-733-20519-01-00 UIC Yes Directional I Inclination Data ® Mud Logs, Image Files, Digital Data Y 1 Core Chips Y 1� Mechanical Integrity Test Information Y 1 NA Composite Logs, Image, Data Files ) Core Photographs Y 1 J� Daily Operations Summary @ Cuttings Samples Y �f NAJ Laboratory Analyses Y /6 Date Comments Comments: Compliance Reviewed By: Date: AOGCC Page 2 of 2 Friday, January 3, 2020 THE STATE GOVERNOR MIKE DUNLEAVY Stephen Ratcliff VP of Drilling Cook Inlet Energy, LLC 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 Re: Redoubt Shoal Field, Undefined Oil Pool, RU 6A Permit to Drill Number: 218-083 Sundry Number: 319-571 Dear Mr. Ratcliff: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276,7542 www.00gcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Ostsie L. Chmielowski Commissioner DATED this 2D day of December, 2019. 1BDMs16'jJAN 0 z 7020 SCANNED JAN 0 2 2020 BEGIN 9E D STATE OF ALASKADEC 17 2019 ALASKA OIL AND GAS CONSERVATION COMMISSION 07-5' 1p f � 117 APPLICATION FOR SUNDRY APPROVALS I'iO G CC 20 AAC 25280 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well ❑ Operations shutdovo Suspend ❑ Perforate ❑v r Other Stimulate Pull Tubing Change Approved Progrel Plug for Redrill El Perforate New Pool 11 Re-enter Susp Well E] Alter Casing Other. 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. COOK INLET ENERGY LLC Exploratory 11 Development Stratigraphic ElService6. 218-083 3. Address: API Number: • 188 W. Northern Lights Blvd, Suite 510, Anchorage, AK, 99503 50-733-20519-01-00 7. If perforating: B. Well Name and Number What Regulation or Conservation Order governs well spacing in this pool? C.O.712 & 20AAC25.055 Will planned perforations require a spacing exception? Yes El No .7 REDOUBT UNIT #6A 9. Property Designation (Lease Number): 10. Field/Pool(s): e � r ADL -381203 surface , ADL -374002 D REDOUBT SHOAL UNDEFINED, UNDEFINED OIL 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): 17450' 12433' TVD 17361' MD 12433' TVD 4298 psi None None Casing Length Size MD TVD Burst Collapse Structural 200' 30" 200' 200' N/A NIA Conductor — — — — — Surface 3840 13 318" 3840 3243 5020 2260 Intermediate 10608' 9 518" Window: 13641' 10608' 6870 4750 Production 2938' 7' 16200' 11907' 9960 6230 Liner 1538' 4-112" 17450' 12433' 8430 7500 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Well Schematic See Well Schematic 4-112" L80 15823' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 4 112" x 7" HES Liner Top Packer 15823' MD 111 745'TVD 12. Attachments: Proposal Summary7 Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program ❑d BOP Sketch s Exploratory s Stratigraphies Developments Service u 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 111120 a OIL WINJ WDSPL Suspended GAS WAG GSTOR SPLUG 16. Verbal Approval: Date: Commission Representative: GINJ Op Shutdown Abandoned 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Stephen Ratcliff Contact Name:Sta hen Ratcliff Authorized Title: VP of Drilling Contact Email: sratclifflacieroil.com Contact Phonego743338oB Authorized Signature- Date: 12/17/19 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 312 -5-71 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: ` f,� qn n I DMS JAN Lu�u Post Initial Injection MIT Rsq'd? Yes 1:1 No Spacing Exception Required? Yes No Subsequent Form Required: ' Er 1 ❑ u r APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 1 2� 1 0 R I.G I N A Lig I r Submit Form and Z".. 10.403 Revised 4/2017 Approved application is valid for 12 months from the date of approval. Attachments In uplicate ?-IrZ a A a.1l ghi GLACIER WELL NAME — RU -05A Requirements of 20 AAC 25.005(f j Well Summary Current Status: Currently on injection. Scope of Work: • Rig up Eline. • Reperforate specified zones with perforating guns. • Reperforate specified zones with Stim Guns. • Rig down Eline. • Turn well over to injection. General Well Information: Reservoir Pressure / TVD: MASP: Wellhead Type/Pressure Rating: BOP Configuration: Well Type: Estimated Start Date: 5358 psi @ 17,285' MD / 12,355' TVD 4,123 psi Vetco Gray — 5M - Wellhead Assembly Eline WLV Water Injector January 1, 2020 2 GLACIER 1. Reperforating Procedure Requirements of 20 AAC25.005 (c)(13) 1. Rig up Eline. 2. Pressure test lubricator to 4,500 psi. 3. RIH with gauge ring and verify access to 17300' MD. 4. RIH with 3-1/8", 6spf, 60deg phase perforating guns and perforate the following intervals from bottom to top: RU -6A — Perf Intervals Top MD Base MD Top TVD Base TVD Notes 16510 16530 12027 12035 Re-perf 16610 16630 12066 12074 Re-perf 16660 16680 12085 112093 Re-perf 16800 16820 12140 12148 Re-perf 16990 17010 12224 12233 New Interval 5. RIH with 3" Stim Guns and reperforate the following intervals from top to bottom: RU -6A — Stim Intervals Top MD Base MD Top TVD Base TVD Notes 16510 16530 12027 12035 Re-perf 16610 16630 12066 12074 Re-perf 16660 16680 12085 1 12093 Re -pert 16800 16820 12140 12148 Re-perf 16990 17010 12224 12233 New Interval 6. Rig down Eline. 7. Turn well over to injection. k] GLACIER RU -06A ' lual Completion Schematic Calc TOC @ 11000' MD 7" TOL @13262' MD/10310' TVD KOP @ 13641' MID/110608' TVD CBL TOC @ 14740' MD 4.5" TOL @ 15823' MD111745' TVD TCP PerroraSons (3.118", 6apf, 60 phase): Top -Bottom MD 1 Top -Bottom TVD 16200'-16240' MD 111902'-11918' TVD 16265'-16290' MD 111928'-11938' TVD 16440'-16465' MD 1 11999'-12009' TVD 16500'-16845' MD 112023'-12156' TVD 17020'-17090' MD 1 122371-122691 TVD 17150'-17285' MD 112296'-12355' TVD Total = 640ft -Specific Intervals reperf using StimTubes in Oct 2019"" 3.5" OD Eline bullnose 6.25" long on top of CIBP Left in hole on 1 012 312 01 9 PBTDICIBP @ 17361' MD Version: Final September 4, 2019 4-1'Pr ftMinq nyn4m wlPHNI3+fi1C7CHT cremover SM jd3 d5M of 00mpMM 4n120k d¢Wq on ralch-latch sem essy 30" 150#A-36 200' L I A-36 200' TVD 13 318" 1 68# L-80 3,450' MD ID - 12AIS-1 BTC 2,975' TVD b-117' 1 � 0 L!#0 CWX?C-H T TubihQ - Iq .1 35&'eUrIR =1933°' Whipstock Window 9618- 47# L-80 13641' MD Inc .38 ID - 8.681" BTC 10608' TVD Azm -107 8-112" Hole - Sidetrack 7" 26# 12110 16200 -MO Inc - 55 ID = 6.184 DMIC 11907' TVD Azm - 73 6" Hole - Sidetrack 4.5" 1 112.6#11-80 17450' MD Inc .62 ID = 3.958 1 DWCIC-HT 12432' TVD Azm - 60 RU -06A P ' Deed Completion Schematic GLACIER 1 18-112" Hole I Calc TOC @ 11 000'MD 114" Hole 7" TOL @13262' MDI10310' TVD KOP @ 13641' MDI10608' TVD CBL TOC @ 14740' MD 4.5" TOL @ 15823' MD111745' TVD TCP Perforations (3-118", 6spf, 60 phase): Top -Bottom MD 1 Top -Bottom TVD 16200-16240' MD 111902'-11918' TVD 16265'-16290' MD 111928'-11939' TVD 16440'-16465' MD 111999'-12009' TVD 16500'-16845' MD 112023'-12158' TVD 16990'-17010' MD 112224'-12233' TVD 17020'-17090' MD 112237'-12269' TVD 17150'-17285' MD 112296'-12355' TVD Total = 660K "Specific Intervals reperf using StimTubes in Oct 2019- 3.5" OD Eline bullnose 6.25" long on top of CIBP Left in hole on 1012312019 rte, PBTDICIBP 0 17361' MD Version: V1 December 17, 2019 4-112" tuning hanger wIPH6xDWC1CHT crossover " Set w13.45ft of compression/20k down on ratch-latch seal assy Ir; 30" 150# A-36 L200' MD A-36 200'TVD 13W8" I 68#L-80 3,480' MD lD -12.415" 1 BTC 2,975' TVD " 4-1I2" 12.6# L80 DWC1C-HT Tubing - ID 3.958" Drift = 1933" Whipstock window 9 518" 1 47# L-80 13641' MD Inc .38 ID . 8.681" I BTC 10608' ND Azm-107 8-112" Hole -Sidetrack 7" 26#P110 16200' MD Inc - 66 ID = 6.164 DWCIC 11907' TVD I Azm - 73 6" Hole - Sidetrack 4.5" 1 12.69 L80 17450' MD Inc - 62 10 = 3.958 1 DWCIC-HT 12432' TVD Azm - 60 GLACIER December 17th, 2019 Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Sundry Application Cook Inlet Energy, LLC: Redoubt Unit 06A API: 50-733-20519-0100 Dear Commissioner, Cook Inlet Energy (CIE) hereby submits a Sundry Application for RLI -06A, PTD: 218-083 to perforate and reperforate selected intervals using perforating guns and Stim Guns. If you have any questions, please contact me at (907) 433-3808. Sincerely, Stephen Ratcliff VP of Drilling Cook Inlet Energy, LLC (a Glacier Oil & Gas owned company) 188 W Northern Lights Blvd, Suite 510 Anchorage, AK 99503 STATE OF ALASKA ALAS+",OIL AND GAS CONSERVATION COMMISP"°N REPO. _ i' OF SUNDRY WELL OPERAI .jNS 1. Operations Abandon LJ Plug Perforations LJ Fracture StimulateD Pull Tubing LJ Operations shutdown LJ Performed: Suspend ❑ Perforate ❑� Other Stimulate❑ Aller Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair We[E] Re-enter Susp Well ❑ Other: StimTubes 0 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: COOK INLET ENERGY LLC Development ❑ Exploratory ❑ Stratigraphic ❑ Service 218-083 3. Address: 188 W Northern Lights Blvd, Suite 510 6. API Number: Anchorage, AK 99503 50-733-20519-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 381203 (surface), ADL 374002 (TD) REDOUBT Unit #6A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): none REDOUBT SHOAL UNDEFINED, UNDEFINED OIL 11. Present Well Condition Summary: Total Depth measured 17450' feet Plugs measured none feet true vertical 12433' feet Junk measured none feet MV 12 zoos Effective Depth measured 17361' feet Packer measured see schematic feet true vertical 12433' feet true vertical see schematic feet AOO CC Casing Length Size MD TVD Burst Collapse Structural 200' 30" 200' 200' N/A NIA Conductor Surface 3840' 13-318" 3840' 3243' 5020' 2260' Intermediate 10608' 9-518" Window: 13641' 10608' 6870' 4750' Production 2938' 7" 16200' 11907' 9960' 6230' Liner 1538' 4-112" 17450' 12433' 8430' 7500' Perforation depth Measured depth see schematic feet True Vertical depth see schematic feet Tubing (size, grade, measured and true vertical depth) 4-1/2" L-80 15823' MD 11745' TVD Packers and SSSV (type, measured and true vertical depth) 4 1/2" x 7' HES Liner Top Packer 15823' MID / 11 745'TVD 12. Stimulation or cement squeeze summary: Intervals treated (measured): See attached for StImTube intervals Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 1274 118 4438 Subsequent to operation: 0 0 1200 195 4484 14. Attachments (required per 20 AAC 25-070,25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑' Exploratory ❑ Development ❑ Service Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil ❑ Gas WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ IGSTOR ❑ WINJ ❑Q WAG ❑ GINJ ❑ SUSP❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or WA if C.O. Exempt: 131g-442 This was an 80 bbl batch injection. Pressures taken during injection. Authorized Name: David Pascal Contact Name: David Pascal Authorized Title: VP Uperations Contact Email: dDascalla glacieroil.com Authorized Si nature: Date: 11/12/2019 Contact Phone: 907-433-3822 WE Form 10-404 Revised 4/2017 SZ R MSIf�' Nov 131019 Submit Original Only GLACIER November 12th, 2019 Commissioner Jessie Chmielowski Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 Re: Report of Sundry Cook Inlet Energy, LLC: Redoubt Unit 06A API No: 50-733-20519-01.00 Dear Commissioner, RECEIVED NOV 12 2019 AOGCC Savant Alaska, LLC, hereby submits a Report of Sundry Well Operations for RU -6A. The work performed was covered under Approved Sundry 319-442. If you have any questions, please contact me at (907) 433-3822. Sincerely, Pascal Vice President of Operations Savant Alaska, LLC (a Glacier Oil & Gas Corp. owned company) 188 W. Northern Lights Blvd, Suite 510 Anchorage, AK 99503 GLACIER RU -6A Daily Summary API: 50-733-20519-01-00 Date Activity Permit #: 218-083 18 October 2019 R/U Eline on RU -6A. RIH run #1: 6' of 2" StimTube and shoot at 17,050'. Base MD Turn over to injection for the night. 19 October 2019 R/U Eline on RU -6A. RIH run #2: 6' of 2.5" StimTube and shoot at 16,760' 16220 RIH run #3: 6' of 2" StimTube and shoot at 16,799'. RIH run #4: 5' of 2.5" 6' StimTube and shoot at 17,210'. Turn over to injection for the night. 20 October 2019 R/U Eline on RU -6A. RIM run #5: 6' of 2" StimTube and shoot at 16,670'. 16284 run #6: 6' of 2.5" StimTube and shoot at 16,720'. RIH run #7: 6' of 2.5" 3" StimTube and shoot at 16,830'. Turn over to injection for the night. 21 October 2019 R/U Eline on RU -6A. RIH run #8: 6' of 2" StirnTube and shoot at 16,445'. 6' _ run #9: 6' of 2" StimTube and shoot at 16,530'. RIH run #10: 6' of 2.5" 12 StimTube and shoot at 16,570'. Turn over to injection for the night. 22 October 2019 R/U Eline on RU -6A. RIH run #11: 6' of 2" StimTube and shoot at 16,220'. RIH RIH RIH run #12: 3' of 2.5" StimTube and shoot at 16,507'. RIH run #13: 6' of 3" StimTube and shoot at 16,560'. Turn over to injection for the night. 23 October 2019 R/U Eline on RU -6A. RIH run #14: 6' of 3" StimTube and shoot at 16,278' Turn over to injection for the night. RU -6A StimTube Summary Run # Top MD Base MD Gun Length Gun Size 11 16220 16226 6' 2" 14 16278 16284 6' 3" 8 16445 16451 6' _ 2" 12 16507 16510 3' 2.5" 9 16530 16536 6' 2" 13 16560 16566 6' 3" 10 16570 16576 6' 2.5" 5 16670 16676 6' 2" 6 16720 16726 6' 2.5" 2 16760 16766 6' 2.5" 3 16799 16805 6' 2" 7 16830 16836 6' 2.5" 1 17050 17056 6' 2" 4 17210 17215 5' 2.5" RU -0' etual Completion Schematic GLACIER 30" Condu Calc TOC Q 11000' MD 14" Hole 7" TOL @ 13262' MD/10310' TVD KOP @ 13641' MD110608' TVD dr CBL TOC @ 14740' MD 4.5" TOL @ 15823' MD/11745' TVD TCP Perforations (3-118". 6spf. 60 phase: Top -Bottom MD 1 Top -Bottom TVD 16200'-1624V MD 111902'-11918' TVD 16265'-16290' MD 111928'-1193V TVD i 16440'-16465' MD 111999'-12009' TVD I I 16500'-16845' MD 112023'-12158' TVD 17020'-17090' MD 112237'-12269 TVD 17150'-17285' MD 112296'-12355' TVD Total = 640ft j 3.5" OD Eline bullnose 6.25" long on tap of CIBP Left in hole on 10/23/2019 Version: Final September 4, 2019 4.1/2" tubing hangerw/PH6xDWC/CHT crossover Set w13.45ft of oompresslon120k down on retch -latch seal assy 30' 1500 A-36 200' MD A-36 200' TVD 13318" 1 68#L-80 3,460' IIID ID - 12A15'j BTC 2,975' TVD 4-112" 12.6# L80 DWC1C-HT Tubing - ID 3.958"/Drift= 3.933" Whipstock Window 9 518" 1 47# L-80 13641' MD Inc - 38 ID - 8.681" 1 BTC 10608' TVD Azm -107 6-1/2' Hole - Sidetrack 7' 26#P110 16200' MD Inc - 65 ID = 6.184 DWC/C 11907' TVD Am .73 i Selective StimTubes shot In October 2019 Q 6" Hole - Sidetrack 9131EP- 1.7-� 4.5" 12.6# L80 17450' MD Inc - 62 a ID a 3.958 1 DWC1C-HT I 12432' TVD Azm - 60 PBTDICIBP @ 17361- MD GLACIER October 2nd, 2019 Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7h Ave., Suite 100 Anchorage, Alaska 99501 Re: RU -06A Well Completion Cook Inlet Energy, LLC Permit to Drill NO: 218-083 API No: 50-733-20519-01-00 Dear Commissioner, Please find our enclosed 10-407 Well Completion Report for the RU -06A well. Included is the 10-407 form, drilling summary, wellbore schematic, final survey, and casing and cementing report. If you have any questions, please contact me at (907) 433-3808. Sincerely, 1 Stephen Ratcliff VP of Drilling Cook Inlet Energy, LLC (a Glacier Oil & Gas Corp wholly owned company) 188 W Northern Lights Blvd, Suite 510 Anchorage, AK 99503 STATE OF ALASKA Al ASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a. Weli Status: Oil ❑ Gas ❑ SPLUG ❑ Other ❑ Abandoned ❑ Suspended ❑ 20AAC 25.105 2MAc 25.110 GINJ ❑ WINJ ❑� • WAGE] WDSPL ❑ No. of Completions: 1 1 b. Well Class: Development ❑ Exploratory ❑ Service ❑� Stratigraphic Test ❑ 2. Operator Name: Cook Inlet Energy, LLC 6. Date Comp., Susp., or Aband.: 9/4/2019 14. Permit to Drill Number/ Sundry: • 218-0831319-376 3. Address: 188 W. ]Northern Lights Blvd, Suite 510, Anchorage, AK 99503 7. Date Spudded: 7/23/2019 15. API Number: 50-733-20519-01-00 4a. Location of Well (Governmental Section): Surface: 1909' FSL, 318' FEL, Sec. 14, T7N, R14W, SM Top of Productive Interval: 360' FNL, 916' FEL, Sec. 19, T7N, R13W, SM Total Depth: 103' FSL, 196' FWL, Sec. 17, T7N, R13W, SM 8. Date TD Reached: 811 a/201 9 16. Well Name and Number: Redoubt Unit #6A 9. Ref Elevations: KB: 90 GL: BF: 17. Field 1 Pool(s): Redoubt Shoal Undefined, Undefined Oil 10. Plug Back Depth MDlrVD: • 17361' MD 1 12391' TVD • 18. Property Designation: ADL 381203, ADL 374002 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 200619.745 ' y- 2449933.955 Zone- 4 TPI: x- 210308.61 y- 2447404.41 Zone- 4 Total Depth: x- 211438.3 y- 2447856 Zone- 4 11. Total Depth MD/TVD: . 17450' MD 112433' TVD • 19. DNR Approval Number: LOCI 01-004 12. SSSV Depth MDITVD: 20. Thickness of Permafrost MD/TVD: nla 5. Directional or Inclination Survey: Yes L,(attached) No Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: 45 (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: - 13641' MD / 10608' TVD - 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary Gamma Ray, Resistivity, cement evaluation 06) 23, CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT CASING FT TOP BOTTOM TOP BOTTOM PULLED 7" 26 Pilo 13262 16200 10310 11907 8-1/2" 533 tuft 15.7ppg G nla 4-1/2" 12.6 L80 15823 17450 11745 12432 6" None cAbar Fc,t2 nla 24. Open to production or injection? Yes 0 No ❑ If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number; Date Perfd):p((y [." 812912019: TCP Perforations (3-118", 6spf, 60 phase): ��,1� Top -Bottom MD / Top -Bottom TVD COMPLETION 16200'-16240' MD 111902'-11918' TVD AT �r�L 16265'-16290' MD 111928'-11939' TVD 4 Zp(q Lj 16440'-16465' MD 1 11999'-12009' TVD R1VI ED 16500'-16845' MD / 12023'-12156' TVD ,� 17020'-17090' MD 112237'-12269' TVD 17150'-17285' MD / 12296'-12355' TVD 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-112" 15823 15823' MD / 11745' TVD 26_ ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes ❑ No LJ Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27_ PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): Date of Test: Hours Tested: Production for Test Period Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Flow Tubing Press. Casinq Press: Calculated 24 -Hour Rate Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity - API (torr): Form 10-407 Revised 512017 �W (Ql g OtCONT NUED ON AGE 2 Submit ORIGiNIAL o 28. CORE DATA Conventional Cords): Yes ❑ No ❑✓ Sidewall Cores: es ❑ 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 ❑Q If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top Permafrost - Base Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval information, including reports, per 20 AAC 25.071. Tyonek G 15427 11572 Hemlock Coal Top 16013 11824 Upper Hemlock 4TPT— 16200 11903 FIE+ Formation at total depth: Lower Hemlock 31. List of Attachments: Baily Operations Summaries, wellbore schematic, directional survey, casing and cement report Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results, per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Authorized Name: Stephen Ratcliff Contact Name: Stephen Ratcliff Authorized Title: VP of Drilling Contact Email: sratcliff@glacieroil.com Authorized Contact Phone: 907-433-3808 �^ Signature: � L Date: to 1-t INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1 a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1 b: Well Class - Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 19: Report the Division of Oil $ Gas 1 Division of Mining Land and Water: Plan of Operations (LO/Region YY-123), Land Use Permit (LAS 12345), and/or Easement (ADL 123456) number. Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 2T 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 512017 Submit ORIGINAL Only GLACIER 30" Conductor RU -06A .,nly Actual Completion Schematic Calc TOC Q 11000' MD 1 12 114" Hole I �7" TOL @13262' MD110310' TVD M.;j =` KOP ,@ 13641' MD/10608' ND r CBL TOC 0 14740' MD 4 yL t 4.5" TOL @ 15823' MD111745' TVD ! TCP Perforations (3-118", 6spf, 60 phase): Top -Bottom MD I Top -Bottom TVD 16200'-16240' MD 111902'-11918' TVD 16265'-16290' MD 111928'-11939 TVD 16440'-16465' MD 111999'-12009' TVD 16500'-16845' MD/12023'-12158'TVD 17020'-17090' MD 112237'-12268' TVD 17150'-17285' MD 112296'-12355' TVD Total = 640ft PBTDICIBP 0 17361' MD Version: Final September 4, 2019 r 4-1f2"tubinghangerwIPH8xDWC1CHTcrossover Set w/3.45ft of compression/20k down on retch -latch seal assy - 4-112" 12.6# LBO DWCIC-HT Tubing - ID 3.958"/Dr R = 3.933" pn 1 250D r Whipstock Window 9 518" 1 47# L-80 I 13641' MD I Inc - 38 ID - 8.681 BTC I 10608' TVD I Azm -187 f�r A 8-112" Hole -Sidetrack 7" 26#131110 18200' MD Inc - 65 ID = 6.184 DWCIC 11 907'TVD Azm - 73 6" Hole - Sidetrack 4.8" 30" 150#A-36 1 200' MD I DWCIC-HT A4 200' TVD y_ y 13 318" 68# L$0 3,480' MD ID - 12AI 5"1 BTC 2,975' TVD - 4-112" 12.6# LBO DWCIC-HT Tubing - ID 3.958"/Dr R = 3.933" pn 1 250D r Whipstock Window 9 518" 1 47# L-80 I 13641' MD I Inc - 38 ID - 8.681 BTC I 10608' TVD I Azm -187 f�r A 8-112" Hole -Sidetrack 7" 26#131110 18200' MD Inc - 65 ID = 6.184 DWCIC 11 907'TVD Azm - 73 6" Hole - Sidetrack 4.8" 1 12.6# LBB 17450' MD Inc .62 ID - 3.958 I DWCIC-HT 12432' TVD Azm - 60 GLACIER RU -06A Daily Operations Summary API: 50-733-20519-01-00 Permit #: 218-083 Rig: Osprey Rig 35 Date Activi 23 July 2019 Continue RIH with whipstock assy to 13604'. Orient tool face to 60deg left of high side. RIH to 13662' MD and find CIBP. Resurvey at 71 deg left of high side. Set whipstock —TOW at 13641', BOW at 13658' MD. Prep for milling window. - f to End of P&A operations under Approved Sundry 318-303. Operations covered under Approved Permit to Drill 218-083. 23 July 2019 Mill window from 13638' to 13662' MD. Milling slowed, vary parameters — no change. POH to 11523' MD.y L�„) 24 July 2019 Continue POH to surface. L/D milling BHA. R/U BOPE test equipment. Change 1►'} top rams to 4-1/2" x 7" VBRs. Test BOPE to 250 psi low / 5000 psi high, annular to 250 psi low / 3750 psi high against 5" and 7" test assy. AOGCC waived witness by Jim Regg. 25 July 2019 Finish testing BOPE. R/D testing equipment. Install wear bushing. M/U 8-3/8" PDC bit to milling assy. RIH with assy to 13385' MD. Wash down from 13386' to 13511' MD. Troubleshoot generator failure. Circulate well at 3bpm. 26 July 2019 Remove failed generator, send in for repairs. Wait on delivery of replacement generator from North Slope. Rig maintenance and top drive repairs. Circulate well at 125 gpm. 27 July 2019 Wait on delivery of replacement generator from North Slope. Rig maintenance. Unload replacement generator. Make modifications for generator install. 28 July 2019 TD: 13683' MD; MW: 10.4ppg; Install replacement generator. Startup Drilled = 21' generators and confirm loading with rig operational. Establish parameters with/without pumps. Drill from 13662' to 13683' MD with 8-3/8" PDC bit and mill assy. Ream & slide mills through window, confirm no issues. POH to / 13623', circulate and prep for FIT. 29 July 2019 TD: 13683' MD; MW: 10.4ppg; Rerform FIT to 13.0 EMW. PDH from Drilled = 0' 13623' to surface. L/D BHA. P/U 8.5" bit and Drilling BHA. RIH to 1600', M/U agitator. RIH to 13415' GLACIER 30 July 2019 TD: 13774' MD; MW: 10.5 ppg; Slip/Cut drill line. Continue RIH to 13602' Drilled = 91' MD. Orient BHA, work through window. Wash to 13683'. Slide drill from 13683' to 13728'. Top drive issue - troubleshoot same. Drill from 13728' to 13774'. Top drive issue - troubleshoot same. POH through window to 13538'. Replace top drive comms cable. RIH to 13630'. Top drive issue - troubleshoot same. 31 July 2019 TD: 14393' MD; MW: 10.5 ppg; Top drive issue - troubleshoot same. RIH Drilled = 619' through window - no issues. Wash to bottom @ 13774'. Drill from 13774' - 14251'. Troubleshoot generator power failure issues. Drill from 14251' to 14393', motor stalled while sliding. Pick up to 14370', pipe stuck - work to free pipe. 1 August 2019 TD: 14393' MD; MW: 10.65 ppg; Continue to work stuck pipe at 14372', Drilled = 0' jarring down. Work stuck pipe jarring up. Coal in returns. Continue to work stuck pipe. Raise mud weight to 10.6 ppg and alter technique for working pipe. Pipe free. CBU x3. PDH backreaming from 14393' to 13570'. Orient and pull through window. Increase MW to 10.6}ppg. RIH to 14168' MD. 2 August 2019 TD: 15146' MD; MW: 10.65 ppg; Wash and ream from 14168' to 14393'. Drill Drilled = 753' to 14639'. Repair top drive. Drill from 14639' to 15146', slide as needed. 3 August 2019 TD: 15562' MD; MW: 10.7 ppg; Drill from 15146' to 15295', slide as needed. Drilled = 416' CBU x2. Backream to 14138'. RIH to 15200' and ream to bottom. Drill to 15562', sliding as needed. 4 August 2019 TD: 16185' MD; MW: 10.7 ppg; Drill from 15562' to 16185', slide as needed. Drilled = 623' Work on generator issues. 5 August 2019 TD: 16210' MD; MW: 10.7 pge• Drill to TD at 16710', sliding as needed. CBU Drilled = 25' x4 and reciprocate pipe, pulling out 1 stand per BU. Backream out of hole from 15849' to 13860'. Work through tight spots as needed. POH on elevators from 13860' to 13415', inside casing. Repair TD. M/U storm packer and hang off for BOPE test. R/U test equipment. Test BOPS 250 psi low / 5000 psi high - good. Test witnessed by AOGCC Rep, Brian Bixby. R/D test equipment. 6 August 2019 TD: 16210' MD; MW: 10.7 ppg; Cut slip drill line. Pull storm packer. RIH and Drilled = 0' orient through window. RIH to 16210', wash and ream as needed. Circulate and reciprocate, prep mud for running liner. Backream out of hole to 14042' 7 August 2019 TD: 16210' MD; MW: 10.7 ppg; Completed the short trip back to the Drilled = 0' window. POH to the directional BHA. L/D 8.5" Bit and Directional tools. Clear the floor and pick up the 7" shoe track. Check floats — good. P/U and RIH with 7" 26# P110 DWC/C liner to 380'. 2 10 TJ. 1 VJAIIIIV GLACIER 8 August 2019 TD: 16210' MD; MW: 10.7 ppg; Continue to P/U 2938ft of 7" 26# P110 Drilled = 0' DWC/C liner. M/U liner hanger and running tool. RIH on 5" DP to window. C&C. RIH to 14873', wash through tight spots as needed. 9 August 2019 TD: 16210' MD; MW: 10.7 ppg; Continue to RIH with 7" liner to 16200', wash Drilled = 0' through tight spots as needed. C&C MOBM for cement job. RU cementing equipment. Pump 35 bbls of 12.659pg mud push, followed ppg cement 1.19 cult sk 443 sks followed by 5bbls mud push, displaced w/331 bbls of 10.7ppg MOBM. Bump plug on time. Floats held. CIP at 23:56hrs. Set hanger at 13262ft. Release running tool from hanger, CBU — mud push trace at surface/no cement. R/D cement equipment. POH to 7630' and L/D extra 5" drill pipe. 10 August 2019 TD: 16210' MD; MW: 10.7 ppg; Continue POH and L/D extra 5" drill pipe and Drilled = 0' L/D liner running tool. C/O VBRs to 2-7/8" x 5", test same - good. M/U 6" directional BHA as per program. 11 August 2019 TD: 16210' MD; MW: 10.7 ppg; Continue M/U 6" directional BHA and RIH to Drilled — 0' 4592ft picking up 4" singles. Rebuild saver sub. Continue RIH on 4' DP to 5429ft. Switch to 5" DP and RIH to 16025ft. Changed out drilling line spool. Wash down last stand to 16072'. CBU. 12 August 2019 TD: 16275' MD; MW: 10.7 ppg; Continue to CBU. Test casing and liner lap to Drilled = 65' 3500 osi for 30 mins. chartand re or -g . R/U and test lower Kelly valve to 250/5000 psi. Drill shoe track to 16200' and old hole to 16210' MD, CBU. Wash and ream rat hole. Drilled new hole to 16230' MD. CBU. Conduct FIT to 14.OpRg FMW - good._Drill from 16230' to 16275'. Troubleshoot MWD detection issues - acquire survey. 13 August 2019 TD: 16793' MD; MW: 10.7 ppg; Troubleshoot MWD detection issues - Drilled = 518' acquire survey. Drill from 16275' to 16793' (290 gpm, 100RPM, 8-10K WOB), backreaming each stand. Slide as necessary. 14 August 2019 TD: 17125' MD; MW: 10.7 ppg; Drill from 16793' to 17125'(285 gpm, Drilled = 332' 100RPM, 8-10K WOB), backreaming each stand. Made 2 slides. CBU x2, R&R. POH on elevators from 17125' to 16745' MD. Worked through 4 tight areas. 15 August 2019 TD: 17187' MD; MW: 10.7 ppg; Continued short trip POH to 16191', inside Drilled = 62' the shoe, worked through tight spots as needed. CBU/R&R. Rig service/slip&cut. RIH to 17125', washing down last 2 stands. Slide from 17125' to 17160'. Rotate from 17160' to 17187'. Unable to drill past 17187', varying parameters. Decision to POH. Unable to pull on elevators due to swabbing. Backream and work through tight spots to 16652'. GLACIER 16 August 2019 TD: 17187' MD; MW: 10.7 ppg; Backream and work through tight spots to Drilled = 0' shoe. POH to surface. Confirm bit was substantially worn. Change bit and M/U BHA #6. RIH to 644'. Shallow test — good. 17 August 2019 TD: 17270' MD; MW: 10.7 ppg; Continue RIH to 16210' MD, circulate. RIH, Drilled = 83' tag at 16247' with 25K. Ream down from 16200 to 16272' and work through until cleaned up. Continue RIH, reaming as needed to 17187'. Drill new hole from 17187' to 17270' MD. 18 August 2019 TD: 17450' MD; MW: 10.7 ppg; Continue to drill new hale from 17270' to TD Drilled =180' @ 17450'. D/. CBU x3, pulling a stand each time. POH, pulled tight at x16934'. BROOH from 16950' to 16840', working through tight spots. 19 August 2019 TD: 17450' MD; MW: 10.7 ppg; Continue BROOH to 16363', working through tight spots. Pumped out to 16180'. C&R. PDH to surface. L/D BHA. 20 August 2019 TD: 17450' MD; MW:10.7 ppg; R/U test equipment. Test BOPE 250 psi low/ 5000 psi high — good. Witness of test waived by AOGCC Rep, Jim Regg. R/D test equipment. R/U to run 4.5"_HU shoe track. RIH with 1613' of 4- 1/2" 12.6# L80 casing. M/U liner hanger. Circulate liner volume. RIH w/liner on 4" DP to 5723'. 21 August 2019 TD: 17450' MD; MW: 10.7 ppg; Continue RIH w/liner on 4" & 5" DP to 16130'. CBU. RIH to 16316' and tag up. Rotate and work through tight spot. Continue RIH to TD at 17450'. Circulate. R/U for cement. Pum 3� 5_bblsof 12.5 ppg mud push, 35 bbls of 15.3 ppg cement. 22 August 2019T D: 17450' MD; MW: 10.7 ppg; Drop dart, displace with 260 bbls of MOBM. Plug did not bump. Floats ok. Attempt to set liner hydraulically x3 —ball not on seat. Attempt to set hanger mechanically— unsuccessful. Circulate cement out to POH w/liner. At 48.5 bbls pumped, ball seated. Pressure up and set hanger. CBU — cement confirmed in returns. POH with running tool. 23 August 2019 TD: 17450' MD; MW: 10.7 ppg; L/D running tool — wiper plug still with tool.,0 la R/U to pressure test liner. Test liner and liner — unsuccess R/U to test� 4 (--' ROPE. Test BOPE against 2-7/8" test joint, 250 psi low / 5000 psi high — good.�� Witness of test waived by AOGCC Rep, Jim Regg. R/D test equipment. L/D excess 4" DP & HWDP. R/U Eline. RIH with CBL into 7" liner, tool malfunction, POH —troubleshoot. It 24 August 2019 TD: 17450' MD; MW: 10.7 ppg; L/D excess 4" DP. Receive backup CBL tool. R/U Eline. RIH with CBL and l0 7" liner from 15758' to 13200' MD. TOC at 14740' MD — approval granted by AOGCC, Guy Schwartz, to proceed. P/U 4- �� 1/2" Cleanout assembly and RIH to 3747'. GLACIER 25 August 2019 TD: 17450' MD; MW: 10.7 ppg; Continue RIH with 4-1/2" Cleanout assembly to 11068'. Work on mud pumps and top drive. Continue RIH to 15977'. Wash from 15977'to 16443' MD. 26 August 2019 TD: 17450' MD; MW: 10.7 ppg; Washed down in the 4-1/2" liner from 16443 to 17363' (LC). Circulated 9-5/8" annulus through well commander. Prep for produced water displacement. Displaced 4-1/2" and 7" liner to produced water, bringing spacer above well commander. Opened WC and displaced 9- 5/8" annulus with produced water. Prepped for POH. POH w/cleanout Assy to 10973'. 27 August 2019 TD: 17450' MD; PW: 8.4 ppg; Continued POH w/cleanout Assy from 10973' to surface. L/D cleanout BHA. Worked on TD, processed MOBM, offloaded 3 ISOs. Received HES CIBP. M/U Plug assembly and RIH to 4716'. D 28 August 2019 TD: 17450' MD; PW: 8.4 ppg; Continue RIH w/CIBP to 173.61'. Dropped ball, �' y once seated pressure up to 3300 psi and set CIBP at 17361' (2' above LC). P/U and mechanically sheared off w/50K over. Pressure tested liner/liner lap against CIBP to 3600 si -good. Received AOGCC approval to move forward with completion program per Guy Schwartz. POH to surface and L/D plug setting tool. P/U TCP guns (3-1/8" guns, 6spf, 60deg phase) as per program to 294. 29 August 2019 TD: 17450' MD; PW: 8.4 ppg; Continue'P/U TCP guns (3-1/8" guns, 6spf, 60deg phase) and RIH as per program to 17307'. R/U Nine. Correlate with RA tag. POH and R/D Eline. Spaced out and fired guns (16200'— 16240' MD, i �(l� 16265'— 16290' MD, 16440'— 16465' MD, 16500'— 16845' MD, 17020'— �" , 17090' MD, 17150'— 17285' MD). Monitored well for 30 mins. Circulate BU. (� 30 August 2019 TD: 17450' MD; PW: 8.4 ppg; Continue circulate BU. POH w/TCP guns. L/D 5", 4", 2-7/8" DP. L/D TCP guns - all shots fired. 31 August 2019 TD: 17450' MD; PW: 8.4 ppg; Continue L/D TCP guns — all shots fired. Wait on boat - service rig/transfer OBM. Offload DP to boat. Continue to L/D DP. R/U to run tubing. Offload tubing from boat. 01 September 2019 TD: 17450' MD; PW: 8.4 ppg; M/U ratch latch seal assy. RIH w/4-1/2" 12.6# L80 DWC/C-HT tubing to 9767'. Prep remaining 155 joints of tubing. 02 September 2019 TD: 17450' MD; PW: 8.4 ppg; RIH with 4-1/2" to 15700'. Establish parameters - no rotation (RH rotation required for ratch latch). Circulate lubricant around. Re-establish parameters - rotation w/up movement. R/U GLACIER 03 September 2019 04 September 2019 Eline, correlate for space out - POH. R/D Eline. Swap out 2 joints. M/U hanger and RIH to 15780'. Pump 100 bbls corrosion inhibitor and displace w/300 bbls produced water. TD: 17450' MD; PW: 8.4 ppg; Slack off to 15822'— slack off with 3.45ft of compression on no go. Test latch with 15K overpull. RILDS and test hanger seals to 250psi low/5000 psi high — good. R/U for pressure test. Test IA to 2500 psi for 30 mins chartsame — good. Witness of test waived by AOGCC Rep, Jim Regg. R/D test equip. Remove landing joint and install BPV. N/D BOPS. TD: 17450' MD; PW: 8.4 ppg; Continue N/D BOPE and N/U tree. Turn well over to Production. End of RU -06A. Cold stack rig. Glacier COOK INLET BASIN REDOUBT SHOAL RU#6A 507332051901 Sperry Orilling Definitive Survey Report 22 August, 2019 HALLIGURTON spsrry Drilling Company: Glacier Protect; COOK INLET BASIN Sftg: REDOUBT SHOAL Well: Redoubt Unit#6 Wellbore: RU#6A Design: RU#6A Prof COOK INLET BASIN Map System; US State Plane 1927 (Exact solution) Geo Datum: NAD 1927 (NADCON CONUS) Map Zone: Alaska Zone 04 Well Redoubt Unit #6 Ha)liburtan Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: System Datum: Well Position +Nl-S 0.00 usft Northing: +El W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore RU#6A Magnettes Model Name BGGM2018 Sample Date 712012018 Well Redoubt Unit 06 Plan: RedoubtUnit# 90.00usft Plan: RedoubtUnit# 90.00usft True Minimum Curvature NORTH US + CANADA Mean Sea Level Using Well Reference Point 2,449,933.9550 usft • Latitude: 60.41' 43.6709 N 200,619.7450 usft . Longitude: 151.40' 14.6560 W usft Water Depth: 40-00 usft Declination n 15.67 DlpAngle Field Strength (°1 (nn 73.57 55,265.65297911 Design RU#6A Dets 8/22/2019 From To (usft) Audit Notes: 148.00 ACTUAL Tie On Depth: 13,634.D0 Version: 1.0 Phase: 13,641.00 16,162.57 MWD+AX+Sag (1) (RU#6A) 16,236.01 17,411.37 MWD+AX+Sag (2) (RU#5A) Depth From (TVD) *NI -S +FJ -W Direction Vertical Sactlon: Section iftt Survey 7001 Name 0.00 UNDEFINED -0.06 3_CB-Flim-GSS (1) -0.42 3 CB-Film-GiSS (1) -0.91 3_CS-Film-GSS(1) -2.09 3_CB-Film-GSS (1) (usft) (usft) (°) 383.93 444.88 534.73 622.47 712.97 (usft) 130.00 0.00 0.00 73.86 Survey Program Dets 8/22/2019 From To (usft) (usft) Survey (Wellbore) 148.00 992.00 RU#6 1361 GYRO (RU#6 PB1) 1,016.00 13,308.00 RU#BPB1 (RU#6 PB1) 13,347.00 13,634.00 RU#6 (RU#6) 13,641.00 16,162.57 MWD+AX+Sag (1) (RU#6A) 16,236.01 17,411.37 MWD+AX+Sag (2) (RU#5A) Survey Tool Name Description 3 CB-Film-GSS A023Ga: Film camera gyro single shot 3 MWD+Sag A002MblISC4: BGGM dec + sag corrections 3_MWD+Sag A002Mb11SC4: BGGM dec + sag corrections 3 MWD+AX+Sag A004Mb/lSC4: BGGM dec & axial + sag Gorr 3 MWD+AX+Sag A004MWISC4: BGGM dec & axial + sag Gorr Survey Date 04/17/2003 04/17/2003 04/17/2003 07/1112019 0 811 31201 9 Map Map Vertical MD (usfg 130.00 148.00 204.00 265.00 324.OD Inc (1) 0.00 0.60 0.60 1.10 1.90 Azi C) 0.00 201,54 305.54 313.54 278.54 TVD (usft) 130.00 148.00 204.00 264.99 323.97 TVDSS (usft) 40.00 58.00 114.00 174.99 233.97 +N1 -S (usft) 0.00 -0.09 -0.19 0.40 0.93 +E1 -W (usft) 0.00 -0.03 -0.38 -1.07 -2.44 Northing ltd 2,449,933.96 2,449,933.87 2,449,933.77 2,449,934.38 2,449,934.95 Easting mil 200,619.74 200,619.71 200,619.36 200,618.69 200,617.33 DLS C M00') 0.00 3.33 1.69 0.84 2.00 Section iftt Survey 7001 Name 0.00 UNDEFINED -0.06 3_CB-Flim-GSS (1) -0.42 3 CB-Film-GiSS (1) -0.91 3_CS-Film-GSS(1) -2.09 3_CB-Film-GSS (1) 364.00 445.00 535.00 623.00 714.00 2.25 2.80 3.90 5.10 7.00 264.54 236.54 197.54 174.54 150.54 383.93 444.88 534.73 622.47 712.97 293.93 364.88 444.73 532.47 822.97 0.97 0.03 -4.10 -10.84 -19.70 -4.60 -7.03 -0.79 -10.32 -7.21 2,449,935.04 2,449,934.17 2,449,930.11 2,449,923.38 2,449,914.44 200,615.17 200,612.71 200,609.85 200,609.15 200,612.04 1.02 2.18 2.74 2.44 3.43 -4.15 3_CB-Film-GSS (1) -075 3_CB-Film-GSS(1) -10.54 3_CB-Film-GSS(1) -12.93 3_CB-Film-GSS (1) -12.40 3_CB-Film-GSS(1) 8/22/2019 8:06.0413114 Paste 2 COMA4SS 5000.15 Build 91 Halliburton Definitive Survey Report Company Project: Site: Well: Wellbore: Design: Glacier COOK INLET BASIN REDOUBT SHOAL Redoubt Unit #8 RU#BA RU#8A Local Co-ordinate Reference: TVD Reference: MD Reierenca: North Reference: Survey Calculation Method: Database: Well Redoubt Unit #8 Pian: RedoubtUnit# @ 90.00ueft Plan: RedoubtUnit# @ 90.00usft True Minimum Curvature NORTH US + CANADA Survey Map Map Vertical MD Inc Azl (usm (1) 0 805.00 8.30 137.54 895.00 10.20 130.54 992.00 13.20 113.54 1,016.00 14.21 111.49 1,110.00 18.60 117.89 TVD TVDSS Waft) (usft) 503.16 713.16 891.99 601.99 986.99 896.99 1,010.31 920.31 1,100.47 1,010.47 +Nl-S (a) -29.38 -39.35 49.36 51.54 -62.78 +EI -W (usft) -0.D5 10.39 27.08 32.34 56.33 Northing lit) 2,449,904.59 2,449,894.35 2,449,883.92 2,449,881.61 2,449,869.76 Easting DLS Section (it) (°1100') (ft) survey Tool Name 200,618.95 2.37 -8.21 3_CS-91rn•GSS (1) 200,629.14 2.45 -0.95 3_C13-Fi1m-GSS (1) 200,645.56 4.68 12.29 3_CB-Film-GSS(1) 200,650.76 4.67 16.74 3_MWD+Sap (2) 200,674.46 5.04 36.66 3_MWD+Sag (2) 1,204.00 1,300.00 1,394.00 1,486.00 1,582.00 22.11 26.53 28.19 29.65 31.74 117.72 116.16 112.67 111.48 111.00 1,186.58 1,276.40 1,360.25 1,440.78 1,523.32 1,GW.58 1,186.40 1,270.25 1,350.76 1,433.32 -78.03 -95.56 -113.G5 -129.77 -147.51 85.25 119.82 158.50 199.73 245.40 2,449,853.78 2,449,835.38 2,449,816.91 2,449,799.15 2,449,780.25 200,702.99 200,737.10 200,775.32 200,816.11 200,861.32 3.73 3.62 3.29 1.71 2.19 60.20 3_MWD+Sag (2) 86.54 3_MWD+Sa9 (2) 120.83 3_MWD+Sag (2) 155.78 3_WM+Sag (2) 194.72 3_MWD+Sag (2) 1,675.00 1,768.00 1,862.00 1,954.00 2,046.00 33.63 36.45 39.18 40.40 41.18 111.62 112.30 112.53 113.17 113.57 1,601.59 1,677.73 1,751.98 1,822.67 1,892.33 1,511.59 1,587.73 1,661.98 1,732.67 1,802.33 -185.77 -185.75 -207.73 -230.60 -254.45 292.19 341.70 394.97 449.22 504.39 2,449,760.81 2,449,739.57 2,449,716.25 2,449,692.01 2,449,666.77 200,907.62 200,956.61 201,009.30 201,062.96 201,117.50 2.06 3.06 2.91 1.40 0.89 234.59 3_MWD+Sag (2) 276.59 3_MWD+Sag (2) 321.65 3_MWD+8ag (2) 367.41 3_MWI7+Seg (2) 413.78 3_MWD+Sag (2) 2,142.00 2,237.00 2,329.00 2,422.00 2,517.00 40.42 40.70 41.21 41.60 41.74 114.32 109.76 109.87 110.08 109.82 1,965.01 2,037.16 2,106.66 2,176.42 2,247.38 1,875.01 1,947.18 2,016.66 2,086.42 2,157.38 -277.90 -299.07 319.51 -340.53 362.08 562.55 620.58 677.31 735.12 794.49 2.449.641.84 2,449,619.20 2,449,597.32 2,449,574.84 2,449,551.79 201,175.05 201,232.52 201,288.71 201,345.97 201,404.77 2.35 0.48 0.56 0.45 0.23 463.13 3_MWD+1;29 (2) 512.98 3_MWD+8ag (2) 561.80 3_MWD+Sag (2) 611.48 3_MWD+Sag (2) 662.52 3_MWD+Sag (2) 2,608.00 2,703.00 2,795.00 2,890.00 2,985.00 42.50 41.94 42.31 41.61 39.26 109.97 109.68 108.37 108.67 109.19 2,314.88 2,385.23 2,453.47 2,524.11 2,596.41 2,224.88 2,295.23 2,363.47 2,434.11 2,506.41 382.85 404.51 424.62 -444.80 464.76 851.88 911.93 970.26 1,030.49 1,088.77 2,449,529.56 2,449,506.39 2,449,484.80 2,449,463.10 2,449,441-64 201,461.61 201,521.09 201,578.90 201,638.59 201,696.34 0.84 0.62 1.04 0.77 2.50 711.87 3_MWD+Sa9 (2) 763.54 3_MWD+Sag (2) 813.98 3_MWD+Sag (2) 866.23 3_M1M3+Sag (2) 916.65 3_MWD+Sag(2) 3,078.00 3,172,00 3,267.00 3,360.00 3,456.00 39.10 39.50 40.51 40.98 41.62 108.85 108.39 110.61 110.97 111.20 2,668.50 2,741.25 2,614.02 2,884.48 2,956.65 2,578.50 2,651.25 2,724.02 2,794.48 2,866.65 483.94 502.95 -523.34 -544.89 567.67 1,144.32 1,200.74 1,258.29 1,315.04 1,374.09 2,449,421.08 2,449,400.64 2,449,378.78 2,449,355.80 2,449,331.53 201,751.38 201,807.30 201,864.32 201,920.50 201,978.96 0.29 0.53 1.84 0.57 0.58 964.69 3_MWD+Sag (2) 1,013.80 3_MWD+Seg (2) 1,063.21 3_MWD+Sa9 (2) 1,111.73 3_MWD+Sag (2) 1,162.13 3 MWD+Sag (2) 3,550.00 3,642.00 3,737.00 3,777.00 3,826.00 42.13 42.38 41.84 41.99 41.05 111.44 111.60 110.35 109.40 109.49 3,026.70 3,094.79 3,165.27 3,195.04 3,231.72 2,936.70 3,004.79 3,075.27 3,105.04 3,141.72 590.46 513.16 535.97 -645.05 555.87 1,432.49 1,490.04 1,549.51 1,574.64 1,605.27 2,449,307.26 2,449,283.11 2,449,258.79 2,449,249.07 2,449,237.48 202,036.75 202,093.71 202,152.59 202,177.48 202,207.82 0.67 0.30 1.05 1.63 1.90 1,211.89 3_MWD+Sa9 (2) 1,260.86 3_MWD+Sag (2) 1,311.65 3_MWD+Sag(2) 1,333.26 3_MWD+S89 (2) 1,359.68 3_MWD+Sag (2) 3,662.00 3,958.00 4,053.00 4,146.00 4,242.00 41.94 43.08 45.01 44.56 44.36 109.56 109.73 109.36 112.20 113.06 3,258.68 3,329.45 3,397.73 3,463.75 3,532.27 3,168.68 3,239.45 3,307.73 3,373.75 3,442.27 563.84 -085.65 -707.75 -730.98 -756.86 1,627.75 1,688.85 1,751.08 1,812.32 1,874.38 2,449,228.94 2,449,205.58 2,449,181.91 2,449,157.12 2,449,129,68 202,230.09 202,290.61 202,352.25 202,412.89 202,474.28 2.45 1.19 2.05 2.20 0.56 1,379.06 3_MWD+Sag (2) 1,431.68 3_MM+Sag (2) 1,485.32 3_MWD+8ag (2) 1,537.69 3_MWD+Sag (2) 1,590.11 3 MWD+Sag (2) tV22J2019 8:06'04PM Paw 3 COMPASS 5000.15 Build 91 company: Glacier Project, COOK INLET BASIN SIW: REDOUBT SHOAL Well: Redoubt Unit #6 Wellbore: RU#6A Design: RU#6A Halliburton Definitive survey Report Local Coordinate Reference. TVD Reference.' MD Reference, North Reference* Survey Caiculatlon Method: Database: Well Redoubt Unit #6 Plan: RedoubtUnit# @ 90.00usft Plan: RedoubtUnit# @ 90.00usft True Minimum Curvature NORTH US + CANADA 8w% -Ey pmp Map Vertical MD Inc Azi TVD TVDSS +W4 +Ef W Northing Easting OLS Sectlon Survey Tool Name Nam 0 (0) (usft) (USM (usft) (usm (ft1 ft rMao) (ftl 4,335.00 42.89 113.01 3,599.58 3,509.58 -781.97 1,933.43 2,449,103.08 202,532.66 1.58 1,639.85 3_MWD+Sag (2) 4,428.00 42.30 113.31 3,568.05 3,578.05 UF. , : 1,991.30 2,449,076.86 202,589.89 0.67 1,688.55 3_MWD+Sag (2) 4,521.00 42.02 113.22 3,736.98 3,646.98 -831.38 2,048.64 2,449,050.75 202,646.58 0.31 1,736.78 3_MWD+Sag (2) 4.614.00 42.25 113.25 3,805.95 3,715.95 -856.00 2,105.97 2,449,024.68 202,703.27 0.25 1,785.01 3_MWD+Sag (2) 4,706.00 41.77 114.51 3,875.80 3,785.80 -881.47 2,163.50 2,446,997.76 202,760.13 1.03 1,833.19 3_MM+Sag (2) 4,806.00 42.60 115.03 3,948.41 3,858.41 -909.04 2,223.25 2,448,968.67 202,819.16 0.92 1,882.92 3_MWD+Sag (2) 4,896.00 42.59 114.57 4,014.67 3,924.67 -934.60 2,278.54 2,448,941.72 202,873.78 0.35 1,928.93 3 MVJD+Seg (2) 4,990.00 41.79 112.50 4,084.32 3,994.32 -959.81 2,336.41 2,448,915.04 202,930.99 1.71 1,977.50 3_MWD+Sag (2) 5,OB3.00 40.43 112.25 4,154.38 4,064.38 -983.09 2,392.95 2,448,890.33 202,986.92 1.47 2,025.35 3 MWD+Sag (2) 5,178.00 39.82 112.48 4,227.02 4,137.03 -1,006.39 2,449.57 2,448,865.60 203,042.93 0.66 2,073.25 3 MWD+Sag (2) 5,270.00 40.69 112.80 4,297.24 4,207.24 -1,029.28 2,504.43 2,448,841.33 203,097.19 0.97 2,119.60 3_M1ND+Sag (2) 5,362.00 42.19 113.36 4,366.20 4,276.20 -1,053.16 2,580.44 2,448,816.03 203,152.58 1.68 2,166.76 3_MWD+Sa9 (2) 5,458,00 42.85 113.60 4,436.96 4,346.96 -1,079.01 2,619.96 2,448,788.67 203,211.41 0.71 2,216.74 3_MWD+Sag (2) 5,551.00 41.53 112.38 4,505.86 4,415.86 -1,103.41 2,677.44 2,448.762.82 203,268.26 1.67 2,265.17 3_MWD+Sag (2) 5,646.00 40.09 111.37 4,577.77 4,487.77 -1,126.55 2,735.05 2,448,738.22 203,325.26 1.67 2,314.08 3_MWD+Sag (2) 5,740.00 39.17 111.50 4,650.16 4,560.16 -1,148.47 2,790.85 2,448,714.B9 203,380.49 0.98 2,361.60 3_MWD+Sag (2) 5,834.00 39.70 112.28 4,722.76 4,632.76 -1,170.73 2,846.26 2,448,691.23 203,435.31 0.77 2,408.62 3_MWD+Sag (2) 5,929.00 41.00 111.06 4,795.15 4,705.16 -1,193.44 2,903.42 2,448,667.07 203,491.87 1.60 2,457.22 3_MWD+Sag (2) 6,022.00 41.62 110.90 4,865.02 4,775.02 -1,215.42 2,960.74 2,448,643.64 203,548.62 0.68 2,506.17 3_MWD+sag (2) 6,1%00 42.48 111.74 4,933.33 4,843.33 -1,237.83 3,018.13 2,448,619.78 203,605.43 1.12 2,555.08 3_MWD+Sag (2) 6,207.00 43.10 110.80 5,001.58 4,911.58 -1,260.75 3,077.01 2,448,595,37 203,663.70 0.96 2,6o5.26 3_MWD+Sag (2) 6,304.00 42.70 109.22 5,072.64 4,982.64 -1,283.35 3,139.04 2,448,571.20 203,725.14 1.18 2,658.57 3_MWD+Sag (2) 6,397.00 41.67 108.00 5,141.55 5,051.55 -1,303.29 3,198.22 2,448,549.77 203,783.79 1.42 2,709.87 3_MWD+Sag (2) 6,491.o0 41.13 109.80 5,212.07 5,122.07 -1,323.42 3,257.03 2,448,526.14 203,842.07 1.39 2,760.76 3_MWD+Sag (2) 6,586.00 40.11 110.41 5,284.17 5,194.17 -1,344.68 3,315.11 2,446,505.42 203,899.59 1.15 2,810.64 3_MVJD+Sag (2) 6,681.00 39.92 li0.98 5,356.93 5,266.93 -1,366.27 3,372.25 2,448,482.38 203,956.16 0.43 2,859.53 3_MWD+Sag (2) 6,775.00 40.12 111.95 5,428.92 5,338.92 -1,388.39 3,428.50 2,448,458.83 204,011.83 0.70 2,907.42 3_MWD+Sag (2) 6,834.00 40.22 112.33 5,474.00 5,384.00 -1,402.73 3,463.75 2,448,443.60 204,048.71 0.45 2,937.29 3_MWD+Sag (2) 6,928.00 40.63 112.12 5,545.46 5,455.46 -1,425.84 3,520.29 2,448,419.05 204,102.64 L,0 2,985.18 3_MWD+Sag(2) 7,022.00 41.26 111.13 5,616.35 5,526.35 -1,448.59 3,577.67 2,448,394.86 204,159.43 0.83 3,033.97 3_MWD+Sag (2) 7,115.00 41.39 110.58 5,686.19 5,596.19 -1,470.45 3635.06 2,448,371.55 2o4,216.24 0.41 3,083.02 3_MWD+Sag(2) 7,210.00 42.23 111.05 5,757.00 5,667.00 -1,492.96 3,694.25 2,448,347.54 204,274.84 0.94 3,133.63 3_MWD+Sag (2) 7,304.00 42.34 110.92 5,826.54 5,736.54 -1,515.51 3,753.30 2,448,323.39 204,333.30 0.15 3,184.05 3_MWD+Sag (2) 7,399.00 42.45 111.36 5,896.70 5,806.70 -1,538.72 3,813.04 2,448,298.76 204,392.43 0.33 3,235.01 3_MWD+Sag (2) 7,491.00 41.81 111.51 5,964.93 5,874.93 -1,561.27 3,870.49 2,448,274.77 204,449.28 0.70 3,283.92 3_MWD+S09 (2) 7,584.00 41.88 110.84 6,034.21 5,94421 -1,583.69 3,928.34 2,448,250.89 204,506.55 0.49 3,333.26 3_MV4D+829 (2) 7,676.00 42.57 111.39 6,102.34 6,012.34 -1,606.96 3,986.01 2,448,227.15 204,563.63 0.85 3,382.47 3_MWD+Sa9 (2) 7,772.00 42.01 110.59 6,173.35 6,083.35 -1,629.11 4,046.32 2,446,202-48 204,623.33 0.81 3,433.97 3_MWD+Sag (2) 7,860.00 42.97 111.19 6,238.24 6,148.24 4,650.31 4,101.85 2,448,179.88 204,678.31 1.18 3,481.42 3_MWD+Sag (2) 7,961,00 44,25 111.65 6,311.37 6,221.37 -1,675.76 4,166.70 2,448,152.79 204,742.49 1.31 3,536.64 3 MWD+Sag (2)- - WV2099 8:00:04PM Paas 4 COMPASS 5000.16 Build 91 Haffiburton Definitive Survey Report Company: Pref' Site: Well. Wellbore: Design: Glacier COOK INLET BASIN REDOUBT SHOAL Redoubt Unit #6 RU#6A RU#8A local Co-ordinate Reference: TVD Reference' MD Reference: North Reference: Survey Calculation Method: Database, Well Redoubt Unit #6 Plan: RedoubtUnit# C 90.00usft Plan: RedoubtUnit# @ 90.00usft True Minimum Curvature NORTH US + CANADA _ ' 9ur�oV Map map Vertical MD (uaft) 8,056.00 8,152.00 8,243.00 8,335.00 8,428.00 Inc (°) 44.96 43.68 43.25 42.23 41.37 AN r) 110.08 110.20 109.99 109.94 109.46 TVD TVDSS Nam Nam 6,379.01 6,289.01 6,447.58 6,357.58 6,513.51 6.423.51 6,581.08 6,491.08 6,650.41 6,560.41 +N1 -S (usft) -1,699.51 -1,722.65 -1,744.20 -1,765.52 -1,786.42 +E/ -W (usft) 4,229.03 4,292.11 4,351.01 4,409.69 4,468.05 Northing fftl 2,448,127.46 2,448,102.72 2,446,079.68 2,448,056.87 2,448,034.50 Easdng DLS Section fftl ('11001 Iftl Survey Tbol Name 204,804.19 1.38 3,589.91 3_MWD+Sag (2) 204,866.67 1.13 3,644.07 3_MWD+Sag(2) 204,925.00 0.71 3,694.65 3_MWD+Sag (2) 204,983.12 1.11 3,745.10 3_MWD+Sag (2) 205,040.92 0.99 3,795.34 3_MWD+Sag(2) 8,519.00 8,615.00 8,714.00 8,803.00 8,898.00 40.91 41.88 41.39 41.75 42.42 109.52 109.40 110.75 110.95 112.09 6,718.94 6,790.96 6,864.95 6,931.53 7,002.04 6,628.94 6,700.96 6,774.95 6,841.54 6,912.04 -1,806.40 -1,827.55 1,650.13 -1,871.15 -1,894.51 4,524.49 4,564.34 4,646.11 4,701.30 4,760.53 2,448,013.09 2,447,990.43 2,447,966.29 2,447,943.87 2,447,919.01 205,096.64 205,156.13 205,217.31 205,271.94 205,330.56 0.51 1.01 1.03 0.43 1.07 3,844.00 3_MWD+Sag (2) 3,895.62 3_MWD+Sag (2) 3,948.68 3_MVVD+8ag (2) 3,995.85 3 MWP+Sag (2) 4,046.25 3_NWD+Sag (2) 8,993.00 9,088.00 9,114.00 9,183.00 9,228.00 42.27 43.72 43.99 43.51 43.74 112.20 112.97 112.92 112.38 112.22 7,072.25 7,141.74 7,160.49 7,210.33 7,242.90 6,982.25 7,051.74 7,070.49 7,120.33 7,152.90 -1,918.63 -1,943.52 -1,950.55 -1,968.92 -1,980.71 4,819.80 4,879.61 4,896.19 4,940.23 4,968.95 2,447,893.38 2,447,866.98 2,447,659.54 2,44T84D.05 2,447,827.54 205,389.20 205,448.35 205,464.76 205,508.31 205,536.72 0.18 1.62 1.05 0.88 0.57 4,095.47 3 MWD+Sag (2) 4,147.01 3_MWD+Sag (2) 4,160.99 3_MWD+Seg (2) 4,198.18 3_MWD+Sag (2) 4,777..49 3_MWD+Sag(2) 9,276.00 9,320.00 9,369.00 9,465.00 9,558.00 44.36 45.24 44.90 43.80 43.48 112.26 112.67 113.40 111.01 110.43 7,277.40 7,308.62 7,343.23 7,411.88 7,479.18 7,187.40 7,218.62 7,253.23 7,321.88 7,389.18 -1,993.34 -2,005.19 -2,018.76 -2,044.14 -2,066.85 4,390.84 5,028.49 5,060.42 5,122.53 5,1B2.56 2,447,814.12 2,447,801.55 2,447,787.17 2,447,760.22 2,447,735.99 205,567.28 205,595.62 205,627.19 205,688.64 205,748.07 1.29 2.11 1.26 2.08 0.55 4,246.66 3 MWD+Sag (2) 4,272.88 3_MWD+Sag (2) 4,299.77 3_MWD+Sag (2) 4,352.39 3 MWD+Seg (2) 4,403.74 3_MWD+Sag (2) 9,652.00 9,745.00 9,836.00 9,929.00 I 10,026.00 42.65 41.99 41.82 40.49 40.55 107.87 106.84 105.66 104.13 105.24 7,547.86 7.616.63 7,684.36 7,754.38 7,828.12 7,457.86 7,526.63 7,594.36 7,664.38 7,738.12 -2,087.91 -2,106.60 -2,123.61 -2,139.35 -2,155.33 5,243.18 5,302.94 5,361.28 5,420.42 5,481.38 2,447,713.39 2,447,693.20 2,447,674.71 2,447,657.48 2,447,639.94 205,808.13 205,867.40 205,925.30 205,984.01 206,044.55 2.06 1.03 0.89 1,79 0.75 4,456.11 3_MWD+Sag (2) 4,508.32 3 MWD+Sag (2) 4,559.64 3_MWD+Sag (2) 4,612.07 3_MWD+Sag (2) 4,666.18 3_MWD+Sag (2) 10,121.00 10,212.00 10,305.00 10,400.00 10,495.00 40.72 39.99 40.62 39.33 38.81 104.66 104.15 104.42 104.66 103.89 7,900.21 7,969.56 8,040.48 8,113.28 B,187.03 7,810.21 7,879.56 7,950.48 8,023.28 8,097.03 -2,171.29 -2,185.96 -2,200.80 -2,216.13 -2,230.90 5,541.15 5,598.22 5,656.52 5,715.60 5,773.62 2,447,622.46 2,447,606.36 2,447,590.03 2,447,573.21 2,447,556.97 206,103.90 205,160.57 206,218.47 206,277.14 206,334.77 0.44 0.88 0.70 1.37 0.75 4,719.16 3_MWD+Sag(2) 4,769.91 3_MWD+Sa9 (2) 4,821.78 3_MWD+Sag (2) 4,874.27 3_MWD+Sag (2) 4,925.90 3_MWD+Sag (2) i I 16,588.00 10,681.00 10,775.00 10,869.00 10,964.00 39.08 39.38 39.83 39.75 39.84 104.37 104A4 103.94 103.78 102.90 8,259.38 8,331.42 8,403.85 6,476.08 8,549.07 8,169.38 8,241.42 8,313.85 8,386.08 8,459.07 -2,245.17 -2,259.80 -2,274.49 -2,288.91 -2,302.94 5,830.30 5,887.25 5,945.35 6,003.75 6,062.91 2,447, 541.26 2,447,525.18 2,447,509.02 2,447,493.13 2,447,477.59 206,391.07 206,447.63 206,505.33 206,563.35 206,622.14 0.42 0.35 0.59 0.14 0.60 4,976.37 3_MWD+Sag (2) 5,027.01 3_MWD+Sag (2) 5,078.74 3_MWD+8ag (2) 5,130.83 3_MWD+Sag (2) 5,183.76 3_MWD+Sag (2) 1106.00 11,153.00 11,249,00 11,343.00 11,436.00 40.09 39.77 39.97 39.88 39.89 103.48 104.15 104.13 103.98 103.02 8,619.58 8,693.96 8,767,64 8,839.73 8,911.09 8,529.58 6,603.96 8,677.65 8,749.73 8,821.09 -2,316.42 -2,331.29 -2,346.33 -2,360.96 -2,374.91 6.120.45 6,180.90 6,240.58 6,299.10 6,357.08 2,447,462.65 2,447,446.25 2,447,429.70 2,447,413.56 2,447,398.17 206,679.31 206,739.37 206,798.64 206,856.77 206,914.38 0.49 0.55 0.21 0.14 0.66 5,235.28 3_MWD+8ag (2) 5,269.22 3_MWD+Sag (2) 5,342.36 3_MWD+Sag (2) 5,394.50 3_MVVD+Sag (2) 5,446.33 3_MWD+Sag (2) - 8/22/2019 8:06:04PM Paine 5 COMPASS 5000.15 Build 91 Halliburton Definitive Survey Report Company: Glacier Local Co-ordinate Reference: Well Redoubt Unit #6 Project COOK INLET BASIN TVD Reference- Plan: RedoubtUnit# C 90.00usk REDOUBT SHOAL MO Reference. Plan: RedoubtUnit# @ 90.00usR Site: Well: Redoubt Unit #5 North Reference: True Wellbore: RU#6A Survey Calculation Method: Minimum Curvature NORTH US + CANADA of ismn Database: Survey 812212019 8:08:04PM Pepe 6 COMPASS 5000.15 Build 91 Map Map Vertical MD Inc (waft) (1) 11,533.00 37.91 11,623.00 37.66 11,710.00 37.69 11,601.00 39.58 11,896.00 40.78 Azi (°) 101.42 102.75 102.70 104.49 107.30 TVD TVDSS (usfU (u�) 6,988.58 8,896.58 9,057.71 8,967.71 9,126.48 9,036.48 9,197.46 9,107.46 9,270.05 9,180.05 +NI -S (usft) -2,387.82 -2,399.37 -2,411.11 -2,424.51 -2,441.31 +E! -W (asst) 6,416.61 6,470.52 6,522.51 6,577.84 6,636.77 Northing rra 2,447,383.75 2,447,370.83 2,447,357.77 2,447,342.97 2,447,324.67 East rig DLS Section If) C 1100') fitl Survey 7col Name 206,973.56 2.29 5,499.92 3_MWD+Sag (2) 207,027.16 0.95 5,548.50 3_MWD+Sag (2) 207,078.83 0.27 5,595.17 3_MWD+689 (2) 207,133.81 2.23 5,644.60 3_MWD+Sag (2) 207,192.29 2.29 5,696.53 3_MWD+Sag (2) 11,994.00 12,085.00 12,176.00 12,267.00 12,364.00 41.57 41.54 41.74 41.44 41.28 106.49 106.2B 105.88 105.20 105.58 9,343.81 9,411.91 9,479.92 9,547.98 9,620.79 9,253.81 9,321.91 9,389.92 9,457.98 9,530.79 -2,460.06 -2,477.09 -2,493.84 -2,510.03 -2,527.04 6,698.50 6,756.41 6,814.51 6,872.71 6,934.50 2,447,304.36 2,447,285.86 2,447,267.64 2,447,249.98 2,447,231.40 207,263.53 207,310.99 207,368.64 207,426.41 207,487.75 0.97 0.16 0.37 0.60 0.31 5,750.62 3_MWD+9a9 (2) 6,801.52 3_MWD+Sag (2) 5,852.67 3_MWD+Sap (2) 5,904.07 3_MWD+Sag (2) 5,958.70 3_MWD+Sag (2) 12,459.00 12,555.00 12,648.00 12,741,00 12,839.00 40.77 40.57 40.70 40.62 40.13 104.94 104.74 104.74 103.16 103.77 9.692.46 9,765.27 9,835.84 9,906.39 9,981.05 9,602.46 9,675.27 9,745.84 9,816.40 9,891.05 -2,543.46 -2,559.49 -2,574.90 -2„589.51 -2,604.29 6,994.66 7,055.14 7,113.71 7,172.51 7,234.25 2,447,213.46 2,447,195.90 2,447,179.00 2,447,162.90 2,447,146.55 207,547.47 207,607.52 207,665.68 207,724.09 207,785.43 0.70 0.25 0.14 1.11 0.64 6,011.92 3 MWD+8ag (2) 6,065.56 3 MWD+Sag (2) 6,117.54 3_MWD+Seg (2) 6,169.96 3_MVJD+Sag (2) 6,225.16 3_MWD+Sag (2) 12,934.00 13,027.00 13,121.00 13,211.00 13,243.00 39.40 39.30 36.67 37.86 37.90 103.79 102.88 102.66 101.65 102.12 10,064.06 10,125.99 10,199.06 10,269.72 10,294.98 9,964.06 10,035.99 10,109.06 10,179.72 10,204.98 -2,618.77 -2,632.37 2,645.55 -2,657.39 -2,661.44 7,293.26 7,350.64 7,408.29 7,462.75 7,481.98 2,447,130.58 2,447,115.52 2,447,100.88 2,447,087.86 2,447,083.13 207,844.06 207,901.07 207,958.37 208,012.51 208,031.63 0.77 0.63 0.67 1.23 0.91 6,277.82 3_MWD+Sag (2) 6,329.15 3 MWD+Sag (2) 6,380.87 3 MWD+Sag (2) 6,429.90 3_MWD+Seg (2) 6,447.24 3 MWD+Sag (2) 13,276.00 13,308.00 13,347.00 13,374.00 13,401.00 37.87 38.35 38.09 37.85 38.00 103.17 103.39 104.72 106.51 106.91 10,321.03 10,346.21 10,376.85 10,398.13 10,419.43 10,231.03 10,256.21 10,286.65 10,308.13 10,329.43 -2,665.87 -2,670.41 -2,676.27 -2,680.74 -21685.51 7,501.75 7,520.97 7,544.38 7,560.37 7,576.27 2,447,078.19 2,447,073.16 2,447,066.71 2,447,061.64 2,447,056.66 208,051.28 208,070.38 208,093.63 208,109.51 208,125.28 1.96 1.56 2.21 4.17 1.07 6,465.00 3_MWD+Sag (2) 6,482.20 3_MWD+Sag (2) 6,503.05 3 MWD+Sap (3) 6,517.18 3_MWD+Sag (3) 6,531.12 3_MWD+Sag (3) 13,439.00 13,498.00 13,574.00 13,603.00 13,634.00 38.49 38.59 37.75 37.51 38.06 107.96 108.02 107.30 107.02 106.74 10,449.27 10,495.42 10,555.17 10,578.14 10,602.64 10,359.27 10,405.42 10,465.17 10,488.14 10,512.64 -2,692.56 -2,703.92 -2,718.17 -2,723.40 -2,728.91 7,595.71 7,633.67 7,678.42 7,695.34 7,713.52 2,447,049.04 2,447,036.80 2,447,021.41 2,447,015.76 2,447,009.79 208,147.53 208,182.19 208,226.57 208,243.35 208,261.38 2.14 0.18 1.25 1.02 1.86 6,550.71 3_MWD+Sag (3) 6,581.14 3_MWD+Sag (3) 6,620.17 3 -MWD +Sag {3) 6,634.97 3_MWD+Sag (3) 6,650.89 3_MWD+Sag (3) 13,641.00 13,731.33 13,743.51 13,836.63 13,930.43 38.06 41.16 41.44 41.81 44.03 106.91 101.94 101.30 96.58 92.21 10,608.15 10,677.74 10,686.69 10,756.66 10,825.22 10,518.15 10,5B7.74 10,596.89 10,666.66 10,735.22 -2,730.16 -2,744.42 2,746.04 -2,755.66 -2,760.49 7,717.65 7,773.41 7,781.28 7,842.48 7,905.00 2,447,008.43 2,446,992.76 2,446,990.94 2,446,979.77 2,446,973.32 208,265.47 208,320.86 208,328.69 206,389.62 208,453.00 1.50 4.89 4.16 3.38 3.97 6,654.51 3_MWD+AX+Sag (4) 6,704.11 3 MWD+AX+829 (4) 8,711.23 3_MWD+AX+Sag (4) 6,767.34 3_MWD+AX+Sag (4) 6,827.01 3_MWD+AX+Sag (4) 14,027.71 14,121.89 14,213.B1 14,308.22 14,402.91 47.81 50.55 54.90 59.83 62.81 87.24 82.40 79.83 76.15 73.70 10,892.90 10,954.48 i1,010.15 11,061.06 11,106.50 10,802.90 10,864.48 10,920.15 10,971.06 11,016.50 -2,760.06 -2,753.57 -2,742.23 -21725.62 -2,7D4.00 7,975.83 8,046.76 8,118.99 8,196.70 8,276.88 2,446,971.96 2,446,976,67 2,446,986.17 2,447,000.79 2,447,020.37 208,522.81 208,593.88 208,666.38 2DB,744.48 208,625.20 5.34 4.86 5.23 6.17 3.88 6,894.21 3_MWD+AX+Sag (4) 6,964.15 3_MWD+AX+8ag (4) 7,036.68 3_MWD+AX+Sag(4) 7,115.94 3_MWD+AX+Sag (4) 7,198.98 3_MWD+AX+Sag (4) 812212019 8:08:04PM Pepe 6 COMPASS 5000.15 Build 91 Company: Project Site Well: Wellbore: Design: SU'wov Halliburton Definitive Survey Report Glacier Local Coordinate Reference: Well Redoubt Unit #6 COOK INLET BASIN TVD Reference: Plan: RedoubtUnit# C 90.00usft REDOUBT SHOAL MO Reference: Plan: RedoubtUnit# @ 90.00usft Redoubt Unit #6 North Reference: True RU#6A Survey Calculation Method' Minimum Curvature RU#BA Database: NORTH US + CANADA MD Inc (usm (°) 14,495.78 62.45 14,588.85 62-67 14,686.90 62.90 14,780.18 63.01 14,874.69 62.04 14,968.36 62.88 15,061.75 62.48 15,155.07 62.54 15,246.08 63.70 15,343.23 64-69 15,438.17 63.86 15,532.23 63.50 15,628.44 63.21 15,720.99 64.39 15,816.62 1.1 .,. 15,909.33 65.41 16,005.71 65.35 16,096.24 65.07 16,162.57 65.16 16,236.01 66.21 16,327.12 66.41 16,419.53 66.53 16,515.48 66.63 1 16,609.62 67.31 16,698.44 67.48 16,735.16 67.62 16,798.41 66.63 16,889.63 63.53 16,968.85 61.06 17 484.26 64.11 17,145.13 63.54 17,239.09 64.06 17,269.36 64.17 17,300.57 - 17,362,68 62.14 „ 17,411.37 61.47 17,450.00 • 61.47 A�1kt[1� Laird - _ r Benjamkn Hand r~ns,rx�d Sir: pC _ owad SY 8/22/2019 8:06:04PM wase 7 Gari_. S.'22,-'2019 i COMPASS 5000.15 Build 91 Map Map Vertical A=I TVD TVOSS +N1-5 +El -W Northing Eseting CLS Section Survey 70ol Name {^) Weft)(usit) (usft) (ueR) vin 1100 roti (.11001 rift 74.64 11,149.20 11,059.20 -2,681.50 8,356.23 2,447,040.84 208,905.09 0.98 7,281.45 3_MWD+A.X+Sa9 (4) 74.78 11,192.08 11102.08 -2,659.72 8,435.90 2,447,060.59 208,965.29 0.27 7,364.04 3_MWD+AX+Sag (4) 73.33 11,236.93 11,146.93 -2,635.78 8,519.74 2,447,082.40 209,069.71 1.34 7,451.23 3_MWD+AX+Sag (4) 73.40 11,279.34 11,189.34 2,611.98 8,599.34 2,447,104.16 209,149.89 0.14 7,534.31 3_MW0+AX+Sa9 (4) 74.52 11,322.94 11,232.95 -2,588.81 8,679.93 2,447,125.27 209,231.04 1.47 7,618.16 3_MWD+AX+Sag (4) 74.41 11,366.26 11,276.26 -2,568.56 8,759.96 2,447,145.48 209,311.61 0.90 7,701.23 3 MWD+AX+Sag (4) 73.73 11,409.12 11,319.12 -2,543.79 8,839.73 2,447,166.21 209,391.94 0.78 7,784.18 3_MWD+AX+Sag (4) 72.10 11,452.20 11,362.20 -2,519.47 8,916.86 2,447,188.51 209,471.66 1.55 7,866.95 3 MWD+AX+Sag (4) 71.65 11,493.34 11,403.34 -2,494.22 8,996.01 2,447,211.79 209,649.42 1.35 7,948.06 3_MWD+AX+Sag (4) 7471 11,535.49 11,445.49 -2,468.90 9,079.79 2,447,234.97 209,633.82 3.09 8,035.59 3_MWD+AX+Sag (4) 74.14 11.576.55 11,486.55 -2,445.92 9,162.24 2,447,255.85 209,716.83 1.21 8,121.19 3_MWD+AX+Sag (4) 74.99 11,618.25 11,528.25 -2,423.48 9,243.51 2,447,276.21 209,798.64 0.90 8,205.49 3_MWD+AX+Sa9(4) 73.19 11,661.40 11,571.40 -2,399.91 9,326.20 2,447.297.67 209,881.91 1,70 8,291.47 3 MWD+AX+Sag (4) 74.48 11,702.26 11,612.26 -2,376.80 9,405.96 2,447,318.75 209,962.23 1.79 8,374.51 3_MWD+AX+Sag (4) 73.93 11,742.81 11,652.81 -2,353.22 9,469.30 2,447,340.20 210,046.14 172 6,461.12 3_MWD+AX+Se9 (4) 74.76 11,781.36 11,691.36 -2,330.47 9,570.48 2,447,350.88 210,127.87 0.81 8,545.43 3_MWD+AX+Sag (4) 75.51 11,621.52 11,731.52 -2,307.99 9,655.17 2,447,381.19 210,213.10 0.71 8,633.02 3 MWD+AX+Sag (4) 74.62 11,859.48 11,769.48 -2,286.81 9,734.58 2,447,400.35 210,293,02 0.94 6,715.19 3_MWD+AX+Sag (4) 73.29 11,887.39 11,797.39 -2,270.18 9,792.40 2,447,415.50 210,351.25 1.82 8,775.36 3_MWD+AX+Sag (4) 73.99 11,917.63 11,B27.63 -2,251.33 9,856.62 2,447,432.71 210,415.93 1.67 8,842.28 3_MWD+AX+Sag (5) 72.87 11,954.23 11,864.23 -2,227.54 9,936.58 2,447,454.47 210,496.47 1.15 8,925.71 3_MWD+AX+Sag (5) 72.36 11,991.13 11,901.13 -2,202.22 10,017.44 2,447,477.72 210,577.95 0.52 9,010.42 3_MWD+AX+Sag (5) 71.15 12,029.27 11,939.27 -2,174.66 10,101.05 2,447,503.15 210,662.24 1.16 9,098.40 3_MWD+AX+Sag (5) 70.05 12,066.10 11,976.10 -2,145.88 10,182.77 2,447,529.84 210,744.66 1.30 9,184.90 3_MWD+AX+Sag (5) 68.19 12,100.24 12,010.24 -2,116.66 10,259.38 2,447,557.11 210,821.98 1.94 9,266.61 3_MVW+AX+Sag (5) 68.12 12,114.26 12,024.26 -2,104.03 10,290.88 2,447,568.93 210,853.79 0.42 9,300.38 3_MWD+AX+Sag (5) 66.73 12,138.85 12,048.85 -2,081.66 10,344.69 2,447,589.92 210,908.15 2.56 9,35828 3_MWD+AX+Sag (5) 65.25 12,177.28 12,087.28 -2,048.02 10,420.25 2,447,621.63 210,964.55 3.70 9,440.22 3_MVJD+AX+Sag (5) 64.50 12,223.41 12,133.41 -2,010.73 10,499.78 2,447,656.89 211,065.00 2.58 9,526.98 3_MWD+AX+Sag (5) 60.18 12,267.35 12,177.35 -1,971.39 10,574.74 2.447,694.31 211,140.94 5.13 9,609.92 3_MWD+AX+Sag (5) 60.61 12,294.20 12,204.20 -1,944.40 10,622.23 2,447,720.08 211,189.10 1.13 9,663.05 3_MWD+AX+Sag (5) 59.82 12,335.68 12,245.68 -1,902.52 10,695.40 2,447,760.08 211,263.31 0.94 9,744.97 3_MWD+AX+Sap (5) 59.75 12,348.90 12,258.90 -1,888.82 10,718.94 2,447,773.19 211,287.19 0.42 9,771.39 3 MWD+AX+Sag (5) 60.84 12,362.72 12,272.72 -1,874.95 10,743.24 2,447,786.43 211,311.84 4.26 9,798.59 3_MWD+AX+Sag(5) 80.08 12,391.20 12,301.20 -1,847.74 10,791.26 2,447,812.41 211,360.53 2.12 9,852.28 3_MWD+AX+Sag (5) 60.00 12,414.20 12,324.20 -1,826.31 10,828.44 2,447,632.89 211,398.24 1.38 9,893.95 3_MWD+AX+Sag (5) 60.00 12,432.65 , 12,342.65 -1,809.34 10,857.83 2,447,849.11 211,428.06 0.00 9,926.90 PROJECTEDtoTD A�1kt[1� Laird - _ r Benjamkn Hand r~ns,rx�d Sir: pC _ owad SY 8/22/2019 8:06:04PM wase 7 Gari_. S.'22,-'2019 i COMPASS 5000.15 Build 91 HALLIBURTOIV Pr°Site: REDOUBT ILS SHOAL sperry orining Well: Redoubt Unit #6 Wellbore: RU#6A Plan: RU#6A I iENCE INFORMATION Co-ordinate (NIE) Reference: Well Redoubt Unit #6, True North Vertical (TVD) Reference: Plan: RedoubtUnit# @ 90.00usft Measured Depth Reference: Plan: RedoubtUnit# @ 90.00ustt Calculation Method: Minimum Curvature WELL DETAU S: Pedwbt Unit 96 woo, north- 40.00 VaFt,cal Se"lon et 73.68' {7004 USTLJln) HALLIBURTON Bpsrry t3rrftting Project: COOK INLET BASIN SiW REDOUBT SHOAL Well: Redoubt Unit 06 Wellbore: RU#6A Plan: RU#6A O� O N � O � O q 44 � hq hN q 0 q b b O nh h N o � O q SIJ�I Q I34U 3i1b0 A56U f C REFERENCE INFORMATION Co-ordinate (N!E) Reference: Well Redoubt Unit #6, True North Vertical (TVD) Reference: Plan: RedoubtUniW @ 90.00usft Measured Depth Reference: Plan: RedoubtUn'd# a 90,00usR Calculation Method: Minimum Curvature WELL DETAM S: Redoubt Unit #6 Well No./ PTD # of it A PTF)91t1I1a3 Glacier Oil d Gas (Cook Inlet Energy) CASING & CEMENTING REPORT County Alaska State Alaska Supv. SING RECORD - Produ ion Casin TO 16210' MD 11190E' TVD Shoe Depth: 18200' MD _/1 1 903' TVO P6TD: Data 10 -Aug -19 Wall/Jeardoe Csg Wt. On Hook: 112k Type Float Culler: Float No. Hrs to Run: 33 Csg Wt On Slips: Type Of Shoe: Pilot Mill Casing Crew: Weatherford Fluid Description: 10.7 ppg OBM J PV = 15 YP= 19 Liner top X Yee No Liner hanger Info (MakelModel): Halliburton VersaFlex - - Liner hanger test pressure: 3500 for 30 mins. Centralizer Placement 1 per first 15, then one every other for 20 its, then one everylhiM for 24. last 11 were bare. First three had stop rings underneath Drifted w18.1 W', used Best -O -Life 2000 dope. Average tq=26k CEMENTING REPORT FSlurry ) Mud Push II Density (ppg) 12.5 Volume pumped (BBLs) 35 ction cement - Class GYell {Ft3lsack): 1.19 15.7 Volume (BBLslsacks): 95bb1s1443sacks Mixing f Pumping Rate (bpm): Yield (Ft3laark): Type: w Density (ppg) Volume (BBLsisaeks): Mixing 1 Pumping Rate (bpm): Post Flush (Spacer) w Type Mud Push II Density (ppg) 13 Rate (bpm): 4 Volume: 5 rc LL Displacement: Type: MOBM Density (ppg) 10.7 ppg Rate (bpm): 7 Volume (actual I calculated): 337337 FCP (psi): Boo Pump used for disp: Rig pumps Plug Bumped? X Yes No Bump press 1300 Casing Rotated? Yes X No Reciprocated? X Yes -No-%Returns during job 100 Cement returns to surface? _Yes X No Spacer returns? X Yes _ No Vol to Surf: Trace mud push Cement In Place At: 21:00 Date: 8!912019 - Estimated TOC: 14,300 Method Used To Determine TOC: CBL TOC =14740' MD Preflush (Spacer) Density (ppg) Volume pumped (BBLs) Type: Lead Slurry Type: Yield (Ftalsack): Density (ppg) _Volume (BBLslsaoks): Mixing f Pumping Rate (bpm): Tail Slurry Yield (Ft3lsaek): Type: a Density (ppg) Volume (BBLslsacks): Mixing 1 Pumping Rate (bpm): �+ Post Flush (Spacer) oRate (bpm): VOlume: o Type: Density (ppg) wDisplacement: Type: Density (ppg) Rabe (bpm): Volume (actual f calculated): FCP (psi): Pump used for tlisp: Plug Bumped? Yes No Bump press Casing Rotated? Yes _ No Reciprocated? _Yes _ No - Returns during job Cement returns to surface? Yes _ No Spacer retums?-Yes _ NO Vol to Surf. Cement In Place At Date: Estimated TOC: Method Used To Determine TOC: Remarks: Well Nod PTD 0 County Glacier Oil & Gas (Cook Inlet Energy CASING & CEMENTING REPORT RI! -08A PTD 218-083 Alaska State Alaska Supv. CASING RECORD - Produ 'on Casin Date 21 -Aug -19 LawsonlJeardoe TO 17450' MD 112433' TVD Shoe Depth: 17450' MD 112433' TVD PBTD: 17381' MD 112391' TVD Csg Wt. On Hook: 320 Type Float Collar. Float No. Hrs to Run: 33 Csg Wt. On Slips: 210 Type of Shoo: Reamer Shoe Casing Crew: Weatherford Fluid Description: 10.7 ppg OBM I PV =18 YF-- 17 Liner hanger Info(MakelModel): HalliburtonVersaFlex Liner topPackeP: X Yes—No Liner hanger test pressure: 3500 for 30 mins. Centralizer Placement 1 perjaim CEMENTING REPORT (Spacer))Density (ppg)Volume pumped (RRCs) rry F Yield {Ft3lsack): ppg) Volume (BBLslsacks): Mixing l Pumping Rate (bpm): ry Type: Yield (Ft3lsack): wDensity (ppg) Volume ( BBLslsacks): Mixing I Pumping Rate (bpm): NPost Flush (Spacer) Density (ppg) Rate (bpm): Volume: � Type: LL 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 % Returns during job Trace mud push 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: No cement Prenush (Spacer) Density (ppg) Volume pumped (BBLs) Type. Lead Slurry Type: Yield {Fl3lsack}: Density (ppg) Volume (BBLslsacks): Mixing! Pumping Rate (bpm): Tail Slurry Type: Yield (FtWsack): w Density (ppg) Volume (BBLsleacks): Mixing !Pumping Rata (bpm): Post Flush (Spacer) Z Type: Density (ppg) Rate (bpm): Volume: yDisplacement: Type: Density (ppg) Rate (bpm): Volume (actual l 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 _ Cement In Place At _ Date: Est(mated TOC: Method Used To Determine TOC: Remarks: ,/ to -'l -ill Schwartz, Guy L (CED) From: Schwartz, Guy L (CED) Sent: Wednesday, August 28, 2019 1:11 PM To: Amanda Dial Cc Don Jones; Osprey Drilling; Stephen Ratcliff Subject. RE: RU -06A - PTD 218-083 Amanda, You have approval to proceed as proposed below .. CBL is waived for the 4.5" liner. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALIff 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 schwartzCalaska.gov). From: Amanda Dial <adial@glacieroil.com> Sent: Wednesday, August 28, 201910:44 AM To: Schwartz, Guy L (CED) <guy.schwartz@alaska.gov> Cc: Don Jones <djones@glacleroil.com>; Osprey Drilling<ospreydrilling@glacieroil.com>; Stephen Ratcliff <sratcliff@gla cie roil.com> Subject: RE: RU -06A - PTD 218-083 Guy, As of this morning we set the CIBP at 17361' (2' above our landing collar) and just finished our 30 minute charted pressure test to 3500 psi. It held (22psi loss over 30 mins), confirming our liner hanger is set and liner lap is good. With the pressure test complete, please confirm approval to proceed. The plan forward as previously described is to RiH with TCP guns and perforate per the depths submitted and run the 4-1/2" completion as per the Sundry. We do not plan to run the CBI- across the 4-1/2" liner. Thank you, Amanda Dial Office: (907) 433-3818 Cell. (907) 382-0124 From: Schwartz, Guy L (CED) < u .schwartz alaska. ov> Sent: Saturday, August 24, 2019 3:53 PM To: Amanda Dial <adial lacieroil.com> Cc: Don Jones <d'ones lacieroil.com>; Osprey Drilling <os re drilAn lacieroil.com>; Stephen Ratcliff <sratcliff&Rlacieroil.com> Subject: Re: RU -06A - PTD 218-083 Amanda, CBL confirms isolation between Hemlock and Tyonek zones. You have verbal approval to proceed. with pressure test and Perforating as proposed. Let me know how the the liner pressure test goes when you get that completed. Regards, Guy Schwartz AOGCC 907-301-4533 Sent from my iPhone On Aug 24, 2019, at 2:16 PM, Amanda Dial <adUal lacleroi Om> wrote: Guy, Please find attached the PDF of the RU -06A 7" CBL. We attempted the CBL run yesterday afternoon but had tool issues that could not be resolved. The backup tool was flown out late this morning and worked properly. We are currently calling TOC at 14740' MD. The shoe is at 16200' MD, however, the 4-1/2" liner top is at 15814' MD. The first tool reading is at 15740' MD. The Tyonek G top is at 15427' MD/11572' TVD. This brings cement 687' MD/311' ND above the Tyonek. Based on the log, there is confirmed cement isolating the Hemlock from the Tyonek. We are not planning to run the GBL across the 4-1/2" liner at this time. Our plan is to move forward with the 4-1/2" cleanout run to ensure we can get the CIBP in place so the pressure test can be conducted. Please let me know if you need any additional information. Thank you, Amanda Dial Office: (907) 433-3818 Cell: (907) 382-0124 From: Schwartz, Guy L (CFD) <guy.schwartz alaska.eov> Sent: Friday, August 23, 201910:36 AM To: Amanda Dial <adial lacieroil.com> Cc: Dan Janes <d'ones lacieroil.com>; Osprey Drilling <ospreydrilline otalacieroil. com>; Stephen Ratcliff <sratcliff ff alacieroil.com> Subject: RE: RU -06A - PTD 218-083 Amanda, Thanks for update... send me PDF of the CBL as soon as you get it. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office ttU-6A Formation MD ND SSTVD Tyonek G 15,427 11,572 -11,482 Hemlock Coal Upper Hemlock 16,013 16,114 11,824 11,867 -11,734 -11,777 Hemlock Silt 16,873 12,170 -12,080 Middle Hemlock 16,980 12,219 42,223 Please let me know if you need additional information. Thank you, Amanda Dial Office: (907) 433-3818 Cell: (907) 382-0124 From: Stephen Ratcliff <sratcliff alacieroil.com> Sent: Thursday, August 22, 201911:39 AM To: Schwartz, Guy L (CED) <euy.schwartz@alaskaa oY> Cc: Amanda Dial <adial lacieroil.com>; Don Jones <d'ones lacieroil.com>; Heather Beat <hbeat lacieroiLcom>; Osprey Drilling <os re drillin lacieroil.com> Subject: Re: RU -06A - PTD 218-083 Guy, Thank you for taking our call this morning. As you are aware, yesterday we ran our 4-1/2" liner to bottom with success and prepared for our cement job. The cement job went as planned, mixing and pumping the planned 35.15 bbls of cement plus the spacer ahead. As we went through our displacement, we did not bump our plug as planned and could not get it to seat. We then shut down for the calculated time for the secondary ball to seat for the backup release. After waiting, we rolled pumps but were unsuccessful in seeing the ball (or plug) seat and pressure up. At that point, we went in to our third and final back up release, stacking weight. We made +/- 20 attempts to stack between 50K to 75K lbs, but were unsuccessful with shearing off and releasing. The decision was made to circulate out the cement and POH. Note that we were not in a position to POH with the cement on bottom and risk getting stuck on the trip out with the liner off bottom or way up in the 7" casing. As we circulated to clear cement, we saw a pressure spike around 40 bbis away. At that point, we moved forward with setting the liner Danger, and all indications are that the setting of the liner was successful. As discussed, we do not believe we have much, if any cement behind the 4-1/2" liner. Based on the previous hole section, we TD'd the 7" liner in the Hemlock and had a successful cement job. Amanda will supply the 7" cement details as well as the FIT test that was performed prior to drilling the remaining Hemlock. Moving forward, we request that we treat the 41/2" liner as a "slotted liner non-cemented" type completion. In order to demonstrate that we have isolation from the Tyonek formation above, we will run a full 7" CBL and submit the data once in hand. We will also perform a casing test to 3,500 psi to confirm that the liner lap holds and there are no leaks. If the conditions above are new . and shown successful, then we would req-„st to move forward with the remainder of the program and TCP the Hemlock zones that were previously submitted in the sundry. In the event that we cannot get a successful casing test to 3,500 psi and a successful cement bond log that demonstrates geologic and zonal isolation we will contact the AOGCC to discuss a contingency plan and how to move forward. We will send over the following data right away: • 7” Cement Details from Daily Drilling Report • 7" FIT Test Data • Well Schematic • Geologic Formation Tops We will also submit the 7" CBL and Casing Test once complete. I will be out of town this weekend and early next week but Amanda Dial will stay in communication with you on all well related matters. In the meantime, please keep Amanda Dial as point of contact, with me copied on all correspondence while I am out of the office. if you have any further questions then please call on my cell or to Amanda directly. Thank youl Regards, Stephen Ratcliff Vice President— Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 0 - (907) 433-3808 C - (907) 433-9738 From: "Schwartz, Guy L (C£D)" < u .schwartz alaska. ov> Date: Thursday, August 15, 2019 at 8:32 AM To: Stephen Ratcliff <sratcliff lacieroil.com> Cc: Amanda Dial <adial lacieroil.com> Subject: RE: RU -06A - PTD 218-083 Exteirnal Sender: Proceed with Caution today.You may bring it by Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALUy 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 yo- . eon unintended recipient of this e-mail, please ate it, without first saving or forwarding it, and, so that the AQGCC is aware of the mistake in sending it to you, contact Guy Schwartz at (907-793- 1226) or (Guy -s hwartz alaska.govj, From: Stephen Ratcliff <sratclifF Iac1 roll.com> Seat: Thursday, August 15, 2019 8:21 AM To: Schwartz, Guy L (CED) < u Schwartz alaska. ov> Cc: Amanda Dial <adial lacieroil.com> Subject: RU -06A - PTD 218-083 Guy, We are nearing TD of our RU -06A sidetrack well. We are currently at 17,125' with planned TD at +/- 17,800'. it is likely that we will TD late Friday. We would like to submit the completion sundry today so that you have time to look at it, as opposed to getting it to you on Monday and after we TD. Are you good with this or would you prefer to have us hold off until. we TD the well. Mainly, I want you to have ample time to review it so we don't put you in a position of needing a verbal to move forward. Call if you would like to discuss. Thanks! Regards, Stephen Ratcliff. Vice President—Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 O - (907) 433-3808 C - (907) 433-9738 <RU -6A 71NCH SCBL RAW.pdf> 6 5350 15400 15450 15500 15550 T� 2 Mr. .I41 1 0 15700 ` I 3 15750 200 VDL (usec) 120011 VAD 650 T T (usec) 150 0 3' AMP (mV) 65 0 RAD AVG 100 -27 — — CCL — 3 3' AMP X 5 - 0 RAD MAX 100 0 GR(GAPi) 150 0(mV)-----_ ------' 20 0 RAD Mid€ 100 GLACIER DATA TRANSMITTAL 2 180 83 3 12 84 Glacier Oil and Gas 188 W. Northern Lights Blvd, Suite 510 Anchorage, Alaska 99503 Cook Inlet Energy_ Phone: (907) 334-6745 Fax: (907) 334-6735 — Date: October 2, 2019 To: Meredith Guhl AOGCC From: Stephen Ratcliff Cook Inlet Energy 1 Glacier Oil and Gas Corp. 333 W. 7th Ave, Suite 100 188 W. Northern Lights Blvd, Suite 510 Anchorage, AK 99501. Anchorage, AK 99503 Phone: 907-279-1433 Phone: (907) 433 - 3808 FAX: (907) 334 - 6735 TRANSMITTAL DESCRIPTION Well Data for RU -06A API: 50-733-20519-01-001 PTD: 218-083 Qty Description 1 CD Contains: - RU -06A Definitive Surveys - RU -06A DGR Dual Gamma Ray & EWR-Phase 4 (MD & ND) - RU -06A Cement Evaluation 1 RU -06A DGR Dual Gamma Ray & EWR-Phase 4 MD 1 RU -06A DGR Dual Gamma Ray & EWR-Phase 4 (ND) 1 RU -06A Cement Bond Log r 1 � Please sign below to acknowledge receipt. THE STATE GOVERNOR MIKE DUNLEAVY George Morris Chief Operating Officer Cook Inlet Energy, LLC 188 W Northern Lights Blvd., Suite 510 Anchorage, AK 99503 Re: Redoubt Shoal Field, Undefined Oil Pool, Redoubt Unit 6A Permit to Drill Number: 218-083 Sundry Number: 319-442 Dear Mr. Morris: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.cogcc.olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision; or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this5a day of September, 2019. SCANNED NOV 2 5 2019 R MS1 OCT 012019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 2n oor ?-% ?ftn 1. Type of Request: Abandon ❑ Plug Perforations ❑ ^Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate 0 • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other. _Stam Guns_ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number. COOK INLET ENERGY LLC Exploratory ❑ Development ❑ Stratigrephic ❑ Service 218-083 3. Address: 6• API Number: 188 W. Northern Lights Blvd, Suite 510, Anchorage, AK, 99503 50-733-20519-01-00 ' 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.712 & 20AAC25.055 Will planned perforations require a spacing exception? Yes ❑ No 10 REDOUBT UNIT #6A 9. Property Designation (Lease Number): J 10. Field/Pool(e): ADL -381203 (surface), ADL -374002 aD)REDOUBT SHOAL UNDEFINED, UNDEFINED OIL ' 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): 17450' - 12433' TVD 17361' MD 12433' TVD 4298 psi None None Casing Length Size MD TVD Burst Collapse Structural 200' 30" 200' 200' WA WA Conductor — — — — — Surface 3840 13 318" 3840 3243 5020 2260 Intermediate 10608' 9 518" Window: 13641' 10608' 6670 4750 Production 2938' 7" 16200' 11907' 9960 6230 Liner 1538' 4-112" 17450' 12433' 8430 7500 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Well Schematic See Well Schematic 4-112" L80 15823' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 4112" x 7" HES Liner Top Packer15823' MD 111745' TVD 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: 10/9/2019 OIL ❑ WINJ ❑r . WDSPL ❑ Suspended GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: George Morris Contact Name: George Morris Authorized Title: lef Operating OfficerContact Email: mortis Iadercill.com Contact Phone: 793-85&0336 ii/� Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commissich so that a representative may witness Sundry Number: ^ k iy1 — L4 Ul- " Plug Integrity F1 BOP Test ❑ Mechanical Integrity Test ElE]`/� Location Clearance Other. Post Initial Injection MIT Req'd? Yes ❑ No ❑ / i L Spacing Exception Required? Yes Subsequent Form Required: 1 E]No / APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Submit Form and 'l L- Form 1 1, Re) s� 41201 7 App ove � pplication isoilitznttf5 flbfr�i t e'R'ateBa�appr a OCT 14�ieMs In Duplicate T %7,7-f I 1 GLACIER September 261fi, 2019 Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7' Ave., Suite 100 Anchorage, Alaska 99501 RE: Sundry Application Cook Inlet Energy, LLC: Redoubt Unit 06A API: SO -733-20519-01-00 Dear Commissioner, Cook Inlet Energy (CIE) hereby submits a Sundry Application for RU -06A, PTD: 218-083 to reperforate selected intervals using Stim Guns. If you have any questions, please contact me at (713) 859-0336. Sincerely, George Morris Chief Operating Officer Cook Inlet Energy, LLC (a Glacier Oil & Gas owned company) 188 W Northern Lights Blvd, Suite 510 Anchorage, AK 99503 r r GLACIER WELL NAME — RU -06A Requirements of 20 AAC 25A05(f) Well Summary Current Status: Currently on injection. Scone of Work: • Rig up Eline. • Reperforate specified zones with Stim Guns. • Rig down Eline. • Turn well over to injection. General Well Information: Reservoir Pressure / TVD: MASP: Wellhead Type/Pressure Rating: BOP Configuration: Well Type: Estimated Start Date: 5,562 psi @ 17,631' MD / 12,642' TVD 4,298 psi Vetco Gray — 5M - Wellhead Assembly Eline WLV Water Injector October 9, 2019 2 GLACIER 1. Completion Procedure Requirements of 20 AA 25.005 (c)(1 3) 1. Rig up Eline. 2. Pressure test lubricator to 5,000 psi. 3. RIH with Stim Guns and reperforate on the following intervals from top to bottom: Top, MD Bottom, MD Top, TVD Bottom, TVD 16200 16240 11902 11918 16265 16290 11928 11939 16440 16465 11999 12009 16500 16845 12023 12158 17020 17090 12237 12269 17150 17285 12296 12355 4. Rig down Eline. 5. Turn well over to injection. 3 GLACIER 1 4 RU -06j, _ Actual Completion Schematic Calc TOG Q 11 000'MD 7" TOL 013282' MD110310' TVD KOP @ 13641' MD110608' TVD CBL TOC @ 14740' MD 4.5" TOL ® 15823' MD111745' TVD TCP Perforations (3-118", Bspf, 60 phase): Top-Boft rn MD1Top-Bottom TVD 16200'-16240' MD 111902'-11919 TVD 15265'-1629[' MD 111928'-11939' TVD 16440'-16485' MD 111999'-12009 TVD 16500'-16645' MD 112023'-12156' TVD 17020'-17090' MD 112237'-12269' TVD 17150'-17285' MD 112296'-12355' TVD Total = 640ft PBTDICIBP 0 17361' MD Version: Final September 4, 2019 4-1W tubing hanger w1PH8xDWC1CHT crossover Sat w13.45ft of oompression120k down on ratch-latch seas asst' 30" 150#A-36 200' MD A -M 200' TVD 1,33/0- 1 ML -80 3,480' MD ID - 112A115"I STC 12,97V TVD 4-112" 12.6# L80 DWCIG-HT Tubing -1D 3.958"/Drift = 3.933" Whl stock Window 9 518" 1 47# L410 1 13641' MD I Od ID - 8.681" BTC 10608' TVD BAR' Hole - Sidetrack 7" 26# P110 16200' MD Inc -65 ID = 6.184 1 DWCIC I 11907' TVD I Azm - 73 6" Hole -Sidetrack 4.5" 1 12.69 L80 17459' MD Inc .62 ID = 3.958 1 DWCIC-HT 12432' TVD Azm - 60 MEMORANDUM date of Alaska Alaska Oil and Gas Conservation Commission Regg DATE: Tuesday, September 24, 2019 P.I. Supervisor ����-j�t SUBJECT: Mechanical Integrity Tests T4; Jim Cook Inlet Energy, LLC. 6A FROM: Bob Noble REDOUBT UNIT 6A Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry JLC NON -CONFIDENTIAL Comm Well Name REDOUBT UNIT 6A Insp Num: mitRCN190922113815 Rel Insp Num: API Well Number 50-733-20519-01-00 Inspector Name: Bob Noble Permit Number: 218-083.0 Inspection Date: 9/21/2019 Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 6A 'Type Inj PTD 2180830 fType W TVD 11752 Tubing 4134 ' ! 4134 4133 " 4133 ` T est SPT Test psi 2938 ' IA 0 3305 00 '� 33 3300 ' BBL Pumped: 8 '1BBL — Returned: 7.9 OA 0 0 1 0 0 Interval MITAI TIF Notes: Tuesday, September 24, 2019 Page 1 of 1 i�2 U-64, P7t� Z -16m_-19 Regg, James B (CED) From: Regg, James B (CED) Sent: Monday, September 9, 2019 11:39 AM �Iqlj To:David Pascal I Cc: Brooks, Phoebe L (CED); Wallace, Chris D (CED) Subject: RE: RU -6 Redoubt Unit Attachments: MIT RU -6A 9-7-19 revised.xlsx Well should be RU 6A PTD should be 2180830 "Test psi" cell is a calculated value and should not be overwritten except for an alternate test pressure required by AOGCC -calculated value is 2936 psi based on the reported packer TVD Test should have been held an extra 15 minutes. For a passing result AOGCC looks for pressure loss during the 2na 15minute interval to be approximately half of the first 15min interval. Test result will be accepted as is. Added to the "Notes": Sundry 319-376. Pre -initial injection MIT. Test witness waived by J. Regg (AOGCC) Revised report attached Jim Regg Supervisor, Inspections AOGCC 333 W.71h Ave, Suite 100 Anchorage, AK 99501 907-793-1236 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 forthe 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 Jim Regg at 907- 793-1236 or iim.reeeCa�alaska.xov. From: David Pascal <dpascal@glacieroil.com> Sent: Monday, September 9, 2019 8:50 AM To: Brooks, Phoebe L (CED) < phoebe. brooks@alaska.gov>; Regg, James B (CED) <jim.regg@alaska.gov>; Wallace, Chris D (CED) <chris.wallace@alaska.gov>; DOA AOGCC Prudhoe Bay<doa.aogcc.prudhoe. bay@alaska.gov> Subject: MIT: RU -6 Redoubt Unit Dear all, Please find the 10-426 for the pre-injection MIT conducted for RU -6 on September 7, 2019. Well was brought online at 2230 on September 8, 2019. Will be requesting another MIT witness when the well stabilizes Thanks and Regards David Pascal Vice President, Operations I Glacier Oil and Gas Corporation SCANNED SEP 17 2419 Email:dpascal@glacieroil.com STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: lim.regg0alaska.94y: AOGCC.Insoeclorsnalaska.gm oebe.brooka s oV OPERATOR: Glacier Oil, and Gas FIELD IF UNIT I PAD: Osprey Platform -Redoubt Unit _ DATE: 09!07!19 OPERATOR REP; Lance Anderson AOGCC REP: waived Chris, wallacenalaska.90 Well RU -BA I Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 0= 01her(desodbe in Notes) PTD 2180830 1 Type Inj W Tubing 0 0 D 0 0 = Other (deswlbe in notes( Type Test P Packer TVD 11745- I BBL Pump 9.3 to 0 3250 3204 3165 L Interval O Test psi 2966 IBBLR@tuml 8.9 1 OA 0 0 0 0 Result P Nates: Sundry319-376. Pre-inital injection MR. Teat witness waived by J. Regg (AOGCC) Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD j Tubing Type Tast Packer TVD p �BBLPRaturn IA Interval Test psi OA Result otes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result Notes Well Pressures: Pretest Initial 15 Min. 3D Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD BBI -Pump IA Interval Test psi 981- Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test PackeriVD 1313L Pump IA Interval Test pal BBL Return OA Result N ea: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO Type Inj Tubing Type Test Packer TVD BBI -Pump IA Interval Test psi BBL Return DA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing Type Test Packer TVD 1381- Pump IA Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTD Type Inj Tubing I I I I I Type Test Packer TVD BBLPUMPI I A I I Interval Test psi BBL Return OA Result Notes: TYPE INJ Codes TYPE TEST codes INTERVAL Codes Result Codes W = Water P - Pressure Test I = Initial Test P = Paw G=C 0= 01her(desodbe in Notes) 4=Four Year Cycle F=Fail S = Slurry V = Required by Vadanw I = lnoondusive I = Industrial Wastewater 0 = Other (deswlbe in notes( N = Not Injectirg Form 10426 {Revised 01!2017} MIT RUGA 9-7-19 revised �.r - LA, ft 2-16063c Reqq, James B (CED) From: Amanda Dial <adial@glacieroil.com> --'Zc cc *-117 C i Sent- Friday, September 6, 2019 5:29 AM To: Regg, James B (CED); Brooks, Phoebe L (CED); Wallace, Chris D (CED); AOGCC Reporting (CED sponsored) Cc: Stephen Ratcliff; Don Jones; Osprey Drilling Subject: CIE RU -06A MIT Test Results (PTD 218-083) Attachments: 10-426 - 09.02.19 - RU -06A MIT -IA Report.xlsx All, Please find attached the Form 10-426 for the MIT -IA conducted on Redoubt Unit #6A. Witness of the test was waived by Jim Regg. The charts are available if required. The work conducted was covered under approved RU -06A Completion Sundry 319-376. Please let me know if you have any questions. Thank you, Amanda Dial Drilling Engineer Glacier Oil and Gas Corp. Office: (907) 433-3818 Cell: (907) 382-0124 188 W. Northern Lights Blvd, Ste 510 Anchorage, AK 99503 SCANNED SEP 1 7 2019 N = Not injetting Form 10426 (Revised 01!2017) 2018-0903_MIT_RU-06A 0 0 G STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to:iim.reoa�alaeka gow' A0GCQ.Insoectors®a1aj ov' Phoabe brcoks0alaska.G4Y chhd a.wallace — alaska.gov OPERATOR: Glacier Oil and Gas 1 FIELD I UNIT I PAD: Redoubt Shoal Field, Undefined Oil DATE: 09/03/19 OPERATOR REP: RDbart Wall I Tim Ashley AOGCC REP: Waived Wap RU-06A Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. PTO 2180830 Type Inj N Tubing 0 160 110 ell Type Test Packer TVD 11745 BBL Pump 8.0 IA D 257Q 2500 2500 Interval Test psi 2500 BBL Return 8.0 DA 10 10 10 10 Result Notes: Sundry #319-376, Tested against 4% liner top @ ISB24 MD. Tested with B,4 ppg PW. Pre-injeotlan MIT. well RU46 Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Type Ta st PTD Type Inj Tubing Packer TVD BBL Pump IA Interval Test psi BBL Return OA Resup Nu s: well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min, Type Teat PTD Type Inj Tubing Interval Packer TVD BBL Pump IA Test psi BBL Return OA Result Nates: Wall Pressures: Pretest Initial 15 Min. 3D Min. 45 Min. eD Min. Type Test PTD Type Inj Tubing Interval PadcerTVO BBL Pump IA Test psi BBL Return OA Result Does: Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. well Type Test PTD Inj Tubing Packer TVD mp �1'3�EILRturn IA Interval Test psi OA Result Nates: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. le Type st PTO Type Inj Tubing Packer TVD BBL Pump A Interval Test psi BBL Return OA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min. 8D Min. Type Test PTD Type Inj Tubing Packer TVD 1381- Mp IA Interval Test psi BBL Return DA Result Notes: Well Pressures: Pretest Initial 15 Min. 30 Min. 45 Min, 60 Min. Type Test PTD Type Inj Tubing Packer TVD BBL Pump IA Interval Test psi BBL Retum OA Result N• ate&: TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Code& W = Water P = Pressure Test I =Initial Test P = Paas G = Gas 0 = Cit., (describe In Notes) 4 u Four Year Cycle F =Feil V = Required by Vwiance I = Inconclusive 5 = Slurry I = InduffUlM Wastewater O = Other (describe in notes) N = Not injetting Form 10426 (Revised 01!2017) 2018-0903_MIT_RU-06A 0 0 G RU -06A Daily Operations Summary API: 50-733-20519-01-00 Permit #: 218-083 Rig: Osprey Rig 35 Date Act_ iylty 19 August 2019 TD: 17450'MD; MW: 1.0.7 ppg; Continue BROOH to 16363', working through tight spots. Pumped out to 16180'. C&R. POH to surface. L/D BHA. 20 August 2019 TD:17450' MD; MW:10.7 ppg; R/U test equipment. Test BOPS 250 psi low/ 5000 psi high — good. Witness of test waived by AOGCC Rep, Jim Regg. R/D test equipment. R/U to run 4.5" liner. WU shoe track. RIH with 1613' of 4- 1/2" 12.6# L80 casing. M/U liner hanger. Circulate liner volume. RIH w/liner on 4" DP to 5723'. 21 August 2019 TD: 17450' MD; MW: 10.7 ppg; Continue RIH w/liner on 4" & 5" DP to 16130'. CBU. RIH to 16316' and tag up. Rotate and work through tight spot. Continue RIH to TD at 17450'. Circulate. R/U for cement. Pump 35 bbls of 12.5 ppg mud push, 35 bbls of 15.3 ppg cement. 22 August 2019 TD:17450' MD; MW: 10.7 ppg; Drop dart, displace with 260.bbls of MOBM. Plug did not bump. Floats ok. Attempt to set liner hydraulically x3 — ball.not on seat. Attempt to set hanger mechanically — unsuccessful. Circulate cement out to POH w/liner. At 48.5 bbls pumped, ball seated. Pressure up and set hanger. CBU —cement confirmed in returns. POH with running tool. 23 August 2019 TD:17450' MD; MW:10.7 ppg; L/D running tool —wiper plug still with tool. R/U to pressure test liner. Test liner and liner lap — unsuccessful. R/U to test BODE. Test BOPE against 2-7/8" test joint, 250 psi low / 5000 psi high — good. Witness of test waived by AOGCC Rep, Jim Regg. R/D test equipment. L/D excess 4" DP & HWDP. R/U Eline. RIH with CBL into 7" liner, tool malfunction, POH —troubleshoot. 24 August 2019 TD: 17450' MD; MW;10.7 ppg; L/D excess 4" DP. Receive backup CBL tool. R/U Eline. RIH with CBL and log 7" liner from 15758'to 13200' MD. TOC at 14740' MD — approval granted by AOGCC, Guy Schwartz, to proceed. P/U 4- 1/2" Cleanout assembly and RIH to 3747'. 25 August 2019 TD: 17450' MD; MW: 10.7 ppg; Continue RIH with 4-1/2" Cleanout assembly to 11.068'. Work on mud pumps and top drive. Continue RIH to 15977'. Wash from 15977'to 16443' MD. G LA C w -'t RU -06A Daily Operations Summary API: 50-733-20519-02-00 Permit #: 218-083 Rig: osprey Rig 35 Date Activily 12 August 2019 TD: 16275' MD; MW: 10.7 ppg; Continue to CBU. Test casing and liner lap to Drilled = 65' 3500 psi for 30 mins, chart and record - good. R/U and test lower Kelly valve to 250/5000 psi. Drill shoe track to 16200' and old hole to 16210' MD. CBU. Wash and ream rat hole. Drilled new hole to 16230' MD. CBU. Conduct FIT to 14.Oppg EMW - good. Drill from 16230' to 16275'. Troubleshoot MWD detection issues - acquire survey. 13 August 2019 TD: 16793' MD; MW: 10.7 ppg; Troubleshoot MWD detection issues - Drill from 16275' to 16793' (290 gpm,10ORPM, 8-10K WOB), Drilled = 518' acquire survey. backreaming each stand. Slide as necessary. 14 August 2019 TD: 17125'MD; MW: 10.7 ppg; Drill from 16793' to 17125'(285 gpm, backreaming each stand. Made 2 slides. CBU x2, R&R. Drilled = 332' 10ORPM, 8-10K WOB), POH on elevators from 17125' to 16745' MD. Worked through 4 tight areas. 15 August 2019 TD: 17187' MD; MW: 10.7 ppg; Continued short trip POH to 16191', inside Drilled = 62' the shoe, worked through tight spots as needed. CBU/R&R. Rig service/slip&cut. RIH to 17125', washing down last 2 stands. Slide from 17125' to 17160'. Rotate from 17160' to 17187'. Unable to drill past 17187', varying parameters. Decision to POH. Unable to pull on elevators due to swabbing. Backream and work through tight spots to 16652. 16 August 2019 TD: 17187' MD; MW: 10.7 ppg; Backream and work through tight spots to Confirm bit was substantially worn. Change bit and Drilled = 0' shoe. POH to surface. M/U BHA #6. RIH to 644. Shallow test — good. 17 August 2019 TD: 17270' MD; MW: 10.7 ppg; Continue RIH to 16210' MD, circulate. RIH, Drilled = 83' tag at 16247' with 25K. Ream down from 16200 to 16272' and work through until cleaned up. Continue RIH, reaming as needed to 17187'. Drill new hole from 17187to 17270' MD. 18 August 2019 TD: 17450' MD; MW: 10.7 ppg; Continue to drill new hole from 17270' to TD Drilled =180' @ 17450' MD/. CBU x3, pulling a stand each time. POH, pulled tight at 16934'. BROOH from 16950' to 1684(, working through tight spots. THE STATE 01ALASKA GOVERNOR MIKE DUNLEAVY Stephen Ratcliff VP of Drilling Cook Inlet Energy, LLC 188 W Northern Lights Blvd., Suite 510 Anchorage, AK 99503 Re: Redoubt Shoal Field, Undefined Oil Pool, Redoubt Unit 6A Permit to Drill Number: 218-083 Sundry Number: 319-376 Dear Mr. Ratcliff: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.adgcc,olaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, J sie L. Chmielowski Commissioner DATED this A day of August, 2019. RBDMS.L� " AU6 2 62019 RECEIVE STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AUG � x/01 20 AAC 25.280 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Aramt4log's hotdown ❑ Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: Run Tubing 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: COOK INLET ENERGY LLC Exploratory ❑ Development ❑ 218-083 3. Address: ❑. B. API Number: Stratigraphic ❑ Service 188W. Northern Lights Blvd, Suite 510, Anchorage, AK, 99503 50-733-20519 01-fl0 . 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? G.O. 712 & 20AAC25.055 Will planned perforations require a spacing exception? Yes No : REDOUBT UNIT #BA 9. Property Designation (Lease Number): 10. FieldlPool(s): ADL-381203 (surface), ADL-374002 (TD) REDOUBT SHOAL UNDEFINED, UNDEFINED OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): I Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): I Junk (MD): Planned: 17790' Planned: 12642' TVD Planned: 17790' Planned: 12642' TVD 4298 psi None None Casing Length Size MD TVD Burst Collapse Structural 200' 30" 200' 200' NIA NIA Conductor -- — - Surface 3640 13 3/8" 3840 3243 5020 2260 Intermediate 10608' 95/8'. Window: 13641' 10608' 6870 4750 Production 2938' 7" 16200' 11907' 9960 6230 Liner Planned: 1960' j 4-112" Planned: 17790' Planned: 12642' 8430 7500 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade:MD (ft): Planned: 16220'-17790' Planned: 11907'-12642' 4-112" 1-80 JuNng Planned: 15830' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): HES Liner Top Packer Planned: 15830' MD 111748' TVD 12. Attachments: Proposal Summary Wellbore schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch F-1Exploratory F1Stratigraphic ❑ Development ❑ Service 14. Estimated Date for 15. Well Status after proposed work: 811912019 OIL ❑ WINJ 0 . WDSPL ❑ Suspended El Commencing Operations: 16. Verbal Approval: Date: GAS ❑ WAG ElGSTOR ElSPLUG ElCommission Representative: GINJ ElOp Shutdown ElAbandoned 17. l hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authged Name: Stephen Ratcliff Contact Name: Stephen Ratcliff Authorized Title: VP of Drilling Contact Email: sratcliff Iaderoil.com el 1 S I t Contact Phone: 907-433-3808 Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ka Plug Integrity ❑ BOP Test M/ Mechanical Integrity Test [ Location Clearance ❑ Other: X- 'S--00/5z � � .a z �iBDMS �w AUG 2 6 2019 Post Initial Injection MIT Req'd? Yes .6 ®❑ f Spacing Exception Required? Yes ❑ No d Subsequent Form Required: / i APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: fjAL Submn Form and, Form 143-Revised 412017 Approved application is veli r o th date of approval. Attachments in Duplicate GLACIER August 15th, 2019 Jessie Chmielowski, Commissioner Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Sundry Application Cook Inlet Energy, LLC: Redoubt Unit 06A API: 50-733-20519-01-00 Dear Commissioner, IT- Vqgg' AUG 15 2019 AOGCC Cook Inlet Energy (CIE) hereby submits a Sundry Application for RU -OSA, PTD: 218-083 to complete the well by running a 4-1/2" completion and TCP perforating intervals as identified by LWD logs. If you have any questions, please contact me at (907) 433-3808. Sincerely, Stephen Ratcliff VP of Drilling Cook Inlet Energy, LLC (a Glacier Oil & Gas owned company) 188 W Northern Lights Blvd, Suite 510 Anchorage, AK 99503 GLACIER WELL NAME — RU -06A Requirements of 20 AA 25.005(f) Well Summary Current Status: RU -06A sidetrack has been drilled. Scope of Work: P/U 600ft of TCP guns • RIH on 4" and 5" drill pipe. • Perforate selected intervals. • POH with spent guns. • Run 4-1/2" 12.6# L80 tubing with seal assembly to 15830' MD. • Space out and land hanger. • Turn well over to injection. Genera! Well information: Reservoir Pressure / TVD: MASP: Wellhead Type/Pressure Rating: BOP Configuration: Well Type: Estimated Start Date: 5,562 psi @ 17,631' MD / 12,642' TVD 4,298 psi Vetco Gray -5M - Wellhead Assembly 13 5/8" 5M BOPE - Annular / VBR / Blind / Kill Line / VBR Water Injector August 19, 2019 2 GLACIER General Note: Full opening Safety Valve will be on rig floor at all times with appropriate crossovers for all pipe being run below rotary table. 1. Completion Procedure Requirements of 20 AAC 25.005 (c)(13) Note: This is a continuation from the RU -06A Permit to Drill procedure (218-013). The sidetrack and completion are operationally intended to be consecutive, pending AOGCC approval. 1. Permit to Drill Submitted separately (PTD 218-083). a. Verify 4-1/2" liner has been run and cemented./ PAg,4�s b. Verify the CBL has been ran and evaluated. ✓ ,,,� C. _ t-0 4pac� ',...arm 2. Verify 3-1/2" x 5" VBRs are installed and tested. cPvr-) 3. Complete BOPE test to 250 psi low/5000 psi high if needed. 4. P/U 600ft of 3-1/8" (6spf, 60deg phase) TCP guns as per program with space pipe as needed. 5. RIH with TCP guns on 4" and 5" drill pipe. 6. Space out guns as directed. ' 7. RU Eline to correlate with RA Tag, RD Eline. 8. Perforate. 1� *-A— /LA's 9. Flow check and confirm well is dead. 10. POH w/spent guns and L/D same. 11. L/D all 4" and 5" drill pipe. 12. M/U 4-1/2" Ratch-latch seal assembly as per Halliburton procedure. 13. RIH with seal assembly on 4-1/2" 12.6# L80 tubing. 14. TIH to +/- 90 ft above the top of sealbore. Take pickup and slackoff weights and record same. 15. Continue slacking off until the string no-gos and ratch-latch is fully engaged. 16. Rotate to the right at least 15 turns to release from the ratch latch. 17. Space out the tubing with space out pups and make-up the tubing hanger and landing joint. 18. Reverse circulate corrosion inhibitor into annulus, prior to landing/engaging hanger. 19. Land the tubing hanger a. Overpull as allowed to verify ratch-latch is re-engaged. 20. Re -land the hanger and RILDS. k GLACIER 21. Test the seals to 250 psi low and 5,000 psi high for 10 mins. 22. Notify AOGCC 48 hours ahead for option to witness upcoming MIT -IA test. 23. Test annulus,A, to 2500 psi for 30 minutes, chart and record same. 24. Lay down landing joint. 25. Install BPV and N/D the BOPE. 26. N/U the 5K 4-1/16" production tree. 27. Test the hanger x adapter void to 250 psi for 5 mins and 5,000 psi for 10 mins. 28. Test the production tree to 250 psi for 5 mins and 5,000 psi for 10 mins. 29. Rig Release. 30. Turn well over to injection. 31. Inform Production Lead Operator of upcoming MIT test requirement (Required once injection stabilizes) rk5 p e- lh v 4 RUd `urrent Wellbore Schematic GLACIER 30" Condi 1 18-112" Hole I Cak:TOC @ 11000' MD 7" TOL @13262' MD KOP @ 73641' MD COP @ 13662' MD TOC tagged @ 14380' MD, Pumped 15.6bbisI 95sx of 15.8ppg Class G cmt 9 518" Model S-3 HYD. Packer @ 1472V MD 2 718" X -Nipple @ 14734' Mn - ID 2.313" 7518 29.7# Model "D" packer @ 14,993' MD TOL @ 14,779' MD 12114" Hole 9 5!8" 1 47# L-80 15,067' MD ID -8.881" BTC 17,748' TVD 7 518" 29.7 # Model "DB" @ 15,030' MD Pertorations 15130' - 15890' MD (11786' - 12393' TVD) s TOC @ 15932' (tagged - 5bbl cmt on top)IM Retainer@ 15,990'MD '8112" Hole Version: V2.1 August 14, 2019 WP05a tangent 30" 150#A-36 200-111113 A-36 200' TVD 13 318" 1 68# LBO 3,840' MD ID .12.415 1 BTC 13,243TVD 6" Hole - Sidetrack 4.5" 1 12.691-80 1 17790' MD Inc - 62 10 = 3.958 1 DWC1C-HT I 12642' TVD Azm - 75 7 518" 1 29.7# LBO I 16,100' MD ID -6.875 dril 527 12,570' TVD 00, "(4 GLACIER 30" Condu 111.1461 posed Completion Schematic CaicTOC @ 11009 MD 7" TOL @13262' MD KOP (1113641' MD CIBP @ 13662' MD TOC tagged Q 14380' MD, Pumped 15.6bbls! t' 95sx of 15.8ppg Class G cmt 9 518" Model S-3 HYD. Packer @ 14728' MD 2 718" X -Nipple @ 14734' MD - ID 2.313" - 7 518"' 29.7# Model "D" packer @ 14,993' MD TOL @ 14,779' MD 12114" Hole 9 516" 1 47# L-80 15,067' MD I. ID - 6.861" BTC 11,748' TVD 7 518" 29.7 # Model "DB" (d 15,030' MD Arno Perforations 15130'- 15899 MD (11786'- 1239T TVD) t�C ®c TOC @ 15932' (tagged - 5bbl cmt on top) Retainer @ 15,990' MD - �s 8112" Hole � " Version: V2.1 August 14, 2019 WP05a tangent 30" 1 11109A-36 I 200' MO A38 200' TVD 13316" I 6891LB0 3,840' MD ID -12AIS I BTC 3,243' TVD 4-112" 12.6# L80 DWCIC-HT Tubing - ID 3.920" 6-112" Hole -Sidetrack 7" 26# P110 I 16210-M Inc - ID = 6.184 - DWCIC 1 1190 %''TVD I AM - 7518" 29.7#11_80 16,100' MD ID - 6.875 H dril 521 12,570' TVD Cut tubing at 14680' COP @ 14685' MD ,; a a-, ! - 4.6" TOL 1 0' MD 2 718" 6.5# P110 EUE Brd Internally Coated ID -2.441" 6" Hole - Sidetrack 4.5" 1 12.0 L80 17790' MD Inc .62 ID = 3.958 1 DWCIC-HT 12642' TVD I Azm - 75 7518" 29.7#11_80 16,100' MD ID - 6.875 H dril 521 12,570' TVD GLACIER 30" Conductor 1 RU -06A Proposed Completion Schematic Cak: T0C @ 11000' MD 7" TOL ®13262' MD KOP 0 13641' MD CIBP @ 13662' MD TOC tagged @ 14380' MD, Pumped 15.6bbls 1 95sx of 15.8ppg Class G cmt 9 518" Model S-3 HYD. Packer @ 14728' MD 2 718" 1FNipple @ 14734' MD - ID 2.313" 7 518" 29.7# Model "D" packer @ 14,993' MD TOL 1 14,779' MD 12114" Hole 9 518' 47# L-00 115,067MD ID - 8.681' 1 BTC 11,748' TVD 7 518.29.7 # Model "DB' (M 15,030'. MD Pertoratlons 15130' -15890' MD (11786'- 1239T TVD) TOC @ 15932' (tagged - 5bbl cmt on top) Retainer® 15,990' MD fIW 30" 15WA-36 200'MD A-36 200' TVD 13 318" 68# L80 3,840' MD ID -12A15 BTC 13,943TVD 4-112' 12.6# L80 DWC/C-HT Tubing - ID 3.920" Version: V2.2 August 22, 2019 W P05a tangent 8.112" Hole - Sidetrack T 26#P110 16210'MD Inc -65 .,.,_ YD ■ 6.181 1 DVNClC 11907' TVD Azm - 73 , fAP �'S7L _ e SIV ` 'I�D 4.5" TOL ® 15815' MD tp I4y Af, Cut tubing at 14680' CIBP @ 14685' MD i't lru� µ 46I1V, r��r 2 718" 6.5# P110 E U E 6rd Internally Coated ID - 2.441" 6" Hole -Sidetrack 12.6#L80 17450' MD Inc - 62 ID 3.958 DWCX-HT 12432' TVD Azm - 60 75!8" 29.7#1-80 16,100' MD ID - 6.a75 Hydrll 521 12,570' TVD Schwartz, Guy L (CED) From: Schwartz, Guy L (CED) Serer Saturday, August 24, 2019 3:53 PM To: Amanda Dial Cc: Don Jones; Osprey Drilling; Stephen Ratcliff Subject: Re: RU -06A - PTD 218-083 Amanda, CBL confirms isolation between Hemlock and Tyonek zones. You have verbal approval to proceed with pressure test and Perforating as proposed. Let me know how the the liner pressure test goes when you get that completed. Regards, Guy Schwartz AOGCC 907-301-4533 Sent from my Whone On Aug 24, 2019, at 2:16 PM, Amanda Dial <adial lacieroil.com> wrote: Guy, Please find attached the PDF of the RU -06A 7" CBL. We attempted the CBL run yesterday afternoon but had tool issues that could not be resolved. The backup tool was flown out late this morning and worked properly. We are currently calling TOC at —14740' MD. The shoe is at 16200' MD, however, the 41/2" liner top is at 15814' MD. The first tool reading is at 15740' MD. The Tyonek G top is at 15427' MD/11572' TVD. This brings cement 687"MD/311' TVD above the Tyonek. Based on the log, there is confirmed cement isolating the Hemlock from the Tyonek. We are not planning to run the CBL across the 4-1/2" liner at this time. Our plan is to move forward with the 41/2" cleanout run to ensure we can get the CIBP in place so the pressure test can be conducted. Please let me know if you need any additional information. Thank you, Amanda Dial Office: (907) 433-3818 Cell: (907) 382-0124 From: Schwartz, Guy L (CED) < u .schwartz alaska. ov> Sent: Friday, August 23, 201910:36 AM To: Amanda Dial <adial@ lacieroll.com> Cc: Don Jones <diones@elacieroil.com>; Osprey Drilling <os re drillin lacieroil.com>; Stephen Ratcliff <sratclifF@glacieroil.com> Subject: RE: RU. -06A - PTD 218083 Amanda, Thanks for update... send me PDF of the CBL as soon as you get it. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CON1FIDENnAUTY NOME. 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; Amanda Dial <adial@ lacieroil.com> Sent: Friday, August 23, 201910:28 AM To: Schwartz, Guy L (CED) < u .schwartz alaska. ov> Cc: Don Jones <diones@glacieroil.com>; Osprey Drilling <os re drillin lacieroil.com>; Stephen Ratcliff <sratcliff@l;lacieroil.com> Subject: RE: RU -06A - PTD 218.083 Guy, Please find attached the RU -06A Daily report for 8/22/19, which describes the operation regarding the 4-1/2" liner cement displacement and setting the hanger. As of this morning, they've pulled and laid down the liner running tool and attempted to achieve the liner test but pressure broke down at 1014psi. Upon pulling the running tool, we found the liner wiper plug had not sheared from the tool which means we do not have anything in the liner to pressure up against since we don't believe there is any cement in the shoe track. I will follow up with you once the results from the 7" CBL are available. Our current plan forward is: Complete the slip/cut. R/U Eline and CBL across full 7" liner. L/D 60 jts of 4" drill pipe and X jts of 5" drill pipe. P/U Cieanout BHA and cleanout 4-1/2" liner and )" liner of any cement stringers. P/U 4-1/2" CIBP and RIH and set above landing collar. Pressure test 4-1/2" liner, liner lap to 3500 psi against CIBP - chart & record. POM. Please don't hesitate to call if you have any questions. Thank you, Amanda Dial Office: (907) 433-381.8 Cell: (907) 382-0124 From: Amanda Dial Sent: Thursday, August 22, 201912:18 PM To: Schwartz, Guy L (CED) < u .schwartz @alaska. ov> Cc: Don Sones <diones lacieroil.com>; Heather Beat <hbeatCu@eiacieroil.com>; Osprey Drilling <os re drillin lacieroil.com>; Stephen Ratcliff <sratcliff lacieroil.com> Subject: RE: RU -06A - PTD 218-083 Guy, Please find attached the following information as requested. • 7" Cement Details from Daily Drilling Report • 7" FIT Test Data • Well Schematic Geologic Formation Tops RU -6A Formation MD ND SmD Tyonek G 15,427 11,572 -11,482 Hemlock Coal Upper Hemlock 16,013 16,114 11,824 1 11,867 -11,734 -11,777 Hemlock Silt Middle Hemlock 16,873 15,980 12,170 12,219 -12,080 -12,223 Please let me know if you need additional information. Thank you, Amanda Dial office: (907) 433-3818 Cell: (907) 382-0124 From: Stephen Ratcliff <sratcliff@glacieroil.com> Sent: Thursday, August 22, 201911:39 AM To: Schwartz, Guy L (GED) <guy.schwartz@alaska.eov> Cc: Amanda Dial <adial lacieroil.com>; Don Jones <d'ones laderoil.com>; Heather heat <hbeat iacieroil.com>; Osprey Drilling:om> Subject: Re: RU -06A - PTD 218-083 Guy, Thank you for taking our call this morning. As you are aware, yesterday we ran our 41/2" liner to bottom with success and prepared for our cement job. The cement job went as planned, mixing and pumping the planned 35.15 bbls of cement plus the spacer ahead. As we went through our displacement, we did not bump our plug as planned and could not get it to seat. We then shut down for the calculated time for the secondary ball to seat for the backup release. After waiting, we rolled pumps but were unsuccessful in seeing the ball (or plug) seat and pressure up. At that point, we went in to our third and final backup release, stacking weight. We made +/- 20 attempts to stack between 50K to 75K lbs, but were unsuccessful with shearing off and releasing. The decision was made to circulate out the cement and POH. Note that we were not in a position to POH with the cement on bottom and risk getting stuck on the trip out with the liner off bottom or way up in the 7" casing. As we circulated to clear cement, we saw a pressure spike around 40 bbls away. At that point, we moved forward with setting the liner hanger, and all indications are that the setting of the liner was successful. 3 As*discussed, we do not believe we have much, if any cement behind the 4-1/2" liner. Based on the previous hole section, we TD'd the 7" liner in the Hemlock and had a successful cement job. Amanda will supply the 7" cement details as well as the FIT test that was performed prior to drilling the remaining. Hemlock. Moving forward, we request that we treat the 4-1/2" liner as a "slotted liner non-cemented" type completion. In order to demonstrate that we have isolation from the Tyonek formation above, we will run a full 7" CBL and submit the data once in hand. We will also perform a casing test to 3,500 psi to confirm that the liner lap holds and there are no leaks. If the conditions above are met and shown successful, then we would request to move forward with the remainder of the program and TCP the Hemlock zones that were previously submitted in the sundry. In the event that we cannot get a successful casing test to 3,500 psi and a successful cement bond log that demonstrates geologic and zonal isolation we will contact the AOGCC to discuss a contingency plan and how to move forward. We will send over the following data right away: e 7" Cement Details from Daily Drilling Report e 7" FIT Test Data e Well Schematic + Geologic Formation Tops We will also submit the 7" CBL and Casing Test once complete. I will be out of town this weekend and early next week but Amanda Dial will stay in communication with you on all well related matters. In the meantime, please keep Amanda Dial as point of contact, with me copied on all correspondence while I am out of the office. If you have any further questions then please call on my cell or to Amanda directly. Thank you I Regards, Stephen Ratcliff Vice President — Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 0 - (907) 433-3808 C - (907) 433-9738 From: "Schwartz, Guy L (CED)" < u .schwartz alaska. ov> Date: Thursday, August 15, 2019 at 8:32 AM To: Stephen Ratcliff <sratcliff lacieroil.com> Cc: Amanda Dial <adial@glacieroil.com> Subject: RE: RU -06A - RTD 218-083 . You may bring it by today. 4 Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office GONFIDENTIALIiy 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 (Guys hwartz@alaska.aov_}. From: Stephen Ratcliff <sratcliff lacieroil.com> Sent: Thursday, August 15, 2019 8:21 AM To: Schwartz, Guy L (CED) < u .schwartz alaska. ov> Cc: Amanda Dial <adial lacieroil.com> Subject: RU -06A - PTD 218-083 Guy, We are nearing TD of our RU -06A sidetrack well. We are currently at 17,125' with planned TD at */- 17,800'. It is likely that we will TD late Friday. We would like to submit the completion sundry today so that you have time to look at it, as opposed to getting it to you on Monday and after we TD. Are you good with this or would you prefer to have us hold off until we TD the well. Mainly, I want you to have ample time to review it so we don't put you in a position of needing a verbal to move forward. Call if you would like to discuss. Thanksl Regards, Stephen Ratcliff Vice President—Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 0 - (907) 433-3808 C - (907) 433-9738 <RU -6A 71NCH SCBL RAW.pdf> SchwarM Guy L (CED) From: Stephen Ratcliff <sratcliff@glacieroil.com> Sent Tuesday, August 20, 2019 10:08 AM To: Davies, Stephen F (CI=D); Schwartz, Guy L (CED) cc Heather Beat, Amanda Dial Subject: Re: Redoubt Unit 6A (PTD 218-083, Sundry 319-376) - Perforation Depths Steve / Guy, See below with updated ND's: RU -6A Perforations Top MD Base MD Top TVD Base TVD Footage 16200 16240 11903 11919 40 16265 16290 11929 11939 25 16440 16465 11999 12009 25 16500 16845 12023 12158 345 17020 17090 12238 12270 70 17150 17285 12296 12356 135 Total Perforated Footage 640 Please let us know it, you need anything else. Regards, Stephen Ratcliff Vice President — Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 0 -1907) 433-3808 C - (907) 433-9738 From: "Davies, Stephen F (CFD)" <steve.davies@alaska.gov' Date: Friday, August 16, 2019 at 10:22 AM To: Stephen Ratcliff <sratcliff@glacieroil.com> Subject: Redoubt Unit 6A (PTD 218-083, Sundry 319-376) - Perforation Depths Extanat Sender: Proceed with Cain an - What are the approximate depths for the planned perforations in RU 6A7 These depths are important as Statewide spacing requirements apply. Digital LWD log data (GR, resistivity, and porosity) for RU 6A in .las format would be most helpful if they are readily available. Thank you, Steve Davies Senior Petroleum Geologist AOGCC CONFIDEN77ALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907.793-1224 or steve.davies a@ataska.g_ov. Dairies, Stephen F (CED) From: Stephen Ratcliff <sratcliff@glacieroil.com> Sent: Friday, August 16, 2019 12:47 PM To:Davies, Stephen F (CED) Cc: Amanda Dial; Heather Beat Subject- Re: Redoubt Unit 6A (PTD 218-083, Sundry 319-376) Perforation Depths Steve, We should have it determined by Monday. As of right now, we still have +/- 400' to drill. Once we TD, hopefully tomorrow, we will send over the interval. Let me know if you have any questions in the meantime. Regards, Stephen Ratcliff Vice President —Drilling Glacier Oil and Gas Corporation 188 W. Northern Lights Blvd., Suite 510 Anchorage, AK 99503 O - (907) 433-3808 C - (907) 433-9738 From: "Davies, Stephen F (CED)" <steve.davies@alaska.gov> Date: Friday, August 16, 2019 at 10:22 AM To: Stephen Ratcliff <sratcliff@glacieroil.com> Subject: Redoubt Unit 6A (PTD 218-083, Sundry 319-376) - Perforation Depths F�cternal Sender: Proceed �wieh Cautiarl ' What are the approximate depths for the planned perforations in RU 6A? These depths are important as Statewide spacing requirements apply. Digital LWD log data (GR, resistivity, and porosity) for RU 6A in .las format would be most helpful if they are readily available. Thank you, Steve Davies Senior Petroleum Geologist AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e- mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 9a7-793-1224 or geve.davies alaska. ov. Davies, Stephen F (CED) From: Davies, Stephen F (CED) Sent: Friday, August 16, 2019 10:22 AM To:Stephen Ratcliff Subject: Redoubt Unit 6A (PTD 218-083, Sundry 319-376) - Perforation Depths Stephen, What are the approximate depths for the planned perforations in RU 6A? These depths are important as Statewide spacing requirements apply. Digital LWD log data (GR, resistivity, and porosity) for RU 6A in .las format would be most helpful if they are readily available. Thank you, Steve Davies Senior Petroleum Geologist AOGCC CONFIDENTIALITY NOTICE: This e-mail message, Including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. if you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies alaska. ov. Daily Drilling Report Te12: Consuilent: Robert WatlNHes Jeardoe Te11: LIWL 50.733-20519-01-00 WELL: RU -06,11 Remzrks: j SAFETY FIRST IN ALL OPERATIONS NO INCIDENTS, ACCIDENTS, OR SPILLS 2 - GIA 15 - Nordic 1- VGES Expeoitor 2 - MI $WACO 4- MagTec 2-BOS 2 - Caring Mud logggers 4 - Sperry 1 - Warrior 1 - Waltiburkon Total Drilling on board =34 Fuel on board 16,241 Gal Fuel used = 969 Gal Potable water = 17,748 Gal Rig water =29,645 Gat Rig water in legs =16,800 24 Hour fluid losses = 0 BELS Fluid losses to date = 0 BBLS Metal recovered last 24 hours = 0,0 lbs Metal recovered to dale - 362.6 lbs Luba 776 added to mud: 0 Lube 776 added to mud to date: 20 �Fim� frorr Tiima is Hours --- 00:00 1 04.00 1 4 1 UConfinue to run 7" liner FI 1487, 15550', Rotate pipe FI 15550 to 15562' and FI 15600 to 15621' at 15 RPM = 22K TQ. 6 BPM : 1150 PSI, ROTW - 280K, WOB = 25K. Wash down with increased running weed FI 15621' to 15180' PI11NT = 365K, SOWT z 185K 04:00 04:30 0.5 M/fJ cement head and single to string. Wash down to TD at 162W MD 04:30 09:00 4.5 Circulate and condition mud. 6 BPM =1700 PSL Reciprocate pipe anu _Wash down to 16210' MD —sT No 611 on bottom. Reciprocate 25 to 28 foot stroke. BriWAMLup to 7 BPM pressure came.__ own after first bottoms up to 1150 PSI dD 7 BPM. a helobin dog house. Rig crew, cementers, Halliburton hand, TP, CM, MM.Covered the cement job Land seftiEg the liner. 09:00 12:00 3 Ria ua rr_rnenters hard line to ria flonr- mrrnect to cement head. Isolate too drive. 1 Pressure up to 1400 PSI. Hold for 5 mins. Bleed off. Floats held. Liner was positioned a 16200 10 fleet off bottom, In tension with 355K on weight indicator. —CIP 11:56,1.19 IMId, 443 sks. --'!lop of liner at 13252' MD 12:00 13:30 1.5 Pressure up to 5000 PSI = 5.7 BBLS to deploy flapper. Bleed off pressure. Pressure up again to 000 PSI = 3.7 t38LS in set packer. PIU to 380K, SIO to 25_OK. PAJ to 400K, W to 200K. PN to 310K and Unsting from Packer. Pull W hole 20 R. �_ _e 13:30 15:00 - 1.5 CBU IX at 500 GPM = 2200 PSI. Minor; of mud push at bottoms up, but no oement observed. ^-- 15:00 16:3_0_ 1.5 RID cement head and cement lines. Pump dry job. 4 BPM - 350 PSI 16:30 18:30 2 — POOH and VD DP 1X1 F/ 13240' to 12098'. 18:30 19:30 1[Troubleshoot sensor override on Iron Roughneck 19:30 00:00 C 4.5 Continue POOH Fl 12098' to 7630' MD. PUWT = 205K. UD a total of 90 joints to pipt deck - --- --Total 24__ Version 1422 WWHman 9 - Resource Energy Solutions Ina (403) 2464220 www.resvurc8energyso1ukxns.WM August 10 2019 Page 2 of 2 UWL 50-733-20519-01-00 Remarks: SAFETY FIRST IN ALL OPERATIONS NO INCIDENTS, ACCIDENTS, OR SPILLS 2 -GLA 15 - Nordic 1 - VGES Expeditor 2 - MI SWACO 6 - MagTec 2-BOS 1- Halliburton 1 -Baker 1 -Weatherford 1-Tripoint 1 -GE Vetw Total Drilling on board =33 Fuel on board 8,493 Gal Fuel used = 894 Gal Potable water = 21,879 Gal Rig water =33,040 Gal Rig water in legs = 16,800 24 Hour fluid losses = 0 BBLS Fluid losses to date = 47 BBLS Metal recovered last 24 hours =0 lbs Metal recovered to date = 419.2 lbs Lube 776 added to mud: 0 Lube 776 added to mud to date: 21 WELL: RU -06A Daily -Drilling Report Te12: ultant: R Lawson I T Ashle Tell: ' DATE: .2019.0$.22 ne from Time to Hours I Code Comments 00:00 01:30 1.5 Wash up cement lines, Drop Dart. Pump 5 bbis of Mud Push and kicked dart out. Displaced Cement with 260 bbls. Did not bump plug. P/U Wt 320k SIO Wt 210k. After cement turned corner, stopped Reciprocating and started Rotating the string. 10 RPM 14-16k torque. Checked floats, OK 01:30 03:30 2 03:30 04:00 0.5 04:00 06:00 2 06:00 07:30 1.5 07:30 12:30 5 12:30 13:30 1 13:30 14:30 1 14:30 15:30 1 15:30 17:30 2 17:30 1$:00 0.5 18:00 19:30 1.5 19:30 20:30 1 20:30 00:00 3.5 I Total 24 n ted to set Liner hydraulically 3 times, attem t 1 pumped .5bbls bled .5bbis back no returns rved, attempt 2 pumped 3bbis and bled 5bbls back no returns observed, attempt 3 pumped 1.5bbls and .5bbls back and observed returns while pumping. Ball not on seat, Worked to set liner using ianical emergency release, Failed. ed Circulating. 240GPM 1800 PSI Pressure increased to 4200 PSI after 48.5 bbls pumped. 'chlumberger up, test lines, and pressure up to 4800 PSI to expand hanger. Rigged down Schlumberger :d up single, WU TD and broke circulation. Worked pipe up 350K, dawn 150k. Free from liner slate bottoms up with 12 BPM & 1800 PSI Cement returned @_ 6000 strokes & kg out for 70 bbls. Sig pipe 1H to 8,800', pipe wet, Dropped drift on stand # 148 we elevators to 4". Move 7 stands in derrick to ODS Change elevators to 5" )H F18,800' to 7,569". Initial PIU Wt 200k, Final PIU Wt 165k, Pull Wet ped Dry fob. Unsucessful. )H FI 7,56910 5,675'. Pulling Wet ip another Dry Job. Unsucessful. Changed out mud bucket rubbers )H Wet F15 675' T/ 4,066'. PIU Wt 100k ncie handling tool Nuipment from 5" to 4" )H Wet F14,066 to Surface. Wiper plug still attached to setting tool. in #1 Mud Pump suction line while POOH Version 1422 Wellman 9 - Resource Energy Solutions Inc. (443) 245-0220 www.resourceenergysolutiona com August 23 2019 Page 2 of 2 PRESSURE INTEGRITY TEST Glacier Gil and Gas Well Name: RU -06A RGg: Glacier 35 pate: 1 8/12/2019 1 Volume Input Volume/Stroke Pump Rate: ' Drilling Supervisor: R. Wall I W. Jeardoe Pump used,* #2 Mud pump Strokes 'W 0.0680 Obis/Strk 7 Strklmin qw Type of Test: 1 11other- See Comments w Pumping down I annulus and DP. ♦ $ ng Test Pressure I rity Test Hole Size: 6" 1w Casing Shoe Depth Hole Depth Pumping Shut-in Pumping Shut-in 116200.01IFt-MD111903.0 RKB-CHF,l IFt Ft N Ft -MD I I Ft -TVD Strks psi Min I psi Strks psi Min psi Casing Size and DescrIPd2n: 9-5/8.40#/Ft L-80 BTC 0 0 0 3650 0 0.00 2040 Cosi T Mud Weight: 10.7 ppg Mud 10 min Gel: 17.0 Lb1100 Ft2. Test Pressure: 3500.0 psi Rotating Weight: Lbs BfxkslTop Drive Weight 45.0 Lbs Estimates for Test: 15.8 bbis Pressure Inte r' Test Mud Weight: 7 ppg Mud 10 -min Gel: 0 Lb/100 Ft2 Rotating Weight: 265.0 Lbs Blocks/Top Drive Weight: 45.0 Lbs Desired PIT EMW: 14.0 ppg Estimates for Test: 2043 I 9.2 bbls 5 132 10 212 1 3650 2 3650 5 130 10 240 0.25 2020 0.50 2010 15 287 3 3647 15 350 1.00 2010 20 363 4 3641 20 450 1.50 2005 25 438 5 3636 25 550 2.00 2000 30 496 6 3630 30 640 2.50 2000 35 564 7 3626 35 735 3.00 2000 . V 40 637 8 3621 40 840 3.50 1995 _ EMVI�'=weak-off Pressuna�ei�jht = - 2� + 10.7 0.052 x TVD 0.052 x 11903 EMW at 16200 Ft-MD(11903 Ft -ND) 14.0 N PR 15 Second Shutan Pressure, I 45 707 9 3617 45 925 4.00 1990 50 784 10 3612 50 1040 4.50 1990 2024 55 858 15 3594 55 1140 5.00 1985 4000 -- --- - -- - - Lost 103 psi during test, field T.2% of test pressure. 60 930 20 3576 60 1245 5.50 1980 - - 65 1003 25 3561 65 1340 6.00 1980 _ 3500 70 1076 30 3547 70 1440 6.50 1975 _ 75 1154 40 3521 75 1545 7.00 1975 - - �- - - - 80 1221 50 3504 80 1650 7.50 1975 _ - 85 1297 85 1740 8.00 1975 3000 - - 90 1375 95 1451 90 1850 95 1945 8.50 1970 9.00 1965 Lu 2500 - 100 1527 '100 2040 9.50 1965 -- ---� - --- y 2D00 All 120 1826 105 10.00 1965 W - 140 2136 110 160 2439 115 M 1500 180 2761 120 1060 200 3085 125 - 220 3390 130 2401 3650 5oa �.. 0 5 10 1s 20 25 30 Shut -In time, Minutes o Prr Point our 0 2 4 a a 10 12 14 18 1s Barrels �wCASIKGTEST -Do-LEAK-OFF TEST Pum d o ume"Pumoed Bled Back Volume Bled Back S S S Comments: During the casing test the pump didnot catch rimeor t e first 8 bbls, the prstrap ►verified the volumes infout were equal. During the FIT the pump was kept at 10 spm and did not got starved for fluid. 7 inch shoe Summary THE STATE 01ALASKA GOVERNOR BILL WALKER Stephen Ratcliff Drilling Manager Cook Inlet Energy, LLC 601 West 5th, Suite 310 Anchorage, AK 99501 Alaska Gil and Gas Conservation Commission Re: Redoubt Shoal Undefined, Undefined Oil Pool, Redoubt Unit 46A Cook Inlet Energy, LLC Permit to Drill Number: 218-083 Surface Location: 1909' FSL, 318' FEL, Sec. 14, T7N, RI 4W, UM Bottomhole Location: 51' FNL, 374' FWL, Sec. 20, T7N, RI 3W, UM Dear Mr. Ratcliff: 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov Enclosed is the approved application for the permit to redrill 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. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. 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, tuz�� Hollis S. French Chair DATED this 2-C day of July, 2018. 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): 16100 12570 15932 15932 12428 NIA Casing Length Size Cement Volume MD TVD Conductor/Structural 200 30 nla 200 200 Surface 3840 13 318 S1: 4171 cuft, S2: surface 3480 2975 Intermediate 15085 9 518 1288 cuft 15085 11748 Production Liner 1321 75/8 547 cuft 16100 12570 Perforation Depth MD (ft): 15130-15890 Perforation Depth TVD (ft): 11786-12393 Hydraulic Fracture planned? Yes❑ No ED 20. Attachments: Property Plat Fl� BOP Sketch e Drilling Program ❑ Time v. Depth Plot e Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirementsE/ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Stephen Ratcliff Authorized Name: Stephen Ratcliff Contact Email: sratcliff@glacieroil.com Authorized Title: Drilling Manager Contact Phone: 907-433-3808 Authorized Signature: 1 Date' 1 I t z S s Commission Use Only Permit to Drill 3 API Number: / Permit Approval See cover letter for other Number: ZC50 3 - 2-CL57 I? —fir —co I Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce con 1beJ Amethee, gas hydrates, or gas contained in shales: Other: � � . �+� $m$a Z'E3i -rd =%dL S { Samples req'd: Yes ❑ No[o Mud log req'd: Yes❑ CIE t� HZS measures: Yes ❑ No Directional svy req'd: YesWNo❑ VOID sc,� to-y6�r r SriQ� Inclination -only s re d: Yes III���III''' Noy C may!,Spacing exception req'd: Yes ❑ No Y �+5+ req' d: �J uy`�,; Post initial injection MIT req'd: Yes No❑ b-'y�*i 42.t}G7Ur<�tc� pesr�R,wr t�� APPROVED BY e, Approved by:kADDT! COMMISSIONER THE COMMISSION Date: A n ❑ I G INAt Submit Form and Form 10-401 Revised 512p17 This permit is vaT approvalyperor 20 AAC 25.005(8) Attachments in Duplicate RECEIVED STATE OF ALASKA f iKA OIL AND GAS CONSERVATION COMP )ON PERMIT TO DRILL JUL 12 2098 20 AAC 25.005 1 a. Type of Work: 1b. Proposed Well Class: Exploratory- Gas 0 Service - WAG Service - Disp 1c. S ed for: Drill ❑ Lateral ElStratigraphic Test F-1Development- Oil ❑ Service - Wini [i . Single Zone ❑� Coalbe' Plydrates ElRedrill 0 ' Reentry F-1 Exploratory - Oil ElDevelopment - Gas ElService - Supply ElMultiple Zone ElGeothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑s . Single Well ❑ 11. Well Name and Number: COOK INLET ENERGY, LLC Bond No. 61212870 - REDOUBT UNIT #6A 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 601 W 5TH AVE STE 310, ANCHORAGE, AK, 99501 MD: 17631ft TVD: 12642ft' 4a. Location of Well (Governmental Section): 7. Property Designation: REDOUBT SHOAL UNDEFINED/ Surface: 1909' FSL, 318' FEL, Sec. 14, T7N, R14W, SM ADL 381203 (surface), ADL 374002 (TD) UNDEFINED OIL Top of Productive Horizon: B. DNR Approval Number: 13. Approximate Spud Date: 371• FNL, 894' FEL, Sec. 19, T7N, R1 3W, SM LOCI 01-004 9/1/2018 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 51' FNL, 374' FWL, Sec. 20, T7N, R1 3W, SM 9531 100' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 90 15. Distance to Nearest Well Open Surface: x- 200619.745 y- 2449933.955 Zone- 4 GL 1 BF Elevation above MSL (ft): NIA to Same Pool: 1839ft 16. Deviated wells: Kickoff depth: 13500 feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) ' Maximum Hole Angle: 60 degrees Downhole: 5562 psi . Surface: 4298 psi 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD I TVD MD TVD (including stage data) 8-117' 7" 29 DWG 2930 1 1 13200 10261 16130 • 11900 496.3 cuft ✓ 8"1 4-1I2" 12.6 L80 DWC 1801 1 15830 1 11752 1 17631 12642 202 tuft 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): 16100 12570 15932 15932 12428 NIA Casing Length Size Cement Volume MD TVD Conductor/Structural 200 30 nla 200 200 Surface 3840 13 318 S1: 4171 cuft, S2: surface 3480 2975 Intermediate 15085 9 518 1288 cuft 15085 11748 Production Liner 1321 75/8 547 cuft 16100 12570 Perforation Depth MD (ft): 15130-15890 Perforation Depth TVD (ft): 11786-12393 Hydraulic Fracture planned? Yes❑ No ED 20. Attachments: Property Plat Fl� BOP Sketch e Drilling Program ❑ Time v. Depth Plot e Shallow Hazard Analysis Diverter Sketch Seabed Report Drilling Fluid Program 20 AAC 25.050 requirementsE/ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Name: Stephen Ratcliff Authorized Name: Stephen Ratcliff Contact Email: sratcliff@glacieroil.com Authorized Title: Drilling Manager Contact Phone: 907-433-3808 Authorized Signature: 1 Date' 1 I t z S s Commission Use Only Permit to Drill 3 API Number: / Permit Approval See cover letter for other Number: ZC50 3 - 2-CL57 I? —fir —co I Date: requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce con 1beJ Amethee, gas hydrates, or gas contained in shales: Other: � � . �+� $m$a Z'E3i -rd =%dL S { Samples req'd: Yes ❑ No[o Mud log req'd: Yes❑ CIE t� HZS measures: Yes ❑ No Directional svy req'd: YesWNo❑ VOID sc,� to-y6�r r SriQ� Inclination -only s re d: Yes III���III''' Noy C may!,Spacing exception req'd: Yes ❑ No Y �+5+ req' d: �J uy`�,; Post initial injection MIT req'd: Yes No❑ b-'y�*i 42.t}G7Ur<�tc� pesr�R,wr t�� APPROVED BY e, Approved by:kADDT! COMMISSIONER THE COMMISSION Date: A n ❑ I G INAt Submit Form and Form 10-401 Revised 512p17 This permit is vaT approvalyperor 20 AAC 25.005(8) Attachments in Duplicate GLACIER July 12th, 2018 Mr. Hollis French, Chair Alaska Oil and Gas Conservation Commission 333 West 7th Ave., Suite 100 Anchorage, Alaska 99501 RE: Application for Permit to Drill Cook Inlet Energy, LLC: RU -06A Dear Mr. French, Cook Inlet Energy (CIE) hereby applies for a Permit to Drill for Redoubt Unit 06A, located on CIE Lease Number 381203 and 374002, in the Redoubt Unit. RU -06A will be completed as a water injection well under Areawide Injection Order (AIO) 32. Please find attached for review of the Commission the 10-401 Form, Drilling & Completion Procedures, Geological Information, Proposed Well Schematics, and Hazard Analysis, as required by 20 AAC 25.005. Additional information includes, MASP Calculations, Rig Layout, BOP & Choke Diagrams, as well as Mud, Cement, and Directional Programs. Glacier Rig 35 will be used to complete this work, commencing approximately September 1, 2018. If you have any questions, please contact me at (907) 433-3808. Sincerely, Stephen Ratcliff Drilling Manager Cook Inlet Energy, LLC (a Glacier Oil & Gas Corp. owned company) 601 W. 5th Avenue STE 310 Anchorage, AK 99501 GLACIER 1, RU -06A Requirements of 20 AAC 25.005C) Well Summary Current Status: RU -06 is currently being used for injection. Scope of Work. • Set whipstock in 9 5/8" casing with top of window at +/-13,500' MD • Mill window in casing with 8 1/2" BHA • Drill 8 1/2" hole from KOP of 13,500' MD to 16,130' MD • Run 7" liner and cement • Drill 6" hole to 17,631' MD / 12,642' TVD. • Run 4-1/2" liner and cement • Run 4-1/2" completion o Completion Sundry to follow • Perforate zones of interest for injection o Separate Sundry to follow General Well Information: Reservoir Pressure / TVD: 5,562 psi @ 17,631' MD / 12,642' TVD MASP: 4,298 psi-..,, Wellhead Type/Pressure Rating: Vetco Gray - 5M - Wellhead Assembly BOP Configuration: 13 5/8" 10M BOPE - Annular / VBR / Blind / Kill Line / VBR Well Type: Water Injector - Estimated Start Date: September 1, 2018 0 GLACIER Z. Location Summary Requirements of 20 AAC25.005(c)(2) • General Location Kenai Peninsula Borough, Alaska • Osprey Platform Center Leg 3 - Slot #16 • Ground Elevation Offshore - N/A • Sea Bottom Elevation 45' to Mud Line • RKB 90' above MSL See Attachment 1: Slot Location See Attachment 2: Rig Schematic & Well Slots 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) BOP Configuration: 13-5/8" IOM BOPE - Annular / VBR / Blind / Kill Line / VBR The BOP system of Glacier Rig 35 is rated at 10,000 psi working pressure. Since the calculated maximum anticipate -surface pressure in this well is 4298 psi, it is planned to routinely test all BOPE to 5,000 psi,'except the annular BOP which will be tested to 50% of its rated working pressure (-2500 psi). BOPE will be tested every 14 days per 20 AAC 25.035. A 0.1 psi/ft gas gradient was used in the MASP calculation. See Attachment 3: BOPE Schematic See Attachment 4: Choke Manifold Schematic See Attachment S: Wellhead / Tree Schematic 4. Drilling Hazard Analysis Requirements of20 AAC25.005(c)(4) Maximum Down Hole Pressure: Expected Reservoir Pressure Normal Pressured Reservoir = (0.052)*(8.46 ppg)*(12,642' TVD) = 5,562 psi 3 X -Coordinate Y -Coordinate FNL FSL FEL FWL Sec / T R Surface Location 200619.745' - 2449933.955' - 1909' FSL - 318' FEL - 14/7 N14W - Kick Off Point 208183.3' 2447036' 798' FNL 2029' FWL 19 7N 13W Top of 1piection Zone 210343.0' 2447408' 371' FNL 894'FEL 19 7N 13W Bottom Hole Location 1 211615.9' 1 2447696' 1 51' FNL I 374' FWL 1 20 7N 13W See Attachment 1: Slot Location See Attachment 2: Rig Schematic & Well Slots 3. Blowout Prevention Equipment Information Requirements of 20 AAC 25.005(c)(3) BOP Configuration: 13-5/8" IOM BOPE - Annular / VBR / Blind / Kill Line / VBR The BOP system of Glacier Rig 35 is rated at 10,000 psi working pressure. Since the calculated maximum anticipate -surface pressure in this well is 4298 psi, it is planned to routinely test all BOPE to 5,000 psi,'except the annular BOP which will be tested to 50% of its rated working pressure (-2500 psi). BOPE will be tested every 14 days per 20 AAC 25.035. A 0.1 psi/ft gas gradient was used in the MASP calculation. See Attachment 3: BOPE Schematic See Attachment 4: Choke Manifold Schematic See Attachment S: Wellhead / Tree Schematic 4. Drilling Hazard Analysis Requirements of20 AAC25.005(c)(4) Maximum Down Hole Pressure: Expected Reservoir Pressure Normal Pressured Reservoir = (0.052)*(8.46 ppg)*(12,642' TVD) = 5,562 psi 3 GLACIER Maximum Anticipated Surface Pressure: MASP = (5,562 psi) -(0.1 psi/ft*12,642' TVD) = 4,298 psi Shallow Gas Analysis: The wellbore is not expected to encounter any shallow gas. Potential Gas Zones: The wellbore is not expected to penetrate any known gas zones. Potential Hole Problems Lost Circulation, Hole Stability, Stuck Pipe, & Coal Drilling, etc. S. Formation Integrity Test Procedure Requirements of20AAC25.005 (c)(5) Prior to drilling out of casing strings, test BOPs, and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak -off tests (LOT) are to be conducted as described below: • Drill 20' to 25' of new formation from the milled casing window and condition the mud to the same properties in and out. • Pull drill bit into the window and close pipe ram preventer. Line up to the choke manifold with a closed choke. • Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drill pipe pressures at 1/2 bbl intervals. • The Drill Site Manager will keep a running plot of pressure versus volume while the test is in progress. • Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. • Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. 6. Casing Program Requirements of 20 AAC 25.005 (c)(6) See Attachment 6: Casing Design Program 4 GLACIER 7. Cement Program Requirements of 20 AAC25.005 (c)(7) 7" Liner (.set at 16130' B-1 12" of PreFlush / Spacer: S3.5 bbl 11.5 ppg Tuned Spacer Slurry: Top of slurry: 13200' MD Premium class G cement, 15.3 ppg density 30% excess from 13500'- 16130'MD Yield: 1.237 cu ft/sk j z Volume: 88.4 bbls/496.3 cuft (401 sx) including excess & shoe track Awa l.hY-lip) 4-112" Liner (set at 17631'. 6" hole PreFlush / Spacer: 17.5 bbl 11.5 ppg Tuned Spacer Slurry: Top of slurry: 15830' MD Premium class G cement, 15.3 ppg density 30% excess from 16130'- 17631'MD Yield: 1.237 cu ft/sk Volume: 36.1 bbls/202 cuft (163 sx) including excess & shoe track 8. Diverter System Information Requirements of 20 AAC 25-005 (c)(7) Not applicable for Sidetrack Operations 9, Drilling Fluid Program Requirements of 20 AAC25.005 (c)(8) INTERVAL MUD DEPTH MUD WT PV YIELD FLU < 5 SYSTEM (PPg) POINT {ml, 8-1/2" Hole OBM 13500-16452' 102 ALAP 13-24 6" Hole OBM 16452-17881' 10.2.10.5 ALAP 10-24 See Attachment 8: Mud Program iID LOSS Cl LGS /30min) (mg/I) (%) < 5 20,000 - 30,000 < 7% < 5 20,000 - 30,000 <7% 5 GLACIER 10. Abnormally Pressured Formation Information Requirements of 20 AAC 25.005 (c)(9) Only applicable for an exploratory or stratigraphic test well, a tabulation setting out the depths of predicted abnormally geo-pressured strata as required by 20 AAC 25.033(f). 11. Seismic Analysis Requirements of 20 AAC 25.005 (c)(10) Only applicable for an exploratory or stratigraphic test well, a seismic refraction, or reflection analysis as required by 20 AAC 25.061(a). 12. Seabed Condition Analysis Requirements of 20 AAC 25.005 (c)(11) Only applicable for a well drilled from an offshore platform, mobile bottom -founded structure, jack-up rig, or floating drilling vessel, an analysis of conditions as required by 20 AAC 25.061(b). 13. Evidence of Bonding Requirements of20AAC25.005 (c)(12) Evidence of Bonding is on file for Cook Inlet Energy with the Commission. 2 GLACIER 14. Proposed Drilling Program Requirements of 20 AAC25.005 (c)(13) July 12th, 2018 General Note: Full opening Safety Valve will be on rig floor at all times with appropriate crossovers for all pipe being run below rotary table. Drilling Procedure Note: This is a continuation from the RU -06 Plug for Redrill Sundry procedure. The plug for redrill and sidetrack operationally is intended to be consecutive, pending AOGCC approval. 1. P&A Sundry Submitted separately. a. Verify timing for next BOP test and provide AOGCC with 48 hours notice if necessary. b. Verify 10.2 ppg mud volume and build additional if necessary prior to milling window. c. Verify 8-1/2" Mill/Whipstock/MWD BHA is set with top 3 00' MD. 3. Start milling window, per Service Company Procedure. a. Drill additional rat hole to clear the BHA, motor, and MWD tools. b. Ream window as needed to assure there is little or no drag. c. After reaming: i. Shut off pumps and rotary (if hole conditions allow). ii. Pass through window checking for drag. 4. Drill 20' of new formation and circulate and condition mud. 13.0 a. If 20 ft of new hole is achieved with Milling BHA, Perform FIT to ppg, b. FIT/LOT Procedure included in Section 5 of PTD. ygz6bls �<<k S. POH and gauge mills for wear. a. Make additional run if window & mill are out of gauge. 6. Pick up 8-1/2" BHA. a. 8-1/2" PDC bit b. 6-3/4" Ultra Extreme Mud Motor c. Stabilizer d. 6-3/4" Navi-Gamma, Density/Neutron LWD/MWD e. Stabilizer f. NM Drill Collars g. HWDP h. jars i. HWDP j. 5" drill pipe to surface 7 GLACIER 7. RIH to 1000'& perform shallow MWD test. 8. Continue RIH to Window. 9. If Mill did not achieve 20 ft of new hole, drill additional new hole required for a total of 20' of new formation and circulate and condition mud. a. Perform FIT to 13.0 ppg. Al, Jr7/F��--cam r b. FIT/LOT Procedure included in Section S of PTD. 10. Directionally drill 8-1/2" hole to +/-16,130' MD / 11,900' TVD, per directional plan. 11. Circulate hole clean with minimum of three bottoms up, or until hole is clean. 12. Short trip to window and CBU. a. Avoid back reaming if possible. 13. RIH to TD and circulate a minimum of three bottoms up, or until hole is clean. 14. POH to window and CBU. 15. Continue POH to surface. 16. Lay down BHA. 17. R/U and Test BOPS - change VERs to Casing Rams - wk, 18. Rig up to run 7" Liner. 19. P/U 7"; 29##, L80 DWC Liner. a. Shoe track is 120' (landing collar, float collar, and reamer shoe). b. Centralizer program to be as follows: i. 1 Centek centralizer every joint for joints 1-25. ii. 1 Centek centralizer every other joint thereafter. c. CBU at stages if necessary. 20. P/U 9-5/8" x 7" Halliburton Liner Hanger and Running tool BHA and RIH on 5" drill pipe to window. a. Planned Liner Hanger depth at 13200' MD (+/- 300' inside 9-5/8" window). b. Break circulation at Window and every 1500' thereafter. c. Establish P/U and S/O weights. 21. Continue to RIH to bottom. 22. Circulate and condition hole. a. Reciprocate liner while circulating. 23. Rig up and test cementers. 24. Cement 7" liner per cement program. a. Continue reciprocating liner while pumping cement. b. Bump plugs with 3,000 psi - DO NOT over displace. c. Planned TOC at Liner Top. 25. Set Liner/Hanger-Packer, per Halliburton Procedure. a. Release pressure and check floats and un -sting from liner. 0 GLACIER 26. Reverse out excess cement. 27. POH and L/D Running Tool. 28. P/U and stand back 4" drill pipe. 29. Pick up 6" BHA. a. 6" PDC bit b. 4-3/4" Ultra Extreme Mud Motor (OR GeoPilot) c. Stabilizer d. 4-3/4" Navi-Gamma, Density/Neutron LWD/MWD e. Stabilizer f. NM Drill Collars g. HWDP h. jars i. HWDP j. 4" and 5" drill pipe to surface 30. RIH to 1000'& perform shallow MWD test. 31. Continue RIH to landing collar 32. Test Casing to 3500 psi and chart for 30 mins. 33. Drill out shoe track. 34. Drill 20' of new formation. 35. Circulate and condition mud and Perform FIT to 12.5 ppg EMW. a. FIT procedure at back of program. 010AS/�s b. Note - this will not be a LOT 36. Directionally drill 6" hole to TD at 17,631' MD / 12,642' TVD, per directional plan. 37. Circulate hole clean with minimum of three bottoms up, or until hole is clean. 38. Short trip to 7" shoe and CBU. 39. RIH to TD and circulate a minimum of three bottoms up, or until hole is clean. 40. POH to 7" shoe and CBU. 41. Continue POH to surface. 42. Lay down BHA. 43. Rig up to run 4-1/2" Liner. 44. P/U 4-1/2", 12.6#, L80 DWC Liner. a. Centralizer program to be as follows: i. 1 Centek centralizer every joint through top of Hemlock only. b. Break circulation at 7" shoe. c. Planned Liner Hanger depth at 15830' MD (+/- 300' inside 7" liner). 45. PU Halliburton Liner Hanger and Running tool BHA and RIH on 4" and 5" drill pipe to window. a. Establish P/U and S/O weights. E GLACIER 46. Continue to RIH to bottom. 47. Circulate and condition hole. a. Reciprocate liner while circulating. 48. Rig up and test cementers. 49. Cement 4-1/2" liner per cement program. a. Continue reciprocating liner while pumping cement. b. Bump plugs with 3,000 psi - DO NOT over displace. 50. Set Liner/Hanger-Packer, per Halliburton Procedure. a. Release pressure and check floats and un -sting from liner. 51. Reverse out excess cement. 52. POH and L/D Running Tool. 53. L/D 1800' of 4" drill pipe. 54. Pick up Polish Mill BHA. 55. RIH and Clean out casing, liner top, and latch assembly in Liner Hanger. 56. Circulate hole clean. 57. T and liner la to 3,500 psi for 30 minutes and chart if past 24 hours CIP 58. POH and L/D Polish Mill BHA. 59. P/U +/-1,900' of 2-7/8" drill pipe and MI Swaco Well Commander. a. Well commander in 5" DP section about 200' above liner top. 60. RIH to bottom and prep to displace OBM to fresh water + 3% KCL. 61. Change over to completion fluid using appropriate spacers. a. Mix and displace with 8.5 ppg KCl Brine. 62. POH and lay down all 2-7/8", 4", and 5" drill pipe. 63. Rig up wireline and run CBL across 4-1/2& 7" liners. �d�Gc r � 64. Evaluate Cement Bond Log. ---T*F;rw"& a. If squeeze is needed, confirm with CIE office on equipment and procedure. 65. Move on to Completion Program (Separate Sundry approval required from AOGCC). 10 GLACIER 15. Time vs Depth LnO Ln O 1 i \7 W O O C? OO O D 0 0O d WO K yi8dadO rl 4Op O pOl Vt6 MM rl 2 ei Ln J eI f I 11 11 O M s � a ri a CL 0o 1D A fn A ' �. m Q% c O ErV O 1 i \7 W O O C? OO O D 0 0O d WO K yi8dadO rl 4Op O pOl Vt6 MM rl 2 ei Ln J eI f I 11 11 GLACIER See Attachment 10: Directional Program 16. Bit Program Type— —7—Size Nozzles TFA HSI Prima8-1/2- PDC 7 x 12s 0.773 3.6 Backup 8-1/2" PDC 7 x 12s 0.773 3.6 Prima 6" PDC 3 x 12s 0.331 3.8 Backup 6" PDC 3 x 12s 0.331 3.8 17. Bottom Hole Assembly 18. Drilling Waste Storage Requirements of20 AAC 25.005 (c)(14) Drilling wastes will be either granular solids (cuttings), or liquids (drilling mud or water). Cuttings and fluids will be disposed of in: Redoubt/Osprey Wells RU -D1 with the Grind & Inject Facility CIE will not request authorization under 2 0 AAC 2 5.080 for an Annular Disposal Operation in the well. 12 GLACIER Solids Control and Equipment Item Equipment 5 ecifications Shakers Derrick Hyperpool Shakers Desander 3 Cone Desander Desilter 24 Cone Desilter Centrifuge BOS Misc Equipment None 19. Geological Formation Tops Requirements of 20 AAC 25.071 See Attachment 11: Geo -Mechanical Plot See Attachment 12: Geological Prognosis 20. Logging Plan Requirementsof20AAC25.071 (a) Open Hole Logging • 8-1/2" Section MWD/Gamma/Resistivity/Neutron/Density • 6" Section MWD/Gamma/Resistivity/Neutron/Density LWD logs are to be run continuously from kickoff point to Total Depth. Final Data in a las, pdf, and tiff formats to be provided on disc to Cook Inlet Energy in the Anchorage office. Cased Hole Logging A Cement Bond Log / Cement evaluation Type survey is to be run across 4-1/2" and 7" liners. A 1"=100' and S"=100' MD and TVD log to be provided after each run. Number of copies to be determined and will include both paper copies and digital data. Data in a LAS and PDF format to be provided to Company man, Cook Inlet Energy Anchorage office, and geologist, after logging is concluded. Mud Logging Pian Mud Logging will not be conducted during RU -06A. 13 GLACIER 21. Regulatory Waiver and Special Procedures Requests AOGCC Regulation 20 AAC 25.071 Geologic Information Not Applicable AOGCC Regulation 20 AAC 25.235 Gas Disposition Not Applicable AOGCC Regulation 20 AAC 25.265 Automatic shut-in equipment SSSV Not Applicable (Injection well) AOGCC Regulation 20 AAC 25.265 Automatic shut-in equipment SSV The Surface Safety Valve will be located in the vertical run of the tree. 14 GLACIER Area of Review - Redoubt Unit 06A This Area of Review is required in preparation of the RU -06A Injection well. This AOR discusses wells within 1/4 mile of the well's entry point into the Hemlock Formation to the bottom of the planned RU -06A wellbore completion. Three other wellbores, RU -04, RU -04A and RU -06, enter the Hemlock formation in this area of review. The table below illustrates the wells within the AOR, annulus integrity/cement conditions based on in-depth review of each well, reservoir status, zonal isolation and mechanical integrity. 15 GLACIER Well PTOR Status TopT"em'Dock Hemloc Topof Top of Cement Top of Cement Determined Reservoir Status Zonal Isolation Cement Ops Summary Mechanical Integrity Name (MD) Cement{MD] jTV by Planned: 4-1/2"liner Est Planned: Planned: Planned: perfs will be Plenned:TOC 15830' Planned: 4- liner- & liner lap Pressure RV -06A TBD New injector Est: 16129' MD 15830' MD 11096' 'TVD Planned: CBL open for Injection MD {CBLwlll confirm) ass 55.6 bbls/Class G test to 3500 psi ND TV13 Planned: Set plug in 9-5/8" -1280 Planned for P&A: Injection 11678' 1100D' MPVolume Planned: P&A for tubing. Cuttubing above and 15 bbls cuft/Class G/no losses Zone P&A'd: Whipstock for 6A YP RU -06 2022280 (wlli be P&A 15109' MD (CaIcTOC]Calculation F10724'. RedriYl - Cuttubing, balanced plug pump cementon mp of top 7.5/a" - 547TVD 13525'MD/10512'for Redrill) set plug cuk/Class G/no losses NDpacker. 9.5/8" - 4295 15565'MD P&A'd for Redrill - Cemented 5-1/2" liner; cuft/Class G/no losses Zone P&A'd: 12214' {top of Volume]Redrill Balanced plug across Balanced plug across 7.5/8" - 247 tuft Whipstock for 4A @ RU -04 201194018875' MD balanced ND Calculation- p erfs; BP set at Paris; BP set at 15080' /Class G/no losses 15080' MD/9733' TVD plugl Balanced plug 15080'MD. MD 5-1/2" - 802 cuft ND /Class G/no losses - " 11971 CBL 07-11- BP setat 14300' MD with 25' of cement on CBLTCC 14583. MD, BP 25' L�5-112"1758 5-1/2" liner tested to RU -OAA 2030810 Producer: 15304'MD ND 14583'MD 9414'ND 2003 top. Add'I BP set at 110000, at 14300' MD with ss G/no losses 3000 psi. Shut -In Mb. cement on top As per 20 ACC 25.402 (15): Well RU -06 (Permit 2022280) enters the Hemlock formation at 15109' MD (11678' TVD). The 9-5/8" Intermediate casing was run to 15067' MD and cemented with lead of 167 bbls of 1.2.5 ppg Class G cement and tail of 61 bbls of 15.8 ppg Class G cement, and bumped the plug with no issues. The 9-5/8" casing was tested to 3000 psi for 30 minutes prior to drilling out the float equipment A 7-5/8" liner was run to 16100' MD (top at 14779' MD) and cemented with 97.5 bbls of 15.7 ppg Class G cement while reciprocating throughout with full returns. Did not bump plug. The 7-5/8 liner lap was tested to 3000 psi for 30 minutes - good. RIH with the 7-5/8" scraper assy to landing collar and tested the liner to 3000 psi for 30 mins. A C13L run on 4/7/2003 shows the upper sections of the liner are cemented and isolated from the 9-5/8" casing shoe. The calculated top of cement for the 9-5/8" casing is estimated at 11000' MD. Well RU -04 (Permit 2011940) enters the Hemlock formation at 18875' MD (12214' TVD). While drilling RU -04, the 9-5/8" intermediate casing was set at 10517' MD and cemented with 718 bbls of 12.5 ppg Class G lead and 47 bbls of 15.8 ppg Class G tail cement, with full returns but did not bump the plug. The casing was tested to 3000 psi for 30 minutes prior to drilling the float equipment. A 7-5/8" liner was run to 18516' MD (top at 9794' MD) and cemented with 44 bbls of 15.8ppg Class G cement, with no issues and bumped the plug. The 7-5/8" liner top packer was tested to 3000 psi - good. The 7-5/8" liner was tested to 3000 psi for but would not hold pressure. The shoe track was drilled out and a cement plug was pumped. The 7-5/8" liner was retested to 3000 psi - good. The CBL ran on 04/07/2002, shows top of cement at 11830' MD. The 5-1/2" liner was run to 20143' MD (top at 18248' MD) and cemented with 143 bbls of 15.7 ppg Class G cement and bumped the plug. The liner top packer was pressure tested to 3000 psi for 15 minutes. The 5-1/2" liner was tested to 3000 psi for 30 minutes. A CBL (04/07/2002) confirmed cement behind pipe across the length of the 5-1/2" 16 GLACIER liner. RU -04 was abandoned for Redrill (RU -04A) in May 2003 with a 29.7 bbls of 15.8ppg cement plug placed across the perfs, top at 18775' MD. A bridge plug was set at 15080' MD (preparation for whipstock). Well RU -04A (Permit 2030810) enters the Hemlock formation at 17735' MD (12138' TVD). While drilling RU -04, the 7-5/8" liner was run to 18516' MD (top at 9794' MD) and cemented with 44 bbls of 15.8ppg Class G cement, with no issues and bumped the plug. The 7-5/8" liner top packer was tested to 3000 psi - good. The 7-5/8" liner was tested to 3000 psi for but would not hold pressure. The shoe track was drilled out and a cement plug was pumped. The 7-5/8" liner was retested to 3000 psi - good. RU -04A was then drilled out of the 7-5/8" casing by section milling from 14820'- 14878'MD. A 5-1/2" liner was run to 18062' MD (top at 14583' MD) and cemented with 318 bbls of 15.8ppg Class G cement and bumped the plug. The 5-1/2" liner was tested to 3000 psi for 30 minutes. A CBL (7/11/2003) confirmed cement behind pipe across the length of the 5-1/2" liner. Under AIO 32, RU -06A will be utilized for water injection in the Central fault block as approved by the AOGCC. AIO 32 provides additional applicable information in regards to the Hemlock formation and the confinement of the Central fault block. Under AIO 32, the following conditions will be met as ordered by the AOGCC: Rule 1: RU -06A injection interval correlates to RU -01 in the Central fault block Rule 2: RU -06A is being permitted as a service well for water injection in conformance with AOGCC regulations. Rule 3: RU -06A would be utilized for injection of Authorized Fluids as listed in AIO 32. Rule 4: RU -06A Injection pressures will follow the same guidelines as described and limited by AIO 32. Rule 5: RU -06A Tubing and casing annulus pressures will be monitored as described in A10 32. Rule 6: RU -06A Mechanical Integrity will be monitored and demonstrated as described in AIO 32. Rule 8: Notification of any well integrity failure and confinement to the AOGCC will be provided as described in AIO 32. Rule 9: AOGCC will be notified as per AIO 32 if any improper Class II injection is identified. ` Rule 10: Any future plan for P&A of RU -06A will be approved as required by AOGCC under AIO 32. 17 Geological Well Prognosis RU -6A Water Iniector Surface Location: X= 200619.745 Y=2449933.955 Lat/long: N 60° 41'43.67112", W 151- 40' 14.65608" Top Hemlock Formation: X =210343.0 Y =2447408.0 Bottom Hole Location: X =211615.92 Y = 2447696.03 Kenai Peninsula Borough, Alaska Ground Elevation: Mean Sea Level KB Elevation Est. 90' feet above MSL Critical Formation Tops Formation Est. M.D. Est. SSTVD Potential Top Window (KOP) 13, 500' 10,407' Sidetrack At Upper Hemlock 16,129' 11,810' Oil (Primary Injection Objective) West Forelands Coal 17,400' 12,438' West Forelands 17631' 12,552' Total Depth 17,631' 12,552* * TD will be determine upon thickness and depth of the Hemlock formation. The Plan is to TD in the lower Hemlock. Permitted TD. Actual total depth may be shortened due to mechanical hole conditions, depth of intersection of Top Hemlock and thicknesses of Hemlock Formation in the sidetrack as well as Top of West Forelands Formation. Note: The above tops are estimated from seismic and offset well control. Measured depths are estimated from directional plan RU -6A (wp04) dated 06/27/2018• These depths are not refined and may be slightly modified. Formation Evaluation Open Hole Logs LWD logs or comparable logs are to be run to Total Depth. Evaluation minimum will consist of a Gamma Ray and Resistivity from Kickoff to TD. A I"=100', 2"=100' and 5"=100' MD and TVD log to be provided twice daily to people designated on a separate list. Data in a .las format to be provided to Company man, Glacier geologist in the Anchorage office, and State of Alaska AOGCC after logging concluded. No open hole logs will be run. Cased hole Logs A Cement Bond Log / Cement evaluation Type survey is to be run across 4-1/2" and 7" liners. A 1"=100' and 5"=100' MD and TVD log to be provided after each run. Number of copies to be determined and will include both paper copies and digital data. Data in a LAS and PDF format to be provided to Company man, Cook Inlet Energy Anchorage office, and geologist, after logging is concluded. Geologic Hazards Primary geologic hazards expected to be encountered in this well are similar to those encountered in other wells previously drilled in the Redoubt structure. There are numerous coal beds present throughout the Tyonek and Hemlock formations. These can range from a few feet thick to upwards of fifty feet in thickness and should only be a concern once the well has kicked out and sidetracked out of the original RU -6 wellbore. Sloughing coals have proven problematic in drilling operations to date. Although no abnormal pressures are expected, care should be exercised when drilling. We are kicking off at a depth sufficient that no shallow gas hazard will be encountered during drilling. The Hemlock top is provided so that reasonable care can be exercised when drilling the targeted interval. Geothermal Temperdure Profile !8D TVD Temperawe Grat mind (tu (etWl [denwan Q.0 0.4 60 90.0 90.4 W -0.0 180.4 159.9 77 -1.8 15228.0 12345.4 190 0.9 it degF Temp. Pmiib JA 119 min SECTION 14 T7N R14 SM A 0 a00 4W 6w O; NO TH GRID SCALE 1 inch =300 f. See I7 WELL SLOTHELL SLOT #22 #12 WELL SLOT PT. NO. 21 WELL RU -7 CENTER LEG 3 WELL SLOT LAT: 60" 41'43.698"N W O LON. 151' 40' 14.573"W 11 WELL SLO N: 2449936.607' WELL SLOT E.200623.92C OSPREY PLATFORM ASP ZONE 4 NAD 27 ELEV SEA BOTTOM: -45' MLLW DETAIL 1"=20' r— #17 WELL RU D-1 PT. NO.6 18 CENTER LEG 2 ELL RU -2 LAT: 6D" 41'44.155"N g LON: 151° 4V 13'520"VV WELL RU -1 N: 2449981.637' E: 200677.509' 6##20 ASP ZONE 4 NAD 27 4 ELEV SEA BOTTOM: -45' MLLW WELL RU -4 #15 WELL RU -3 See Tabular Sheet WE Ru- " F16 WELL L for Well Slot Coordinates 1. BASIS OF HORIZONTAL AND VERTICAL CONTROL WAS DETERMINED BY AN OPUS SOLUTION FROM CORS BASE STATIONS "AC23 PID DM748" &"AC51 PID DD1812" & "KEN5 PID DJ3029" ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2010 HORIZONTAL DATUM AND NAVD88 VERTICAL DATUM UTILIZING GEOIDI2A. 2) SECTION LNE OFFSETS DETERMINED FROM PROTRACTED SECTION CORNER VALUES. 3) MLLW ELEVATIONS WERE DERIVED NOTES Inc ENGINEERfNG - TESTING SURVEYING - MAPPING P.O. BOX 468 SOLDOTNA, AK. 99669 VOICE: (907) 283-4218 FAX: (907) 283-3265 WWW.MCLANECG.COM PROJECT NO. 4 DRAWN DY: 133075 msm DATE: Sept 15, 2015 !01 *'49� � ........, 4 ....00 M. SCOTT McLANE aw AW 7#4 4928- L Lin PLA M 322' FEL - t 269' FEL C �.1 c 0 U (D V) OSPREY PLATFORM COOK INLET, ALASKA WELL LOCATIONS NAD27 ✓ CLIENT: COOK INLET ENERGY, LLC 601 W. 5TH AVENUE SUITE 310 Cook lniet Ener y ANCHORAGE, AK 99501 LOCATION: PROTRACTED SECTION 14 TOWNSHIP 7 NORTH, RANGE 14 WEST SEWARD MERIDIAN, ALASKA Cook Inlet Energy /IffMcLane Consulting Inc. Osprey Platform, Cook Inlet Alaska w C�nsuLtlookz Project: 133075,9/16/2015 —A ew— nt wue &Nark -s -w ve%ur w NOTES 1) Refer to Diagram for Well Slots Orientation 2) All Data In U.S. Survey feet 3) Datum Conversions Done Using Autocad Cad 2013 LEGEND DD DECIMAL DEGREE DMS DEGREES MINUTES SECONDS N NORTH W WEST -RU-06 Current Wellbore Schematic GLACIER 30" Conductor 18-112" Hole Calc TOC @ 1 1000'MD TOL § 14,779' MD 12114" Hole 8112" Hole Version: Current December 8, 2014 3.1/2" tbg hgrw/ 3-112"EUE x 2-718' EUE8rd XO 30" 150#A-36 200'MD A-36 200' TVD 2 7/8" 6.5# P110 EUE 8rd Internally Coated ID - 2.441" 13 318" 1 689 L-80 3,480' MD _ ID -12.415" 1 BTC 2,975' TVD 2 718"'7C" Nipple C 14686' MD - ID 2.313" 9 518" Model 5-3 HYD. Packer @ 14728' MD 2 7/8"'X" Nipple @ 14734' MD - ID 2.313" 7 518" Model "DB' packer @ 14,970' MD 9518" 1 479 L-80 15,067' MD ID - 8.681" 1 BTC 111,748' TVD 7 5/8' Model "AD" Packer @ 15,030' MO End of Tubing @ 15043' MD TOC @ 15932' (tagged - 5bbl curt on top) -- ---= Retainer @ 15,990' MD 7518" 29.7# L-80 16,100' MD ID - 6.875" 1 Hydril 521 12,570' TVD Perforations Top MD Btm MD Top TVD I Btin TVD 15130 15164 117861 11814 15192 15226 118381 11867 15252 15302 118881 11930 15316 15336 119421 11958 15418 15444 120251 12046 15458 15480 12057 12074 15542 15630 12123 12190 15580 15760 12229 12290 15788 15812 12312 12331 15856 15890 12366 12393 8112" Hole Version: Current December 8, 2014 3.1/2" tbg hgrw/ 3-112"EUE x 2-718' EUE8rd XO 30" 150#A-36 200'MD A-36 200' TVD 2 7/8" 6.5# P110 EUE 8rd Internally Coated ID - 2.441" 13 318" 1 689 L-80 3,480' MD _ ID -12.415" 1 BTC 2,975' TVD 2 718"'7C" Nipple C 14686' MD - ID 2.313" 9 518" Model 5-3 HYD. Packer @ 14728' MD 2 7/8"'X" Nipple @ 14734' MD - ID 2.313" 7 518" Model "DB' packer @ 14,970' MD 9518" 1 479 L-80 15,067' MD ID - 8.681" 1 BTC 111,748' TVD 7 5/8' Model "AD" Packer @ 15,030' MO End of Tubing @ 15043' MD TOC @ 15932' (tagged - 5bbl curt on top) -- ---= Retainer @ 15,990' MD 7518" 29.7# L-80 16,100' MD ID - 6.875" 1 Hydril 521 12,570' TVD RU -06A Proposed Wellbore Schematic GLACIER 30" Conductor Calc TOC @ 11000' MD 7" TOL @13200' MD CKOP @ 135DMD Bridge Plug @ 13525' MD 2 718" X Nipple @ 14686' MD - ID 2.313" with Plug set In profile 9 518" Model S3 HYD. Packer @ 14728' MD 2 718" X -Nipple @ 14734' MD - ID 2.313" 7 518ff" 29.7# Model "D" packer @ 14,993' MD TOL @ 14,779' MD° 121W Hole I1 9 518" 47# L-80 15,067' MD Al� Itl 4.5" 12.6# L80 17631' MD Inc - 60 lD - 8.681" BTC 11,748' TVD F177--3.9581DWC 12642' TVD Azm - 77 7 518" 29.7 # Model "DB' @ 15.030' MD= a� Perforations 15130'- 15890'MD r (11786' -12393' TVD) awe +vie TOC @ 15932' (tagged - 5bbl curt on top) Retainer @ 15,990' MD 8112" Hole b.a�s 4y ` 30" 11509A-36 200' MD A36 200'TVD 13 318" 68# L80 3,840' MD ID -12A15 BTC 3,243' TVD 4-112" 12.6# L80 DWC Tubing - ID 3.920" Version: V1.5 July 10, 2018 WP04 tangent ole - Sidetrack 7" 299 PIIQj 16130' MD Inc - 60 ID = 6.184 1 DWC 11900' TVD Azm - 77 R -Nipple @ 15700' MO - ID 3.688" 14,1 Cw 100+' of cement I. -i Cut tubing at 14680' , J4w 4.5" TOL @ 15830' MD _W4;� A�� b '7 2 718" 6.5# P110 EVE Brd Internally Coated �r ID -2.441" 6" Hole -Sidetrack � 4.5" 12.6# L80 17631' MD Inc - 60 F177--3.9581DWC 12642' TVD Azm - 77 75M" 29.7# L80 16,100' MD ID - 6.875 Hydril 521 12,570' TVD 176.3" 41.7" 4-1116" 5M �+ i ! i 60.5" 4-1/16" 5M 4-1116" 5M 13-518" 5M I 28.0" ! 13518" SM I 46.1" I i 31.0" I 41116" SM x 9-112: 4 -ACME OTIS 29.9" to 2-1/16" SM 27.2" to M& (f)A 2-1116" 5M I! r�113T-W 30'Casing ICasing sing g Pressure Control 13-318' x 9-518" x 4-112" 5M, MB -205 Multibowl Assembly T�UIECPRIHES B-205 Tubing Head, Tubing Hanger GE company and Tubing Bonnet C[M'YNRRGXTl1YMIPWRT"nr' DRAWN BY: CR DRAWING N0.: XPSRDiR.4 Lopy.M9M1IP0fl 9Y"NURFq,fiE raapnl. 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APPRDY®BY: DA 29JUN%a OSPREY PLATFORMIRII-06A COOK INLET ENERGY Cook Inlet Energy Casing Plan Well Information WELL NAME: RU -06A ENGINEER: Amanda Dial DATE: 2 -Jul -18 Hole Sizes (in) Casing Size (in) MD (ft) TVD (ft) Max EMW (Pore Pressure) EstimatedEstimated Frac Grad at Shoe Range -Mud Weight (ppg) Mud Type Comments - 30 200 200 — -- -- -- -- Conductor pipe 18 1/2" 13 3/8" 3,840 3,243 -- -- — -- -- Previously Set on Original RU -06 Well 121/411 95/8'. 13,500 10,497 8.3 250 10.2 10.2 - Whipstock and Window 81/2" 7" 16,130 11,900 846 14.0 10.2 102 OBM Tyonek and Hemlock Coal 6" 41/211 17,631 12,642 8.46 150 10.2 10.5 OBM Lower Hemlock & West Forelands - Abnormal Pressure Gradient Casing Plan JENTER YELLOW CELLS MANUALLY Casing Size {in) Wt (lb/ft) Grade Connection API rating MD (ft) TVD (ft) Type OD (in} Burst (psi) Tension ki s30 - -- — — ECollapse - 200 200 133/8" -- — - -- -- -- -- 3840 3243 9.5/8" 47 L80 BTC -M 10-625 6870 4760 1122 13500 10497 7" 29 Pilo Hydril521 85 11220 8530 929 16130 11900 41/2" 12.6 L80 DWC 5 8430 7500 288 17631 12642 Variables & Formulas Wellhead 5,000 1psi Gas Gradient 010 psi/ft Pore Pressure Gradient 0.440 1psi MAWP = (0.80 X CASING BURST) or Limiting Wellhead Pressure MASP = Lessor of {Frac Pressure @ (0.052 X (MW + 0.5ppg SF) X TVD) - GasGRD X TVD)) or (Max Pore Pressure - (GasGRD X TVD)) MASCP = (0.80 X CASING BURST) - (MW - Backup FluidWt.) X.052 X TVD 5F Burst = Burst Value/MASP SF Collapse = Collapse Value/((0.052 X Max EMWPore Pressure X TVD) -(gas gradient X TVD)} SF Tension = Tension Value/(Length X Ib/ft) Max Allowable Working Pressure MAWP = (0.80 X CASING BURST) or Limiting Wellhead Pressure Safety Wellhead MAWP (psi) Hole Sizes (in) Casing Size (in) MD (ft) TVD (ft) Burst (psi) Factor (psi) 121/4" 9 5/8" 13,500 10,497 6870 0.8 5,000 81/2" 7" 16,130 11,900 11220 0.8 5,000 6" 41/2" 17,631 12,642 8430 0.8 5,000 Max Anticipated Surface Pressure 5496 8976 6744 Burst= Burst Value/MASP Collapse = Collapse Value/((0.052 X Max EMW Pore Pressure X TVD) -(gas gradient X ND)) Tension = Tension Value/(Length X Ib/ft) MASP = Lessor of (Frac Pressure @ (0.052 X (MW + 0.5ppg) X TVD) - GasGRD X TVD)) or (Max Pore Pressure - (GasGRD X TVD)) Hole Sizes Casing Size ND (ft) Max EMW Frac Grad at MW Safety Gas Frac Pressure at Max PP at MASP (psi) (in) (in) MD (ft) (ppg) Shoe Factor Gradient Shoe Next TVD 121/4" 95/8" 13,500 10,497 8.3 15.0 0.50 0.10 7411 3,341 3,341 81/2" 7" 16,130 11,900 8.46 14.0 0.50 0.10 7783 3,971 3,971 6" 41/2" 17,631 12,642 8.46 15.0 0.50 0.10 8925 4,297 4,297 Max Allowable Surface Casing Pressure MASCP = (0.80 X CASING BURST) - (MW - Pore Pressure) X.052 X TVD Max EMW Hole Sizes Casing Size MD (ft) TVD (ft) Burst (psi) Safety MW (Pore MASCP (psi) (in) (in) Factor Pressure) 121/4" 9 5/8" 13,500 10,497 6870 0.8 10.2 8.3 4459 81/2" 7" 16,130 11,900 11220 0.8 10.2 8.46 7899 6" 41/2" 17,631 12,642 8430 0.8 10.5 8.46 5403 Safety Factors Hole Sizes Casing Size Collapse Tension Wt (Ib/ft) Liner Length SAFETY FACTORS (in) (in) MD (ft) TVD (ft) Burst (psi) (psi) (kips) (ft) Burst Collapse Tension 12 1/4" 95/8'. 13500 10497 6870 4760 1122 47 - 2.1 1.4 1.8 81/211 7" 16130 11900 11220 8530 929 29 2930 2.8 2.1 10.9 6" 4 1/2" 17631 12642 8430 7500 288 12.6 1801 2.0 1.7 12.7 Burst= Burst Value/MASP Collapse = Collapse Value/((0.052 X Max EMW Pore Pressure X TVD) -(gas gradient X ND)) Tension = Tension Value/(Length X Ib/ft) OSPREY PLATFORM MWNG MG SPEWCAMN POG POUNE PUKRED 1.0 w HM DEi1FlIC1t X 147 FT 29P#U MMXIUC 650 K SEMO tom w amffm sm ammiAm 5w TON lop D!t NORM RCTAfff tow Wvw Rms IBM f. !A $lim A0=4 fff OTHM Row " fffim KATropW 1c MmPtUity "loam Im 9D LAE 1.0 r M Lam 4W K IQFTXX FT DRILLING RIG ARRANGEMENT - SIDE VIEW ,y OSM U._T MG murm 25FTOM CIE Rig 35 Redoubt Unit 13 5/8" 10,000 PSI BOP STACK 5000 psi Annular ,r" 10,000 psi pipe rams Double Gate 10,000 psi Blind Rams Double Gate 3" Kill line Mud ' Cross 2 2 2 1= HCR Valve ; �10,000 psi 2=Gate Valve Pipe Rams Single Gate L- -- 13 5/8» sM Wellhead I 4" outlets DSA T/3" Both sides 1 3" Choke line 13 3/8" Surface Casing 9 5/8" Intermediate Casing Panic line Shaker Poorboy line degasser .. 3 1/8' SK 3 118" 5K/, Vaive O Valve {1i 3 1/8' SK x 3 1/16 IOK adaptor spool 3 1/16' 10K Valve B4O.P. Products Hydraulic Choke Well bore 3 1/8' 5K Valve 3 1/8' SK x 3 1/16 10K — adaptor spool 3 1/16` IOK Vakve B4O.P. Products Manual Choke Glacier Oil COOK INLET BASIN REDOUBT SHOAL Redoubt Unit #6 RU#6A Plan: RU#6A WP04 Standard Proposal Report 03 July, 3018 HALLIBURTON Sperry Drilling Services 1"IALLIBiIRTON Vje�t CMK Ipt�F_T BASIN West( -)bast(+) (2000 usffln) REDOU9T SHOAL 0 100{ Q_it� ILOt}3 158h6 R0910YQi UU110U110 06 I rP00 "M cm 51Q4 11=1 70Q0 0404 . SNC)II oG e- R1��9h !11! Taco CL&CIC12 f 4 7800 STIR �A a445Q A e G * � } 1 W Foreland To Target Rev 2 1861 ! lame'. ysa.�i RUGA- Tap Namlock Rev 3 . } 1006 3333 4 J' # aC �rS S RU05 PB1= _ ; 4112` �3 S a" RUNGor 1!7!hl N- B' t 8887 m 8331 y`#1' ik ti 1004Q ,� - nslrrx 1.7'GI 11887 4 I WF—LDiFTAr& ReSmIg UoI06 TYD19270CWCCMCCa1081 AWb7.aor04 51hta NPP, 4e00 RUGA • Top Hemlock Rev 3 +Nl,8 +ELW Nra6w Ia1aude Louptek 0.00 O.W 1449433.96 200619.74 60"41' 13.67117 151.40' 14"W W Foreland TD Target Rev 2 - 18900 I CASING DETAILS ` . . • , . - - - TVD TVDSS MD Slee Name 18 r -1887 0 67 3833 5000 8887 6333 10000 11887 18838 10486.98 10406.99 15500.09 9.516 9 sw IIIF VeL4Q8! S.I. s! 101-50` (2500 usRlrl} I 112&12-00 12552-00 167651-19 4.112 41? 9900 4 pp0 ,l3 I \ KOP :Start Dir 12'1100': 135OO'MD, 10496.99`TVD : 45° LTTF 10175 % REFERENCE INFORMATION HALLIBURT©N North V Co ordinate (NUE) Reference: Wen Redoubt unit y, Grid _ RedDubtUniW 91 Pie usft (Pie niW 90.0 ` Vertical (TVD) Reference: Plan: (Plan: R�ubtUrM y lan: Redoe�tUnit# @ 90.0 (Pie @ 90.�00us8 (P arc RedoublUnit#' 0 90.0 Sperry Drilling GLACIER Measured Depth Reference: Start Dir 501100' : 13550' MD, 10535.327VD Calculation Method: Minimum Curvature SECTION DETAILS Sec MD Inc Azi TVD +NIS on +E/ -W Dial;TFace VSeel Target Annota tar : Start Dir 12°ItO10 13500' MD, 10498.99TVD : 45' LT TF 1 13500.00 38.57 109.46 10496.99 2897.57 7563.62 0.00 0.00 7969.55 End 8002.16 End Da : 13520' MD, 10512.43' TVD 2 13520.00 40.30 106.84 10512.43 2901.52 7575.69 12.00 _45.00 2'TVD 0.00 8021AS Start Dir 5°400' .13550' FAD, 1 3 13550.00 40.30 105.84 10535.32 -2907.14 7594.26 0.00 .4V TVD 8482.77 End Dir : 1 MD, 10921.81899 4 14150.26 60.38 77.25 10921.48 2905.75 8044.88 5.00 -69.10 W: `1' 11899.98'fyD 0.00 10031.62 Start Dir 16MD, 5 16129.77 60.38 77.25 11899.96 -2525.97 9723.18 0.00 1612'. 11 W 5.00 5.89 10031.69 RUSA-Tap Hemlock Rev 3 End Dir :16129.85' MD, 11900' TVD 6 16129.65 60.38 77.25 11900.00 2525.96 12642.00 2237.92 9723.25 10996.17 0.00 0.00 11221.59 W Foreland TD Target Rev 2 Total Depth; 17631.13' MD, 12642' TVD 7 17631.13 60.38 77.25 Q Cook Inlet Energy WELL DETAILS: Redoubt Unit #6 PrOSite COOK INLET BASIN 40.00 Site: REDOUBT SHOAL Calculation Method: Minimum Curvature I Water Depot: Easting Latiltude Longitude Redoubt Unit #6 Error System: ISCWSA +NI -S +Ef-W Northing Scan Method: Closest Approach 3D 0.00 2449933.96 200619.74 60'41'43.671 N151° 40' 14.656 W Well: RU#6A Error Surface: Elliptical Conic 0.00 I Wellbore: Start Dir 501100': 161 29.7T MD, 11899.98`ND Warning Mevw& Error Reno Design. RU06A WP04 J SURVEY PROGRAM Dale: 201826-18700:00:00 Validated: Y09 Version: O ^5� Depth From Depth To SurveylPlan Tool 148.00 992.00 RU#B PB1 GYRO (RUI PBI) 8 9075-- 1016.00 13308.00 RUQBPBI (RUINS PB1) 2_�+� 2 MWD+Sag 1 oo 13347.00 13500.00 RU#6 (RUd!'i) 13600.00 13760.00 RLW6AWP04 (RU #3A) 2_MWD ln"T M 11550-10 13760.00 17631.13 RLWSA WP04 (RU#W 2 MWD+bag 9350 CASING DETAILS TVD TVDSS MD Size Name 11825 10406.99 13500.00 9Sle 9ISM, 9625. y00 110496.99 11900.00 11810.00 le129.85 7 7" 112642.00 12552.00 17631.13 4-1/2 4 1/2" ��y 7„- - o0 9900 4 pp0 ,l3 I \ KOP :Start Dir 12'1100': 135OO'MD, 10496.99`TVD : 45° LTTF 10175 ` End Dir : 13520' MD, 10512.43' TVD 10450---1 9 518"y00 Start Dir 501100' : 13550' MD, 10535.327VD RU#6 PB1 pow 10725-I g� ^� End Dir : 14150.28' MD, i092i.48' TVD n ^�h r Q y0. O 11000 pp 1b0 y0 ^�` � . Start Dir 501100': 161 29.7T MD, 11899.98`ND 11275� 2 O ^5� End Dir 16129.85` MD, 11900' TVD oo 11550-10 Total Depth: 17631.13' MD, 1264T TVD + 11825 7„- - o0 12100 RUGA - Top Hemlock Rev o o� 12375_- 5 4112"� 12650 RUN R1,1j6A '. PO4- W Foreland TD Target Rev T 74 74 2525 7700 7975 8250 8525 8600 9075 9350 9625 9900 10175 10450 10725 11000 11275 Vertical Section at 101.50' (550 usftlin) - -1000 -1750 a J -2000J -i 2250-. Q a i 1'0161 Dg4h:17631.13' MI 126477VD Y.1%'' SFa'.Ib 117100: ]3507 LSD, 10496.997VD :4i' Li TP 111186-0 l'.'F[W Brd l)o = 1611815'3-07. D900'h'D EDd Dp ' 13iZ UD, 10512.4.1' 7YD SmDir5710716119.711m, 11899.96T9D ''. _ 4111` lQzs1 Dir 5111W: 13550L07, 1a535.329W - _ 4 ad Dir : 1415028'L81. 10921AMD i W Fordwd3DTaw Rte' 2 7. -__ __- R1MA-Top 11®lo�i Rev3 Rum PD1 1 - ----RIV6 7n" 7250 7500 ' 7750 8000 8250 8500 8750 9000 9250 9500 9750 10006 10250 10500 10750 11000 11250 11 West(-)/EaW+) (500 umMn) °��Y°9 �" cAsu4c n13iAlLS HA AJOURTOM Protect: COOK INLET BASIN i Site: REDOUBT SHOAL �: 90.GO FVD rJnss MD twineWell: Redoubt LiRi[ +1" +&-W If®� 1 010 0'�;'�61474 60.41'49 fiR114 15!•4n i<b56 A' 10496.99 1040fi.99 E1906.90 11810,00 Ifi129.85 7" 13500.00 9 51sT"Wellbore: bore: RllpGA ;Vhft NCE: [WPON 12542.00 12552.00 17671.15 419, ROMA WP04REFERE Plan0 IX.KRn OMR �VWawWdWh %%M.W gvcg Reblwrn' Poe[ wn...,.. 6-06-0 ®mmit�Phrt:IhtloWYeiN@m011'r[ Ileauad D R jm Peet l dX&-JM o GSA Q G;=a (FRCS: RK*bhkM 600-0fb� Re dIR0g9n IfM.d u-- - -1000 -1750 a J -2000J -i 2250-. Q a i 1'0161 Dg4h:17631.13' MI 126477VD Y.1%'' SFa'.Ib 117100: ]3507 LSD, 10496.997VD :4i' Li TP 111186-0 l'.'F[W Brd l)o = 1611815'3-07. D900'h'D EDd Dp ' 13iZ UD, 10512.4.1' 7YD SmDir5710716119.711m, 11899.96T9D ''. _ 4111` lQzs1 Dir 5111W: 13550L07, 1a535.329W - _ 4 ad Dir : 1415028'L81. 10921AMD i W Fordwd3DTaw Rte' 2 7. -__ __- R1MA-Top 11®lo�i Rev3 Rum PD1 1 - ----RIV6 7n" 7250 7500 ' 7750 8000 8250 8500 8750 9000 9250 9500 9750 10006 10250 10500 10750 11000 11250 11 West(-)/EaW+) (500 umMn) HALLIBURTON Database: Sperry EDM - NORTH US + CANADA Company: Glacier Oil Project: COOK INLET BASIN Site: REDOUBT SHOAL Well: Redoubt Unit #6 Wellbore: RU#6A Design: RU#6A WP04 Halliburton Standard Proposal Report Local Co-ordinate Reference: Wein Redoubt Unit #6 PlaRedoubtUnit# @ 90.0 (Pia 0 90.00usft (PI TVD Reference: MD Reference: Plan: RedoubtUnh# 6 90.0 (Pla @ 90.00usft (PI North Reference: Grid Survey Calculation Method: Minimum Curvature COOK INLET BASIN ct ystem. E US State Plane 1927 (Exact solution) System Datum: Mean Sea Level, Using Well Reference Point NAD 1927 (NADCON CONUS) atum:one: Alaska Zone 04 gNe REDOUBT SHOAL Northing: 2,449,990.00usft Latitude: 60° 41'44-224 N 151° 49 14.539 W Site Position: Map Fasting: 200,627.00usft Longitude: -1.46 ° From: Position Uncertainty' 0.00 usft slot Radius: 0" Grid Convergence' Well Redoubt Unit #6 2,449,933.56 usft Latitude: 60° 41'43.671 N Well Position +N/ -S 0.00 usft Northing: 200.619.74 usiE Longitude: 151 ° 40' 14.656 W +El -W 0.00 usft Fasting: usil Water Depth: 40.00 usft Position Uncertainty 0.00 usft Wellhead Elevation: Wellbore RU#6A ll�iagnetics Model Name Sample Date Declination Dip Anglo (1)(nT) Field Strength (') BGGM2018 6I1�1!Lt198 15.70 73.57 S5,711 Design RUt16A WP04 Audit Notes: Phase: PLAN Tie On Depth: 13,500.00 Version: Depth From VW) +NIS +E14M1I Direction Vertical Section (USM (usm (USM (°} 130.00 0.00 0.00 101.5Q Plan Sections Dogleg Build Tum Measured Depth Vertical TVD Depth Inclination Azimuthm +NIS +EIdN (`1100usm Rate Rate (11100usm Rate Tool Face C1100ust" (°} (usft) / ( ( (usm MM 13,500.00 38.57 109.46 10,496.99 10,406.99 -2,897.57 7,563.62 0.00 0.00 12.00 8.64 0.00 0-00 -13.12 X5.00 13,520.00 40.30 106.84 10,512.43 10,422.43 -2,901.52 7,575.69 0.00 0.00 0.00 Q.00 13,550.00 40.30 106.84 10,535.32 10.445.32 -2,907.14 7,594.26 5.00 3.35 -4.93 -59.10 14,150.28 60.38 77.25 10,921.48 10,831.48 -2,9115.75 8,044.88 0.40 0.00 0.00 0.00 16,129.77 60.38 77.25 11,899.96 11,809.96 -2,525.97 9,723.18 5.00 4.97 0.57 5.69 16,129.85 60.38 77.25 11,900.00 11.810.00 -2,525.96 9,723.25 10,996.17 0.00 0.00 0.00 0.00 17.631.13 60.38 77.25 12,642.00 12,552.00 -2,237.92 7/3/2018 1:21:45PM Page 2 COMPASS 5000.1 Build 81E Hal iburton Standard Proposal Report HALLIBURTON Database: Sperry EDM -NORTH US +CANADA Local Co-ordinate Referents: tgdl Redoubt Unit #6 Plan: RedoubtUnit# @ 90.0 (Pla @ 90.00usft (PI Company: Glacier Oil TVD Reference: Plan: RedoubtUnrg @ 90.0 (Pla a 90.00usft (PI Project: COOK INLET BASIN MD Reference: Grid T S Site: REDOUBT SHOAL North Reference: Survey Calculation Method: Minimum Curvature Welt: Redoubt #6 Wellbore: RU#6A Design: RU96A WP04 Planned Survey Measured Vertical +W -S +El W Map Northing ifiap F_astin9 DLS Vert Section inclination Azimuth )sfta ( USM () (ustt) 10,406.99 /D/epth i Planned Survey Measured Vertical Depth TVDss +W -S Halliburton Vert Section Depth inclination Azimuth (usft) usft Standard Proposal Report HALLIBURTON (usft) €°) r) 16,900.00 60.38 77.25 12,28D.64 12,190.64 Database: Sperry EDM - NORTH US + CANADA Local Co"ordmaie Reference' WeIn RedoubtUnit 06 tUnit# 90.0 (Pia 90.00usft (PI Company: Glacier Oil ND Reference: Pian: RedoubtUnit# 90.4 (Pia 94.OQusft (Pi Project: COOK INLET BA81N MD Reference: Grid REDOUBT SHOAL North Reference: Survey Calculation Method: Minimum Curvature Well: Redoubt Unit #6 Well: 10,715.41 2,447,632.50 211,335.15 0.00 10,959.14 Wellbore: RU#6A -2,301.45 -2,282.27 10,800.20 2,447,651.69 211,419.94 0.00 Design: RU#6A WPD4 17,400.00 60.38 17,500.00 60.38 77.25 12,577.19 12,487.19 -2,263.08 Planned Survey Measured Vertical Depth TVDss +W -S Map Map +E1 -W Northing Easting DLS Vert Section Depth inclination Azimuth (usft) usft (usft) (usft) (usft) (usft) 12,190.64 (usft) €°) r) 16,900.00 60.38 77.25 12,28D.64 12,190.64 -2,378.20 10,376.25 2,447,555.76 210,996.00 0.00 211,080.79 0.00 10,642.10 10,721.36 17,000.00 60.38 77.25 12,330.07 12,240.07 -2,359.01 10,461.04 2,447,574.94 2,447,594.13 211,165.57 0.00 10,800.62 17,100.00 60.38 77.25 12,379.49 12,289.49 -2,339.83 10,545.83 10,630.62 2,447,613.32 211,250.36 0.00 10,879.88 17,200.00 64.38 77.25 12,428.91 12,338.91 -2,320.64 10,715.41 2,447,632.50 211,335.15 0.00 10,959.14 17,304.00 60.38 77.25 12,476.34 12,388.34 77.25 12,527.76 12,437.76 -2,301.45 -2,282.27 10,800.20 2,447,651.69 211,419.94 0.00 11,438.39 17,400.00 60.38 17,500.00 60.38 77.25 12,577.19 12,487.19 -2,263.08 10,884.98 2,447,670.87 211,504.73 0.00 O.DO 11,117.65 11,196.91 17,600.00 60.38 77.25 12,626.61 12,536.61 -2,243.90 10,969.77 2,447,690.06 211,589.52 2,447,696.03 211,615.91 0.00 11,221.59 17,531.13 60.38 77.25 12,642.00 12,552.00 -2,237.92 10,996.17 Total Depth: 17631.13' MD, 12642' WD Targets Target Name - hit/miss target Dip Angle flip Dir. +Ef-W Northing ND +Nl-S g (usft) (usft) Easting (usft) - Shape (°) C) (usm (usft) 0.00 3 60.00 12,642.00 -2,258.95 10,981.25 2,447,675.00 211,601.00 W Foreland TO Target Rev 2 17600.00u6ft MD (12626.61 TVD, -2243.90 N, 10969.'!`1 E) - plan misses target center by 24.40usft at - Point 4.00 360.00 11,900.00 2,525.96 9,723.25 2,447,408.40 210,343.00 RUGA -Top Hemlock Rev 3 hits center ircle (radius - Carcc Casing Points Casing hole Measured Vertical Diameter Dtameter Depth Depth €) (") (usft) f� Name 9-518 12-1f4 13,500.00 10,496.99 9 518 „ 4= 6 17,631.13 12,642.00 4112" 7 8-112 16,129.85 11,900.00 7" Pian AnnaWlom Measured Vertical Local Coordinates Depth Depth +N1 -S (usft) (usft) (usft) +E[.W (usft) Comment 7,563.62 KOP : Start Dir 121100': 13500' MD, 10496.99'TVD : 45° LT TF 13,500.00 10,496.99 -2,897.57 -2,901.52 7,575.69 End Dir : 13520' MD, 10512.43' TVD 13,520.00 10,512.43 13,550.00 10,535.32 -2,907.14 7,594.26 Start Dir 501100': 13550' MD, 10535.327VD End Dir : 14150.28' MD, 10921.48' TVD 14,150.28 10,921.47 -2,905.75 8,044.88 9,723.18 Start Dir 5°1100' : 16129.77' MD, 11899.96'TVD 16,129.77 11,899.96 -2,525.97 11,900.00 -2,525.96 9,723.25 End Dir : 16129.85' MD, 11900' TVD 16,129.85 17,631.13 12,642.00 -2,237.92 10,996.17 Total Depth: 17631.13' MD, 12642' TVD 7/3/2018 1:21:45PM Page 4 COMPASS 5000.? Build 81E Glacier Oil COOK INLET BASIN REDOUBT SHOAL Redoubt Unit #6 RU#6A RU#6A WP04 Sperry Orilling Services Clearance Summary Anticollision Report 03 July, 2018 Closest Approach 3D Proximity Scan on Gnrent Survey Data (North Reference) Reference Design: REDOUBT SHOAL - Redoubt Unit 6a - RU#6A - RU#6A Y41`04 Welt Coordinates: 2,449,933.86 N, 200,619.75 E (60' 41'43.67* N, 161'40' 14.66" VO Datum Height: Plan- RedoubfUnitS @ 90.0 (Pla a 90.110usit (Pian: RedoubtunIW @ SDA (Plan: RedoubtUnM)) Scan Range: 1300.00 to 17,531.13 uW% Measured Depth. Scan Radius to 1,550.11 ¢sit . Clearance Factor culoli Is Unlimited. Max Ellipse Separation Is Unlimited Vsrslon: 5000.1 Build: SIE Scan Type - Scan Typo: 25.00 HALLIBURTON Sperry Grilling Seewiae s Glacier Oil HALLIBURTON COOK INLET BASIN Anticollision Report for Redoubt Unit #6 - RUNA WP04 Closest Approach 3D Proximity Scan an current Survey Data (North Reference) Reference Design. REDOUBT SHOAL - Redoubt Unit 06 - RU#6A - RUS6A WPO4 Scan Reage. 13,680.00 to 17,631.13 as1L Measured Depth. Scan Radius IS 1,968.11 Loft. Clem ,&r" Factor cutaR Is Unlimited. Max Ellipse Separation Is UrdWtad measured Minimum Qlleasured Ellipse site Name Depth Distance Depth Separation Comparison Wer Name - Werbere Name - Design (a1 (U1 (-ft) (LOM COOK INLET BASIN REDOUBT SHOAL ST 1 - REDOUBT SHOAL ST 1 - F REDOUBT SHOAL UNIT 2 - REDOUBT SHOAL UNIT REDOUBTSHOAL Redoubt UnitKt -RU#1 -RU#1 Redoubt Unit 91 - RU -1 A - RU -1 A Redoubt Unit E2 - Redoubt Unit 2A - Rrxlnubt Unit 2A Redoubt Unit #4 - RU64A - RU94A Redoubt Ural 118 - Rll#6 - RUIMB Redoubt Unit 08 - R!#8 PB1 - RU96 PBI RedmM UnIt #7 - RU#75T91 - RU#7ST#1 Redoubt Unit #7 - RU#75T#1- RU#7ST01 Redoubt Unit #7 - RU -73 - RU -78 Redoubt Unit #7 - RU -7B - RU -7B @Measurad Clearance Summary Based on Depth Factor Minimum Separation Warning craft 13,500.08 1,340.51 13,508.00 832.02 11,821.52 2-636 Clearance Factor Pass - 13,500.00 1,337.$8 13,500.00 829.28 11,822.47 2.631 Clearance Factor Pass - 13,500.00 1,383.34 13,5w.00 1,191.28 13,503.61 7.202 Clearance Factor Flags - 13,500,00 1,473.34 13,500.00 1270.55 13,322.52 7,265 Clearance Factor Pass - 13,500.00 1,895.40 13,500.04 1,551.97 13,449,95 5.519 Clearance Factor Pass - 17,$31.13 1,126-44 17,831-13 861.78 18,091.00 4.256 ClearenceFactor Pass - 13,800.00 38,89 13,800-00 34.99 13,796.92 9.983 CiearanceFactor Pass - 13,625.00 28.D8 13,624.00 2023 13,598.00 3.578 Clearance Factor Pass - 13,500,00 1,067.16 13,500-00 824.81 13,400.47 4,403 Ellipse Separation Pass - 15,575.00 1,640.05 15,575-00 1,218.57 15,950,00 3.891 Clearance Factor Pass - 13,500,00 1,044-65 13,500.00 843.03 13,526.88 5,181 Claarance,Factor Pass - 13,573.17 1,043.41 13,573.17 844-79 13,604.58 5.253 Centra Distance Pass - From To (usm (ustt) 148.06 992.00 1,616.06 13,308.00 13.347.00 13,500.00 13,500-6D 13,764.00 RUMBA WF`04 13,766.06 17,631.13 RUNfiA WP04 survey~ Survey Toot 2_CBFft-GSS 2 MWD+Sag 2_MWD+Sag 2_MYW Irderp Aa 1 MVYD*Sag 03 July, 2018 - 13. 13 Page 2 of 5 COMPASS HALLIBURTON Anticollision Report for Redoubt Unit #6 - RU#6A WP04 Ellipse error terms are correlated across survey tool fie -on points. Calculated Ellipses incorporate surface errors. Separation is the actual distance between ellipsoids. Disfance Between centres is the straight line distance between wellbofe centres. Clearance Factor= Distance Between Profiles !(Distance BeweenProfiles- Ellipse Sepafation}. Al station coordinates were calculated using the Minimum Curvature method. 03 July, 2018 - 1113 Glacier Oil COOK INLET BASIN Page 3 01`5COMPASS REFERENCE INFORMATION HALLIBU14TON "qrerm.-: Ym Reawe MA 0% OW Rents 1r�9cN IfVDI WIem¢+: PYK RedaWdY 60-O 07F W90irn (CIrK ���� SP.P"0010n0 m- r�tlC Aliacd: PYKRdmftW/ a" NM�IojAM(PlmrrmwMMie WD / r Project: COOK INLET BASIN suRV61 PROGRAM 111 Site: REDOUBT SHOAL D� sole-Q&i D:w V r WW6:re. 1mkw- Ian To Well: Redoubt Unit #6 I Dolan From DepN Te 6LA471ER W141bore: Ri3tf6A I 149.09 a62.00 R1.108 PB1 GYRO (RU/6 PBt) ice-Fer.c�s Pian: RLNGA WP04 lalaoo 13308 -Do RUPOPBI SRS Pal) 2 Aalro�sap 13347.00 13500.00 RLW (RUd61 2J4r�D�6e9 13500.00 13760.00 RUM° WP04 (RUMW zJ D N Azl. 17mo.oD 17631-13 RLWA%WN 1RLWA) �dderj$.F. Plots 2Da.a0 c x160.00 c F 20,00 10 0 BO, O U 2 40.0 0 � 0,0 13600 137515 14000 14250 14500 14750 16000 WEI.r-DETA1LS: R dednl®!M6 11a JyXltpNlA:41Y 1-ual .... T -- ----T ! f yq 1 No GLOBAL FILTER: Using user defined selection B GHef919 cdleria 13500.00 To 17631.13 i CASING DI=AILS r ND 7VDSS ARD elza Noma n Collision Risk PlocefteS Rett; y 1.50 r=_ - Auoldance Req. 1 12842.00 _Collision No -Go Zone-Stp Dr1ng 0.oa 19500 14750 15000 15; 13750 14000 14260 14600 WEI.r-DETA1LS: R dednl®!M6 11a JyXltpNlA:41Y 1-ual .... Wtic Dq6.. 40.90 ad 00 l:wd^g5 00.1 y4gg933.96 ¢ Ge71.4 1-ealW Dm617.74 60-g1'43b71 .'�' 351.40'14.616W D.00 D.00 No GLOBAL FILTER: Using user defined selection B GHef919 cdleria 13500.00 To 17631.13 CASING DI=AILS r ND 7VDSS ARD elza Noma 16496.90 1040a.99 13500.00 11-516 6 516" 11600,00 11810.00 16129.65 7 7" 12842.00 12552.00 17631.13 4.112 412" Measured Depth (500 usfurin) 16500 15750 16000 16260 16500 167x.0 1ruuu Measured Depth 17250 17500 1775D 18000 A $c =berger Camperry INTEGRATED FLUIDS ENGINEERING DRILLING FLUIDS PROGRAM RU -06A GLACIER OIL & GAS Prepared by: Name: Position: Project Engineer Company: M-1 SWACO Alaska FDP #: Version 1.1 Approvals Owner Signature: Date: Name: Job Title: Project Engineer Customer Approval: Name: Amanda Dial Position: Drilling Engineer Company: Glacier Oil & Gas AFE #: Approver ID: Reviewer I Approver Sales / Operations Manager I Drilling Engineer/ Drilling Manager MI Version I Date Description 1.0 6128/18 Draft Technical Program 1.1 7/01/18 Edited 8.5° interval 1.2 7/05118 Updated Depths and Volumes Version 1.2 NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties and product additions required for well -bore inte d . MII BYV=0 AkW=h"WCfflWW Glacier Oil & Gas RU -06A The RU -06A well will be a side track injector with a window cut in the 9.625" casing at 13,500' MD and drilled to a total depth of 17,631' MD with a 10.2 ppg ACTIMUL MOBM Drilling fluids system. Prior to total depth an 8.5" open hole will be drilled from the window to 16,130' followed by the installation of the 7" liner. After completing the 8.5" interval a 6" open hole will be dulled to 17,631' and completed with 4.5" tubing. The expected 6" production interval formation pressures should be drilled with a mud weight range of 10.2 —10.5 ppg. Key Performance Indicators HSE Cost Performance TRIR-Zero Actual vs Plan—+1-10% Mud Related Problem Time - Spill Rate - Zero Cost savings Downhole losses Zero I1,10111omnim-- nrillina fluid costlbbi hole drilled Technical su ort RU -06A CasingDepirl Peet Drilled 2,630 1,501 4,131 MON Required 2,491 453 BELS in Active 1,192 859 NA Open Hole Volume 203 57 NA Footage 8.6" intermediate 6" Production inner 1 14ole Size C6sing Intervals Depth M -D TV0 of Hole Mud System Mud Weight Tubing 170 _ Drilled 9.625" Casing NIA 13,500 16,130 10,500+/- 11,900 NA 2,fi30 N/A ACTIMUL MON N/A 10.2 7.1 85++ 17,631 12,642 1,501 ACTIMUL 10.2 -10.5 4.6" fi" Intervals Peet Drilled 2,630 1,501 4,131 MON Required 2,491 453 BELS in Active 1,192 859 NA Open Hole Volume 203 57 NA BBLS of Formation Drilled 203 57 260 8.6" intermediate 6" Production Total Version 1.2 Page 2 of 11 Confidential M1 SIAdAC A &W mhwW CNPPNq Version 1.2 Glacier Oil & Gas RU -06A *Hole conditions may dictate fluid properties Confidential Page 3 of 11 PROPERTIES AND SPECIFICATIONS 8.5" HOLE SECTION 6" HOLE SECTION Hole Size 8.5" 6° From MD 13,500' 16,130' To MD 16,130 17,631' TVD TBD TBD Length of Section 2,952' 1,429' Hole Angle NA NA Mud System ACTIMUL ACTIMUL Mud Weight - pAV 10.2 10.2-10.5 * Plastic Viscos' - CP ALAP ALAP * Yield Point - ibs1100ftz 13-24 10-24 ** LSYP - lbs1100M 6-10 5-8 Gel Strengths 40s/90m 6-15/8-20 6-15/8-20 API Fluid Loss - cc/30 min NA NA HTHP Fluid Loss - cc/30min@ 175OF <5 <5 H NA NA Chlorides - mg1L 20k - 30k 20k - 30k Hardness as Car- - m /L NA NA Sand Content - % x0.25 :50.25 MBT-ppb NA NA Drill Solids - % Vol :57 157 OWR 80120 80/20 E -Stability- volt >300 >300 Excess Line- ppb 1.0-2.0 1.0-2.0 *Hole conditions may dictate fluid properties Confidential Page 3 of 11 mi In Glacier Oil & Gas p%&LM W%Wcwip.., RU -06A Fluids Concerns for Intermediate & Production • Hole Instability — Coals have played a major part in the challenges that are faced when drilling in the Cook Inlet. Ensure that all lessons teamed from RU -07B are reviewed with the team in preparation for drilling RU -06A. Review coal drilling best practices that will be put together with Glacier Energy & Gas and M-1 SWACO prior to program • Hole Cleaning — Maintain rheology with TRUVIS as needed. The target LSYP is 6-8 Ibs1100ft2, the Yield Point may drift out of suggested values; this is acceptable as long as the LSYP remains in range. Record all test results in ONE-TRAX, Refer to the Virtual Hydraulics Hole Cleaning model for proper hole cleaning. It is recommended to stay within the Good Hole Cleaning range while drilling ahead, flow rate & ROP may need to be adjusted. • Losses- Follow the recommended Lost Circulation Decision Tree. It is recommended to add background LCM when losses occur. If a LCM pill is to be pumped, it is preferred that the pill be spotted across the loss zone and pull above to circulate and dynamically apply the treatment. For losses while drilling ahead, constant LCM additions is preferred over pumping LCM pills around. To minimize ECDs it is recommended to maintain the I-SYP as close to 6 lbs1100ft2 as possible. Elevated rheology can have a significant impact on ECDs. • Drill Solids- Maintain the DS below 6% through use of the shakers and whole mud dilutions as needed. Do not run the centrifuge continuously, it should only be used when mud weight needs to be reduced. Any used fluid should be shipped back to the mud plant for centrifuging & re -conditioning Fluid Loss Control —Add SAFE -CARE to help lower the fluid loss. It is only recommended to run the centrifuge periodically while drilling the production interval as this will strip out the larger particles and concentrate the fine solids. When running the centrifuge, ensure that SAFE -GARB is being added to the active. Emulsion Stability — Maintain 6 ppb ACTIMUL. If a significant drop in E -Stability is seen, VERSACOAT HF may be needed. SAG - Monitor and document VSST while drilling ahead and prior to tripping. if the VSST results are greater than 0.5 ppg, TRUVIS should be added to minimize the sag. VSST should be conducted and recorded daily in ONE- TRAX. • Lubricants — If torque becomes excessive and fluid loss, filter cake & hole cleaning are adequate, then a lubricant should be considered. LUBE 776 has shown to lower the friction factors in oil base mud. Track all lubricant additions and note before and after torque values on daily mud reports. Please track all lubricant additions on the 'Lubricant Tracking Form', Filling in all the fields. Version 1.2 Weight up strategy — If higher than expected pore pressure is encountered begin weighting up with additions of M-1 WATE. Weight up should be performed in 0.2 ppg increments per circulation. Carefully monitor VSST when weighting up and adjust rheology as needed to maintain a AMW of less than 0.5 ppg. While drilling ahead, always ensure proper additions of ACTIMUL or VERSAWET are made during the any weight up to properly oil wet the Barite. Confidential Page 4 of 11 Mill SWACD Glacier Oil & Gas "S,Wmbw" O�m RU -06A 8.5" Intermediate Interval Overview 13,500'— 16,130' Upon arriving on the rig, the current fluid that was stored from RU -07B will need to be tested and re conditioned to spec if needed. Once reconditioned the well will need to be prepped for drilling and the prior fluid displaced in preparation for milling operations. There is an option to mill out with milling fluid if desired due to the lubricity of the MOBM that will be utilized to drill the 8.5' interval. After successfully setting the whipstock and milling the 8.5" interval will be drilled to final TD and a 7" liner will be installed and cemented into place. Solids Control Equipment • Finest API mesh possible 200 — 270 Ensure all decking rubbers are in good condition and properly set • Spray down shaker screens with base fluid prior to use Shakers • Maintain proper deck angle to optimize shaker performance. Shaker discharge should be slightly wet, but not whole mud. Avoid jetting the flowline while drilling; this should be done only at connections or in short bursts while circulating. Check screens at every connection for holes or damage. Centrifuge Should only be run periodically while drilling in the production interval. 9 Note that the centrifuge will strip out all larger Calcium Carbonate Version 1.2 Pae 5 of 11 Confidential g MI S1AlAICr�� R SW+ehww Cagy Intermediate Interval Operations: Glacier Oil & Gas RU -06A 1. Ensure that all lines & pits are cleaned of any water based mud before bringing on ACTIMUL MOBM, 2. Upon completing the displacement mill out the window. There is a chance that this will be completed prior to the displacement to MOBM and milled with a high vis WBM . 3. Prior to drilling ahead ensure that drilling fluid is to spec and that all testing has been completed. 4. While drilling the intermediate section be attentive to hole conditions. If large pieces of coal are encountered make the necessary communications to the team. 5. Perform the HTHP fluid loss on each mud check. The HTHP should be run at 150°F to simulate downhole conditions. 6. if torque becomes excessive and fluid loss, filter cake & hole cleaning are adequate, then a lubricant can be considered. Add LUBE 776 in 0.25% increments to 3% maximum & track all lubricant additions and note before and after torque values on daily mud reports. Please track all lubricant additions on the `Lubricant Tracking Form', filling in all the fields. When adding the LUBE 776, carefully monitor the rheology as thinning has been seen in the past when the lubricant has been added to the ACTIMUL. 7. Record all volume activity (water, whole mud additions, chemical additions & losses), be sure to note any losses on daily mud reports (include depth encountered, initial loss rate, daily losses & total losses). If lost circulation material is pumped, note type and concentration of the LCM and the results (record on daily mud report & recap). Please track all whole mud additions on the 'Dilution Tracking Form', filling in all the fields. 8. Maintain excess Lime at 1.0 — 2.0 ppb 9. Once TD is reached ensure that the hole is clean and in good condition by monitoring shakers, checking torque and drag, pick up and slack off weights along with any tight spots when tripping out of hole. Version 1.2 Confidential Page 6 of 11 Me AScWmbAWCmWW Glacier Oil & Gas RU -06A 6" Production Interval Overview: 16,130'— 17,631' MD The 6" production interval will be drilled after successfully running the 7" liner. Inclination of the production interval will be greater than 60 degrees so hole conditions will dictate fluid properties. While drilling ahead ensure that the cuttings are being monitored to ensure that sluffing coals and/or hole instability are identified in a timely manner. Drill the production interval to TD ensuring that the hole is in good condition prior to running the 4.5° liner. 10.2 ppg Base Fluid Formulation Product Quantity Mineral Oil - 0.572 bbls/bbl TRUVIS 4 b Lime 2 ppb ACTIMUI. 6 ppb M -I WATE 100 ppb Calcium Chloride 44.47 ppb Solids Control Equipment Version 1.2 Finest API mesh possible 200 — 270 Ensure all decking rubbers are in good condition and properly set Spray down shaker screens with base fluid prior to use Shakers Maintain proper deck angle to optimize shaker performance. Shaker discharge should be slightly wet, but not whole mud. Avoid jetting the flowline while drilling; this should be done only at connections or in short bursts while circulating. • Check screens at every connection for holes or damage. Centrifuge Should only be run periodically while drilling in the production interval. Note that the centrifuge will strip out all larger Calcium Carbonate Confidential Page 7 of 11 Baee laid Piropqq Bum Weight 101—U.5 PV ALAP YP 13-18 Ibs/100ft2 LSYP 6-8 lbs/100ft2 Gels 10 sect 10 min 6-16/8-20 Modified HTHP @ 175T < 5.0 cc130 min using E-Stability'300 OWR 80120 Excess Lime 1.0 — 2.0 pb Prilmary 'Products _ Base Fluid LVT-200 Internal Phase 10.8 -11.0 ppg Calcium Chloride Brine _ Viscosifier TRUVIS & HRP Wetting Agent I Emulsifier ACTIMUL Bddqino Agent SAFE -CARE Alkalinit Control Lime Conting#pq Products Viscosifier TRUEVIS Lubricant LUBE 776 Lost Circulation Material WALNUT PLUG FINE & MEDIUM, SAFE -GARB & FORM-A-BLOK Solids Control Equipment Version 1.2 Finest API mesh possible 200 — 270 Ensure all decking rubbers are in good condition and properly set Spray down shaker screens with base fluid prior to use Shakers Maintain proper deck angle to optimize shaker performance. Shaker discharge should be slightly wet, but not whole mud. Avoid jetting the flowline while drilling; this should be done only at connections or in short bursts while circulating. • Check screens at every connection for holes or damage. Centrifuge Should only be run periodically while drilling in the production interval. Note that the centrifuge will strip out all larger Calcium Carbonate Confidential Page 7 of 11 Mr ERA Cc . A SDMJ orBM OWWW Glacier Oil & Gas RU -06A Production Interval Operations: 1. The 8.5" drilling fluid that was utilized will be re used to drill the 6° interval, ensure that all fluid is to spec prior to drilling ahead. 2. Drill out 7" shoe track taking cement back into the system to substitute for the need to add additional Lime. 3. Perform the HTHP fluid loss on each mud check. The HTHP should be run at 150°F to simulate downhole conditions. 4. if torque becomes excessive and fluid loss, filter cake & hole cleaning are adequate, then a lubricant can be considered. Add LUBE 776 in 0.25% increments to 3% maximum & track all lubricant additions and note before and after torque values on daily mud reports. Please track all lubricant additions on the 'Lubricant Tracking Form', filling in all the fields. When adding the LUBE 776, carefully monitor the rheology as thinning has been seen in the past when the lubricant has been added to the ACTIMUL. 5. Record all volume activity (water, whole mud additions, chemical additions & losses), be sure to note any losses on daily mud reports (include depth encountered, initial loss rate, daily losses & total losses). If lost circulation material is pumped, note type and concentration of the LCM and the results (record on daily mud report & recap). Please track all whole mud additions on the `Dilution tracking Form', filling in all the fields. 6. Maintain excess Lime at 1.0 — 2.0 ppb 7. Once TD is reached ensure that the hole is clean and in good condition by monitoring shakers, checking torque and drag and observing any tight spots when tripping out of hole. 8. Run in hole with 4.5" liner and set, depending on the completion method a decision will need to be made when to displace over to production water. 9. Prior to displacing over to production water ensure that the correct amount of biocide and corrosion inhibitor has been added to the completion fluid. 10. Displace out MOBM by pumping M-1 SWACO's displacement sequence using a push pill, cleaning spacer and high viscosity spacer. Version 1.2 Pae 8 of 11 Confidential 9 ME SWi4C�- A &*LxnkKg@r ' Glacier Oil & Gas RU -06A Intermediate and Production Interval Lost Circulation Recommendations Measure rate of loss *The particle sizing is smaller than WALNUT Plug Medium for these products Prior to pumping LCM, Directional Driller and MWD should be notified and the plan reviewed Ensure Particle sizes of bridging materials can pass' duorwgh the dow►rha+le teats and motors prior to roofing and spotdny. Spat pill across thief zarihe, dlosws stop. pu# into casing and 4WIy 50-100 psi squeeze pressure and watch far FvzWe bleed -off if pv%T" hok* for 15 minutes, resume drillingif pregwm dopes not hold, spot another pill as dela eed above. Repeat FORM-A-BLOK (Consider Bull Heading Pill from above the loss zone) Or Gunk Squeeze or Cement Plug Version 1.2 Pae 9 of 11 Confidential 9 Seepage losses < 20 bbl/hr static Partial losses 20 -60 bbllhr static Severelosses660 — 20 bbl/hr or ss of returns If fault related drill acrossfault If fault related drill across fault If fault related drill across fault 1-1.5 times the length of the 1-1.5 times the length of the 1-1.5 times the length of the throw before treating losses throw before treating losses throw before treating losses Begin additions of Begin additions of Begin mons of WALNUT PLUG FINE 1-3 WALNUT PLUG FINE 1-3 WALNUT PLUG ppb to the active while ppb to the active while MEDIUM to the active circulating. circulating. system while drilling past the fractured zone. If lasses don't improve, proceed to the FORM-A-BLOK pill. Consider pumping the 20-60 No so�sess 13PH pill prior to the FORM-A-BLOK pill. Spot 20 ppb pill*: Spot 40 Ppb pill*: Na soccer M -I -X 11 FINE 1 ppb 1.<<, M4 -X H FINE 1 ppb M -I -X H MEDIUM 2 ppb M -I -X 1I MEDIUM 2 ppb SAFE-CARB 250 6 ppb WALNUT PLUG F 13 ppb WALNUT PLUG FINE 11 ppb WALNUT PLUG M 5 ppb Squeeze high -fluid -loss pill*: SAFF CARi3 250 10 ppb SAFE -GARB 500 10 ppb No race= FORM-A-BLOK 40 ppb in base oil weighted up to desired density with Safe Carb-20. Note—Pill should be a m"inint= of 1.5 times the length of auef zone *The particle sizing is smaller than WALNUT Plug Medium for these products Prior to pumping LCM, Directional Driller and MWD should be notified and the plan reviewed Ensure Particle sizes of bridging materials can pass' duorwgh the dow►rha+le teats and motors prior to roofing and spotdny. Spat pill across thief zarihe, dlosws stop. pu# into casing and 4WIy 50-100 psi squeeze pressure and watch far FvzWe bleed -off if pv%T" hok* for 15 minutes, resume drillingif pregwm dopes not hold, spot another pill as dela eed above. Repeat FORM-A-BLOK (Consider Bull Heading Pill from above the loss zone) Or Gunk Squeeze or Cement Plug Version 1.2 Pae 9 of 11 Confidential 9 Mt SNVio►CO Glacier Oil & Gas na�mbwv'Cm"�" RU -06A Quality, Health, Safety & Environmental (QHSE) Health & Safety ➢ Ensure all SDS sheets are up to date and readily available for workers to access for information. Review SDS's regularly before completing tasks. ➢ Drilling crews should be instructed in the proper procedures for handling fluid products. ➢ Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, & the office of the Drilling Forman. ➢ PPE must be in good working order & be utilized as recommended by the PPE charts. Ensure a good stock of PPE is available prior to starting the well. ➢ Ensure sufficient weight material is on location to raise the planned fluid weight by a minimum of 1.0 ppg. ➢ Ensure that needed LCM is available at the rig site in the event of losses Environmental ➢ Ensure that all product stored outside is protected from the weather. ➢ Do not store partial units (sacks) outside if possible ➢ When transferring fluids Wor cuttings from the rig to tanks, insure all hoses are properly secured. Ensure that all fluid transfer forms have been completed in order to avoid spills. Do not use aluminum cam lock fittings when transferring brine or brine base mud. ➢ Product additions should be made with the intent to use the complete unit amounts of products (sacks, drums, cans), as much as possible in order to minimize inventory of partial Units. > Ensure that all drilling wastes are properly documented & manifested as per the Alaska Waste Disposal & Reuse Guide (Red Book). Any questions about drilling wastes should be directed to Oil Search Environmental. ➢ Ensure that all liquid products are stored within the correct secondary containment. ➢ Properly dispose of all mud product waste (empty sacks, pallets, etc.) in the appropriate disposal bins. Ensure that all drums have been emptied & rinsed (follow the M-1 SWACO Drum Disposal Guidelines). Quality Mud engineers will be present in the pits during any fluid critical tasks, These include displacements, cement jobs, sweeps & well kill operations. ➢ During displacements, ensure that proper valve alignment is included in the procedure provided to the rig crew. ➢ A minimum of 4 mud checks will be performed daily and recorded in ONETRAX on a daily basis, regardless of rig activity. The only time that 4 checks will not be required is when the pits are empty, or the well has been secured. ➢ If mud formulation or concentrations differs from the programmed recommendations, the project engineer must be notified for approval. ➢ Do not substitute products in formulations unless approval is given from the project engineer. ➢ Follow the Standard Work Instructions (SWI) for fluids; M-1 SWACO DS & WP Fluids SWI 1, 2, 3, 4 & 5. ➢ Review all Engineering Local Work Instruction (LWI) when applicable ➢ The HARCIJSA covering Testing Mud Samples (Quest #20151023200027) will be reviewed by each mud engineer every tour. Ensure that the ONE-TRAX file is uploaded into PROJECT VIEW daily ➢ Complete the Well -Site Interval Execution (7.1.4.01) at the end of each interval and submit with the End of Well Recap ➢ Ensure that sufficient products are on location to drill each interval prior to starting that interval. Version 1.2 Pae 11 of 11 Confidential 9 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION 333 West 7t' Avenue, Suite 100 Anchorage, Alaska 99501 Re: THE APPLICATION OF FOREST } Area Injection Order No. 32 OIL CORPORATION for an order } authorizing the underground ) Redoubt Unit injection of fluids for enhanced oil ) Redoubt Shoal Undefined Oil Pool recovery in the Hemlock Formation, } Redoubt Shoal Undefined OR Pool, ) Redoubt Unit, Cook Inlet, Alaska ) January 30, 2008 IT APPEARING THAT: 1. By application dated and received by the Alaska Oil and Gas Conservation Commission ("Commission's on July 30, 2007, Forest Oil Corporation ("Forest"), operator of the Redoubt Unit ("RU") requested a Commission order authorizing, under 20 AAC 25.402, the underground injection of fluids for enhanced oil recovery ("EOR") in the Hemlock Formation ("Hemlock") of the Redoubt Shoal Undefined Oil Pool. 2. The Commission published notice of the opportunity for a public hearing in the Anchorage Daily News on August 8, 2007 and in the Peninsula Clarion on August 9, 2007. 3. On August 8, 2007, Commissioner Daniel T. Seamount, Jr. recused himself from this case. 4. By emails dated August 6 and 7, 2007, and September 12, 2007, the Commission requested additional information. Forest responded on August 22, 2007, and September 14, 2007. 5. No comments, protests or requests for a public hearing were received. FINDINGS I. O_uerator Forest operates the Redoubt Shoal Undefined Oil Pool in the RU, Cook Inlet, Alaska. Area Injection Order 32 January 30, 2008 Page 2 2. Project Area and Proposed Enhanced Recovery Injection Interval Enhanced recovery injection is proposed for the Redoubt Shoal Undefined Oil Pool. This pool is compartmentalized by faulting into three fault blocks: the Northern, Central and Southern fault blocks. The Central and Southern fault blocks contain the majority of reserves in the pool. In the Central fault block, the injection zone is correlative with the interval from 14,140' to 14,945' measured depth ("MD") in the RU #1 well. In the Southern fault block, the injection zone is correlative with the interval from 14,365' to 13,222' MD in the RU #2 well. 3. Proposed Injection Area Forest has requested authorization to inject fluids for the purpose of enhanced recovery operations on RU land within. T07N R13W and T07N R14W, Seward Meridian. Most of the wells affected by the proposed injection activities were drilled from the Osprey Platform, which is located approximately 1.5 miles southeast of West Foreland, offshore Cook Inlet. However, there are also four exploratory wells within the proposed injection area that, between 1967 and 1976, were drilled and then plugged and abandoned. 4. O_yerators/Surface Owners Notil cation Forest is the only operator and the State of Alaska is the only surface owner within one-quarter of a mile of the proposed injection area. Forest provided the State a copy of the application for enhanced oil recovery injection. 5. Description of Operation Injection will occur within the Hemlock Formation ("Hemlock"). The Redoubt Shoal Undefined Oil Pool is being developed under statewide regulations. It has not yet been defined in vertical or regional space. There are three active wells in the Central fault block. There is no production from the Southern fault block. Pilot waterflood enhanced recovery operations conducted in the Central fault block were authorized by Enhanced Recovery Injection Order No. 2 in August 2004. During those pilot operations, from March 2005 through September 2007, Forest utilized the RU #6 well to inject 1.3 •million barrels of authorized fluids into the Hemlock and recovered 652,000 barrels of oil. The operator plans to progressively expand development within the RU, using new and re -drilled wells from the Osprey platform. However, development options will ultimately be determined by field performance and economic factors. To facilitate reservoir management and field development, surveillance data will be collected on an ongoing basis through static bottom -hole pressure surveys, production logging, injection logging and production well testing. 6. H drocarbon Recove The estimated original oil in place ("OOIP") for the RU is 54 million barrels of oil ("MMBO'�: 30 MMBO in the Central fault block and 24 MMBO in the Area Injection Order 32 January 30, 2008 Southern fault block. expected to be 6% waterflood operations OOIP. Page 3 Primary recovery from the Hemlock within the RU is f the OOIP. Results of the pilot project suggest that will increase recovery by on additional 5% to 7% of the 7. OwlQgic Inf rmation The Hemlock reservoir within the RU resulted from fluvial deposition in meandering„ coalescing stream channels. It consists of interbedded fine-grained to medium -grained sand, gravels, pebble conglomerates, dense silts and scattered thin coal beds. Conventional core analysis indicates that there are at least six lithofacies within the Hemlock, The Redoubt Shoal Undefined Oil Pool accumulated in a northeast -trending anticline that is bound to the west by east -dipping reverse faults. The anticline is transected by several southeast -trending, normal faults. Core data and well logs were used to estimate rock properties. Porosity is intergranular with well -cemented and competent rock. Clay volume ranges from 9% to 20% of rock volume and appears to be dispersed. Reservoir facies consist of pebble conglomerate (porosity 7% to 13%), pebble -gravel sandstone (porosity 10% to 161/o), medium -grained to coarse-grained sandstone (porosity 1016 to 169/x) and fine-grained sandstone (porosity 12% to 14%). Permeability ranges from 0.1 millidarcy to several hundred millidercies. The oil from the Hemlock at RU has a gravity of approximately 26.5° API, a gas - oil ratio of 250 standard cubic feet per stock tank barrel, and a bubble point pressure of 1,490 pounds per square inch absolute (" psia'). Upper confinement will result from an interval of tuffaceous siltstone and coal that lies at the top of the Hemlock. This interval is laterally continuous and ranges in thickness from 40' to 80'. Lower confinement will result from a series of laterally continuous, tuffaceous siltstone and claystone layers that lie at and near the base of the Hemlock. The aggregate thickness of these layers ranges from 40' to 501 . Well Logs The RU well logs are on file with the Commission. 9. Mechanical Integrity and Well Design of ILrij ection Wells The only injection well being used for EOR is RU #6, which has been injecting since March 2005 in accordance with Enhanced Recovery injection Order 2 C'ERIO 2'J. This well was converted from a producer to an injector in accordance with Commission regulations. There is no indication of any mechanical integrity issues with this well. 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Rule 2: Fluid Injection Wells The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412 Rule 3: Authorized Fluids for Enhanced Recovery The following fluids are authorized for injection: a. produced Hemlock RU water; b. treated sanitary waste; c, treated gray water from platform and camp living facilities; d. produced Hemlock water from the West McArthur River Oil Pool; e. storm water from secondary containment areas at the Kustatan Production Facility and the West McArthur River Production Facility; f. deck drainage from the Osprey Platform; and g. produced water from the gas wells in the West Foreland field. Rule 4: Authorized Injection Pressure for Enhanced Recovery a. Injection pressures must be maintained so that injected fluids do not fracture or migrate into the confining strata. b. If injected fluids fracture or migrate into the confining strata, the operator must immediately shut in the injection wells. Injection may not be restarted unless approved by the Commission. 30 31 All NWA; NW/4 of NE/4 T07N R14W 13 E/2 of NEA; E/2 of SEA; SW/4 of SEI4 23 SEA of SE/4 24 E/2; SWA; SE14 ofNW/4 25 All 26 E/2; S W/4; SE/4 of NW/4 34 E/2 of NEA; NE/4 of SEA 35 N/2; SEA; N/2 of SW/4 36 N/2; SWA; N/2 of SE/4; SW/4 of SE/4 Rule 1: Authorized Injection Strata for Enhanced Recovery Authorized fluids may be injected for purposes of pressure maintenance and enhanced recovery within the Redoubt Shoal Undefined Oil Pool into strata that are common to, and correlate with, the interval from 14,140' to 14,945' MD in the RU #1 well in the Central fault block and the interval from 14,365' to 15,222' MD in the RU #2 well in the Southern fault block. Rule 2: Fluid Injection Wells The underground injection of fluids must be through a well that has been permitted for drilling as a service well for injection in conformance with 20 AAC 25.005, or through a well approved for conversion to a service well for injection in conformance with 20 AAC 25.280 and 20 AAC 25.412 Rule 3: Authorized Fluids for Enhanced Recovery The following fluids are authorized for injection: a. produced Hemlock RU water; b. treated sanitary waste; c, treated gray water from platform and camp living facilities; d. produced Hemlock water from the West McArthur River Oil Pool; e. storm water from secondary containment areas at the Kustatan Production Facility and the West McArthur River Production Facility; f. deck drainage from the Osprey Platform; and g. produced water from the gas wells in the West Foreland field. Rule 4: Authorized Injection Pressure for Enhanced Recovery a. Injection pressures must be maintained so that injected fluids do not fracture or migrate into the confining strata. b. If injected fluids fracture or migrate into the confining strata, the operator must immediately shut in the injection wells. Injection may not be restarted unless approved by the Commission. Area Injection Order 32 Page 7 January 30, 2008 Rule 5: Monitoring Tubing -Casing Annulus Pressure The tubing and casing annuli pressures of each injection well must be monitored at least daily, except if prevented by an extreme weather condition, emergency situation, or similar unavoidable circumstance. The results shall be made available to the Commission upon request. Rule 6: Demonstration of Tubing/Casing Annulus Mechanical Integrity The mechanical integrity of an injection well must be demonstrated before injection begins, and before returning a well to service following a workover affecting mechanical integrity. A Commission -witnessed mechanical integrity test must be performed after injection is commenced for the first time in a well, to be scheduled when injection conditions (temperature, pressure, rate, etc.) have stabilized. Subsequent tests must be performed at least once every four years thereafter. The Commission must be notified at least 24 hours in advance of each mechanical integrity test to enable a Commission representative to witness the test. Unless an alternate means is approved by the Commission, mechanical integrity must be demonstrated by a tubing/casing annulus pressure test using a surface pressure equal to the maximum anticipated injection pressure that shows stabilizing pressure and does not change more than 10 percent during a 30 - minute period. The results of all mechanical integrity tests must be provided to the Commission. Rule S: Well Integrity Failure and Confinement Whenever any pressure communication, leakage or lack of injection zone isolation is indicated by an injection rate, operating pressure observation, test, survey, log, or other evidence, the Operator shall notify the Commission by the next business day and submit a plan of corrective action (on Form 10-403) for Commission approval. The Operator shall immediately shut in the well if continued operation would be unsafe, would threaten contamination of freshwater, or if so directed by the Commission. Monthly reports of daily tubing and casing annuli pressures and injection rates must be provided to the Commission for all injection wells indicating well integrity failure or a lack of injection zone isolation. Every five years from the effective date of this order, the operator shall analyze the mechanical integrity of all potentially affected wells and provide a report to the Commission. Rule 9: Notification of Improper Class II Injection The injection of fluids other than those listed in Rule 3 without prior Commission authorization is improper Class R injection. Upon discovering any such event, the operator must immediately notify the Commission, provide details of the event, propose actions to prevent a recurrence, and take any other action required by the Commission. Compliance with the notification requirements of any other State or Federal agency remains the operator's responsibility. Rule 10: Plugging and Abandoning Fluid Injection Wells An injection well within the Affected Area must not be plugged and abandoned unless such action is approved by the Commission in accordance with 20 AAC 25. Area Injection Order 32 Page 8 January 30, 2008 Rule 11: Other conditions It is a condition of this authorization that the operator complies with all applicable Commission regulations. The Commission may suspend, revoke, or modify this authorization if any Rule is violated or injected fluids fail or might fail to he confined within the designated injection strata. Rule 12: Administrative Actions Upon application or its own motion, the Commission may, without notice and public hearing (unless such are otherwise required), administratively waive the requirements of any Rule or administratively amend this Order as long as the change does not promote waste or jeopardize correlative rights, is based on sound engineering and geoscience principles, and will not result in an increased risk of fluid movement out of the designated injection strata or into freshwater. "-I DONE at Anchorage, Alaska, and dated January 31, . firman, Chairman Oil and Gas Conservation Commission Cathy P, oerster, Commissioner Alaska Oil and Gas Conservation Commission AS 31.05.080 provides that, within 20 days after written notice of the entry of an order, a person affected by the order may file with the Commission an application for reconsideration. To be timely filed, the application must be received by 4:30 p.ni, on the 23'd day following the date of the order, or the next working day if the 23'd day is a state holiday or weekend. The Commission shall grant or refuse the application in whole or in part within 10 days after it is filed. The Commission can refuse the application by not acting on it within the 10 -day period. A person who submitted an application for reconsideration has 30 days from the date the Commission refused the application or mailed (or otherwise distributed) an order on reconsideration, both being the final order of the Conmiission, to appeal the decision to Superior Court. Where an application for reconsideration is denied by nonaction of the Commission, the 30 -day period for appeal to Superior Court runs from the date on which the application is deemed denied i.e. 10a` day after the application for reconsideration was filed). Rixse. Melvin G (DOA) From: Stephen Ratcliff <sratcliff@glacieroil.com> Sent: Tuesday, July 24, 2018 8:03 AM To: Rixse, Melvin G (DOA) Cc: Amanda Dial Subject: Re: PTD(202-228) Redoubt Unit #6 Ram Configurations - Drilling and Liner Running Mel, Plan will be as follows: Annular / Double Gate Variable Rams / Double Gate Blind Rams / Cross / Single Gate Pipe Rams. We will also have the 2-7/8" X 4", 3-1/2" X 5-1/2", and 5" X 7" variable sizes on location for the different scenarios that you asked about. See my notes below in red for further details. Regards, Stephen Ratcliff Drilling Manager Glacier Oil and Gas Corporation 601 W. 5th Avenue, Suite 310 Anchorage, AK 99501 0 - (907) 433-3808 C - (907) 433-9738 From: "Rixse, Melvin G (DOA)" <melvin.rixse@alaska.gov> Date: Monday, July 23, 2018 at 3:24 PM To: Stephen Ratcliff <sratcliff@glacieroil.com> Subject: RE: PTD(202-228) Redoubt Unit #6 Ram Configurations - Drilling and Liner Running Steve, What will be your ram configuration when drilling 8-1/2" hole, i.e. size, VBRs(?), location? - 5" Pipe Rams + 5" X 7" Variable Rams What will be your ram configuration when drilling 6" hole, i.e., size, VBRs(?), location? - 5" Pipe Rams + 3- 1/2" X 5-1/2" Variable Rams (4" + 5" Combo String) What will be your ram configurations when running 7" and 4-1/2" liners? - On the 7" run we will install the 5" X 7" Variables. On the 4-1/2" liner we will have our 3-1/2" X 5" Variables. Mel Rlxse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-223-3605 Cell CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Mel Rixse at (907-793-1231) or (Melvin. RixsePalaska.sov). Davies, Stephen F (DOA) From: Stephen Ratcliff <sratcliff@glacieroil.com> Sent: Wednesday, July 18, 2018 8:05 AM To: Davies, Stephen F (DOA) Subject: Re: RU 6A (PTD 218-083) - Questions Steve, We will have H2S alarms, as required per the regs. We have not encountered any H2S on the Osprey in the past from any of thewells. Thanksl Regards, Stephen Ratcliff Drilling Manager Glacier Oil and Gas Corporation 601 W. 5th Avenue, Suite 310 Anchorage, AK 99501 0 - (907) 433-3808 C - (907) 433-9738 From: "Davies, Stephen F (DOA)" <steve.datries:�klaska.gov> Date: Tuesday, July 17, 2018 at 5:56 PM To: Stephen Ratcliff <sratclif`r@glacieroil,roin> Subject: RU 6A (PTD 218-083) - Questions Stephen, Maybe I missed this within CIE's Permit to Drill Application for RU -6A, but has any H25 been encountered in, or produced from, any well within the Redoubt Unit? Will the rig have H2S sensors and alarms? Will H25 scavenging mud additives be available aboard the rig? Thank you, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the Intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davie.5@alaska.gov. Remark: AOGCC PTD No. 218-083 Coordinate Check 17 July 201 B INPUT Geographic, NAD27 OUTPUT State Plane, NAD27 5004 - Alaska 4, U.S. Feel RU 6A 111 Latitude: 60 41 43.67112 NorlhingM. 2449933.973 Longitude: 153. 40 14.65608 EastinglX: 200619.743 Convergence: -1 27 25.32158 Scale Factor: 1.000001991 Corpscon v6.0.1, U.S. Army Corps of Engineers TRANSMITTAL LETTER CHECKLIST WELL NAME: �1� �i� 1 GOot PTD: -- Development ✓ Service _ Exploratory _ Stratigraphic Test Non -Conventional FIELD: Jas 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 ( PIT) 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. (CompanNaame) 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 Com an Name in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 212015
