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Home My WebLink About200-148Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 1/16/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240116 Well API #PTD #Log Date Log Company Log Type AOGCC ESet # BCU 09A 50133204450100 224113 10/26/2024 YELLOWJACKET SCBL BCU 12A 50133205300100 214070 8/21/2024 YELLOWJACKET GPT-PLUG-PERF BRU 233-23T 50283202000000 224088 12/28/2024 AK E-LINE PPROF BRU 233-27 50283100260000 163002 12/31/2024 AK E-LINE PPROF BRU 243-34 50283201240000 208079 12/27/2024 AK E-LINE PPROF GP 03-87 50733204370000 166052 12/25/2024 AK E-LINE CBL GP AN-17A 50733203110100 213049 12/16/2024 AK E-LINE CBL GP AN-17A 50733203110100 213049 12/21/2024 AK E-LINE Perf GP BR-03-87 50733204370000 166052 1/3/2025 AK E-LINE CBL IRU 44-36 50283200890000 193022 1/3/2024 AK E-LINE Depth Determination/Plug IRU 44-36 50283200890000 193022 12/26/2024 AK E-LINE DepthDetermination KU 31-07X 50133204950000 200148 12/3/2024 AK E-LINE Perf MPU B-21 50029215350000 186023 1/4/2025 AK E-LINE PlugSettingRecord MPU H-08B 50029228080200 201047 12/28/2024 AK E-LINE Welltech MRU G-01RD 50733200370100 191139 12/12/2024 AK E-LINE IPROF MRU G-01RD 50733200370100 191139 12/18/2024 AK E-LINE Perf MRU M-25 50733203910000 187086 12/3/2024 AK E-LINE Perf MRU M-25 50733203910000 187086 12/19/2024 AK E-LINE Perf PBU 01-37 50029236330000 219073 11/23/2024 HALLIBURTON PPROF PBU 06-05 50029202980000 178020 12/21/2024 HALLIBURTON RBT PBU 06-19B 50029207910200 224095 12/11/2024 HALLIBURTON RBT PBU 11-38A 50029227230100 198216 11/27/2024 HALLIBURTON TEMP PBU 14-31A 50029209890100 224090 11/11/2024 HALLIBURTON RBT PBU L-103 50029231010000 202139 11/25/2024 HALLIBURTON IPROF PBU M-207 50029238070000 224141 12/25/2024 HALLIBURTON RBT PBU P2-55 50029222830000 192082 12/5/2024 HALLIBURTON PPROF PBU S-15 50029211130000 184071 11/18/2024 HALLIBURTON RBT TBU M-25 50733203910000 187086 12/13/2024 AK E-LINE Perf T39958 T39959 T39960 T39961 T39962 T39963 T39964 T39964 T39965 T39966 T39966 T39967 T39968 T39969 T39970 T39970 T39971 T39971 T39972 T39973 T39974 T39975 T39976 T39977 T39978 T39979 T39980 T39981 KU 31-07X 50133204950000 200148 12/3/2024 AK E-LINE Perf Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.01.16 13:56:40 -09'00' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Re-Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: Sterling 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 5,790'N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,090psi Liner 5,410psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng ZXP Packer; N/A 5,151' MD/4,313' TVD; N/A; N/A 4,749'5,356'4,450' Kenai 3, 4, 5.1, 5.2 & 6 Gas, Sterling 6 GS 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Unit (KU) 31-07XCO 510C Same 4,679'9-5/8" ~200psi 5,669' 5,525' Length November 28, 2024 5,680'530' Tie back 7" 4,672' 5,690' Perforation Depth MD (ft): 7" See Attached Schematic 3,090psi 93'93' 1,508' Size 72' 1,487' MD Hilcorp Alaska, LLC Proposed Pools: 26# / L-80 TVD Burst 5,151' 5,750psi 1,483' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 200-148 50-133-20495-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Daniel Taylorr, Optimization Engineer AOGCC USE ONLY 7,240psi Tubing Grade: dtaylor@hilcorp.com 907-947-8051 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:12 pm, Nov 15, 2024 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2024.11.15 14:50:20 - 09'00' Noel Nocas (4361) 324-652 DSR-11/21/24SFD 11/18/2024BJM 11/26/24 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.11.26 15:26:28 -09'00'11/26/24 RBDMS JSB 112924 Well Prognosis Well: KU 31-07X Date: 11-14-24 Well Name: KU 31-07X API Number: 50-133-20495-00 Current Status: Storage Prod/Inj Permit to Drill Number: 200-148 First Call Engineer: Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer: Daniel Taylor (907) 777-8319 (O) (907) 978-9135 (C) Maximum Expected BHP: ~ 300 psi @ 4587’ TVD (Pool 6 Max pressure in 4 years) Max. Predicted Surface Pressure: ~ 200 psi (Current Pool 6 SI pressure) Brief Well Summary KU 31-07X was drilled to facilitate annular flow from the low-pressure Sterling reservoirs within KGF. Well was perforated in Pool 6 brought online in April 2001. Well currently produces about 3.7 mmscfd @ 180 psi bottom hole pressure and 60psi tubing pressure. The reservoir model indicates this well is underperforming and the purpose of this work is to reperforate the Pool 6 sands. Notes Regarding Wellbore Condition x 7” completion with tieback liner hanger at 5,150’ MD x SL tagged fill @ 5,322’ (10/16/24) Pool Top in KU 22-06X - Sterling Gas Pool 6 Top: 5,295’ MD; 4,325’ TVD Pre-sundry procedure 1. MIRU SL, PT to 1,000 psi 2. Bail fill to 5,370’ 3. RDMO SL E-Line Procedure 1. MIRU E-line, PT lubricator to 250 psi low and 1,000 psi high 2. PU GPT and RIH to ensure well is dry and complete correlation log 3. PU Guns and Reperforate Sterling Pool 6 sands: Proposed Perforated Intervals Pool Sand Top, MD ft Bottom, MD ft Top, TVD ft Bottom, TVD ft Total ft MD Sterling Gas Pool 6 Pool 6 ±5,320’ ±5,370’ ±4,340’ ±4,380’ ±50’ a. Proposed perfs also shown on the proposed schematic in red font. b. Send the correlation pass to the Reservoir Engineer (Daniel Taylor), and Geologist (Daniel Yancey) for confirmation. c. Verify PTs are open to SCADA before perforating. Record tubing pressures at 5, 10 and 15 minutes after each perforating run. d. These sands are in the Sterling Gas Pool 6 per CO 510C. 4. RDMO e-line. Well Prognosis Well: KU 31-07X Date: 11-14-24 5. Turn well over to production. Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 7" Liner Hanger & ZXP Packer @ 5,150' MD (6.00" ID) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Unit 31-7x Kenai Peninsula Borough 5,330' - 5,630' ~ 1.4º / 100 ft @ 450' 7/14/2009 Donna Ambruz Lease: State: Perf (TVD): A - 028142 Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,433' - 4,637' 47º RKB:66' (AMSL)21' (AGL) 01/05/2022 TD 5,790' MD 4,749' TVD PBTD 5,356' MD 4,450' TVD KU 31-7x Pad 14-6 320' FSL, 1,325' FWL, Sec. 6, T4N, R11W, S.M. Permit #:200-148 API #:50-133-20495-00-00 Prop. Des:A - 028142 KB elevation:87' (21' AGL) Spud:12/26/2000 @ 16:45 hrs TD:1/9/2001 @ 9:30 hrs Rig Released:1/15/2001 @ 16:30 hrs Conductor 20" K-55 133 ppf Top Bottom MD 0' 93' TVD 0' 93' Surface Casing 13-3/8" Top Bottom K-55 61 ppf MD 0' 1,211' TVD 0' 1,201' L-80 68 ppf MD 1,211' 1,508' TVD 1,201' 1,483' 17-1/2" hole Cmt w/ 515 sks (229 bbl) of 12.0 ppg, Type 1 cmt, 43 sks (19 bbls) Production Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,690' TVD 0' 4,679' 12-1/4" hole cmt w/ 1,150 sks (230 bbls) of 15.8 ppg, Class G cmt. Lost returns, 150 sks (30bbls) during cementing. C1 C1 C2 C2 Date 12/10/21 (9/15/04) (8/24/04) (9/9/04) Gun Type 3-3/8", 60º, 6 SPF 3-3/8", 60º, 6 SPF 4-1/2", 60º, 6 SPF 3-3/8", 60º, 6 SPF TVD 4,433'-4,450' 4,433'-4,460' 4,597'-4,637' 4,597'-4,637' Ft 26' 40' 58' 58' MD 5,330'-5,356' 5,330'-5,370' 5,572'-5,630' 5,572'-5,630' Sterling Pool-6 Perfs: Liner (2004 RWO) 7" L-80 26 ppf Mod BTC Top Bottom MD 5,150' 5,680' TVD 4,313' 4,672' 9-5/8" casing Cmt w/ 18.8 bbls 15.8 ppg CMT 9-5/8" TOC @ 3640' (1/14/2001 CBL) Tie-Back Tubing7" L-80 26 ppf Mod BTCTop BottomMD 21' 5,150'TVD 21' 4,313' Tag sand with 3.5" DD Bailer 11/9/2021 @ 5,560' SCHEMATIC CIBP set at 5,525' on 11/17/21 TOC @ 5,356' on 12/8/21 7" Liner Hanger & ZXP Packer @ 5,150' MD (6.00" ID) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Unit 31-7x Kenai Peninsula Borough 5,330' - 5,630' ~ 1.4º / 100 ft @ 450' 7/14/2009 Donna Ambruz Lease: State: Perf (TVD): A - 028142 Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,433' - 4,637' 47º RKB:66' (AMSL)21' (AGL) 11-15-24 TD 5,790' MD 4,749' TVD PBTD 5,356' MD 4,450' TVD KU 31-7x Pad 14-6 320' FSL, 1,325' FWL, Sec. 6, T4N, R11W, S.M. Permit #:200-148 API #:50-133-20495-00-00 Prop. Des:A - 028142 KB elevation:87' (21' AGL) Spud:12/26/2000 @ 16:45 hrs TD:1/9/2001 @ 9:30 hrs Rig Released:1/15/2001 @ 16:30 hrs Conductor 20" K-55 133 ppf Top Bottom MD 0' 93' TVD 0' 93' Surface Casing 13-3/8" Top Bottom K-55 61 ppf MD 0' 1,211' TVD 0' 1,201' L-80 68 ppf MD 1,211' 1,508' TVD 1,201' 1,483' 17-1/2" hole Cmt w/ 515 sks (229 bbl) of 12.0 ppg, Type 1 cmt, 43 sks (19 bbls) Production Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,690' TVD 0' 4,679' 12-1/4" hole cmt w/ 1,150 sks (230 bbls) of 15.8 ppg, Class G cmt. Lost returns, 150 sks (30bbls) during cementing. C1 C1 C1 C2 C2 Date Proposed 12/10/21 (9/15/04) (8/24/04) (9/9/04) Gun Type 3-3/8", 60º, 6 SPF 3-3/8", 60º, 6 SPF 4-1/2", 60º, 6 SPF 3-3/8", 60º, 6 SPF TVD ±4,340'-4,380' 4,433'-4,450' 4,433'-4,460' 4,597'-4,637' 4,597'-4,637' Ft ±50' 26' 40' 58' 58' MD ±5,320'-5,370' 5,330'-5,356' 5,330'-5,370' 5,572'-5,630' 5,572'-5,630' Sterling Pool-6 Perfs: Liner (2004 RWO) 7" L-80 26 ppf Mod BTC Top Bottom MD 5,150' 5,680' TVD 4,313' 4,672' 9-5/8" casing Cmt w/ 18.8 bbls 15.8 ppg CMT 9-5/8" TOC @ 3640' (1/14/2001 CBL) Tie-Back Tubing7" L-80 26 ppf Mod BTCTop BottomMD 21' 5,150'TVD 21' 4,313' Tag sand with 3.5" DD Bailer 11/9/2021 @ 5,560' PROPOSED CIBP set at 5,525' on 11/17/21 TOC @ 5,356' on 12/8/21 Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/28/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240228 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# AN-37 50733203940000 187109 11/8/2023 HALLIBURTON RBT KBU 31-18 50133206490000 215024 2/22/2024 HALLIBURTON PressTemp KBU 42-6 50133205460000 204209 2/23/2024 HALLIBURTON PPROF KU 31-07X 50133204950000 200148 2/2/2024 HALLIBURTON PressTemp MPU C-13 50029213280000 185067 2/23/2024 READ CaliperSurvey MPU C-14 50029213440000 185088 2/23/2024 READ CaliperSurve MPU L-43 50029231900000 203224 2/14/2024 READ CaliperSurvey MPU J-08A 50029224970100 199117 1/21/2024 HALLIBURTON COILFLAG TBU M-20 50733205870000 209093 1/1/2024 HALLIBURTON COILFLAG Please include current contact information if different from above. T38535 T38536 T38537 T38538 T38539 T38540 T38541 T38542 T38543 2/29/2024 KU 31-07X 50133204950000 200148 2/2/2024 HALLIBURTON PressTemp Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.29 09:17:32 -09'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE:Thursday, May 11, 2023 SUBJECT:Mechanical Integrity Tests TO: FROM:Adam Earl P.I. Supervisor Petroleum Inspector NON-CONFIDENTIAL Hilcorp Alaska, LLC 31-07X KENAI UNIT 31-07X Jim Regg InspectorSrc: Reviewed By: P.I. Suprv Comm ________ JBR 05/11/2023 31-07X 50-133-20495-00-00 200-148-0 N SPT 4313 2001480 1500 135 135 135 135 0 0 0 0 4YRTST P Adam Earl 4/6/2023 MIT IA 30 MinPretestInitial15 Min Well Name Type Test Notes: Interval P/F Well Permit Number: Type Inj TVD PTD Test psi API Well Number Inspector Name:KENAI UNIT 31-07X Inspection Date: Tubing OA Packer Depth 394 1580 1571 1570IA 45 Min 60 Min Rel Insp Num: Insp Num:mitAGE230412102346 BBL Pumped:0.5 BBL Returned:0.5 Thursday, May 11, 2023 Page 1 of 1          Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 31-7X (PTD 200-148) Plug 11/17/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 12:35 pm, Jan 11, 2022 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 31-7X (PTD 200-148) Gauge Ring Run 11/15/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 12:35 pm, Jan 11, 2022 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 1/12/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 31-07X (PTD 200-148) Gamma Ray Correlation 12/08/2021 Please include current contact information if different from above. 37' (6HW Received By: 01/12/2022 By Abby Bell at 8:54 am, Jan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The coil squeeze of the IA wasn't done, nor was the second CIBP set, nor were the shallower Sterling perfs shot. Rather, Sundry 321-600 was approved, allowing the first CIBP to be set and the well left completed only in the C1 sands, w/EL re-perfing the existing C1 perfs. This change (no IA squeeze and no newly perforated pool) negated the Sundry 321-390 requirements of a post-perf MIT-IA to 2000 psi and isolation plugs being tagged and pressure tested. -WCB Z/,ǁŝƚŚϭͲϭϭͬϭϲΗ>͕ϯϬΖŽĨϯ͘ϱΗďĂŝůĞƌ ǁŝƚŚϭϯ͘ϱŐĂůůŽŶƐŽĨĐĞŵĞŶƚ;ϴ͘ϰΖͿ͘^ĂƚĚŽǁŶΛϱϱϬϲΖ͘WƵůůĞĚƵƉŚŽůĞĂŶĚƐĂƚĚŽǁŶĂƚϱϰϴϮΖ>ŽŽƐŝŶŐŚŽůĞ͘WŝĐŬƵƉĂŶĚ ƌƵŶďĂĐŬĚŽǁŶĂƚϱϰϵϬΖ͘tŽƌŬĞĚƚŽŽůƐĚŽǁŶƚŽϱϱϭϴΖĂŶĚĚƵŵƉĐĞŵĞŶƚ ^ĞƚƉůƵŐĂƚϱϱϮϱΖ^ĞƚůŽŽŬĞĚŐŽŽĚ͘WhĂŶĚƚĂŐƉůƵŐ͘ 8.4' cement dumped atop CIBP @5525'. -WCB D/ZhͲůŝŶĞƵŶŝƚĂŶĚĞƋƵŝƉŵĞŶƚ Z/,t/d,ϮϯͬϰΗ''͕ϮϯͬϰΗ^^E^dd/E'dKK>t/d,ϱ͘ϲϭΗ K/W͕ϭϯΖ&ZKD>dKdKWK&W>h'͕^dW>h'ΛϱϱϮϱΖ͕ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϭϭͬϭϱͬϮϭ ϭϮͬϭϬͬϮϮ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϯϭͲϬϳy ϱϬͲϭϯϯͲϮϬϰϵϱͲϬϬͲϬϬ ϮϬϬͲϭϰϴ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ϭϮͬϬϭͬϮϬϮϭͲtĞĚŶĞƐĚĂǇ ƌĞǁĂƌƌŝǀĞĚĂƚ<'&͕DĞƚǁŝƚŚůĞĂĚŽƉĞƌĂƚŽƌ͕ƌĞĐĞŝǀĞĚƉĞƌŵŝƚĂŶĚĐŽŶĚƵĐƚĞĚ:^͘ ^ƚĂƌƚĞĚƵƉĞƋƵŝƉŵĞŶƚ͕ǁĂƌŵĞĚƵƉ͕ͬŽƚŽŽůƐƚƌŝŶŐǁŝƚŚϮ͘ϮϱΗƐƚĞŵ͘ WŝĐŬ>ƵďƌŝĐĂƚŽƌ͕ƐƚĂďŽŶƌŝƐĞƌ͕ƉƌĞƐƐƵƌĞƚĞƐƚƚŽϮ͕ϱϬϬƉƐŝ͕ƉĂƐƐĞĚ͘Z/,ǁͬϯΖΖǆϲΖĚĚďĂŝůĞƌƚŽϱϮϳϱΖ<ǁͬƚŽŽůƚŽϱϮϳϴΖŬď ƉŽŽŚϭͬϰĨƵůůĚƌǇŵƵĚ Z/,ǁͬƐĂŵĞƚŽϱϮϳϴΖŬďǁͬƚŽŽůƚŽϱϮϵϭΖŬďƉŽŽŚďŽƚƚŽŵƉĂĐŬĞĚǁͬĚƌǇŵƵĚ͘Z/,ǁͬϱ͘ϵϱΖΖŐͲƌŝŶŐƚŽϱϮϳϭΖŬďǁͬƚŽŽůƚŽ ϱϮϳϱΖŬďƉŽŽŚŐͲƌŝŶŐƉĂĐŬĞĚĨƵůůŽĨŵƵĚ Z/,ǁͬϯ͘ϱΗǆϭϭΖĂŝůĞƌƚŽϱϮϳϲΖŬďǁͬƚŽŽůƚŽϱϮϳϴΖŬďƉŽŽŚďŽƚƚŽŵƉĂĐŬĞĚ Z/,ǁͬϯΗǆϲΖĂŝůĞƌƚŽϱϮϳϵΖŬďǁͬƚŽŽůƚŽϱϮϴϵΖŬďƉŽŽŚƐĂŵĞďŽƚƚŽŵĨƵůů͘Z/,ǁͬϱ͘ϵϱΖΖŐͲƌŝŶŐƚŽϱϮϳϴΖŬďǁͬƚŽŽůƚŽ ϱϮϴϬΖŬďƉŽŽŚŐͲƌŝŶŐƉĂĐŬĞĚĨƵůůŽĨŵƵĚ Z/,ǁͬϮ͘ϱΖΖǆϲΖĚĚďĂŝůĞƌǁŚŝůĞďƌŝŶŐŝŶŐǁĞůůŽŶƚŽϱϮϴϵΖŬďǁͬƚŽŽůƐůŽǁůǇůŽƐŝŶŐŚŽůĞͲĂĨƚĞƌϭϱŵŝŶ͘ůŽƐƚϭϳΖƉƵůůƵƉϭϬϬΖ ƐŚƵƚŝŶǁĞůůƌŝŚƚŽϱϮϳϭΖŬďƚĂŐƉŽŽŚϭͬϰĨƵůůǁĞƚŵƵĚďŽƚƚŽŵƉĂĐŬĞĚǁͬĚƌǇŵƵĚ͘>ĂǇĚŽǁŶůƵď͘ĐƵƚǁŝƌĞ͕ƌĞŚĞĂĚ͕ĐŚĞĐŬ ƚŽŽůƐƚƌŝŶŐ͕ĚĞƉĂƌƚĨŝĞůĚ͘ ^ůŝĐŬůŝŶĞĂƌƌŝǀĞƐĂƚ<'&͕ŵĞĞƚǁŝƚŚKƉĞƌĂƚŝŽŶƐ͕ŽŵƉůĞƚĞ:^͕ƌĞĐĞŝǀĞWdt͘^ƚĂƌƚƋƵŝƉŵĞŶƚ͕WdKŶŽƚĞŶŐĂŐŝŶŐͲ ZĞƉĂŝƌĞĚ͘Wͬh>ƵďƌŝĐĂƚŽƌ͕ĚŝƐĐŽǀĞƌŬŝŶŬŝŶǁŝƌĞ͕ůĂǇĚŽǁŶ͕ĐƵƚǁŝƌĞ͘ Wͬh>ƵďƌŝĐĂƚŽƌ͘ƐƚĂďŽŶƚƌĞĞWͬƚůƵďƌŝĐĂƚŽƌƚŽϮ͕ϱϬϬƉƐŝ͕ŐŽŽĚƚĞƐƚ͘Z/,ǁϮ͘ϱΗǆϲΖĂŝůĞƌƚŽϱ͕ϯϵϱ<ǁͬƚŽŽů͘ůŽƐĞ ƐƉĂŶŐĂĐƚŝŽŶ͕WKK,ĨƵůůŽĨƚŚŝĐŬŵƵĚ͘>ĂǇĚŽǁŶϯͲϭͬϮΗ>ƵďƌŝĐĂƚŽƌ͘ĂĚĚϭϰΖŽĨϳΗůƵďƌŝĐĂƚŽƌ͘ Z/,ǁͬϯ͘ϱΗǆϭϭΖĂŝůĞƌƚŽϱ͕ϮϱϲΖ<^/dǁͬdŽŽů͘WKK,ĂŝůĞƌŽƚƚŽŵƉĂĐŬĞĚǁŝƚŚϴΗŽĨƐĂŶĚĚƌǇŵĂƚĞƌŝĂů͘Z/,ǁͬ ƐĂŵĞƚŽϱ͕ϮϲϰΖ<͘ǁŽƌŬƚŽŽůƐ͕WKK,ƐĂŵĞďŽƚƚŽŵƉĂĐŬĞĚǁŝƚŚĚƌǇŵƵĚ͘tŝƌĞũƵŵƉĞĚƚŽƉƐŚĞĂǀĞĚŽƚŽŝĐĞ͕ůĂǇĚŽǁŶ ůƵď͕&ŝǆ͘Z/,ǁͬϯ͘ϵΗŐĂƵŐĞƌŝŶŐƚŽϱ͕ϮϰϬ<ǁͬƚŽŽůƚŽƐĐƌĂƉĞƉŝƉĞĚŽǁŶƚŽϱ͕Ϯϳϭ<͘WKK,͘Z/,ǁͬϳΗďƌĂŝĚĞĚůŝŶĞďƌƵƐŚ ƚŽϱ͕ϮϱϲΖ<ǁŽƌŬƚŽŽůƐƚŽϱ͕ϮϳϮΖ<͘ǁŽƵůĚŶŽƚĨĂůů͘WKK,͘>ĂǇĚŽǁŶůƵďƌŝĐĂƚŽƌ͕ƐĞĐƵƌĞǁĞůůĨŽƌƚŚĞŶŝŐŚƚ͘ĐŚĞĐŬŽƵƚ ǁŝƚŚŽƉƐĂŶĚůĂǇĚŽǁŶĨŽƌƚŚĞŶŝŐŚƚ͘ KŶ>ŽĐĂƚŝŽŶ͕ĐŚĞĐŬŝŶǁŝƚŚKƉĞƌĂƚŝŽŶƐ͕ŽŵƉůĞƚĞ:^ĂŶĚWĞƌŵŝƚ͕ZŝŐƵƉtŝƌĞůŝŶĞĂŶĚƉƌĞƐƐƵƌĞƚĞƐƚĞƋƵŝƉŵĞŶƚ͕ϮϱϬϬ W^/͘ dWϳϱƉƐŝǁŝƚŚǁĞůůĨůŽǁŝŶŐΛĂƉƉƌŽǆ͕ϭ͘ϱŵŵƐĐĨĚ͘Z/,ǁͬϱ͘ϵϱΗŐĂƵŐĞZŝŶŐƚŽϰ͕ϭϬϬΖ<͕ĞŐŝŶĨĂůůŝŶŐƐůŽǁƚŽϱ͕ϭϬϬΖ<͕ tŽƌŬdŽŽůƐĨĂůůƚŽϱ͕ϮϬϬΖ<͕tŽƌŬdŽŽůƐƚŽϱ͕ϮϲϬΖ<͘>ŽƐŝŶŐǁĞŝŐŚƚ͕ĚĞĐŝƐŝŽŶƚŽWKK,͘KŶĐĞƚŽŽůƐKK&͕ƚŽŽůƐĐŽǀĞƌĞĚŝŶ ĚƌǇŵƵĚ͘Z/,ǁͬϮ͘ϱΗǆϲΖĂŝůĞƌƚŽϱ͕ϯϴϱΖ<tŽƌŬdŽŽůƐƚŽϱ͕ϯϵϬΖ<͘WKK,͘KK,ǁŝƚŚĨŝŶĞĚƌǇƐĂŶĚ͘tĂŝƚŝŶŐŽŶ dŽǁŶĨŽƌƉůĂŶĨŽƌǁĂƌĚ͘ĞĐŝƐŝŽŶŵĂĚĞƚŽŬĞĞƉďĂŝůŝŶŐĂŶĚĐůĞĂŶǁĞůůƵƉ͕ƉƌŝŽƌƚŽ>ŝŶĞĚƵŵƉŝŶŐĐĞŵĞŶƚĂŶĚ ƌĞƉĞƌĨŽƌĂƚŝŶŐ͘ >ĂǇŽǁŶ>ƵďͲƉƌĞƉĨŽƌŵŽƌŶŝŶŐŽƉĞƌĂƚŝŽŶƐ͕ĐůŽƐĞŽƵƚƉĞƌŵŝƚǁŝƚŚKƉĞƌĂƚŝŽŶƐ͘ ϭϭͬϮϯͬϮϭͲdƵĞƐĚĂǇ Wdt͕:^͘D/Zh,<ŚŽƚŽŝůƚƌƵĐŬƚŽƚƵďŝŶŐĨůŽǁůŝŶĞ͘WdůŝŶĞƐǁŝƚŚϲϬͬϰϬŵĞƚŚĂŶŽůƚŽϮϱϬͬϰϬϬϬ͘t,WϴϬƉƐŝ͘/ϭϬϬ͕K ϬƉƐŝ͘KŶůŝŶĞǁŝƚŚŶĞĞƚŵĞƚŚĂŶŽůĂƚϮďďůƐͬŵŝŶĨŽƌϭϬďďůƐ͘>ŝŶĞƵƉŽŶyǇůĞŶĞ͘WƵŵƉϭϮďďůƐǆǇůĞŶĞĂƚϮ͘ϮďďůƐͬŵŝŶϴϬϬ ƉƐŝƉƵŵƉƉƌĞƐƐƵƌĞ;ϭΗŚŽƐĞͿ͘ŚĂƐĞǁŝƚŚϮϬďďůƐŽĨDĞƚŚĂŶŽů͘ZŝŐĚŽǁŶŚŽƚŽŝůƚƌƵĐŬĂŶĚŵŽǀĞƚŽ<hͲϭ ϭϭͬϮϵͬϮϬϮϭͲDŽŶĚĂǇ ϭϭͬϯϬͬϮϬϮϭͲdƵĞƐĚĂǇ KK,ǁŝƚŚĨŝŶĞĚƌǇƐĂŶĚ ĞĐŝƐŝŽŶŵĂĚĞƚŽŬĞĞƉďĂŝůŝŶŐĂŶĚĐůĞĂŶ ǁĞůůƵƉ͕ƉƌŝŽƌƚŽ>ŝŶĞĚƵŵƉŝŶŐĐĞŵĞŶƚĂŶĚ ƌĞƉĞƌĨŽƌĂƚŝŶŐ͘ ŐͲƌŝŶŐƉĂĐŬĞĚĨƵůůŽĨŵƵĚ KŶůŝŶĞǁŝƚŚŶĞĞƚŵĞƚŚĂŶŽůĂƚϮďďůƐͬŵŝŶĨŽƌϭϬďďůƐ͘>ŝŶĞƵƉŽŶyǇůĞŶĞ͘WƵŵƉϭϮďďůƐǆǇůĞŶĞĂƚϮ͘ϮďďůƐͬŵŝŶϴϬϬ ƉƐŝƉƵŵƉƉƌĞƐƐƵƌĞ;ϭΗŚŽƐĞͿ͘ŚĂƐĞǁŝƚŚϮϬďďůƐŽĨDĞƚŚĂŶŽů WKK,ĂŝůĞƌŽƚƚŽŵƉĂĐŬĞĚǁŝƚŚϴΗŽĨƐĂŶĚĚƌǇŵĂƚĞƌŝĂůĨ KŶĐĞƚŽŽůƐKK&͕ƚŽŽůƐĐŽǀĞƌĞĚŝŶ ĚƌǇŵƵĚ͘ ^ůŝĐŬůŝŶĞĂƌƌŝǀĞƐ Trying to get down to cement top @5516', but only getting to 5272'. -WCB ŵƵĚ͘ ďŽƚƚŽŵƉĂĐŬĞĚǁͬĚƌǇŵƵĚ͘ WKK,ĨƵůůŽĨƚŚŝĐŬ ZŝŐƵƉtŝƌĞůŝŶĞ ƉŽŽŚŐͲƌŝŶŐƉĂĐŬĞĚĨƵůůŽĨŵƵĚ ZŝŐ ^ƚĂƌƚĂƚĞ ŶĚĂƚĞ ϭϭͬϭϱͬϮϭ ϭϮͬϭϬͬϮϮ ,ŝůĐŽƌƉůĂƐŬĂ͕>> tĞůůKƉĞƌĂƚŝŽŶƐ^ƵŵŵĂƌǇ W/EƵŵďĞƌ tĞůůWĞƌŵŝƚEƵŵďĞƌtĞůůEĂŵĞ <hϯϭͲϬϳy ϱϬͲϭϯϯͲϮϬϰϵϱͲϬϬͲϬϬ ϮϬϬͲϭϰϴ ĂŝůǇKƉĞƌĂƚŝŽŶƐ͗ ϭϮͬϬϲͬϮϬϮϭͲDŽŶĚĂǇ ZŝŐƵƉƐůŝĐŬůŝŶĞ͕WdůƵďƚŽϮ͕ϬϬϬƉƐŝ͘Z/,ĂŶĚĐůĞĂŶŽƵƚǁĞůůǁŝƚŚŵƵůƚŝƉůĞďĂŝůĞƌƐĂŶĚŐĂƵŐĞƌŝŶŐƐƚŽϱ͕ϰϬϮΖ<͘ ^ůŝĐŬůŝŶĞĂƌƌŝǀĞĚŽŶůŽĐĂƚŝŽŶ͕ŽďƚĂŝŶƉĞƌŵŝƚƐ͕ĐŽƵůĚŶŽƚŐĞƚƚƌƵĐŬƐƐƚĂƌƚĞĚ͕ĨƌŽǌĞŶĨƵĞůůŝŶĞŽŶďŽŽŵƚƌƵĐŬ͘DĞĐŚĂŶŝĐ ƚŚĂǁĞĚƚƌƵĐŬ͘Zh͕WdǁŝƚŚǁĞůůƉƌĞƐƐƵƌĞ͕Z/,ǁͬďŽǁƐƉƌŝŶŐĐĞŶƚ͘ĂŶĚϮ͘ϱΗǆϲΖĂŝůĞƌƚŽϱϯϴϳΖŬď͕ǁͬƚƚŽϱϯϵϴΖŬď͘ ĨƚĞƌĐůĞĂƌŝŶŐƚŽŽůƐƵƉŚŽůĞ͕ůŽƐƚϭϮΖƚŽϱϯϳϳΖŬď͘tͬƚƚŽϱϯϴϵΖŬď͘WKK,͕ďĂŝůĞƌĨƵůůǁͬƐŽƵƉǇƐĂŶĚZ/,ǁͬĐĞŶƚƌĂůŝǌĞƌĂŶĚ ϯΗǆϴΖĂŝůĞƌƚŽϱϯϵϬΖŬď͘tͬƚƚŽϱϯϵϭΖŬď͘&ƵůůďĂŝůĞƌŽĨƐĂŵĞ͘Z/,ǁͬƐĂŵĞƚŽϱϯϴϲΖŬď͕ǁͬƚƚŽϱϯϵϯ͘WKK,ǁͬĨƵůů ďĂŝůĞƌŽĨƐĂŵĞŵĂƚĞƌŝĂů͘Z͕ĐůĞĂŶƚŽŽůƐĂŶĚĂƌĞĂ͘WůƵŐŝŶĞƋƵŝƉŵĞŶƚĨŽƌƚŚĞŶŝŐŚƚ ϭϮͬϬϰͬϮϬϮϭͲ^ĂƚƵƌĚĂǇ ^ůŝĐŬůŝŶĞĂƌƌŝǀĞĚŽŶůŽĐĂƚŝŽŶ͘WĞƌŵŝƚ͕:^͘tĂƌŵƵƉĂŶĚŐĞƚĞƋƵŝƉŵĞŶƚƌƵŶŶŝŶŐ͘ WdǁŝƚŚǁĞůůƉƌĞƐƐƵƌĞ͘Z/,ǁͬďŽǁƐƉƌŝŶŐĐĞŶƚƌĂůŝǌĞƌϯΗǆϴΖƚŽϱϯϳϵΖŬď͘tͬƚƚŽϱϯϴϭΖ͕ďĂŝůĞƌĨƵůůŽĨƐůƵƌƌǇŵƵĚ Z/,ǁͬƐĂŵĞƚŽϱϯϳϴΖŬď͕ǁͬƚƚŽϱϯϴϭΖ͘WKK,ǁͬĨƵůůďĂŝůĞƌŽĨƐĂŵĞŵĂƚĞƌŝĂů Z/,ǁͬƐĂŵĞƚŽϱϯϳϵŬď͕ǁͬƚ͘>ŽƐƚϭΖƚŽϱϯϳϴΖ͘WKK,ǁͬĨƵůůďĂŝůĞƌŽĨƐĂŵĞ Z/,ǁͬϯ͘ϱΗǆϭϭΖĂŝůĞƌǁͬŽĐĞŶƚƌĂůŝǌĞƌƚŽϱϮϳϵΖŬď͘tͬƚ͕ĨĞůůƚŽϱϯϲϰΖŬď͘WKK,ǁͬďĂŝůĞƌϭͬϮĨƵůů͘Z/,ǁͬƐĂŵĞƚŽ ϱϯϳϰΖŬď͕ǁͬƚƚŽϱϯϳϴΖŬď͘WKK,ǁͬĨƵůůďĂŝůĞƌ͘ZƐůŝĐŬůŝŶĞ͘,ĞĂĚŚŽŵĞĨŽƌƚŚĞŶŝŐŚƚ͘ ϭϮͬϬϴͬϮϬϮϭͲtĞĚŶĞƐĚĂǇ ^ŝŐŶŝŶ͘WdtĂŶĚ:^͘DŽďĞƚŽůŽĐĂƚŝŽŶĂŶĚŚĂǀĞƚĂŝůŐĂƚĞŵĞĞƚŝŶŐ͘^ƉŽƚĞƋƵŝƉŵĞŶƚĂŶĚƌŝŐƵƉůƵďƌŝĐĂƚŽƌ͘'ŽƉŝĐŬƵƉ ŵĂŶůŝĨƚ͘WdϮϱϬƉƐŝĂŶĚϮϱϬϬƉƐŝ͘dWͲϭϱϳƉƐŝ͘Z/,ǁͬϯ͘ϲϭΗK'ZĂŶĚ:ĂŶĚƚŝĞŝŶƚŽƉůƵŐůŽŐ͘dŽŽůƐƐĞƚĚŽǁŶĂƚϱϯϵϲΖ ƉƐŝ͘ŽƵůĚŶΖƚŐŽĂŶǇĚĞĞƉĞƌ͘tŽƌŬĞĚƚŽŽůƐĨŽƌϭϱŵŝŶĂŶĚWKK,͘ĂůůƚŽǁŶĂŶĚĚŝƐĐƵƐƐĞĚ͘:ǁĂƐĨƵůůŽĨŵƵĚ͘ĞĐŝƐŝŽŶ ŵĂĚĞƚŽƌƵŶŝŶǁͬϯ͘ϱΗǆϯϬΖƵŵƉďĂŝůĞƌĨŝůůĞĚǁŝƚŚϭϯŐĂůƐ;ϭϬΖͿ͘Z/,ǁͬϯ͘ϱΗǆϯϬΖĐĞŵĞŶƚĚƵŵƉďĂŝůĞƌĨŝůĞĚǁŝƚŚϭϯŐĂůŽĨ ϭϲ͘ϰƉƉŐ;ϴΖͿĂŶĚƚŝĞŝŶƚŽƉůƵŐůŽŐ͘dŽŽůƐƐĞƚĚŽǁŶĂƚϱϯϳϮΖ͘tŽƌŬƚŽŽůƐďƵƚĐŽƵůĚŶΖƚŐĞƚƉĂƐƚϱϯϳϮ͘ZĂŶĐŽƌƌĞůĂƚŝŽŶůŽŐ ĂŶĚƐĞŶĚƚŽƚŽǁŶ͘ĂůůƚŽǁŶĂŶĚŐĞƚŽŬƚŽĚƵŵƉĞĚĐĞŵĞŶƚĂƚϱϯϳϮΖ͘^ƉŽƚƚĞĚďĂŝůĞƌϱϯϳϬΖĂŶĚĚƵŵƉĐĞŵĞŶƚďĂŝůĞƌ͘>ŽƐƚ ǁĞŝŐŚƚĂŶĚǁŽƌŬĞĚƚŽŽůƐƐŽŵĞĂŶĚWKK,͘KƵƚŽĨŚŽůĞͬďĂŝůĞƌǁĞŶƚŽĨĨŐŽŽĚ͘Z/,ǁͬϯ͘ϱΗǆϯϬΖĐĞŵĞŶƚĚƵŵƉďĂŝůĞƌĨŝůĞĚ ǁŝƚŚϭϯŐĂůŽĨϭϲ͘ϰƉƉŐ;ϴΖͿĂŶĚƚŝĞŝŶƚŽƉůƵŐůŽŐ͘dĂŐĂƚϱϯϲϰΖ͘ĂůůĞĚƚŽǁŶĂŶĚĚŝƐĐƵƐƐĞĚĂŶĚĚƵŵƉĞĚϴΖŽĨϭϲ͘ϰƉƉŐĂƚ ϱϯϲϰΖ͘WKK,͘ĂŶĚďĂŝůĞƌůŽŽŬŐŽŽĚ͘'ŽŽĚĚƵŵƉ͘ZŝŐĚŽǁŶ>ƵďƌŝĐĂƚŽƌĂŶĚĞƋƵŝƉ͘^ĞĐƵƌĞǁĞůůĂŶĚǁĂŝƚŽŶĐĞŵĞŶƚ͘DŽǀĞ ĞƋƵŝƉŵĞŶƚƚŽ<hϮϰͲϯϮ͘ƐƚdKϱϯϱϲΖ͘ ϭϮͬϬϮͬϮϬϮϭͲdŚƵƌƐĚĂǇ ^ůŝĐŬůŝŶĞĂƌƌŝǀĞĚĂƚ<'&͕ŵĞƚǁŝƚŚŽƉĞƌĂƚŝŽŶƐ͕ĐŽŵƉůĞƚĞ:^ĂŶĚĨŝůůŽƵƚƉĞƌŵŝƚ͘^ƚĂƌƚƵƉĞƋƵŝƉŵĞŶƚ͕WͬhůƵď͘^ƚĂďŽŶ ƌŝƐĞƌ͘WƌĞƐƐƵƌĞƚĞƐƚůƵďƚŽϮ͕ϱϬϬƉƐŝ͕ŐŽŽĚƚĞƐƚ͘Z/,ǁͬďŽǁƐƉƌŝŶŐĐĞŶƚ͘ǁͬϮΖΖǆϯΖĚĚďĂŝůĞƌƚŽϱϮϴϬΖŬďǁͬƚŽŽůƚŽϱϮϴϱΖŬď ƉŽŽŚďĂŝůĞƌďŽƚƚŽŵƉĂĐŬĞĚǁŝƚŚĚƌǇŵƵĚ͘Z/,ǁͬƐĂŵĞƚŽϱϮϵϴΖŬď͕ǁͬƚƚŽϱϮϵϵΖŬďƉŽŽŚďŽƚƚŽŵƉĂĐŬĞĚĨƵůů͘Z/,ǁͬ ƐĂŵĞƚŽϱϮϵϴΖŬď͕ǁͬƚƚŽϱ͕ϯϬϬΖŬďƉŽŽŚďŽƚƚŽŵƉĂĐŬĞĚĨƵůů͘Z/,ǁͬƐĂŵĞƚŽϱϮϵϴΖŬď͕ǁͬƚƚŽϱϮϵϵΖŬďƉŽŽŚďŽƚƚŽŵ ƉĂĐŬĞĚĨƵůůĚŝƐĐƵƐƐƉůĂŶĨŽƌǁĂƌĚĨůŽǁǁĞůůĨŽƌϭϬŵŝŶ͘ƐƚĂŶĚďǇĨŽƌĚŝĞƐĞůͲĚƵŵƉϭϬŐĂů͘ŝŶƚƌĞĞ͘Z/,ǁͬƐĂŵĞƚŽϱϮϵϭΖŬď ǁͬƚŽŽůƚŽϱϮϵϱΖŬďƉŽŽŚϭͬϮĨƵůůƚŚŝĐŬŵƵĚ͘Z/,ǁͬƐĂŵĞƚŽϱϮϵϭΖŬď͕ǁͬƚƚŽϱϯϬϬΖŬď͘&ĞůůƚŽϱϯϴϲΖŬď͕ǁͬƚƉŽŽŚĨƵůů ƚŚŝĐŬŵƵĚ͘Z/,ǁͬďŽǁƐƉƌŝŶŐĐĞŶƚ͘ǁͬϮ͘ϮϱΖΖǆϰΖĚĚďĂŝůĞƌƚŽϱϯϴϳΖŬďǁͬƚŽŽůϱϯϵϯΖŬďƉŽŽŚĨƵůůƐĂŵĞ͘Z/,ǁͬďŽǁƐƉƌŝŶŐ ĐĞŶƚ͘ǁͬϮ͘ϱΖΖĚĚďĂŝůĞƌƚŽϱϯϴϳŬď͕ǁͬƚƚŽϱϯϵϯΖŬď͘WKK,ĨƵůůŽĨƐĂŵĞ͘>ĂǇĚŽǁŶůƵď͕ƐĞĐƵƌĞǁĞůůĨŽƌƚŚĞŶŝŐŚƚ͘ƚƵƌŶŝŶ ƉĞƌŵŝƚ͘ ϭϮͬϬϯͬϮϬϮϭͲ&ƌŝĚĂǇ ĂůůƚŽǁŶĂŶĚŐĞƚŽŬƚŽĚƵŵƉĞĚĐĞŵĞŶƚĂƚϱϯϳϮΖ͘^ƉŽƚƚĞĚďĂŝůĞƌϱϯϳϬΖĂŶĚĚƵŵƉĐĞŵĞŶƚďĂŝůĞƌ͘ ďĂŝůĞƌĨƵůůŽĨƐůƵƌƌǇŵƵĚ WKK,ǁͬďĂŝůĞƌϭͬϮĨƵůů Dumped 13 gal (8') cement, for est TOC @5356'. -WCB Dumped 13 gal (8') cement @5372', 144' above first batch of cement dumped atop CIBP. -WCB WKK,͕ďĂŝůĞƌĨƵůůǁͬƐŽƵƉǇƐĂŶĚZ/, ^ůŝĐŬůŝŶĞĂƌƌŝǀĞĚŽŶůŽĐĂƚŝŽŶ WKK,ǁͬĨƵůůďĂŝůĞƌŽĨƐĂŵĞ Trying to get down to cement top @5516', but only getting to 5386'. -WCB Here they only got 8.4' cement atop the CIBP @5525'. Due to obstructed casing, and after multiple SL bailing runs, 16' cement was dumped from 5372' to 5356'. 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Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 5,790'N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,090psi Liner 5,410psi Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12.Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14.Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Chad Helgeson Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE AOGCC Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Bryan McLellan (for MeOH/Xylene Treatment) 4,749'5,665'4,662'1,000 5,525' 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Dan Marlowe, Operations Manager chelgeson@hilcorp.com (907) 777-8405 7,240psi 11/19/2021 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: ZXP Packer; N/A 5,150' MD/4,313' TVD; N/A; N/A See Attached Schematic See Attached Schematic November 23, 2021 7" 4,672' PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 200-148 50-133-20495-00-00 Kenai Gas Field / Sterling 3, 4, 5.1, 5.2 & 6 Gas, Sterling 6 Gas Storage Pools CO 510B 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99516 Hilcorp Alaska, LLC Other: MeOH/Xylene Length Size 26# TVD Burst 5151' 5,750psi MD 3,090psi 93' 1,483' 93' 1,508' 4,679'9-5/8" Kenai Unit (KU) 31-07X 1,487' 5,690' Perforation Depth MD (ft): 5,669' 7"5,680'530' 20" 13-3/8" 72' ry Statu Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:18 am, Nov 23, 2021 321-600 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.11.23 09:27:48 -09'00' Dan Marlowe (1267) BJM 11/23/21 Development DSR-11/23/21 May remain a service well if job is successful-bjm 10-404 - ensure the well is correctly Classified as either Service or Development, depending on production results. X DLB 11/23/2021dts 11/23/2021 11/24/21 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2021.11.24 07:30:52 -09'00' RBDMS HEW 11/24/2021 Well Prognosis Well: KU 31-07X Date: 11-22-2021 Well Name:KU 31-07X API Number: 50-133-20495-00 Current Status:Gas Storage Well Leg:N/A Estimated Start Date:11/23/21 Rig:Hot Oil Truck Reg. Approval Req’d?403 Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:200-148 First Call Engineer:Chad Helgeson (907) 777-8405 (O) (907) 229-4824 (C) Second Call Engineer:Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) AFE Number:215-03532 Current Surface Pressure: 170 psi (Pool 6) Maximum Expected BHP:~ 220 psi Max. Potential Surface Pressure:~ 1000 psi (Expected pressure limit for pump truck) Well Status KU 31-07X is a Pool 6 gas storage producer/injector that was offline since January 2021 due to sand production. The well was recently cleaned out with slickline work and a CIBP was set to isolate the C2 Sand as approved in AOGCC Approved Sundry # 321-390. The well was brought online in the C-1 Sand making approximately 700 mcfd with just C-1 Sand open and sand removed from well. Prior to continuing with approved sundry to plug back the Pool 6 zones entirely and move up hole, Hilcorp would like to determine if the well could be cleaned up and returned to a Pool 6 producer/injector with only the C-1 sand open. Brief Well Summary KU 31-07X was originally drilled and completed in 2001 targeting the Sterling Pool 6 formations. A workover in 2004 recompleted the well from having 3-1/2” tbg to having a cemented 7” liner / tieback completion. In April of 2006, the well was converted to a gas storage injector/withdrawal well. Geologically the KU 31-07X wellbore sits at the top of structure in the Sterling and is the highest offtake point for many of the Sterling sands. The purpose of this Sundry is to pump methanol and xylene into the C-1 sand to try and cleanup any near wellbore damage from lube oils on the compressor. If there is improvement but not back to the original well performance as an injector or producer, additional perfs will be added in the same interval. Procedure (Verbal approval received from Bryan McLellan on 11/19/21 for the pumping work) 1. MIRU pump truck, PT hoses and hardline. 2. Pump 10 bbls of methanol (fill sump from top of plug to perfs) 3. Pump 10 bbls of Xylene into well 4. Pump 20 bbls of MeOH into well 5. Pressure well up with gas pressure, max pressure is 700 psi (gas injection pressure) 6. Wait 24 for well to soak 7. Return well to production and try to produce the well. 8. Test SVS system within 5 days if well is stable production Contingency (If well does not achieve stable rates above 3 mmcfd of production)Verbal approval is not granted for the perforating work below this line. DLB -00 DLB additional perfs will be added in the same interval. Well Prognosis Well: KU 31-07X Date: 11-22-2021 9. MIRU E-Line, Pressure test equipment. 10. Re perforate existing open zones in well in Sterling Pool-6 C-1 Sands: Sand MD Top MD Bottom Total Gross Footage (MD) TVD Top TVD Bottom Estimated Reservoir Pressure Pool-6 C-1 ±5,330’ ±5,370’' 40' ±4,433 ±4,460' 210 PSI a. Discuss wellhead pressure with OE, prior to perforating (max 600 psi) b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Chris Kanyer 907.250.0374 Geologist Daniel Yancy 907.250.9632 d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. 11. POOH. 12. RD E-Line. 13. Turn well over to production.(Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) If the well does not perform after fluid treatment and/or perforating, the rest of the steps in Sundry # 321-390 will be followed. Attachments: Current Well Schematic Proposed Well Schematic Re perforate existing open zones in well in Sterling Pool-6 C-1 Sands: DLB 7" Liner Hanger & ZXP Packer @ 5,150' MD (6.00" ID) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Unit 31-7x Kenai Peninsula Borough 5,330' - 5,370' ~ 1.4º / 100 ft @ 450' 7/14/2009 Chad Helgeson Lease: State: Perf (TVD): A - 028142 Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,433' - 4,637' 47º RKB:66' (AMSL)21' (AGL) 11/22/2021 TD 5,790' MD 4,749' TVD PBTD 5,663' MD 4,660' TVD KU 31-7x Pad 14-6 320' FSL, 1,325' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 200-148 API #: 50-133-20495-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) Spud: 12/26/2000 @ 16:45 hrs TD: 1/9/2001 @ 9:30 hrs Rig Released: 1/15/2001 @ 16:30 hrs Conductor 20" K-55 133 ppf Top Bottom MD 0' 93' TVD 0' 93' Surface Casing 13-3/8" Top Bottom K-55 61 ppf MD 0' 1,211' TVD 0' 1,201' L-80 68 ppf MD 1,211' 1,508' TVD 1,201' 1,483' 17-1/2" hole Cmt w/ 515 sks (229 bbl) of 12.0 ppg, Type 1 cmt, 43 sks (19 bbls) Production Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,690' TVD 0' 4,679' 12-1/4" hole cmt w/ 1,150 sks (230 bbls) of 15.8 ppg, Class G cmt. Lost returns, 150 sks (30bbls) during cementing. C1 C1 C2 C2 Date (9/15/04) (9/15/04) (8/24/04) (9/9/04) Gun Type 3-3/8", 60º, 6 SPF 3-3/8", 60º, 6 SPF 4-1/2", 60º, 6 SPF 3-3/8", 60º, 6 SPF TVD 4,433'-4,460' 4,433'-4,460' 4,597'-4,637' 4,597'-4,637' Ft 40' 40' 58' 58' MD 5,330'-5,370' 5,330'-5,370' 5,572'-5,630' 5,572'-5,630' Sterling Pool-6 Perfs: Liner (2004 RWO) 7" L-80 26 ppf Mod BTC Top Bottom MD 5,150' 5,680' TVD 4,313' 4,672' 9-5/8" casing Cmt w/ 18.8 bbls 15.8 ppg CMT 9-5/8" TOC @ 3640' (1/14/2001 CBL) Tie-Back Tubing7" L-80 26 ppf Mod BTC Top BottomMD 21' 5,150' TVD 21' 4,313' Tag sand with 3.5" DD Bailer 11/9/2021 @ 5,560' SCHEMATIC CIBP set at 5,525' on 11/17/21 7" Liner Hanger & ZXP Packer @ 5,150' MD (6.00" ID) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Unit 31-7x Kenai Peninsula Borough 5,330' - 5,370' ~ 1.4º / 100 ft @ 450' 7/14/2009 Juanita Lovett Lease: State: Perf (TVD): A - 028142 Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,433' - 4,637' 47º RKB:66' (AMSL)21' (AGL) 11/23/2021 TD 5,790' MD 4,749' TVD PBTD 5,663' MD 4,660' TVD KU 31-7x Pad 14-6 320' FSL, 1,325' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 200-148 API #: 50-133-20495-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) Spud: 12/26/2000 @ 16:45 hrs TD: 1/9/2001 @ 9:30 hrs Rig Released: 1/15/2001 @ 16:30 hrs Conductor 20" K-55 133 ppf Top Bottom MD 0' 93' TVD 0' 93' Surface Casing 13-3/8" Top Bottom K-55 61 ppf MD 0' 1,211' TVD 0' 1,201' L-80 68 ppf MD 1,211' 1,508' TVD 1,201' 1,483' 17-1/2" hole Cmt w/ 515 sks (229 bbl) of 12.0 ppg, Type 1 cmt, 43 sks (19 bbls) Production Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,690' TVD 0' 4,679' 12-1/4" hole cmt w/ 1,150 sks (230 bbls) of 15.8 ppg, Class G cmt. Lost returns, 150 sks (30bbls) during cementing. C1 C1 C2 C2 Date Re-perf (9/15/04) (8/24/04) (9/9/04) Gun Type 3-3/8", 60º, 6 SPF 3-3/8", 60º, 6 SPF 4-1/2", 60º, 6 SPF 3-3/8", 60º, 6 SPF TVD ±4,433'-±4,460' 4,433'-4,460' 4,597'-4,637' 4,597'-4,637' Ft ±40' 40' 58' 58' MD ±5,330'-±5,370' 5,330'-5,370' 5,572'-5,630' 5,572'-5,630' Sterling Pool-6 Perfs: Liner (2004 RWO) 7" L-80 26 ppf Mod BTC Top Bottom MD 5,150' 5,680' TVD 4,313' 4,672' 9-5/8" casing Cmt w/ 18.8 bbls 15.8 ppg CMT 9-5/8" TOC @ 3640' (1/14/2001 CBL) Tie-Back Tubing7" L-80 26 ppf Mod BTC Top BottomMD 21' 5,150' TVD 21' 4,313' Tag sand with 3.5" DD Bailer 11/9/2021 @ 5,560' PROPOSED CIBP set at 5,525' on 11/17/21 From:McLellan, Bryan J (CED) To:Chad Helgeson Subject:RE: KGF Well KU 31-07X (PTD# 200-148) Sundry # 321-390 Date:Friday, November 19, 2021 4:01:00 PM Chad, That’s a good question and I have reached out to some of the others here to make sure I’m being consistent with my answer. A lot of people are out today and I don’t think I’ll have an answer before Monday. If you want to do it more urgently, you have approval to proceed as described below, but should follow up with a Sundry within 3 days. You can tick the “Change Approved Program” box on the sundry when you submit it. Feel free to call again if needed. Regards Bryan Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, November 19, 2021 3:40 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: KGF Well KU 31-07X (PTD# 200-148) Sundry # 321-390 Bryan, I left you a message in regards to KGF Well KU 31-07X. We currently have an open approved sundry to plug back this pool 6 storage well and move uphole. We have isolated the C-2 sand with our 1st CIBP and dumped some cement. But before we walked away from this zone after slickline work to get it bailed, we wanted to see if the well would behave any better. I would like to pump 10 bbls of Methanol to fill up the sump from setting the CIBP above the C-2 sand and then pump 10 bbls of Xylene to treat the near wellbore from compressor oils that I think might be impacting the wells permeability, and then pushing that into the formation with another 20 bbls of Methanol to dryout any water that may have cross flowed from the C-2 sand below. I know this is a grey area and have heard int eh past that Guy would allow these treatments if they aren’t stimulating the rock without a sundry. How would like me to handle this situation, I can amend our current sundry, write a new sundry, etc? Thanks and sorry to hit you with this on Friday evening. Chad Helgeson ASC Operations Engineer Hilcorp Alaska LLC chelgeson@hilcorp.com 907-777-8405 (O) 907-229-4824 (C) The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2, Cement IA 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 5,790'N/A Casing Collapse Structural Conductor Surface 1,540psi Intermediate Production 3,090psi Liner 5,410psi Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15.Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval: Date: GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: October 1, 2021 5,680'530' 7" 4,672' 5,690' Perforation Depth MD (ft): See Attached Schematic 5,669' 7" 4,679'9-5/8" 20" 13-3/8" 72' 1,487'3,090psi 93' 1,483' 93' 1,508' 26# TVD Burst 5151' 5,750psi MDLength Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 028142 200-148 50-133-20495-00-00 Kenai Unit (KU) 31-07X Kenai Gas Filed / Sterling 6 Gas, Sterling 6 Gas Storage COMMISSION USE ONLY Authorized Name: 7,240psi Tubing Grade: Tubing MD (ft): See Attached Schematic jake.flora@hilcorp.com 4,749'5,665'4,662'985 N/A ZXP Packer; N/A 5,150' MD/4,313' TVD; N/A; N/A Perforation Depth TVD (ft): Tubing Size: Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 11:30 am, Aug 09, 2021 321-390 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.08.09 10:16:36 -08'00' Taylor Wellman (2143) Isolation plugs between pools must be tagged and pressure tested per 20 AAC 25.112(g)(2). MITIA to 2000 psi post-perforation. Provide 24 hrs notification for AOGCC witness. SFD 8/19/2021 CO 510B 10-404 X SFD 8/19/2021 Perforate New Pool Sterling 3, Sterling 4, Sterling 5.1, Sterling 5.2, X DSR-8/9/21 SFD 8/19/2021 CT Contingency X DLB 08/09/2021 CT BOP test to 3000 psi. 1213 bjm Review CBL log results with AOGCC before perforating BJM 8/27/21 JLC 8/27/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.30 15:37:13 -08'00' RBDMS HEW 9/1/2021 Well Prognosis Well: KU 31-07X Date: 08-03-2021 Well Name: KU 31-07X API Number: 50-133-20495-00 Current Status: Shut-in Gas Storage Well Leg: N/A Estimated Start Date: 10/01/21 Rig: N/A Reg. Approval Req’d? 403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 200-148 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Current Surface Pressure: 170 psi (Pool 6) Maximum Expected BHP: ~ 1400 psi @ 4,148’ TVD Max. Potential Surface Pressure: ~ 985 psi (Based on current offset well conditions minus a gas gradient to surface (0.10 psi/ft)) Well Status KU 31-07X is a Pool 6 gas storage producer/injector that has been offline since January 2021 due to sand production. Brief Well Summary KU 31-07X was originally drilled and completed in 2001 targeting the Sterling Pool 6 formations. A workover in 2004 recompleted the well from having 3-1/2” tbg to having a cemented 7” liner / tieback completion. In April of 2006, the well was converted to a gas storage injector/withdrawal well. Most recently the well is having issues with mud production and will not sustain desired production rates. As a solution the nearby SI producer KDU-01 will be converted to a gas storage injector/ producer in order to meet deliverability rate targets and replace KU 31-07X. Geologically the KU 31-07X wellbore sits at the top of structure in the Sterling and is the highest offtake point for many of the Sterling sands. The purpose of this Sundry is to plug back KU 31-07X over the Pool 6 sands, cement the 7” x 9 5/8” annulus, and test up-hole Sterling pay zones. Notes Regarding Wellbore Condition x 10/26/20 Tag fill at 5596’ w 3.5” Bailer x 04/15/19 MITIA PASSED x 9 5/8” TOC = 3640’ (1/14/2001 CBL) Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 3,000 psi High. 2. Set CIBP at 5525’ and dump bail 25’ cement top. 3. Set CIBP at 5280’ and dump bail 25’ cement top. 4. Load well with water, MIT 7” tubing to 3000 psi. 5. Tubing punch squeeze holes above the 7” LTP at ~5145’. 6. Confirm circulation rate from tubing to IA is sufficient to cement squeeze through (Need at least 3 bpm). 7. RU cement truck, PT lines. 8. Mix and pump ~ 60 bbls 15.3# cement down tubing, with returns from IA. Planned TOC in IA is 3000 ft. DLB 08/09/2021 MIT 7” tubing to 3000 psi. 1213 psi pump ~ 60 bbls 15.3# cement d 1600 psi @ 3947' TVD (P5.1_B4) to 1775 psi. bjm annulus, and test up-hole Sterling pay zones. The purpose of this Sundry is to plug back KU 31-07X over the Pool 6 sands, cement the 7” x 9 5/8” -00 DLB Tag and Pressure test per 20 AAC 25.112(g)(2) Verified cement volume - bjm Well Prognosis Well: KU 31-07X Date: 08-03-2021 9. Drop wiper ball and displace 7” tubing to the tubing punch depth (~196 bbls). 10. SI master valve, hold pressure. Discuss freeze protecting with Operator. WOC 3 days. 11. MIRU E-line. PT Lubricator. Log CBL from TD to surface. Send log to AOGCC. Coil Tubing Milling Contingency (if cement is left too high in 7” tubing) I. MIRU CTU, 24hr notice for BOP test. II. Conduct BOP test 250psi low, 3000psi high. III. RIH w milling BHA, mill out cement to ~10’ above jet cut depth. IV. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU. 12. MIRU Dyna Coil Unit with ½” capillary string. 13. Remove tree cap and install wellhead pack-off assembly. 14. Stab 1/2” capillary line into wellhead pack-off assembly. Make up BHA components. Install pack-off and pressure test against swab valve 250 psi low/3,000 psi high. 15. RIH with 1/2” capillary string to TD at ~5100’ MD. 16. Install slips, stand back injector and remove spool. 17. Install double block and bleed to cap string and route to a gas diffuser return tank. 18. RD Dyna Coil Unit. 19. Turn well over to production. 20. Pressure up the 7” x capillary string annulus with field gas (max available field gas pressure ~ 750 psi). 21. Open the capillary string to the diffuser tank, taking water returns up the ½” capillary string. 750 psi will void the 7” tubing down to ~1700’ and create a larger void to apply nitrogen pressure. a) Operator must be on location actively monitoring returns during this operation. b) This operation may continue for a number of days depending on unloading rate. 22. RU Nitrogen, pressure up the 7” x capillary string annulus to maximum 3000 psi, unload the remaining water from the 7” tubing. 23. Trap sufficient WHP to perforate. 24. MIRU Dyna Coil Unit. 25. Pull slips and POH with 1/2” capillary string. 26. Remove wellhead pack-off assembly and install tree cap. 27. RD Dyna Coil Unit. 28. RU E-Line, PT Lubricator to 3000 psi High. Perforate below zones from the bottom up: Sand MD Top MD Bottom Total Gross Footage (MD) TVD Top TVD Bottom Plan to shoot Estimated Reservoir Pressure P3_A8 ±3,396' ±3,963' 27' ±3,159' ±3,550' A few lobes (9-5/8” cement remediation?) 600 PSI P3_A10 ±4,052' ±4,057' 5' ±3,607' ±3,610' All of it 200 PSI P3_A10 ±4,092' ±4,136' 44' ±3,632' ±3,661' Top 5' 200 PSI P3_A11 ±4,181' ±4,208' 27' ±3,689' ±3,706' Top 10' 200 PSI P4_B1 ±4,280' ±4,343' 63’ ±3,751' ±3,791' Top 10' 200 PSI P5.1_B3 ±4,475' ±4,508' 33' ±3,875' ±3,897' Top 10' 1600 PSI P5.1_B4 ±4,586' ±4,631' 45' ±3,947' ±3,976' A few lobes 1600 PSI P5.2_B5A ±4,898’ ±4,906’ 8' ±4,148' ±4,153' All of it 1400 PSI Sterling 4 Gas Pool Sterling 5.2 Sterling Undef SFD 8/19/2021 Tubing punch Sterling 3 ±3,947' Sterling 5.1 Log CBL from TD to surface. Send log to AOGCC. Pressure test tubing to 2000 psi. bjm 1600 Remedial cement required before perforating P3_A8 or shallower. Separate Sundry Required. bjm Well is plugged at this point - no open perfs. Cap string operation is only permitted so long as well is plugged and pressure-tested. - bjm Well Prognosis Well: KU 31-07X Date: 08-03-2021 P5.2_B5B ±4,958' ±5,108' 150' ±4,187' ±4,285' A few lobes 1250 PSI a. Discuss wellhead pressure with OE. If necessary RU Nitrogen to pressure well prior to perforating. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Trudi Hallett 907.301.6657 Geologist Ben Siks 907.229.0865 d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. e. A CIBP with 25’ cement top is required to isolate each pool before perforating a new pool 29. POOH. 30. RD E-Line. 31. Turn well over to production. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Nitrogen (Contingency) 1. If Nitrogen is required during Dyna Coil operation to unload water from the 7” tubing OR to pressure up on the tubing prior to perforating: 2. MIRU Nitrogen Unit, review Nitrogen SOP, pressure well to desired perforating or unloading pressure. E-line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 3. RIH and set CIBP above the zone and dump 25’ of cement on top of the plug. Attachments: Current Well Schematic Proposed Well Schematic Capillary String Flow Diagram Standard Well Procedure – N2 Operations CTU BOP Schematic Sterling 5.2 Plugs must be tagged and pressure tested per 20 AAC 25.112(g)(2). - bjm MITIA to 2000 psi after perforating and within 10 days of returning well to production. (CO 510A Rule 3) - bjm A CIBP with 25’ cement top is required to isolate each pool before perforating a new pool SFD 8/19/2021 7" Liner Hanger & ZXP Packer @ 5,150' MD (6.00" ID) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Unit 31-7x Kenai Peninsula Borough 5,330' - 5,630' ~ 1.4º / 100 ft @ 450' 7/14/2009 Jake Flora Lease: State: Perf (TVD): A -028142 Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,433' - 4,637' 47º RKB:66' (AMSL)21' (AGL) 5/13/2021 TD 5,790' MD 4,749' TVD PBTD 5,663' MD 4,660' TVD KU 31-7x Pad 14-6 320' FSL, 1,325' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 200-148 API #: 50-133-20495-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) Latitude: Longitude: Spud: 12/26/2000 @ 16:45 hrs TD: 1/9/2001 @ 9:30 hrs Rig Released: 1/15/2001 @ 16:30 hrs PA #: Conductor 20" K-55 133 ppf Top Bottom MD 0' 93' TVD 0' 93' Surface Casing 13-3/8" Top Bottom K-55 61 ppf MD 0' 1,211' TVD 0' 1,201' L-80 68 ppf MD 1,211' 1,508' TVD 1,201' 1,483' 17-1/2" hole Cmt w/ 515 sks (229 bbl) of 12.0 ppg, Type 1 cmt, 43 sks (19 bbls) Production Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,690' TVD 0' 4,679' 12-1/4" hole cmt w/ 1,150 sks (230 bbls) of 15.8 ppg, Class G cmt. Lost returns, 150 sks (30bbls) during cementing. C1 C1 C2 C2 Gun Type 3-3/8", 60º, 6 SPF 3-3/8", 60º, 6 SPF 4-1/2", 60º, 6 SPF 3-3/8", 60º, 6 SPF TVD 4,433'-4,460' 4,433'-4,460' 4,597'-4,637' 4,597'-4,637' Ft 40' 40' 58' 58' MD 5,330'-5,370' 5,330'-5,370' 5,572'-5,630' 5,572'-5,630' Sterling Pool-6 Perfs: Liner (2004 RWO) 7" L-80 26 ppf Mod BTC Top Bottom MD 5,150' 5,680' TVD 4,313' 4,672' 9-5/8" casing Cmt w/ 18.8 bbls 15.8 ppg C 9-5/8" TOC @ 3640' (1/14/2001 CBL) Tie-Back Tubing7" L-80 26 ppf Mod BTC Top BottomMD 21' 5,150' TVD 21' 4,313' Tag sand with 2.5" DD Bailer 1/25/2020 @ 5596' Schematic MD Deviation 1000' 12 deg 2000' 24 deg 3000' 30 deg 4000' 49 deg 5000' 49 deg 7" Liner Hanger & ZXP Packer @ 5,150' MD (6.00" ID) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Unit 31-7x Kenai Peninsula Borough 5,330' - 5,630' ~ 1.4º / 100 ft @ 450' 7/14/2009 Jake Flora Lease: State: Perf (TVD): A -028142 Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,433' - 4,637' 47º RKB:66' (AMSL)21' (AGL) 8/03/2021 TD 5,790' MD 4,749' TVD PBTD 5,663' MD 4,660' TVD KU 31-7x Pad 14-6 320' FSL, 1,325' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 200-148 API #: 50-133-20495-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) Latitude: Longitude: Spud: 12/26/2000 @ 16:45 hrs TD: 1/9/2001 @ 9:30 hrs Rig Released: 1/15/2001 @ 16:30 hrs PA #: Conductor 20" K-55 133 ppf Top Bottom MD 0' 93' TVD 0' 93' Surface Casing 13-3/8" Top Bottom K-55 61 ppf MD 0' 1,211' TVD 0' 1,201' L-80 68 ppf MD 1,211' 1,508' TVD 1,201' 1,483' *cmt to surface Production Casing (8.835" ID) 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,690' TVD 0' 4,679' C1 C1 C2 C2 Gun Type 3-3/8", 60º, 6 SPF 3-3/8", 60º, 6 SPF 4-1/2", 60º, 6 SPF 3-3/8", 60º, 6 SPF TVD 4,433'-4,460' 4,433'-4,460' 4,597'-4,637' 4,597'-4,637' Ft 40' 40' 58' 58' MD 5,330'-5,370' 5,330'-5,370' 5,572'-5,630' 5,572'-5,630' Sterling Pool-6 Perfs: Liner (2004 RWO) 7" L-80 26 ppf Mod BTC Top Bottom MD 5,150' 5,680' TVD 4,313' 4,672' 9-5/8" casing Cmt w/ 18.8 bbls 15.8 ppg CMT 9-5/8" TOC @ 3640' (1/14/2001 CBL) Tie-Back Tubing7" L-80 26 ppf Mod BTCTop BottomMD 21' 5,150'TVD 21' 4,313' Tag sand with 2.5" DD Bailer 1/25/2020 @ 5596' Proposed Proposed Sterling Perfs ±4,052' - ±5,108' MD * 5100' MD = 4250' TVD 1. Set CIBP @ 5525' & 5280' w 35' cement top 2. Tubing punch above LTP at 5145' 3. Cement IA 4. CBL 5. Perforate and test up-hole Sterling Planned TOC @ 3000' (60 bbls slurry) * 7" x 9 5/8" annulus = 0.0282 bpf STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Open Top Diffuser TankLayout of Monitoring Tank and Capillary StringWellhead GasOR NitrogenFlow of Well Fluids through 1/2” Capillary String Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Coil Tubing BOP Data Collection Report Chassis Left Scale Right Scale Serial Number 823373 822132 567620 Datatype Lower Upper Units PSI G PSI G Lower Upper 0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1760 1762 1764 1766 1768 1770 1772 1774 1776 1778 1780 PSI GPSI G Elapsed Time hh:mm:ss Tag 1 - 15-Apr-19, 01:42:40, 20393 PSI G PSI G 1 Carlisle, Samantha J (CED) From:Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent:Tuesday, August 17, 2021 4:17 PM To:McLellan, Bryan J (CED) Subject:RE: [EXTERNAL] KU 31-07X (PTD 200-148) IA squeeze Sundry Attachments:KU 31-07x well history_cbl mention.pdf; MIT 31-7X 4-15-2019.xls Bryan, IwentthroughourpaperfilesandcannotlocatetheCBL.WouldthestatekeepacopyfromthePool6injection application?I’veattachedthepageinthewellhistorythatmentionsitinthemiddleoftheparagraph. TheMITIAisattached,looksliketheywentto1775psiover36minutes. Thanks, Jake From:McLellan,BryanJ(CED)<bryan.mclellan@alaska.gov> Sent:Tuesday,August17,20212:49PM To:JakeFloraͲ(C)<Jake.Flora@hilcorp.com> Subject:[EXTERNAL]KU31Ͳ07X(PTD200Ͳ148)IAsqueezeSundry Jake, Acouplerequestsregardingyoursundryapplicationonthiswell. x Couldyousendthe9Ͳ5/8”CBLfrom1/14/2001forthiswell? x WhatwasMITIAtestpressurein2019? Thanks BryanMcLellan SeniorPetroleumEngineer AlaskaOil&GasConservationCommission 333W7thAve Anchorage,AK99501 Bryan.mclellan@alaska.gov +1(907)250Ͳ9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: JimRegg o� DATE: Monday, April 29, 2019 P.I. Supervisor Ci 41N(t Iq SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 31-07X FROM: Guy Cook KENAI UNIT 31.07X Petroleum Inspector Sre: Inspector Reviewed By: P.I. Supry Jw— NON-CONFIDENTIAL Comm Well Name KENAI UNIT 31-07X Insp Num: mitGDC190423172025 Rel Insp Num: API Well Number 50-133-20495-00-00 Inspector Name: Guy Cook Permit Number: 200-148-0 Inspection Date: 4/15/2019 Pretest Initial Ii Min 30 Min 45 Min 60 Min 195 - 195- 99 1780 1--U Monday, April 29, 2019 Page I of I Packer Depth Well 31-07X Inj N- TVD 43)3 Tubing PTD 2001480 iType Test SPT 'Test psi 1-- lsoo IA BBL Pumped: _Type 1.5 . BBL Returned: 1.5 OA Interval 4vRTSTT - --- ' P/F P ✓ Notes: Testing performed with a triplex pump and calibrated gauges. - Pretest Initial Ii Min 30 Min 45 Min 60 Min 195 - 195- 99 1780 1--U Monday, April 29, 2019 Page I of I Kik -3 -0x P7) WO 1 460 Regg, James B (DOA) From: Larry Greenstein <Igreenstein@hilcorp.com> Sent: Tuesday,June 02, 2015 4:21 PM 6IS To: Regg, James B (DOA) I Cc: Wallace, Chris D (DOA); Roby, David S (DOA) Subject: RE: MIT Kenai Gas Field 04-21-15 - Questions on KU 12-17 & KU 31-07X Attachments: UL Test Equipment Calibration Intervals (Document 00-OP-C0045).pdf; KU 31-07X.xlsx; KU 12-17.xlsx I fully understand,Jim. Thank you for looking these over and letting me know your thoughts and suggestions. —) The TIO plots leading up to the April MITs are attached. Both plots show stable IA and OA pressures leading up to the MIT with good indications of mechanical integrity. I was putting myself in your shoes as I was looking at those MIT results. Five were no-brainers, but those other two...l could almost hear you saying 'let them run longer or start them over as inconclusive'when I first saw the pressures on the test even though the inspector called both of them a passing test. Believe I'll settle in on annually for our MIT/No-flow test equipment calibrations(ie. 1C on your UL attachment,thank you for that) Appreciate the candor and open discussion on this and many other topics. Sure there'll be more to come in the future. Larry Original Message SCANNED JUL 0 2 2015 From: Regg,James B (DOA) [mailto:jim.regg@alaska.gov] Sent: Tuesday,June 02, 2015 1:37 PM To: Larry Greenstein Cc: Wallace, Chris D (DOA); Roby, David S (DOA) Subject: RE: MIT Kenai Gas Field 04-21-15-Questions on KU 12-17 & KU 31-07X KU 12-17 (PTD 2080890) KU 31-07X (PTD 2001480) My opinion is the MIT results for these 2 wells (tested 4/21/15) are the r-suit of sloppy work, and based on what I heard yesterday during our meeting one contributing factor could be the ruto get 7 MITs done in one day. I am not suggesting there is a problem with bundling wells to maximize the .pportunity to witness as many wells as possible during a single visit and appreciate Hilcorp's willingness to do t :t with some of its MITs and SVS testing (our Inspectors are few in number with a huge workload). These regulation- equired tests(every 2-4 years), however, cannot be done in a manner that ends up with questionable results-qual' of test must supersede the quantity of tests completed. It was a mistake on my part not deeming these test,snconclusive" and requiring them to be scheduled for retests- neither well demonstrated a stabilizing pressure kiss during the test period. Both should have been monitored for additional 15-30 minute increments or tests r,gstarted. Please send TIO plots for these 2 wells to help substantiate the passing MIT results. In the future I will beJooking for more definitive results before making a pass-inconclusive-fail determination. You raised concerns about the "excessive and potentially damaging" test pressure imposed for the KU 12-17 MIT and specifically the need to avoid p-ressuring up the annulus 1000psi over the required test pressure (higher test pressure 1 O O O O O O O O O - 0 O vn o O N .-+ .-0 V1 O NY .- .. ,a r � -tom 0...~..'.."..."."" ....- f_. l 4 WI C 0 O M N O V In r� ea 104 I 3 . N O 40 ZO 0 Q )I N -- I O O 6 a_ "' c 1 N C N ti O - N .-y O O O O O O O O O O CO ^ VD In d CO N O.•-• KL( 31 -0-7 k PT Zoo a4 o Regg, James B (DOA) From: Regg, James B (DOA) Sent: Tuesday, June 02, 2015 1:37 PM 1 (4115 To: 'Larry Greenstein' Cc: Wallace, Chris D (DOA); Roby, David S (DOA) Subject: RE: MIT Kenai Gas Field 04-21-15 - Questions on KU 12-17 & KU 31-07X Attachments: UL Test Equipment Calibration Intervals (Document 00-OP-C0045).pdf KU 12-17 (PTD 2080890) KU 31-07X(PTD 2001480) My opinion is the MIT results for these 2 wells(tested 4/21/15) are the result of sloppy work, and based on what I heard yesterday during our meeting one contributing factor could be the rush to get 7 MITs done in one day. I am not suggesting there is a problem with bundling wells to maximize the opportunity to witness as many wells as possible during a single visit and appreciate Hilcorp's willingness to do that with some of its MITs and SVS testing (our Inspectors are few in number with a huge workload). These regulation-required tests (every 2-4 years), however, cannot be done in a manner that ends up with questionable results- quality of test must supersede the quantity of tests completed. It was a mistake on my part not deeming these tests "Inconclusive" and requiring them to be scheduled for retests- neither well demonstrated a stabilizing pressure loss during the test period. Both should have been monitored for additional 15-30 minute increments or tests restarted. Please send TIO plots for these 2 wells to help substantiate the passing MIT results. In the future I will be looking for more definitive results before making a pass-inconclusive-fail determination. You raised concerns about the "excessive and potentially damaging" test pressure imposed for the KU 12-17 MIT and specifically the need to avoid pressuring up the annulus 1000psi over the required test pressure (higher test pressure was imposed to assure there was sufficient pressure differential to monitor for any pressure communication or leakage). To avoid this, several things need to happen: 1)TIO plot (90days leading up to MIT)should be available at the location for the Inspector's review(refer to information requested at location per AOGCC Industry Guidance Bulletin 10-02A); 2) Monitor TIO pressures 30 minutes before pressuring up the annulus for MIT to confirm there is no pressure buildup in annulus (adjust as necessary to ensure 500psi pressure differential between tubing and annular spaces); 3) Isolate the well from batch injection while the well is being pressure tested. You also raised questions about what constitutes a "current calibration" for a test gauge (phrase used in AOGCC Industry Guidance 10-02A). A time frame was not appended to the term "current" since others are more qualified to establish the recommended gauge calibration interval than AOGCC. According to UL for example, calibrating test equipment should occur at intervals specified by the manufacturer or annually with some time interval extension possible (see attached). Did not check NIST website or any others but I'd be surprised if there was any controversy among the various national labs. AOGCC will need to discuss if additional prescription is necessary to clarify what is meant by "current calibration" (e.g., calibrated within the past 12 months) and if so how it should be addressed. Notice that UL also recommends more frequent calibration for test equipment that is subjected to severe conditions and frequent use. If these are not sufficient guidance, AOGCC is open to an operating company's recommendation for test gauge calibration frequency if it comes with justification. Jim Regg Supervisor, Inspections AOGCC 1 333 W. 7th 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 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 Jim Regg at 907-793-1236 or jim.regg@alaska.gov. Original Message From: Larry Greenstein [mailto:Igreenstein@hilcorp.com] Sent: Monday,June 01, 2015 4:57 PM To: Regg,James B (DOA) Cc: Wallace, Chris D (DOA); Roby, David S(DOA) Subject: FW: MIT Kenai Gas Field 04-21-15 -Questions on KU 12-17 & KU 31-07X Thank you all for your time today to discuss a number of different topics. It's always a pleasure to brainstorm ideas and understand all aspects of our different working worlds. This is the original e-mail that asked the questions about the MITs on KU 12-17 and KU 31-07X and offered up to meet and discuss alternative to the 1000 psi above minimum test pressure on the KU 12-17 MIT. Please review the MIT forms and let me know what your thoughts are. Larry Original Message From: Larry Greenstein Sent:Thursday, April 23, 2015 7:17 AM To:Jim Regg @ AOGCC;AOGCC Inspectors; Phoebe Brooks @ AOGCC; Chris Wallace @ AOGCC Cc: Christopher Walgenbach; Pete Iverson Subject: MIT Kenai Gas Field 04-21-15 Gentlepeople, Here are the official reports of the MITs performed and witnessed on the gas storage injectors and water disposal wells at KGF on 4-21-15. Of the seven wells tested a couple appear marginal although the inspector did label them a passing test. The KU 12-17 water disposal well on pad 41-18 showed 20 psi drops in the last two 15 minute readings which appear to indicate a lack of a 'stabilizing trend' for a successful MIT. The recorded tubing pressures show that this batch disposal well started injecting part way into the MIT and an extra 15 minute reading was added to attempt to achieve annulus pressure stabilization. As the initial flush fluids pumped upon start-up of the G&I wells are relatively cold, we expect to see the pressure drop off in the annulus, due to cooling, as a normal reaction. Therefore, it appears this well would have stabilized nicely had injection not began during the test. 2 The testing performed on this well concerns me as the annulus pressure was taken to over 1000 psi above the minimum required test pressure. This seems excessive and potentially damaging to the casing and/or packer for no particular • benefit. The integrity of the casing can be verified in a much gentler manner than this. The injection pressure on the tubing would require some adjustment to the testing pressure of the annulus, but nothing that extreme would be necessary to prove integrity of the casing (the integrity of the tubing had already been proven by the pretest wellhead pressures). As shown in the monthly KGF disposal well monitoring reports sent to AOGCC, the G&I wells don't inject anywhere near that high of an injection pressure (routinely<2000 psi vs> 2500 psi on the MIT), so there is an increased risk of breaking something to pressure test the annulus that high. Be glad to discuss alternatives with AOGCC that would satisfy integrity requirements and avoid self-inflicted pressure caused potential wellbore damage. The KU 31-07X gas storage injection well on pad 14-06 showed 10 psi drops in both 15 minute readings and as such doesn't seem to indicate a 'stabilizing trend' for the pressure readings. This well could be retested, as a longer MIT or a re-started MIT would probably have shown full mechanical integrity. There has been no indication of an integrity issue with this well in routine low pressure storage operation as confirmed by the monthly KGF gas storage monitoring reports sent to AOGCC. The MITs on the other five wells look pretty standard for approvals. Larry 3 DATA ACCEPTANCE PROGRAM1111) Equipment Calibration Intervals What information you are looking for (minimum requirements): • Equipment calibration intervals. Guidance on setting these intervals are provided in Appendix A When should you provide this information? • Before the visit -Test instruments are to be calibrated at intervals which maintain required tolerances specified in the test standard, manufacturer's stated tolerances or tolerances defined by the equipment owner. • During the visit—A review of historical calibration records will provide details to confirm whether the calibration interval is appropriate. See Appendix A for details. Why this requirement is • Equipment accuracy has a direct impact on important? test data. Reliance on stated instrument tolerances is based on stability of the instrument during the defined calibration interval. UL does not endorse any vendors or products referenced herein. UL ASSUMES NO RESPONSIBILITY FOR ANY OMISSIONS OR ERRORS OR INACCURACIES WITH RESPECT TO THIS INFORMATION. UL MAKES NO REPRESENTATION OR WARRANTY OF ANY KIND WHATSOEVER,WHETHER EXPRESS OR IMPLIED,WITH RESPECT TO THE ACCURACY,CONDITION,QUALITY,DESCRIPTION,OR SUITABILITY OF THIS INFORMATION,INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE AND EXPRESSLY DISCLAIMS THE SAME. Copyright@ 2012 UL LLC.All rights reserved.May not be reproduced without permission. This document is controlled and has been released electronically.The version on the UL intranet is the up-to-date document.Hard copies are uncontrolled and may not be up-to-date. Users of hard copies should confirm the revision by comparing it with the electronically controlled version. 00-OP-00045—Issue 2.0 Page 1 of 4 DATA ACCEPTANCE PROGRAM Equipment Calibration Intervals Certificates, Approval Forms, • Certificates and other related documentation and Other Documentation associated with testing are to be processed in the following manner: For WTDP - o Historical records for calibration intervals are to be retained by the client for proof of appropriate calibration cycles. UL staff is to request copies of calibration certificates and related documentation for the equipment used in testing under the present project. For other DAP programs (CTDP, TCP, TPTDP, etc)— o Clients are to index and retain copies of certificates and related documentation for the equipment used in testing. o In lieu of storage of paper copies of the documentation, these may be stored electronically. o Retention time for the records is in accordance with Client Test Data and TCP Laboratory agreement (L-56). UL does not endorse any vendors or products referenced herein. UL ASSUMES NO RESPONSIBILITY FOR ANY OMISSIONS OR ERRORS OR INACCURACIES WITH RESPECT TO THIS INFORMATION. UL MAKES NO REPRESENTATION OR WARRANTY OF ANY KIND WHATSOEVER,WHETHER EXPRESS OR IMPLIED,WITH RESPECT TO THE ACCURACY,CONDITION,QUALITY,DESCRIPTION,OR SUITABILITY OF THIS INFORMATION,INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE AND EXPRESSLY DISCLAIMS THE SAME. Copyright©2012 UL LLC.All rights reserved.May not be reproduced without permission. This document is controlled and has been released electronically.The version on the UL intranet is the up-to-date document.Hard copies are uncontrolled and may not be up-to-date. Users of hard copies should confirm the revision by comparing it with the electronically controlled version. 00-OP-00045—Issue 2.0 Page 2 of 4 DATA ACCEPTANCE PROGRAM Equipment Calibration Intervals APPENDIX A 1 All test equipment requiring calibration shall undergo an initial calibration before being put into service. Thereafter, the maximum nominal calibration interval shall be as indicated below. A calibration vendor that is accredited by a Signatory of APLAC, ILAC or EU must provide the calibration whenever possible. See 00-OP- J0026 for further guidance. 1A Calibration cycles shall be: 1B As recommended by the manufacturer of the instrument; 1C One year for electrical, electronic and mechanical test equipment; or 1D Three years for mechanical test equipment made of solid materials not subject to deterioration. 2 Calibration intervals may be extended based on the following conditions and the reasons must be documented: 2A Passive electrical test equipment, such as current shunts, current transformers, potential transformers, may be extended to 3 years with good results for the initial calibration period and if not subject to severe use conditions. 2B Weights may be extended to 5 years if there is a laboratory procedure that takes into account usage and has provisions for physical examination and / or intermediate checks of the weights. 2C Where there is sufficient calibration data to statistically establish a trend of the test equipment to assure good measurement results for a longer period. 3. Calibration of the following types of equipment can be put on an initial calibration only (ICO) calibration cycle : o steel rules, o tape measures, o weights 4.5 kg or greater calibrated to ± 1% tolerance, UL does not endorse any vendors or products referenced herein. UL ASSUMES NO RESPONSIBILITY FOR ANY OMISSIONS OR ERRORS OR INACCURACIES WITH RESPECT TO THIS INFORMATION. UL MAKES NO REPRESENTATION OR WARRANTY OF ANY KIND WHATSOEVER,WHETHER EXPRESS OR IMPLIED,WITH RESPECT TO THE ACCURACY,CONDITION,QUALITY,DESCRIPTION,OR SUITABILITY OF THIS INFORMATION,INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE AND EXPRESSLY DISCLAIMS THE SAME. Copyright©2012 UL LLC.All rights reserved.May not be reproduced without permission. This document is controlled and has been released electronically.The version on the UL intranet is the up-to-date document.Hard copies are uncontrolled and may not be up-to-date. Users of hard copies should confirm the revision by comparing it with the electronically controlled version. 00-OP-00045—Issue 2.0 Page 3 of 4 DATA ACCEPTANCE PROGRAM 110) Equipment Calibration Intervals o single piece steel probes greater than or equal to 3 mm diameter with blunt ends, o graduate cylinders, thermometers, o steel impact balls, o steel or plastic probes with no moving parts and sufficient structural integrity so as to not deform o electronic time pieces, regulated by a quartz crystal or similar stable frequency source (e.g., there are oscillator devices such as silicon-based and micro-electromechanical oscillators that can be applied in timing devices.). With ICO, the equipment undergoes calibration and is then subjected to intermediate checks to ensure that the equipment continues to meet calibration requirements. These checks shall be conducted per a defined procedure and interval. Equipment records shall include the details on the original calibration, including certificates and the like. The last and next inspection dates shall be indicated on the equipment and in equipment records. 4. Weights do not need to be calibrated if verified with a calibrated scale before each use. The verification must be documented in the datasheets with the weighing device included in the equipment list. 5. Test equipment that is delicate, subject to frequent usage or severe conditions (i.e., shock and vibration, excessive heat or humidity, or transported) shall be assigned shortened calibration intervals. 6. Infrequently used test equipment (e.g., once or twice between calibration cycles) may be assigned the status of"Calibrate Before Use" instead of a periodic calibration. UL does not endorse any vendors or products referenced herein. UL ASSUMES NO RESPONSIBILITY FOR ANY OMISSIONS OR ERRORS OR INACCURACIES WITH RESPECT TO THIS INFORMATION. UL MAKES NO REPRESENTATION OR WARRANTY OF ANY KIND WHATSOEVER,WHETHER EXPRESS OR IMPLIED,WITH RESPECT TO THE ACCURACY,CONDITION,QUALITY,DESCRIPTION,OR SUITABILITY OF THIS INFORMATION, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE AND EXPRESSLY DISCLAIMS THE SAME. Copyright©2012 UL LLC.All rights reserved.May not be reproduced without permission. This document is controlled and has been released electronically.The version on the UL intranet is the up-to-date document. Hard copies are uncontrolled and may not be up-to-date. Users of hard copies should confirm the revision by comparing it with the electronically controlled version. 00-OP-00045—Issue 2.0 Page 4 of 4 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE:Monday,May 04,2015 r �1 P.I.Supervisor r' �lu i SUBJECT: Mechanical Integrity Tests HILCORP ALASKA LLC 31-07X FROM: Jeff Jones KENAI UNIT 31-07X Petroleum Inspector Src: Inspector Reviewed By: P.I.SupraB- NON-CONFIDENTIAL Comm Well Name KENAI UNIT 31-07XAPI Well Number 50-133-20495-00-00 Inspector Name: Jeff Jones Permit Number: 200-148-0 Inspection Date: 4/21/2015 Insp Num: mitJJ 1 50501 08 1 1 1 5 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 31-07X Type Inj N TVD 4313 - Tubing 170 170 - -1 170 - 170 - PTD 2001480 - Type Test SPT Test psi 1500 - IA 0 1740 1730 1720 • Interval 14YRTST P/F P / OA o o o - o - Notes: <1 BBL methanol pumped 1 well)inspected,no exceptions noted SatNEV UPI 2 27M Monday,May 04,2015 Page 1 of I • • AOGCC Docket 10 -12 MIT Test Anniversary Dates Marathon Oil Company Request Dated May 26, 2010 : ,r ;* t:,) 1 F ; 0 h Z D I1 Background Marathon requested changing the anniversary dates of eight Kenai Peninsula injection wells to allow the mechanical integrity test (MIT) required by regulation/order to be performed during summer months. Marathon proposed the wells be adjusted to show a September 1 anniversary 1 date. Action Marathon's email request dated May 26, 2010 followed several telephone discussions between Kevin Skiba (Marathon; 907 - 283 -1371) and Jim Regg (AOGCC; 907 - 793 - 1236). Subsequent to the email request, telephone discussions were held on June 1, 2010, February 7, 2011 and February 8, 2011. Mr. Skiba was told that the following during discussions: - MIT due date can be changed by simply scheduling the test during the summer months; - Tests must be completed in advance of the next due date; - Make sure to give AOGCC Inspectors the required advance notice to allow for opportunity to witness; AOGCC witness is required to adjust the anniversary date; - Industry Guidance Bulletin 10 -002 provides details about testing injectors for mechanical integrity. Marathon was told the proposed September 1 anniversary date would not work for all wells since some MITs would be performed later than the currently required anniversary date. Resulting from the guidance provided to Marathon, the anniversary date for each of the eight injection wells has been changed based on successful, witnessed MITs as shown below: Well PTD MIT Completed Next MIT Due Beaver Creek Unit 2 1670260 5/4/2011 5/4/2015 Kenai Beluga Unit 23x -6 1841090 5/25/2011 5/25/2015 Kenai Unit 11 -17 1811760 5/3/2011 5/3/2013 Kenai Unit 12 -17 2080890 5/3/2011 5/3/2013 Kenai Unit 24 -07RD 2050990 5/3/2011 5/3/2015 z,:) Kenai Unit 31 -7X 2001480 5/25/2011 5/25/2015 . Kenai Unit WD -1 1811070 5/3/2011 5/3/2015 Sterling Unit 43 -09 1630110 5/4/2011 5/4/2015 With MITs completed on these wells during May 2011, Docket 10 -12 can be closed. ,,i \g/C r- B ' James B. Regg l I - O ctober 6, 2011 • • Colombie, Jody J (DOA) From: Regg, James B (DOA) Sent: Wednesday, May 26, 2010 11:25 AM To: Colombie, Jody J (DOA) Subject: FW: MIT tests anniversary date setup Jim Regg AOGCC 333 W.7th Avenue, Suite 100 Anchorage, AK 99501 907 - 793 -1236 From: Skiba, Kevin J. [mailto:kskiba @marathonoil.com] Sent: Wednesday, May 26, 2010 11:10 AM To: Regg, James B (DOA) Subject: MIT tests anniversary date setup Jim, Below is a list of Marathon Alaska's injection well MIT dates. Well Last test Frequency Next test BC -2 1/15/08 4 -year 1/15/12 KBU 23x -6 6/4/07 4 -year 6/4/11 KU 11 -17 5/12/10 1 -year 5/12/11 KU12 -17 8/27/09 2 -year 8/27/11 KU 24 -7RD 2/12/10 2 -year 2/12/12 KU 31 -7x 8/8/07 4 -year 8/8/11 SU 43 -9 5/13/09 2 -year 5/13/11 WD -1 5/12/10 4 -years 5/12/14 As per our telephone conversation, we would like to set up an anniversary date for the MIT tests on these wells. As stated, the anniversary date would allow us to complete the MIT tests in the summer months without having the forward movement affect on the test dates. With that said, we are interested in a September 1 date as the anniversary date. Please let me know if you need any additional information concerning this request. Thanks again, Kevin Skiba • Regulatory Compliance Representative Marathon Alaska Production LLC 1 Office (907) 283 -1371 • • Cell (907) 394 -1880 Fax (907) 283 -1350 2 • 0 MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Thursday, June 09, 2011 TO: Jim Regg , ' P.I. Supervisor (, (71 /I SUBJECT: Mechanical Integrity Tests (I MARATHON OIL CO 31-07X FROM: Matt Herrera KENAI UNIT 31-07X Petroleum Inspector Src: Inspector Reviewed By: P.I. Supry --J3(2-- NON-CONFIDENTIAL Comm Well Name: KENAI UNIT 31-07X API Well Number: 50-133-20495-00-00 Inspector Name: Matt Herrera - Insp Num: mitMFH110608062612 Permit Number: 200-148-0 Inspection Date: 5/25/2011 Rel Insp Num: Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. , -, , I Well 31-07X •I i 1 G ' TVD 4313 " IA 10 1640 1 1630 1625 - ' ! p 2001480 ,, TypeTest SPT Test psi 1500 OA 0 0 0 0 1 Interval 4YRTST P/F P Tubing 260 260 260 260 _± ! Notes: ,"A„:8;.'taliE0 JUN 1 3 ZU11 Thursday, June 09, 2011 Page 1 of 1 • ~arathon Oil Company Alaska Asset Team Marathon ~, P.O, Box 1949 ~ ~ ~ ~a ;~~ ~;~,~ :~ ~~ Kenai, AK 99611 MARATHON Oil Company ~'u~• "~` ~~ ~ Telephone 907/283-1371 MAY ~ ~ 2008 Fax 907/283-1350 Oil $~ ~~ C~ns. Com~~~~~~ '~ t~ b~laSk~ ~~ ..- ~ May 15, 2008 ~chorag~ ~ Mr. Tom Maunder ~ ~ 5~~~ Alaska Oii & Gas Conservation Commission -~~~SE ~~`~~~~ 333 W 7th Ave ~ ~. ~c ~, ~ ~L~~ ~ ~ ~ Anchorage, Alaska 99501 ~ ~~t~~C ~ Reference: 10-404 Sundry Submittal List ~/~ ~~~~5~ ~.°~~ i~~~`~- `'~~a~lo''s~ ~~ ,~~- ~~s~~-~- ~.«o~, ~.~ ~e Dear Mr. Maunder: ~~~~~~~~~~~C1~\ ~ c~ "~- ~~~ Marathon and the AOGCC have had discussions on the follow-up reporting needed to close out 10-403 Sundry approved well work activities. Work has been ongoing to `~ /~c~ ~~ identify the suspect well activities and comp(ete the appropriate reporting. Submitted for your records is a list of the completed reports along with the indicated 10-404 Sundries. I am continuing to work on the remaining sundry reports and plan to submit them upon their completion. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, 'r t~ ~~/'~/'T/l~(,/ ~.~ Kevin J. Skiba Engineering Technician ~~~~; :,~~~~~~ ~~t~;. , ~ ~. } ;~~s~~s Enclosures: 10-404 Sundry Submittal List cc: Houston Well File Accompanying 10-404 Sundries Kenai Well File KJS • M Marathon MARATHON Qil Company • April 28, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~~~~~~~~ {v`iH~ ~ ~ <<<J~;3 E~laska ~if ~` ~'nchorage~ommissiorr A Reference: 10-404 Sundry Report Field: Kenai Gas Field Well: Kenai Unit 31-7x Dear Mr. Maunder: Attached for your records is the 10-404 Sundry Report for KU 31-7x well. KU 31-7x has been configured to permit gas injection into the Kenai Gas Field, Sterling Pool 6 sands. Accurate measurement of the production and injection flows are metered through a bi- directional ultrasonic meter. Gas injection was initiated on April 22, 2006. Gas is produced and injected from KU 31-7x as economics require. Please contact us at (907) 283 -1371 if you have any questions or need additional information. Sincerely, ~~~U~ ~ ~~ Kevin J. Skib Engineering Technician Enclosures: 10-404 Sundry Report cc: Houston Well File Operation Summary Kenai Well File KJ S KDW S~~ STATE OF ALASKA ALAS~OIL AND GAS CONSERVATION COMMI ION ~~~~~ V ~~ i~~-~Y ~. 6 2008 REPORT OF SUNDRY WELL OPERA~~~?~~~~ ~~~~ Cons. Commission Anrhnr~nc / 1. Operations Abandon Repair Well Plug PerForations Stimulate t er ~ Gas In' on Performed: Alter Casing ~ Pull Tubing ~ PerForate New Pool ^ Waiver~ Time Extension ~ S ~~ Change Approved Program ^ Operat. Shutdown ~ PerForate ^ Re-enter Suspended Well ~ 2. Operator Marathon Oil Company N 4. Well Class Before Work: 5. Permit to Drill Number: ame: Development ^~ Exploratory^ 200-148~ 3. Address: p0 Box 1949 Stratigraphic ^ Service ~ 6. API Number: Kenai Alaska, 99611-1949 50-133-20495-00-00 7. KB Elevation (ft): 9. Well Name and Number: 87' - Kenai Unit 31-7x ' 8. Property Designation: 10. Field/Pool(s): A- 028142 ~ Kenai Gas Field / Sterling Pool 6 11. Present Well Condition Summary: Total Depth measured 5,790' - feet Plugs (measured) NA true vertical 4,749' - feet Junk (measured) NA Effective Depth measured 5,665' feet true vertical 4,662' feet Casing Length Size MD ND Burst Collapse Structural Conductor 72' 20" 93' 93' Surface 1,487' 13-3/8" 1,508' 1,483' 3,090 psi 1,540 psi Intermediate Production 5,669' 9-5/8" 5,690' 4,679' S,750 psi 3,090 psi Liner 5,659' 7" 5,680' 4,672' 7,240 psi 5,410 psi Perforation depth: Measured depth: 5,330' -5,630' gross True Vertical depth: 4,433'-4,637' gross Tubing: (size, grade, and measured depth) NA NA NA Packers and SSSV (type and measured depth) ZXP Packer 5,150' 12. Stimuiation or cement squeeze summary: Intervals treated (measured): 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: 0 680 average 1 0 130 production Subsequent to operation: 0 9,150 average 0 0 425 injection 14. Attachments: 15. Well Class after work: ~y~ , Copies of Logs and Surveys Run Exploratory ^ ~ Development Service i Daily Report of Well Operations 16. Well Status aft wor • `~~l ~~ Oil ^ Gas WAG ^ GINJ ~ WINJ ^ WDSPL ^ 17. i hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 305-251 ~ Contact Kevin Skiba (907) 283-1371 ~~~~~ Printed Name Ken D. Walsh Title Se nior Production Engineer Signature ~~.-~~~ ~~L.Y`-- Phone (907) 283-1311 Date April 28, 2008 Form 10-404 Revised 04/2006 ~ ~~;~~ ~ ~;L L~ 200~G Submit Original Only MEMORANDUM . State of Alaska . Alaska Oil and Gas Conservation Commission TO: Jim Regg /<;. .. P.I. Supervisor èit S{Z(/ù 7 DATE: Monday, August 13, 2007 SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 31-07X KENAI UNIT 31-07X FROM: Lou Grimaldi Petroleum Inspector Src: Inspector Reviewed By: P.I. Suprv 3.e... Comm NON-CONFIDENTIAL Well Name: KENAI UNIT 31-07X Insp Num: mitLG070809104921 Rei Insp N urn: API Well Number: 50-133-20495-00-00 Permit Number: 200-148-0 Inspector Name: Lou Grimaldi Inspection Date: 8/8/2007 Packer Well 31-07X !Type Inj. ! G ! TVD ; P.T. 2001480 ITypeTest I SPT ! Test psi i Interval 4YRTST P/F P /' Notes: Well not injecting at time of test, conditions stable at time of test. Good test. Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. 1'~ IA I I 6000 150 1660 1660 1660 i I ! 1500 fOA 0 0 0 0 I Tubing! 145 145 145 145 I , ~~ AUG 2 32007 Monday, August 13,2007 Page I of I . . MEMO WELLS PRODUCING IN KENAI, STERLING POOL 6 AS NATIVE & STORAGE GAS WELLS Reference letter in file dated October 25, 2006 about wells producing from the Kenai, Sterling 6 Pool (pool code 448568) and the Kenai Pool 6 Gas Storage (pool code 448809). Storage Injection Order 7 A has a report, 2007 Annual Gas Storage Performance Evaluation dated March 2, 2007 which has a statement with an official start date of May 8, 2006 where storage started in the pool. There was no formal paperwork submitted about this change so this letter is for the official well status date change for the well status or date it was accomplished by AOGCC. The following is a list of wells that is reported with both pool codes 448568 and 448809: APD No. 201-097 201-231 159-013 165-007 178-055 168-071 181-092 181-154 182-015 182-085 184-109 185-181 200-148 Well No. 21-6RD 43-6RD 34-31 33-32L 44-30L DU5-L 14X-6AN 34-32L 14-32L 13-6L 23X-6SAN 33-7S 31- 7X I 0 ?yI{ ,-O~ ~t- "-1-.'" sCANNED JUL 2 7 2.007 October 25, 2006 . AlaSka. Team Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 Alaska Oil and Gas Conservation Commission Attn: Steve McMains 333 W. 7th Street, Suite 100 Anchorage, AK 99501 ç. ',f" i!\.~,!\1l\I~Tí \.,'1iö!'r1\, 'F ~w;.¿ ;3 (. RE: Wells Completed in Pool Codes 568 and 448809 Dear Steve, . '. Per your request, this letter is being provided to the AOGCC to identify wells completed in the Kenai Sterling Pool 6 (Pool Code 568) and the Kenai Pool 6 Gas Storage (Pool Code 448809). As you are aware, the above pool codes refer to the same geologic reservoir, a partially depleted gas reservoir which is being used for gas storage operations. Subsequent to the initiation of storage operations in May 2006, all future production from this reservoir is allocated between the remaining native gas and the injected/stored volumes, per written agreements between Marathon Oil Company and both the ADNR and the BLM. Therefore, any production from the wells completed in Pool 6 will be reported monthly on Form 10-405 under both pool codes. The wells appearing on Form 10-405 will appear the same for both pool codes. Per your request, the following is a list of wells which will be reported on Form 10-405, for both Pool Code 568 and 448809: ¥!el1 No. 21-6RD 43-6RD 34-31 33-32L 44-30L DU5-L 14X-6AN 34-32L 14-32L 13-6L 23X-6SAN 33-7S 31- 7X API No. 5011331009001 5011331009101 5011331009700 5011331009800 5011332013900 5011332031900 5011332034200 5011332034800 5011332035100 5011332035600 5011332037100 5011332038000 5011332049500 APD No. 201097 201231 159013 165007 178055 168071 181092 181154 182015 182085 184104 185181 200148 . . Please advise if you have any questions or need any additional information. I can be reached at 907.565.3041 or lcibele@marathonoi1.com. yndon Ibele, PE Production Coordinator Cc Randy Jindra, IBM, Tulsa Ken Walsh, MOC, Kenai Marathon Houston Central Files Brian Havelock, ADNR, Anchorage Greg Noble, BLM, Anchorage ~. /'rw ·'~-rJ ,\ :;-li:J r? ~) U~~~U!E, .~." ¡ ! I ,...........") ) .':":..:1,' ~ '1 ì 11': 1"';'\ ï,~ I \ l .:' \ '\ :: :::1, .)' / /.\ \ " -'.) \ ~,,,~,'.,.~; i L~ L:;j '-G " j /\\ , i~i \ ,/ i} :: ~!-.J ,l~ FRANK H. MURKOWSK/, GOVERNOR l~j 333 W. pH AVENUE, SUITE 100 ANCHORAGE. ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 A..fA.SIiA OIL AND GAS CONSERVATION COMMISSION Denise M. Titus Production Engineer Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6188 Re: KU 31-7X Sundry Number: 305-251 J.-oO ---lit 1 st;ANINHED NO~ (~ ~ 2U05 Dear Mrs. Titus: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely , "- DATED thisiL day of October, 2005 Enc!. ()('f fD-IO-o6 ¡J~E(j~Fff~' ( STATE OF ALASKA O)S IO~ -'Is L) ALASK.A Oil. AND GAS CONSERVATION COMM!SSluN SEP 2 8 2005 APPLICATION FOR SUNDRY APPROVALS AI..kl 01'& G C C .. 20 MC 25.280 -. .. I as ons. OmfTlISSlOn T Type of RCQuest: -- -, ,- -^b~n~io~ U Su.spend l. J Opr,~r(;tian(1 5h~ldõwl1 [T-"'-fêíiõ·t;lë LJ Walv~~r LJ A-nchorag8)thed~.J Aller eÔlsing 0 Rep<-)Îr Wf;! D Plug Perfomlions 0 Slimulolc D ¡ïme Extf-:n$ion [,1 Ch.:;mgG ~pprcvèd prógram D P~J!I Tubíng 0 Perforate New Pool 0 RlH:rll~)r SlJspt-:ndi?c;! Well [l 2. O'pêralar Name: 4. Current Well Class: 5. Þ~rmi1 to Drill Nu~b~·~ ----,.".,---- ,- M~r;)thon 011 Company Development [2] _. _ _ -- -- -'" - .... 3. Addmss; S~r(;!tigr3phÎC 0 Service Explor~tory U o 2.00-1 tiS ",.-- ........-"'....-. ------ 6. API NUfflbN: PO Box 196168. Anchorage, AI<1ska MS1 ¡;¡-S1 as 7. KB ElevatIon (rt): KB 87' ElovrJLlOIl from MSL 50-133-20495-00-00 9:\^ieJl Ñãmè'a-rldN'umbcr: ----,-...---......-.... ...,-....- Total DCptl1 TVD (ft): KU 31·7X ~/ 10. Field/Pools.(s): Kenai Gas Field. Sterling Pool G PRËSEÑi·vi/ËÜ. CONDITION SUMMARY Erfeclivé Dépth MD (ft): Ërfectiv·e De-pitïrVD (ft):'Plugs (m(,:~sur~d): ~...--,~"'_.....#,_...~".._...._._...... --- 8. Propcrty Dc~ignalion: A-OZ6142 11. Total Depth MD (ft): __ _.. a ..._. _ . . ___ .--- ..~.__. --..,.--'- J U 11 k (nlë;'S;:m;; :1}~-'-- Casing Struclural LQ n 9th Sizo Mo _ ",......._"""""'-1.............""'--'--"'--0.1_.. TVD Burst CI)I!¡;¡PSC "'.......----~a_ .. n. . ... _ _..__ .__. . .-. - .. - -.. - Surface 93 1508 20 13 3/8 93 1508 93 cjd\lr¡,n dr¡~ñ-~~' M~_~' 1~8$ .....'.-5õÐõ~.~~-~) Conductor Intermcdiate FI ród LJ c\ion Liner ... _~~"'I--~__- --- --- -. - - 5690 5678 95/8 ., 5ß90 --467'9" , 5678 ~~-"...~- -.- '4669 -- . ----"Tublng Gmdú: ....,-~ ._~- 5750 3090 72'iC1 -~~G4Tõ Tubing ~iD(IT);"-·- --.- Perloration Depth MD (ft):· .. perióralion Depth 1'VD (rl)~ T~lbjng Size: 5530 4433 N/A Paek(::Jrs r)nd SSSV l'Yp(i~ Model ZXP liner hanger'pãcker Packers and SSSV MD (f): 515ÕO;-~~'~~~~~----' _. --.. .... . . 12. Altachments; De~cription Summ~ry of Proposal LJ 13. Well Class Dfter p!'opo':3~d ·wúrÏc.: - DetaIled Operaflons Program 0 BOP Sketch 0 Exploratory D D~velopment rJ .-....--..,¡- . -. .. - . .. 14. E::Ülrnatod Date for 15. Well S\¡;¡t~$ ~fter proposed woi·k: CornmGndrlg Op~~r'iiliOIÌ$: 9/28/2005 Oil 0 Gas 0 Plugg(?¡j D 16. Verb~.¡1 Approv::II;- - - ----- - D~te: WAG [J G!NJ .-Et WINJ [1 ~om~iss~o~ ~~~pr_e5cntatjve: .._.., . c.t ~ roR r¡ \JJ6A- 17. I herøby cerlify that tho fOI'0going is true and correct to the be'it õrñw knowledge. CQí1l;:)ct Denise M. Tftùš"'""--'·"'·~----------" Prlntod Name A D.~ni~~~.T' .'.. Titla P",dualian !;'gineer Signature /¡~ f f ;lf7fJfl--;) A'-' - PI';onc 907 -283-1333 DDte "·,"^""-'1)/~t872õõ5 .... ( .1'. i' COMMISSION US~-ONLV ~-~'~~~'"-'"'~~'~~--'---- Service [~l -------.- Ab¡:¡Mönec [1 [] WDSPL .-.----... . . ~,~ Conditions of approval: Noli(y Commission so that a represcnwtivo may wílness Sundry Number": ~ 0 5 /0-. 2- <; , ~-"~_~.~,,.J~_. ~~~~_ Plug Intèority [J BOP TOGt D Mêchanicsllntegrity Test Lif Location CIÚé)r~nç8 [J Nt r r .,-,eet, ttA' /'\Pi d Olher: It_ . Ú .J-- . . ,··-i-,·~ "'1) P h,J V f d ~~"l--ð r ").,..R d "1'..e,ci/{;c~,-- () II' Je. .y r"'bt-t,{,,-,J fVv'OY {¿, ';i" <;.- 'ttj ¿ l:Þ""- Sub5equent Form Re APP""'C . RBDMS BFL 0 C1 1 2 2005 . - ----- -. _...._~. Dow: r~- COMMISSIONER APPROVED BY THE COMMISSION Forn-I 10-403 Revised 07/2005 "- ORIGiNAL Subr'ni( ill n~JpIiCGIC GO 'd 9L19 E8G LOB 'ON X~~ ^N~dWOO 110 NOHl~H~W W~ 81:80 03M 900G-8G-d3S 1(' Alaska Asset Team , , M MARATHON f Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565.3076 August 29, 2005 H':""'''ì\i?''''-'I''''''''~'' - 1.,~ï.7: \I '..\ ~i._.. ~': 'I, I'] ~l ".',,,,. ' /I J . b t~$ ~,." !I \ f ,\""" '" c:. ,~~~ ~j \~;, b11,~'~,,"", Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W ih Ave Anchorage, Alaska 99501 AUG 2 9 Z005 1~:!2:gl(;~ Oii [-} Reference: KU 31-7x Pool 6 Gas Storage Dear Mr. Aubert: Enclosed is the 10-403 Sundry Application to permit gas injection in KU 31-7x. The Kenai Gas Field Pool 6 Sterling zone has been identified as a desirable storage reservoir due to its low pressure and favorable reservoir qualities. Also, the Kenai Gas Field possesses an appropriate compression and piping infrastructure to allow gas from other reservoirs to be stored in the Sterling Sands for improved high rate deliverability as required. A bidirectional ultrasonic meter is installed on KU 31-7x to allow accurate injection or production measurement. Sundry approval is sought to permit the use of KU 31-7x for Pool 6 for Gas Storage. Storage will begin as demand dictates upon approval of the Gas Storage Application, which was submitted to the AOGCC (attn: Bob Crandall) via a transmittal letter dated August 26,2005. If you need any additional information or have questions, I can be reached by phone at 907-283-1333 or bye-mail at dmtitus@marathonoil.com. Sincerely, Ó~4 ~~ ~nise M. Titus Production Engineer fðv--DMI c: Bob Crandall, AOGCC Enclosure: 10-403 Sundry OD ('1 i\1 /1\ L ."\ " \1 "l'C~ ,./ l ì \. 1 ,\ . j \ \ . 'l tf..t.CRANI CAL INTEGRITY REPORT' '--. :. ~ G 2 S ~ ~ ;. :: ~ : ~ I ~ i ~¿ Q 0 ¡ , i OPER & FIELD Moc - Ile-'A.~ StM/I'kit -W=:L.L NUKBER ¡¿LA.. ~) - D7 Y- 200 ~ l4 ~ ! ¡. -' : ? U D D .:. ~_, _-=- : I 'ì f ., ¡' ,i 'ì r} () :'! I r;...;, ¿ v/ "" v' q ~ S/o II c ê.. s ir:. 6 : ¡) TD: 51 qo ,till.. 474-q TVD; :?BTD: S~.g 2.. HI> tl~ 1 ~ TVD Shoe: St.,qo HD ¿\tt,lq TVD¡ DV: MD ·Ivl) ~rl r,.LL DATA _:...:¡e::-: Shoe: M:D T'JD ; :CF: l·m ;: "'¡ D T \71) j Set. Er S&-''SS 5_ ~ "30 , S"to~D , Perfs to :"Joi.:-:g: 7'1 P aCKe:r- S I 5 D ill) :'ale Siz.e 12-1(4 II ana :-:EC?.ANIC;'.l.. INTEGRITY - PART ! 1 Þ_Ilnulus Press Test: ~p ¡ çqö 15 min IÇqo ; 30 min /C;Jìo . Co=ents: îês.+ ~ WI.V ,\ 6¡ L, c,: 4 I q I 2-005" Po~t - fÞvj uþ,",- ;4 I T r<'ÖtM' ~.(d . / :-Œ:CHJL1\IICÞ.~ INTEGRITY - PART ¡ 2 C em en t Volumes:' Þ...mt. Line.r ; Cs g l/(:O ç ~ ; DV Cwt -~o 1 to cove:r- per:: s 2 qq .elL +C W v..(!f' top f.eA + S; 00 \ @ :SD eii tIC. S . "Iheore tical Toe "L ~ ~ 7;, kt- "I,,{ J;~~lt1 CÆ "'L~.ct-{ ~ ~c \#' tl v ~.Æ".. ' Cement Bond Log (Yes or No) t( i In AOGCC File . vr CEL ~valuation, zone above perfs (¿~"~- Adk¡ it'-tr ~4\¡\,à.t\,-~¡ J "ì'~;., jtt "' Proåuction Log: Type Evaluation CONC;LUSIONS: ? ar -= n: ,All I T V't "6 t.M \A.d d .12 AA / I I-: 'J-. \ ) '....t,ð! hJ,., f : IV ( .e",.tA-. I ~í t-l !-M I "t,,(Y'f', 'v,i-~' ~ í ¡ At ¡; J'¡;'?\!~' I r~:t~·(r~'~\.- ~t--1_ d.~e d " 1,J-J{¡ I\ttr~!l"~""~-- f of "1l'2};~~fì()Ç'" . \ S t-Av/h h1.A,' tk~J C f~ l. ~, ,¿ç AD (I... LJALlI S" ?art ~ .. - -- " ;~ 1M \ MarathOfl \.r:oATHONt' Oil Company r.'~Glu..ìî ().~'3 Fh~!d PO Bn,~ iu'~9 ¡{~\r.r..i, AK ~ì~)J31'1 ~·t D49 T(ð\i"~phorH:i: (907) ;¿G3~Î:WO ~~x(307)~US-G~75 Fax Cover Sheet DATE: _____.._'1o?i1/11___ TIME: . ,_......."'~~_..... TO: f NAME:J¿Jìv1~ /'-L1h¡,-r1-- ~..._~_ COMPANY: A(2(+cG:...._.._..- ¿'Î ~,"/ ¿~ L/ FAX: -.~~..' (), ((J ,~__._."w..,...~,~______ FROM: NAME: w....' ()R/"vt ~ ~~'lu s .., ,1"IrI1II""I-.¡.....¡"""'O'O---I PHONE: I") ~(L- 7 "-. ,-~ ...... ,:I-- ) · )"" ../.... wr' { ~"~L.:~....2J~_..........-.. _I~-..-~·LI"""""-I FAX: '""""m.._9ill:2B 3 ~617 5 ., .,11,.."'1'\""''''\''------ PAGES SENT (Including CovGr Sheet) [] Response Requested ( ] Immediate [] I nformatiol1 Only .-"'--_~"'~~Mr""lW'''''''''''''''' REMARKS: t·LA ~)_L::Jy If) ~. (16 =3 ~_~W'_N~_____ 7 l.~~,.¡¡.. . _,,_.ILI ''(I ,·...-iw..~~& ~ """"".~"'M.''''-'_ -----..~,/.. ~'IfI' .....--..-...-...,. .~ I \IIN''''' . ............,"',..........., ~....~~I.I\-I....II\ ~..,·I~IooIo\\~. 1olo. ___ _._~.,_."-.~_ _,__..._ ",........- -.. ,..--..--.-- ..... ~... "" ...."'. ..-,-- ...~....._..,.. ,.. I';'~""tt'. , """ ,1~, \T"'" ~-\ :¡''''''''''.'') '-'-~~t;;. --.....f-. ,,¡c'''ì'.''-· ~, ; 7~",^, ,[.- -~ ~~1 ~\'.\ ::: ~~~f# ~:~.: I '"if!' l: _. f'r-'r (1 8 ~)C -' Z ,.' ~\\..;~ (:x~ & G.~. ~~~n ,A\:~,on~ to 'd 9Lt9 E8G LOB 'ON X~d AN~dWOO 110 NOH1~H~W W~ 8t:80 G3M 900G-8G-d3S ,r,' Alaska I~ _ .Jet T earn tIIjllf Ii Uf. A-thwt Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/565-3076 August 26, 2005 AUG 2 9 1.005 State of Alaska Alaska Oil and Gas Conservation Commission 333 West ih Ave, suite 100 Anchorage, AK 99501 Attn: Mr. Bob Crandall Re: Kenai Gas Field Gas Storage Application Dear Mr. Crandall: Enclosed please find Marathon Oil Corporation's request for Gas Storage within the Kenai Gas Field into Sterling Pool 6. The application document is intended to cover all engineering and geologic aspects for review of a gas storage project utilizing a partly depleted gas reservoir. Per statute, we have completed mechanical integrity tests of all well within the ~ mile 1, radius of the injection well cut point. All wells tested passed the test with the exception of well KBU 41-07. Remedial plans for KBU 41-07 have been activated and a rig workover to perform repairs is scheduled for September. Please note that it was not possible to test KU 41-07X (a monobore) because it has no annular space. We request this application proceed while we address the mechanical integrity issue in well KBU 41-07. Please call me if you have questions, 565-3042 or email me at lcibele@marathon.com. /,"',...#.) /') Sincerel~, . ,?\"'/i/ ,/\S / ,i/'" ,;' »"ì .,··....._1\. /~ \,,(.' <{// ,( ,.,.......' " ¡ ~í··'-·....'·· Lyndon Ib'ele Production Coordinator LCI:bjv Enclosures Hand delivered c: Steve Martinez, Bureau of Land Management Brian Havelock, Alaska Department of Natural Resources Section A. B. C. D. E. F. G. H. I. J. K. L. M. N. O. P. Q. R. ( Application for Injection Order for Gas Storage Kenai Gas Field Storage Facility Reeulatorv Citation 20 AAC 25.252(c)(I) 20 AAC 25.252(c)(2) 20 AAC 25.252(c)(3) 20 AAC 25.252(c)(4) 20 AAC 25.252(c)(4) 20 AAC 25.252(c)(5) 20 AAC 25.252(c)(6) 20 AAC 25.252( c)(7) 20 AAC 25.252(c)(8) 20 AAC 25.252(c)(9) 20 AAC 25.252(c)(10) 20 AAC 25.252(c)(II) 20 AAC 25.252(c)(I) Table of Contents Subiect Plat Operators/Surface Owners Affidavit Description of Operation Storage Zones Geologic Information Production History Reservoir Modeling Well Logs Mechanical Integrity Inj ection Fluid Inj ection Pressure Fracture Information Formation Fluid Aquifer Exemption Wells Within ~ Mile of Injection Well Gas Measurement Reporting Paee 3 4 4 4 4 5 5 5 6 6 7 8 8 8 9 9 10 10 1 .~ Kenai Gas Field Application for Injection Order for Gas Storage Kenai Gas Field Storage Facility Number 1 2 3/ 4 5 6 7 8/ 9/ 10/ 11/ 12/ 13/ 14/ 15/' 16/ 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 List of Attachments Description Cook Inlet Map Sterling Pool 6 Completions Map Cut Point Map - Wells within ~ Mile Radius ofKU 31-07X List of Parties with Rights to Share Production List of Surface Owners within ~ Mile on Injection Well Affidavit Injection Well KU 31-07X Production Historical Graph August 2004·Sterling Model MS PowerPoint presentation (on CD) Cement Bond Log Well KU 31-07X Cement Bond Log Well KBU 31-07 Cement Bond Log Well KBU 31-07RD Cement Bond Log Well KU 32-07H Cement Bond Log Well KU 32-07 Cement Bond Log Well KU 43-07 Cement Bond Log Well KBU 41-07X Cement Bond Log Well KBU 41-07 Well 31-07X Well Bore Diagram Sterling Pool 6 Gas Analysis Sterling Pool 6 Water Analysis Instromet Model Q.Sonic-C literature (on CD) Well KU 31-07X Completed 10-403 Well KU 31-07X Completed 10-404 Sterling Formation Structural Cross Section Map N-S orientation Sterling C-l Structure Map with GWC and PA boundary Sterling Pool 6 P/Z Graph Sterling Pool 6 Production Historical Graph May 2004 Shut In Surface Pressures May 2005 Shut In Bottom Hole Pressures Well KU 31-07X Injection Plot Sterling Pool 6 Well Bore Utility Table Well 31-07X MIT Results Well KBU 41-07 Type Log 2 ,( ~' ,I I Kenai Gas Field Kenai Gas Field Storage Facility Application for Storage Injection Order August 28, 2005 Introduction Marathon Oil Corporation (Marathon) requests permission to utilize the Kenai Gas Field, Sterling Pool 6 located within the Kenai Sterling Participating Area for natural gas storage. The injection intervals are known as the Sterling C-1 and C-2 sands, both of which are partly-depleted gas sands. The proposed injection well, KU 31-07X was designed and completed specifically to support a gas storage operation. The project will be used to help meet seasonal contract demands and to help mitigate well problems incurred by choking-back production or shutting in wells during low market-demand periods. The proposed gas storage operation is expected to increase the current reservoir pressure from 192 psia to no more than 500 psia. The gas storage reservoir will be continuously monitored to ensure proper containment. Injection operations will not commence until all necessary approvals have been obtained. Brief History Marathon Oil Company is currently the Operator and sole Working Interest Owner (WIO) of the Kenai Gas Field. Historically, Marathon has been a WIO in the Kenai Gas Field since its discovery in 1959. Marathon acquired the interests of Union Oil Company of California in 1994 and assumed operatorship of the field. In 2000, Marathon acquired the interests of a minority owner and became the sole working interest owner. Over the years, Marathon has pioneered new technologies in the Kenai Gas Field in order to increase reserve recovery and extend its economic viability. Cost effective gas storage operations might further extend field life and may increase ultimate reserve recovery. Section A - Plat Regulation 20 MC 25.252(C)(1) - a plat showing the location of all proposed disposal and storage wells, abandoned or other unused wells, production wells, dry holes, and any other wells within one-quarter mile of each proposed disposal or storage well; A Cook Inlet map (Attachment #1) shows the Kenai Gas Field in relation to other fields and points of interest. A Sterling Pool 6 Completion map is included (Attachment #2) showing KU 31-07X and other wells completed into Pool 6. A map showing all wells penetrating within 1,14 mile at the top of the injection location and zone is included (Attachment #3). 3 I~: Section B - Operators/Surface Owners Regulation 20 AAC 25.252(C)(2) - a list of all operators and surface owners within a one-quarter mile radius of each proposed disposal or storage well; A complete listing of surface owners is attached. (Attachment #4 a& b). All surface owners have been notified. Marathon is the sole operator within the Kenai Gas Field. There are no other operators within 'Ä mile of the proposed storage project. Section C - Affidavit Regulation 20 AAC 25.252(C)(3) - an affidavit showing that the operators and surface owners within a one-quarter mile radius have been provided a copy of the application for disposal or storage; Affidavit in reference to SectioQ. A and B are attached. (Attachment #5) Section D - Description of Operation Marathon proposes to inject natural gas produced within the Kenai Gas Field and from the Cannery Loop Unit into the Kenai Sterling PA, Sterling Pool 6 (C-l and C-2 sands). Well KU 31-07X will be used to both inject and produce gas. All other active completions into the Sterling Pool 6 will be utilized as take points or for reservoir monitoring purposes. A well utility chart is included as Attachment 29. Gas will be injected during low market demand periods and produced during periods of increased market demand. Future gas storage operations will include gas produced from other sources. Section E - Stora2e Zones Regulation 20 AAC 25.252(C)(4) - the name, description, depth, and thickness of the formation into which fluids are to be disposed or stored and appropriate geological data on the disposal or storage zone and confining zones, including lithologic descriptions and geologic names; The Sterling Pool 6, C-l and C-2 sands, will be used for gas storage. The C-l injection interval is between 4366' and 4500' TVD (134' TVD thickness) in injection well KU 31- 07X. The C-2 injection interval is between 4530' and 4569' TVD (39' TVD thickness) in inj ection well KU 31-07X. The C-l and C- 2 sands are in communication with each other and have been managed as a single reservoir-Sterling Pool 6- as defined by the AOGCC. 4 it Section F - Geologic Information The Sterling Formation is the youngest geologically and most prolific of the three gas producing formations in the Kenai Gas Field. The Sterling Formation consists of eleven separate sands and is grouped into five separate pools as defined by the AOGCC. The Sterling Pool 6 is comprised of the C 1 and C2 sands which are managed as a single reservoir. The Sterling Sand sequence is Miocene-Pliocene in age and was deposited by large, meandering stream systems. Individual sands are typically 30 to 60 feet thick, fine upward slightly, and are separated by coal, silt, and shale barriers. The thickest reservoir bodies in the Sterling are amalgamated sand sequences deposited in the central portions of the meander belts and can be in excess of 200 feet thick. The quartz-rich litharenites contain little matrix and are only slightly cemented with calcite, smectite, and kaolinite. The sand is fine to coarse-grained, angular to subrounded, and moderately well sorted. These represent the highest quality reservoirs in the field with porosities of 20 - 35% and permeability ranging from 10s to commonly 1000s of millidarcies (md). The subsurface structure of the Kenai Gas Field has a North-South trending anticline. Section G - Production History Well KU 31-07X was completed into the Sterling Pool 6 in both the C-l and C-2 sands in January 2001 with first production occurring April 2001. The well was originally completed as an annular producer with 3 'li" tubing and a sliding sleeve to allow access to the annulus. In 2004, the 3 Y2" tubing was pulled and replaced with a cemented 7" liner. Well KU 31-07X produced 5.2 BSCF and 2.4 MBW of fluid as of December 2004. A monthly production graph of KU 31-07X is attached to this permit (Attachment #6). Also included is a Pool 6 production graph (Attachment #25). Section H - Reservoir Modeling The Pool 6 reservoir performance has been modeled for many years, and was recently updated. Attached is an August 2004 model report (Attachment #7). The model has been an accurate predictor of the reservoir's past and present behavior. The model is essentially a tank model with a weak aquifer driven by pressure. The model contains the historical gas and water production and observed BHP data either calculated from surface tubing pressures or directly from BHP pressure gauges. Each well within the model has an excellent history match. The Pool 6 model will continue to be used as a tool to monitor performance during gas storage injection and withdrawal cycles. 5 Section I - Well Loes Regulation 20 AAC 25.252(C)(5) - logs of the disposal or storage wells, if not already on file, or other similar information; All logs from wells in the Kenai Gas Field have been previously submitted to Alaska Oil and Gas Conservation Commission. Log sections for well KU 31-07X and the wells intersecting Pool 6 within a ~ mile radius of the injection well are attached to this application (Attachments # 8 -15). Section J - Mechanical Inteerity Regulation 20 AAC 25.252(C)(6) - a description of the proposed method for demonstrating the mechanical integrity of the casing and tubing under 20 AAC 25.412 and for demonstrating that fluids will not move behind casing beyond the approved disposal or storage zone, and a description of (A) the casing of the disposal or storage wells, if the wells are existing; or (8) the proposed casing program, if the disposal or storage wells are new; A pressure test of the casing-tubing annulus will be the primary means of demonstrating mechanical integrity. The proposed injection well, KU 31-07X, passed an MIT (Mechanical Integrity Test) on April 29, 2005. The test was witnessed by an AOGCC representative. (Attachment 30) Additionally, all wells identified within the ~ mile radius of the KU 31-07X cut point into Sterling Pool 6 were tested for mechanical integrity except for KBU 41-07X. It was . not possible to test well KU 41-07X (a Beluga monobore) since it has no annular space. /' Well KU 41-07X is an inactive well however and has not produced since May 2003. All other wells tested passed the MIT test per AAC 25.412, except KBU 41-07 which is being addressed at this time. A rig workover of KBU 41-07 is planned to restore / mechanical integrity. The proposed injection/withdrawal well, KU 31-07X (API 50-133-20495-00), was completed with a cemented 7" liner with a ZXP packer above the cemented liner section at a measured depth (MD) of 5,330'. The casing information below is provided to summarize the data depicted in the attached well bore diagram. (Attachment #16) KU 31-07X Casing Information Casing Size From (MD) 20" Surface 13 3/8" Surface 7" Surface To (MD) 114' 1,508 ' 5,737' Comments Cemented from 5,330' to TD Further evidence of mechanical integrity and confinement The Pool 6 P/Z plot, referenced in Section D shows 40 years of history as evidence that the reservoir is confined and there is no movement of fluids behind casing beyond the proposed storage interval. 6 ;(' The Sterling Pool 6 is part of the greater Sterling Participating Area (P A). The Sterling P A is comprised of the Sterling Pools 3, 4, 5.1, 5.2 and 6 in sequence with Pool 3 being the shallowest. Pools 3 and 4 are nearing depletion and some completions are experiencing water loading problems. Pool 5.1 is shut in and considered depleted. Pool 5.2 has been watered out for several years and contains high pressure water. The latest observed pressure in Pool 5.2 was nearly 1400 psia. The Sterling, Beluga and Tyonek formations are configured in a layer cake fashion. The Sterling Pool 6 is beneath Sterling Pool 5.2 and above the Beluga formation. Recent bottom hole pressures range from 500+ psi to 2000+ psi in the Beluga formation. Clearly, any communication between the Sterling Pool 6 and the adj acent pools would appear as influx into Pool 6 due to the significantly higher pressure above and below the target sands. For more than 40 years Pool 6 has followed a classic P/Z curve indicating no communication or water influx. Future P/Z performance will be closely monitored as an indicator of continued reservoir confinement. The Pool 6 reservoir performance is expected to track the established P/Z line during injection and withdrawal cycles with possible slight deviation due to compaction and aquifer encroachment. Industry literature indicates that this behavior has been observed in other gas storage projects using depleted gas reservoirs. Section K - Injection Fluid Regulation 20 AAC 25.252(C)(7) - a statement as to the type of oil field wastes to be disposed or hydrocarbons stored, their composition, their source, the estimated maximum amounts to be disposed or stored daily, and the compatibility of fluids to be disposed or stored with the disposal or storage zone; Marathon intends to inject a stream of gas which is typically over 98% methane into Sterling Pool 6. Initially, the injected gas source will be from wells within the Kenai and Cannery Loop Units. The attached gas analysis (Attachment #17) is from well KU 43-06A. K"U 43-06A is completed into Pool 4 and its gas analysis is representative of all native gas originating from the Sterling P A. Marathon will only inject gas from sources which are of similar composition and deemed compatible with Pool 6. The anticipated average injection rate is expected to be approximately 32 MMSCFPD. The maximum anticipated injection rate is approximately 68 MMSCFPD. 7 ( .~ Section L - Iniection Pressure Regulation 20 AAC 25.252(C)(8) - the estimated average and maximum injection pressure; The injection pressure is expected to be 500 psi at the surface and 474 psi at bottom hole for the expected daily average injection rate of approximately 32mmcfd. Daily injection rates will be dependent upon gas volumes available for injection. Marathon intends to conduct gas injection operations in KU 31-07X at a maximum surface tubing pressure of 900 psi which correlates to an estimated injection rate of 68 MMSCFPD and a bottom hole pressure of 810 psi. The bottom hole injection pressure of 810 psi at the maximum anticipated injection rate of 68 MMSCFPD is nearly 2,000 psi below the estimated fracture gradient of 2,785 psig referenced in the Section M. Section M - Fracture Information Regulation 20 AAC 25.252(C)(9) - evidence to support a commission finding that the proposed disposal or storage operation will not initiate or propagate fractures through the confining zones that might enable the oil field wastes or stored hydrocarbons to enter freshwater strata; Leak off tests in well penetrations KBU 42-7 and KBU 42-6 show the fracture gradient to be 0.69 psi/ft at 5,350 feet true vertical depth (TVD) and 0.7 psi/ft at 5,367 feet TVD, respectively. Using a frac gradient of .695 psi/ft at 5,360 feet TVD and correcting back to a TVD of 4,420 using a conservative 1.0 psi/ft overburden gradient results in a frac gradient of 0.63 psi/ft. at the depth of the injection interval (approximately 4,420 feet TVD). Marathon intends to maintain wellhead injection pressures below a gradient of .63 psi/ft at a target injection depth of 4420 feet TVD, or 2,785 psig bottom hole injection pressure. This corresponds to a maximum wellhead surface pressure, for 0.56 specific gravity gas, of 2,500 psig during gas injection operations. KU 31-07X was modeled with injection rates up to 68 MMSCFPD. The model indicates bottom hole injection pressure of 810 psi at the maximum anticipated injection rate of 68 MMSCFPD, which is nearly 2,000 psi below the estimated fracture gradient of 2,785 pSlg. Section N - Formation Fluid Regulation 20 AAC 25.252(C)(1 0) - a standard laboratory water analysis, or the results of another method acceptable to the commission, to determine the quality of the water within the formation into which disposal or storage is proposed; A produced water sample collected from a produced water tank at Pad 14-32 in the Kenai Gas Field is attached (Attachment #18). This sample is representative of produced water collected throughout the Kenai Gas Field. 8 ~.. ( Only trace amounts of water are expected to be introduced into the Sterling Pool 6 as a result of gas injection/storage operations. No adverse impact is expected from the trace water. Section 0 - Aquifer Exemption Regulation 20 MC 25.252(C)(11) - a reference to any applicable freshwater exemption issued in accordance with 20 MC 25.440; All aquifers in the Kenai Gas Field below 1300' TVD have been exempted by the EPA under 40 CFR 147.102 EPA (b)(l)(c). (1) The portions of aquifers in the Kenai Peninsula, greater than the indicated depths below the ground surface and described by a 1 4 mile area beyond and lying directly below the following oil and gas producingfields: (i) Swanson River Field-1700 feet. (ii) Beaver Creek Field-1650 feet. (iii) Kenai Gas Field-1300 feet. Section P - Wells Within 1;4 Mile of Injection Well / Regulation 20 AAC 25.252(C)(1) - a report on the mechanical condition of each well that has penetrated the disposal or storage zone within a one quarter mile radius of a disposal or storage well. The wells listed in the table below cut the top of the Sterling Pool 6 within ~ mile of the proposed injection well KU 31-07X's penetration into the pool. All wells within the Y4 mile radius were tested for mechanical integrity with the exception of KBU 41-07X which is a monobore completed into the Beluga formation. None of the wells within the Y4 mile radius have active completions into Pool 6 with the exception of KU 31-07X, the proposed injection well. Well Depth Depth KU31-07X Drill API# l\b.y2005 Completion CBL. Over MD (ft) TVD(ft) Homontal Penuit # BlIP Into SietllitgPool OftSef(ft) SterllitgPoo161 61 KBU:31~07 4757.82 4433 103.6:66 181·153 50·133·20347.00 N y KBU31·07RD 4757.82 4433 1036:66 195.055 50.133·20347-01 N Y KU31·07X 533035 4433 0 200~148 50·133~20495.00 X Y Y r KDU 04 4948.99 4433 1003.62 169·012 50·133·20176.00 N N KDU 4RD 4939.92 4433 1020.15 KTU 32-07 4720,02 4433 763.36 200.023 50.133·20491·00 N N KBU 41~07X 4493.27 4433 888,21 202.025 50:133~2051 0.00 N N KTU 32.07H 4433.7 4433 1336:65 202-043 50:133·20491·00 N N KBU 41·07 4433.19 4433 1225,73 179-029 50:133"20327·00 N y Additionally, a map showing the wells within the Y4 mile radius is show as Attachment # 3 as previously referenced. 9 \ Section 0 - Gas Measurement All gas volumes injected into Pool 6 will be measured with an Instromet Q.Sonic Ultrasonic TM gas meter. The Q.Sonic is capable of bidirectional flow and will be used during both injection and withdrawal cycles. The meter will be given a dual name designation, one for injection the other for withdrawal. Manufacturer literature on the Q.Sonic is attached to the permit request and can be viewed online at following website http://www.instronlct.com/Products. (Attachment # 19). Section R - Reportine Marathon will modify the Kenai Gas Field Plan of Development to reflect the proposed gas storage operations upon approval of this permit. Marathon will submit a Material Balance report specifically addressing the Sterling Pool 6 gas storage. Marathon will submit the required monthly reports tracking injection and withdrawal volumes. Marathon has attached the required forms 10-403 and 10-404 converting KU 31-07X to well with dual purposes (injection/withdrawal) (Attachments #20-21). Marathon will perform an MIT on KU 31-07X every four years as required by 20 AAC 25.252(d). cc: All interest owners with the right to share in production from existing Pool 6 Gas Surface owners within ~ mile radius of injection well 31-07X 10 MEMORANDUM State of Alaska 1 Alaska Oil and Gas Conservation Comm.. TO: Jim Regg P.I. Supervisor 'T{¿11 ~1101D5 DATE: Monday, May 02, 2005 SUBJECT: Mechanical Integrity Tests MARATHON On.. CO 31-07X KENAI UNIT 31-07X âYJ/\~ FROM: Lou Grimaldi Petroleum Inspector Src: Inspector Reviewed By: P.I. Suprv ~£-. Comm NON-CONFIDENTIAL Well Name: KENAl UNIT 31-07X Insp Num: mitLG050501074609 Rei Insp Num: API Well Number: 50-133-20495-00-00 Permit Number: 200-148-0 Inspector Name: Lou Grimaldi Inspection Date: 4/29/2005 Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well 31-07X Type Inj. N TVD 4314 IA 980 620 620 620 1590 1590 P.T. 2001480 TypeTest SPT Test psi 1078.5 OA 0 0 0 0 0 0 Interval OTHER P/F P Tubing 165 165 165 165 165 165 Notes: Well being evaluated for future gas injection possibility. Observe well in pretest condition for 15 min's. Bleed IA to 620 and observe for 30 min's. Pressure IA to 1590 and observe for 30 minutes. SCANNED MAY 3 1 2005 Monday, May 02, 2005 Page 1 of 1 ) ) ~ ' M MARATHON f Marathon Oil Company Alaska Business Unit Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 April 25, 2005 d.,OO -11+3 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: Field: Well: Report of Sundry Well Operations Kenai Gas Field KU 31-7X SCANNED APB 2, 7 20D5 Dear Mr. Aubert: Enclosed is the 10-404 Report of Sundry Well Operations for Marathon well KU 31-7X. Work was completed to optimize production by pulling the 3.5" tubing and packer completion and replace it with a 7" 26 ppf casing string with packer for production tubing. Modeling indicated 7" casing for production tubing would allow the well to sustain unload rates with maximum deliverability. The well was perforated in September, 2004 and returned to production flowing at 8.1 MMcfd @ 50psi. If you need any additional information, I can be reached at 907-283-1333 or bye-mail at DMTitus@MarathonOil.com. Sincerely, , -IIIL f fr ')Ofr Denise Titus Production Engineer Enclosures Sundry Report Operations Summary Current wellbore diagram RECEIVED APR 2 7 Z005 Alaska Oil & Gas Cons. Commission Anchorage 1. Operations Abandon U Repair Well U Performed: Alter Casing D Pull Tubing [] Change Approved Program D Operat. Shutdown D 2. Operator Marathon Oil Company Name: \ STATE OF ALASKA ) ALASk-/OIL AND GAS CONSERVATION COMMk..v1oN REPORT OF SUNDRY WELL OPERATIONS Stimul.teU REr~IVED Waiver D Time ExtÅa~ [2 7 ZDO~ Re-enter Suspended Well D 5.~at¡Jlb~ WtatIiftns. l;ommission Exploratory D 200-148 Anchorane Service D 6. API Number: 50-133-20495-00 9. Well Name and Number: KU 31-7x 10. Field/Pool(s): Kenai Gas Field, Sterling Pool 6 Plug Perforations U Perforate New Pool D Perforate D 4. Current Well Class: Development [] Stratigraphic D PO Box 196168 Anchorage, Alaska 99519-6168 7. KB Elevation (ft): KB 87' Elevation from MSL KB-GL: 21' 8. Property Designation: A-028142 11. Present Well Condition Summary: 3. Address: Total Depth measured 5790 feet true vertical 4749 feet Effective Depth measured 5682 feet true vertical 4673 feet Casing Length Size MD Structural Conductor 93 20" 93 Surface 1508 13-3/8" 1508 Intermediate Production 5690 9-5/8" 5690 Liner 529 7" 5678 Plugs (measured) N/A Junk (measured) N/A TVD Burst Collapse 93 N/A N/A 1483 3090 1540 4679 5750 3090 4669 7240 5410 Perforation depth: Measured depth: 5330'-5370'; 5572'-5630' True Vertical depth: 4433'-4460'; 4598'-4637' Tubing: (size, grade, and measured depth) 7" 26 ppf, L-80 5160 Packers and SSSV (type and measured depth) ZXP Liner Hgr/Pkr 5149 12. Stimulation or cement squeeze summary: Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: 13. Oil-Bbl Representative Daily Average Production or Injection Data Gas-Met Water-Bbl Casing Pressure Tubing Pressure 50 50 Prior to well operation: N/A Subsequent to operation: N/A 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations 6000 2 8100 2 15. Well Class after proposed work: Exploratory D Development [] 16. Well Status after proposed work: OilD Gas [] WAG D 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Service D x GINJ D WINJ D WDSPL D Sundry Number or N/A if C.O. Exempt: Contact Denise M. Titus pnn::.::: D¡;~!yjr_ Form 10-404 Revised 04/2004 Title Production Engineer Phone 907-283-1333 Date 4/25/2005 ~ß,VM5 L.~ ( ,-- J7 Ò.S Submit Original Only '1'1.\1 ) } Start: 4/13/2004 Rig Release: 1/16/2001 Rig Number: 1 RECElVetJof6 APR2 7 2005 Alaska Oi' & Gas Cons. Commission Spud D_~e/2000 End: Group: Marathon Oil Gompany Operations ··SummaryReport Legal Well Name: KENAI UNIT 31-7X Common Well Name: KENAI UNIT 31-7X Event Name: WORKOVER . Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Sub Date From - To HÓurs Code Code Phase 4/13/2004 16:00 - 19:00 4/16/2004 06:00 - 12:00 12:00 - 00:00 Dßscription of Operations 3.00 NUND WLHD WBPREP Remove secondary 4" annular vavles from tubing head outlet for rig access. RU lubricator and install 4" VR plugs in BOTH tubing head outlets. 6.00 RIG MIRU MIRU Accept rig from KBU11-8X@ 06:00hrs 04/15/2004. 12.00 RIG MIRU MIRU 00:00 - 06:00 6.00 RIG MIRU MIRU 4/17/2004 06:00 - 12:00 6.00 RIG MIRU MIRU 12:00 - 00:00 12.00 RIG MIRU MIRU 00:00 - 03:30 3.50 WLCNTL KILL WBPREP 03:30 - 04:30 1.00 WLCNTL KILL WBPREP 04:30 - 06:00 1.50 WLCNTL KI LL WBPREP 4/18/2004 06:00 - 08:00 2.00 MUD MMIX WBPREP 08:00 - 08:30 0.50 WLCNTL KILL WBPREP 08:30 - 09:30 09:30 - 11 :30 11 :30 - 12:30 I 12:30 - 14:30 I '14:30 - 15:30 : 15:30 - 16:00 16:00 - 17:00 117:00 - 00:00 I 00:00 - 00:30 I 00:30 - 05:30 1.00 MONITR MNwL WBPREP 2.00 WLCNTL KILL WBPREP 1.00 MUD MMIX I WBPREP 2.00 CIRC CLN WBPREP 1.00 MONITR MNwL 0.50 EQUIP RURD 1.00 NUND DTRE 7.00 NUND UBOP 0.50 TEST BOP 5.00 TEST BOP WBPREP WBPREP WBPREP WBPREP WBPREP WBPREP Load matting boards and move. Move remaining rig components. Prep sub and carrier, layover derrick. Pull sub off of well and lower sub and secure mud boat. R/U pitts. C/O hydraulic oil in sub rams. Set pump room, pits, generator, boiler, water tank. Raise sub and set in. set mud boat. Plug in electrical. Run water line. R/U pits. Crane in fuel tank, choke house, flow line and stairs. Note: Due to substructure size, orientation, and length of Vetco lubricator removed VR-plug from one annulus outlet prior to moving substructure over well. Pneumatic valve also had to be removed from wing to allow sub base to be set R/U outriggers. Set V-door. Set driller side stairs, back landing, windwalls, catwalk, and beaver slide. Set TD on floor. R/U elect, air, water, steam lines to rig floor. Prep derrick and scope up. R/U mud manifold, rig floor spill containment, drillers console. Hook up carrier engine exhaust. R/U choke line and kill line. R/U gas buster and lines. Unload trailers. R/U cylinder and carrier tarps, derrick board, shock hose. Spot slop tank. R/U TD torque tube and TD. Mix 6% KCL brine and 60bbl LCM pill. R/U rig floor and panic line. Test run pumps and TD. Accept rig for well work @ OO:OOhrs 4/17/04. N/U choke line to annulus. Pull BPV w/lubricator(280psi on TBG). R/U kill line to TBG. PJSM prior to killing well. TBG 230psi ANN Opsi. Spot 30bbl LCM pill(3PPB flovis, 10PPB CaCo2 fine, 10PPB CaCo2 Med) down TBG across perfs. No returns to ANN. Let pill soak. C/O choke to other annulus outlet (discovered that choke line was hooked up to side w/VR-plug). TBG 300psi ANN 280psi. Spot 46bbl LCM pill (3PPB flovis, 10PPB CaCo2 fine, 10PPB CaCo2 Med) across perfs. While letting LCM pill set across perfs and monitoring well mix LCM pill#3 and add volume to 6% KCL brine in pits. Pump LCM pill#3 50bbls (5ppb flovis, 20ppb CaCo2 fine, 20ppb CaCo3 med) and clear lines w/6%KCL brine(returns established after 54bbls pumped, total 320bbls pumped in well. TBG on vaccum after shut off pumps). Let LCM work and monotor well. Circ. 6% KCL brine. Took 12BBLS to get returns. Monitor for 30min. Fill well (losses 12BPH). Mix 50BBL LCM pill while monitor well. Fill well (losses 7.5BPH). Circ. well volume to SS@4329'(lost 9 BBLS while eirc. no sand or debris across shakers). Monitor well(losses 5BPH). R/D choke and kill lines. Set BPV. N/D tree. N/U BOPE. Pull BPV and set TWC. Test 1-12 CMV's. Inner and outer kill line valves, choke HCR, manual Printed: 4/23/2005 3:10:39 PM ) ) MarathonOilGQrT'Ipany Qperatlol'1s··Sl.lml11aryReport Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: KENAI UNIT 31-7X KENAI UNIT 31-7X WORKOVER GLACIER DRILLING GLACIER DRILLING From': To Hours Code 5~Je Phase Date 4/18/2004 00:30 - 05:30 RECEIVErr 2()f6 APR ~72005 Alaska ~~JJ~~~n~2~~~on Start: 4/13/2004 End Anchorage Rig Release: 1/16/2001 Group: Rig Number: 1 ( Description of Operations 5.00 TEST BOP WBPREP choke line valve, Annular, TIW valve, Upper and lower TD valves, 3.5" IBOP valve 250/2500psi 10min. Test 27/8" X 51/2" variable and blind rams 1 00/2500psi 10min. Perform accumulator test. RID test equipment. 0.50 EQUIP. RURD WBPREP R/U EL guide for TD. 1.50 EQUIP RURD EQPPUL Pull TWC(TBG on slight vaccum). Check ANN (slight vaccum). Fill hole took 15BBL. R/U 5" DP for LJ. R/U safety valves and head pin. 0.50 CIRC CLN EQPPUL P/U hanger out of bowl w/60K. Circ. well(took 25bbls total to fill well after BOP testing). After circulating 20bbls well packed off and max pressure was 400psi. R/U APRS. PJSM. P/U APRS tools. RIH w/2.7" gauge to 4405'. POOH. PJSM. RIH wi FPI. Pipe free @ 4375'. POOH. RIH w/2.7" jet cutter: Cut TBG @ 4374'(left 25' stick 'up to next coupling). POOH w/EL. RID APRS. RID TD wireline guide. P/U on TBG and pull 65K. TBG came free(P/U wt 40K, well took 40bbls to fill). Circ. outwhile R/U Weatherford TBG tools. PJSM. POOH. LID 3.5" 9.2ppf L-80 Butt TBG(146jnts total, check for norm ). PJSM. R/U dual slips and LID Y-block and Perf guns. Cont. to LID remainder of 3.5" TBG. RID Weatherford TBG tools. Install wear bushing. C/O bales. M/U Overshot assY. Prep to P/U remainder of BHA. Cont. P/U fishing BHA#1 (overshot assy). P/U 5" DP while RIH w/fishing BHA#1. Repair M/U tong line valve and replace flow line boots. Cont. P/U 5" DP while RIH with overshot assy. Engage TOF @ 4379'. Mill over TBG flare(took 1 hr). Release anchor( difficult to release). POOH with overshot assy. LID 33' TBG and anchor( 100% recovery). LID overshot assy. P/U fishing BHA#2(PKR mill and PRT) RIH w/fishing BHA#2. Tag top of packer @ 4412'. Mill packer. Cont. to mill 95/8" Baker permanent packer until it released. Drop circulating bar and open circulating ports above packer. Drop down 30' and circ(noticable increase in gas during circulation). Shut in well and circ. through choke. Open stack after getting B/U. Cont. to circ. until gas was gone. Observe well (losses 5BPH). POOH w/Packer and tail pipe. Packer dragging for first 500'. ¡Work fish through well head(observed parts of packer fall back in hole). LID Fishing tools and packer assy. I R/U Weatherford TBG tools. LID 15 joints 3.5 9.2 Butt TBG. M/U BHA#3. RIH to 5337'(P/U 26jnts 5.0" DP). Work mill through tight CSG F/5337' to 5347'(had metal shavings across shakers @ B/U). POOH. Cont POH for bha C/O. Losses at 5 bph. 05:30 - 06:00 4/19/2004 06:00 - 07:30 4/20/2004 4/21 12004 4/22/2004 07:30 - 08:00 08:00 - 09:30 1.50 LOG CSGD EQPPUL 09:30 - 10:00 0.50 LOG CSGD EQPPUL 10:00 - 11 :30 1.50 LOG CSGD EQPPUL .11 :30 - 13:30 2.00 LOG CSGD EQPPUL 13:30 - 15:00 1.50 LOG CSGD EQPPUL 15:00 - 16:00 1.00 TRIP LDDP .EQPPUL 16:00 - 17:30 1.50 CIRC CLN EQPPUL 17:30 - 21 :30 4.00 TRIP LDDP EQPPUL 21 :30 - 01 :30 4.00 TRIP LDDP EQPPUL 01 :30 - 02:30 1.00 EQUIP RURD EQPPUL 02:30 - 03:00 0.50 TRIP WEAR EQPPUL 03:00 - 04:00 1.00 EQUIP RURD EQPPUL 04:00 - 05:00 1.00 TRIP BBHD EQPPUL 05:00 - 06:00 1.00 TRIP BBHD EQPPUL 06:00 - 07:00 1.00 TRIP BBHD EQPPUL 07:00 - 13:00 6.00 TRIP PUDP EQPPUL 13:00 - 14:00 1.00 REPAIR RIG - EQPPUL 14:00 - 16:30 2.50 TRIP. PUDP EQPPUL 16:30 - 18:00 1.50 FISH EGNG EQPPUL ..¡ 8:00 - 21 :30 3.50 FISH PFSH EQPPUL 21 :30 - 00:00 2.50 FISH RFSH EQPPUL 00:00 - 02:00 2.00 FISH RFSH EQPPUL 02:00 - 06:00 4.00 FISH MLCT EQPPUL 06:00 - 10:00 4.00 FISH MLCT EQPPUL 10:00 -10:30 0.50 CIRC CLN EQP.PUL 10:30 - 11 :30 1.00 CIRC CLN EQPPUL 11:30-16:00 4.50 FISH PFSH EQPPUL 16:00 - 17:00 1.00 FISH PFSH I EQPPUL 17:00 - 18:00 1.00 FISH PFSH EQPPUL 18:00 - 20:30 2.50 FISH PFSH EQPPUL 20:30 - 01 :30 5.00 FISH RFSH EQPPUL 01 :30 - 03:30 2.00 FISH MLCT EQPPUL I I 03:30 - 06:00 2.50 FISH PFSH EQPPUL 06:00 - 07:00 1.00 TRIP BHA PR1CSG Printed: 4/23/2005 3:10:39 PM ) ) MClrathonOil Qornpany Operations 'Summary Report R',I::', ,CE',I,' lr"':'~,·æ,",""'\..,,,',',,' I:: ' " . 'Pag'~lS of 6 APR 27 2UUj Legal Well Name: KENAI UNIT 31-7X Common Well Name: KENAI UNIT 31-7X Event Name: WORKOVER Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Sub Date From-To Hours Code Code Phase 4/2212004 4/23/2004 4/24/2004 07:00 - 08:00 1.00 TRIP 08:00 - 09:00 1.00 RIG 09:00 - 12:00 3.00 CSG 12:00 - 13:00 1.00 TRIP 13:00 - 16:00 3.00 TRIP 16:00 - 20:00 4.00 CIRC 20:00 - 00:00 4.00 CIRC 00:00 - 00:30 0.50 TRIP 00:30 - 02:30 2.00 WAIT 02:30 - 03:00 0.50 TRIP 03:00 - 04:00 1.00 CIRC 04:00 - 06:00 2.00 TRIP 06:00 - 07:00 1.00 TRIP 07:00 - 10:30 3.50 TRIP 10:30 - 12:00 1.50 CSG 12:00 - 13:00 1.00 CSG 13:00 - 14:00 1.00 WAIT 14:00 - 00:30 10.50 WAIT 00:30 - 02:00 1.50 CSG 02:00 - 04:30 2.50 TRIP 04:30 - 05:00 0.50 CSG 05:00 - 06:00 1.00 RIG 06:00 - 12:00 6.00 CSG 12:00 - 14:30 2.50 CEMT Handle BHA #3, layout mill I csg scraper. Service Rig Prepare 7" csg, clean I drift I strap, record tally. MU BHA #4, (Btm mill, string mill), RIH same. Follow BHA with 5" DP to tag at 5355 ft Ream 5355 - 5370 ft. Wash I ream 5370 - 5680 ft Large quantity sand at shaker. Also scale I rubber particles PR1CSG Circ Hi Vis sweeps, shaker clean. Losses 5 bph PR1CSG POH above top perfs at 5200 ft PR1 CSG Wait on possible wellbore influx (sand) as fill test PR1CSG RIH, 1 ft fill. PR1 CSG Circ final sweep, shaker clean. Losses 5 bph PR1CSG POH for 7" comp, correct hole fill, slight loss seepage. PR1CSG I Cont POH 5" DP PR1 CSG Layout BHA #4, clear floor. Recover 5 gallon bucket of metal fl junk/baskets. Upper 8-114" mill 1/4" UG, lower 8" mill 5/8" UG. PJSM, RU Weatherford, MU shoe I 1 jt 7" csg Pre tour safety meeting. Receive order change, layout 7" equip. Wait I receive new 7" liner I cmt program Wait on pkr mods I delivery Take delivery BOT pkr I float equip, layout DCs PJSM, Commence run 7" liner, (Guide shoe, jt csg, Float jt csg, Idg collar) follow with 10 jts 7", 26#, L80, BTC mod csg RUN PR1CSG MU Baker pkr, prepare RIH same RCOM PR1CSG Repair hyd hose, top drive RUN PR1CSG Follow liner hgrwith 5" DP Shoe 5680, Float collar 5635, Ldg collar 5592, TOL 5150 ft. Total losses while RIH 10 bbls. PRIM PR1 CSG PJSM, commence cmt 7" liner as follows: Test lines 4500 psi, drop ball, set hgr with 3200 psi Pump 18 bbl H2o, mix I pump 18.8 bbls 15.8# "G" cmt Drop plug, confirm plug dropped, Pump 5 bbls H2o, Displace with 76 bbls brine, latch plug, bump plug 1500 psi Bleed, check floats Plug bumped at 1425 hrs, 100% returns, no losses BBHD PR1 CSG SERV PR1CSG DRFT PR1CSG BBHD PR1CSG BHA PR1CSG WSHD PR1CSG FILL WTRP OTHR WTRP FILL BIT BHA BBHD RUN RUN ORDR EQIP BBHD PUDP PR1 CSG PR1CSG PR1CSG PR1 CSG PR1CSG PR1CSG Start: 4/13/2004 Rig Release: 1/16/2001 Rig Number: 1 Alaska Ûil& Gas Con::...., :'¡h.. .ì~~.SIOI1 Spud cfm~~Of~~6/2000 End: Group: Description' of Operations 14:30 - 15:00 0.50 CSG RUN PR1CSG Build 500 psi on DP, PU I shear dogs, note press bleed Set pkr with 30K, confirm set, pull set tool free. 15:00 - 15:30 0.50 CIRC CLN PR1CSG CBU, no cmt to surface. 15:30 - 16:00 0.50 CEMT PRIM PR1CSG Rig dn cmt hd, clear floor. 16:00 - 19:00 3.00 TRIP BHA PR1CSG POH 5" DP, layout HWDP I liner set tools 19:00 - 19:30 0.50 RIG SERV PR1CSG Service Rig 19:30 - 23:00 3.50 TRIP BIT PR 1 CSG MU polish mill, RIH same to 5100 ft 23:00 - 00:00 1.00 RIG SCDL PR1CSG I Slip and Cut Drill Line 00:00 - 01 :00 i 1.00 CLEAN WELL PR1CSG MU top drv, wash to TOL, clean out liner top I PBR 5148 - 5162 ft, no obstruction I emU debris 01 :00 - 01 :30 0.50 CIRC CLN PR1CSG CBU, no cmt I debris to surface 01 :30 - 05:00 3.50 TRIP BHA PR1CSG POH, layout polish mill assy, clear floor. 05:00 - 06:00 1.00 TRIP BBHD PR1CSG MU 6" drill out assy, BHA #5 4/25/2004 06:00 - 07:30 1.50 TRIP BBHD PR1CSG Cont MU BHA #5 (6" drill out assy) 107:30 - 12:00 ¡ 4.50 TRIP BIT I PR1CSG Follow BHA with 5" DP to tag at 5530 ft 12:00 - 18:30 6.50 DRILL ICEMT PR1CSG Drill cmt I float equip to 5665 ft. ( Ldg collar 5590, Float collar 5632) Printed: 4/23/2005 3:10:39 PM ) ) . . Hl::CI::IVI::LJ M th Q·'I·C·· ... .... .. .. ..... . Page4of6 ....araonl. ompany,... APH 27 2005· . ,Operations Summary Report .., .... ,. ...., Alaska 011 ö(h~~s tens. CommiSSion KENAI UNIT 31-7X ¡JjIJcborûoe KENAI UNIT 31-7X Spud Date: 12/26/2000 WORKOVER Start: 4/13/2004 End: GLACIER DRILLING Rig Release: 1/16/2001 Group: GLACIER DRILLING Rig Number: 1 Frorn- To Hours CÒdé c3'~dbe Phase Description of Operations Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date 4/25/2004 12:00 - 18:30 18:30 - 22:00 22:00 - 23:00 6.50 DRILL 3.50 CIRC 1.00 TEST CEMT PR1CSG CLN PR1 CSG Circ clean. CSG PR1CSG PJSM, test 7" csg I liner lap 1500 psi I 30 min, no test. Bleed 1500 - 1050 psi 30 min 23:00 - 00:00 1.00 TRIP CSG PR1CSG Inspect surface equip, replace chart sensor diaphragm 00:00 - 01 :00 1.00 TEST CSG PR1CSG Re-test, 1500 psi I 30 min. test successful. 01 :00 - 06:00 5.00 TRIP LDDP PR1CSG PJSM, POH laying dn 5" DP. 4/26/2004 06:00 - 07:00 1.00 TRIP LDDP PR1CSG Cont lay dn 5" DP 07:00 - 08:30 1.50 TRIP BBHD PR1CSG Layout BHA #5 08:30 - 09:30 1.00 TEST WEAR PR1CSG Pull wear bshg, Change out rams to 7", install test plµg. 09:30 - 10:30 1.00 TEST BOP PR1CSG Test BOP I door seals, test successful 10:30 - 11 :00 0.50 CSG RUN CMPRUN Perform pre-landing csg hgr, mark I record strap 11 :00 - 12:00 1.00 CSG RUN CMPRUN PJSM, Place Weatherford equip rig floor, rig up same 12:00 - 20:30 8.50 CSG RUN CMPRUN Commence RIH 7" completion as follows: Mule shoe, seal subs, pup, 135 jts csg (26#, L80, BTC mod) Sting in PBR, space out, add pups, install hgr. 20:30 - 21 :30 1.00 FLUID DPLC CMPRUN Displace 7 X 9 5/8 annulus to Concor inhibitor 21 :30 - 22:00 0.50 CSG RUN CMPRUN Land hgr, run lock dn screws 22:00 - 23:00 1.00 TEST CSG CMPRUN Test 7 X 9518 annulus 1500 psi I 30 min, test successful 23:00 - 23:30 0.50 CSG RUN CMPRUN Lay dn Idg jt, clear rig floor 23:30 - 04:00 4.50 NUND BOPE CMPRUN PJSM, Flush lines I BOPE, nipple dn BOPE 04:00 -06:00 2.00 NUND TREE CMPRUN Install prod tree, prepare for tree test. 4/27/2004 06:00 - 07:00 1.00 NUND TREE CMPRUN Finish install tree. Test void to 3000 psi for 10 minutes. Test tree to 3000 psi for 10 minutes. Pull TWC valve, install BP valve. 07:00 - 12:00 5.00 RIG RDMO RDMO LID choke hose & kill hose. RID rig floor. Clean T/D. Remove tarp on service loop. Clean hoses 7 inspect same. LID tongs 7 subs. Clean rig floor. Clean mud pits. 12:00 - 00:00 12.00 RIG RDMO RDMO Clean mud pits. Clean & wrap service loop. Change oil & service T/D. Change out #1 mud pump suction screen. Change oil & change rod bearings in #1 mud pump. RID top drive & torque tube. Finish clean mud pits. 19:12 - 19:35 0.38 Release rig to Scheduled Maintenance @ 00:00 hrs 4/27/2004. RU CT on tree. Held PJSM and discussed well procedure. Continue making up unit to tree. Brought out Vac truck to move liquid for pressure testing the reel, BOPS and make sell test. Tested BOP's to 250 psig low pressurel 2500 psig high pressure. Small leak off from swab valve and upper master to well bore. No leaks on surface iron. Tested good. Open well to coil. RIH to 1000 CTM. Sarted N2 at 350 SCFM. CT at 980' CTM. Continue down hole with coil. Coil sat down at 5663' KBD. PU Coil to 5645'. Started N2 rate at 750 SCFM. Good returns to open top tank. WHP= 1490 psig, N2 total= 63025 SCF. N2 rate at 750 SCM. Flow back tank has 87.5 bbls returned to tank Continue to pump N2 at 750 SCFM, while Coil at 5647', good steady returns to tank. Return fluids 207 BBLS to Flow back tank. WHP= 2161 psig. ,N2 pumped = 185, 674 SCF ¡WHP= 2191 psig, total N2= 194, 640 SCF. N2 pump reate at 750 SCFM. CT at 5648', returns good to flow back tank. WHP= 2160 psig, returns to flow back tank= 228 BBLS, total N2= 209, 5/26/2004 07:00 J'13:30 6.50 13:20 - 15:38 2.30 15:38-16:30 I I 16:30-18:50 I 0.87 2.33 I I I 18:50 -19:12 0.37 Printed: 4/23/2005 3:10:39 PM ) ) Start: 4/13/2004 Rig Release: 1/16/2001 Rig Number: 1 REC.EI\JiIDöf6 APR27Z005 ^Iasko Oil & Gas Cons. Commission Anchoraoe Spud Date: 12/26/2000 End: Group: Mar~thon>Oil QOrT1pany ·Øperati.ons·....·~·LJ I11rnaryReport Date KENAI UNIT 31-7X KENAI UNIT 31-7X WORKOVER GLACIER DRILLING GLACIER DRILLING O d Sub Frorn - To ' Hours 0 eCOde Phase Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: 5/26/2004 19:12 - 19:35 0.38 19:35 - 19:55 0.33 19:55 - 20:00 0.08 20:00 - 20: 1 0 0.17 20:10 - 20:20 0.17 20:20 - 22:30 2.17 8/24/2004 8/25/2004 07:30 - 08:00 0.50 LOG_ CSG_ CMPPRF 08:00 - 08:45 0.75 RURD - ELEC CMPPRF 08:45 - 09:15 0.50 PULD - LOG - CMPPRF 09:15 - 10:45 1.50 LOG - CSG - CMPPRF 10:45 - 11 :00 0.25 PULD - PGUN CMPPRF 11:00 -11:30 0.50 RUNPUL ELEC CMPPRF 11 :30 - 12:00 0.50 LOG - CSG CMPPRF 12:00 - 12:45 0.75 RUNPUL ELEC CMPPRF 12:45 - 13:00 0.25 PULD - PGUN CMPPRF 13:00 - 13:30 0.50 RUNPUL ELEC CMPPRF 13:30 -13:45 0.25 LOG_ CSG - CMPPRF 13:45 - 14:30 0.75 RUNPUL ELEC CMPPRF 14:30 - 14:45 0.25 PULD - PGUN CMPPRF 14:45 - 15:15 0.50 RUNPUL ELEC CMPPRF 15:15-15\30 0.25 LOG - CSG - CMPPRF 15:30 - 16:15 0.75 RUNPUL ELEC CMPPRF 16:15 - 16:30 0.25 PULD - PGUN CMPPRF 16:30 - 17:00 0.50 RUNPUL ELEC CMPPRF 17:00 -17:15 0.25 LOG - CSG - CMPPRF 17:15 - 18:00 0.75 RUNPUL ELEC CMPPRF 18:00 - 19:00 1.00 RURD - ELEC CMPPRF 9/10/2004 07:30 - 08:30 1.00 SAFETY MTG - CMPPRF 08:30 - 14:00 5.50 RURD - ELEC CMPPRF I 14:00 - 14:45 0.75 PULD_ PGUN I CMPPRF 14:45 - 15:45 1.00 RUNPUL ELEC CMPPRF 15:45 - 16:00 0.25 LOG - CSG - CMPPRF ,16:00 - 16:30 0.50 RUNPUL ELEC CMPPRF I I 116:30 - 16:45 0.25 PULD PGUN ! CMPPRF I 16:45 - 17:20 0.58 RUNPUL ELEC CMPPRF DesçriþtiOn Öf Opérations 900 SCF. N2 at 760 SCFM. POOH with coil, WHP= 2140 psig, Total N2= 220,600 SCF, Coil at 5340' PIP= 7 psig, CTW= 7890 Ibs. CT @ 4330' WHP= 2084 psig, PIP= 26 psig, start choking back on choke. CTW= 3880 Ibs. Total N2= 231, 200 SCF. SD N2. Continue POOH with coil. Total N2 pumped= 232,800 SCF. WHP= 2017 psig, CT @ 3690'. PIP= 40 psig. 24" left in F.B. tank. total bbls = 252 bbls. ' CTat 2590' , WHP= 1876 psig, PIP= 100 psig, POOH at 155' PM. PIP coming up, PIP= 1002 psig, still slight returns to tank. OOH with coil, shut in choke, WHP= 1690 psig, 266 bbls in flow back tank. RD coil. Attempted to run correlation log. Had trouble getting CCL to read. Once CCL was working, GR match was difficult to make through two string of pipe. Plan to discuss correlation in AM. Meet and discuss correlating log obtained yesterday. Compare to additional well logs from filè. Elect to re-run correlation due to poor quality log obtained through two strings of casing. Rig up 3rd party 7" lubricator. Pwh=150psi (N2 pressure remaining from jet-out) PU slim hole logging tool (scintillation counter expected to give better GR readings) Log perforating depth to obtain correlation. PU perforating gun #1. 21' total length (2x 10' tandem, missing l' of perfs in middle). , RIH wi gun #1 to perforation depth Correlate and pull into firing position. Attempted to fire w/o success. POOH wi gun. At surface, exchange firing head on tandem gun. Re-run gun #1. Correlate gun on depth and successfully perforate 5609'-5630' POOH wi gun. Carrier was wet. Pwh unchaged at 150psi PU gun #2 Run in hole with gun #2. Correlate and perforate with positive indications from 5588'-5609'. POOH with carrier. PU gun #3 Run in hole to depth. Correlate on depth and perforate 5572'-5588' POOH wi carrier #3. Rig back for night Arrive on location. Obtain work permit and hold safety meeting. Begin rig up. Open jumper gas to tree from sales. Remove wellhouse and pickup manlift. Struggle to find appropriate hammer wrenches. Pickup combi-bolts for 7" 3M x 7" 5M cxn. Flange up to wellhead. Arm 29' 3-3/8" perforating gun #1 wi PX-1 SAFE detonator. RIH to depth with gun. Pwh=370psi Uumper gas) Correlate guns to depth and pull into firing position. Perforate 15601 '-5630'. POOH wi spent carrier. At surface, gun appears black and charred. Completely dry. Pwh=370 psi (unchanged) Arm and PU perforating gun #2 wi SAFE detonator. RIH with gun to flag depth. Printed: 4/23/2005 3:10:39 PM ') ) RECE'VEÐe'60f6 APR 27 2005 k 0·,' & Gas Cons. Commission A\as a , Spud Affthnr8gJ26/2000 Start: 4/13/2004 End: Rig',Release: 1/16/2001 Group: Rig Number: 1 Marathqn<Oil. Cornpany 'Operations ··Su.mmar~'·R~port Legal Well Name: KENAI UNIT 31-7X Common Well Name: KENAI UNIT31-7X Event Name: WORKOVER Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING DatE} From~TQ Hours Code Sub Phase Code 9/10/2004 17:20 - 17:30 0.17 LOG CSG - CMPPRF 17:30 - 18:00 0.50 RUNPUL ELEC CMPPRF 18:00 - 18:15 0.25 PULD - PGUN CMPPRF 18:15 - 20:30 2.25 RURD - ELEC CMPPRF 9/16/2004 07:30 - 08:30 1.00 SAFETY MTG - CMPPRF 08:30 - 10:00 1.50 RURD - ELEC CMPPRF 10:00 - 10:30 0.50 PULD - PGUN CMPPRF 10:30 - 11 :30 1.00 RUNPUL ELEC CMPPRF 11 :30 - 12:00 0.50 LOG - CSG_ CMPPRF 12:00 - 13:00 1 :00 RUNPUL ELEC CMPPRF 13:00 - 13:15 0.25 PULD - PGUN CMPPRF 13:15 - 13:30 0.25 LOG - CSG - CMPPRF 13:30 - 14:30 1.00 RUNPUL ELEC CMPPRF 14:30 - 17:00 2.50 RURD - ELEC CMPPRF Description of Operations Correlate to collars and perforate gun #2. 5572'-5601'. POOH wi gun #2. Pwh=375psi. At surface, lay down second gun., Spent gun carrier covered in residue had some sand and water. Rig down equipment and depart Arrive at KGF. Obtain work permit. Discuss procedure. PJSM. Spot equipment and begin RU on KU 31-7x. Well flowing from C-2 perfs about 300MCFD to low P system Pwh=70psi. PU gun #1. 40' tandem wi CCL and lubricator. RIH wI perf gun to approximate depth. Correlate at ZXP packer. RIH and PUH into firing positon. Perforate entire C-1 zone 5330'-5370' (6spf, 60 deg phase) with good indication. Immediate rate to test separator of 3MM wi 138psi at wellhead. POOH wi spent carrier. Rate increased to wi same WHP. Change orifice plate at test separator. Well flowing at 4.8MMcfd at 11 Opsi. PU 40' gun #2. RIH to same depth. Correlate and fire same zone 5330'-5370'. See immediate rate response in test separator. Increase rate to 5.2MMetd with pressure increase to 116psi. POOH wi perf gun. Route production out of test separator due to excess backpressure at 4" meter run. At surface with spent carrier #2. LD guns. Rig down equipment and secure well for night. Well flowing through 8" flowline at 7.3MMetd @ 87psi. Printed: 4/23/2005 3:10:39 PM Kenai Gas Field Well: KU 31-7x Pad 14-6 KB: 21' RB to GL API: 50-133-20495-00 ) 1······,7.,i ~r: >I~ .' ; ,; . ..'" 'J ~.,..'...~.: ····',!·~.·'··.·.I·,'·.·'···'·~.'.. ;1" ~' .,'. ~." Ii.: ~'" ,,~ ,.,) i~i ~~ !.",'".'.Ii.·.,.'.·:··.'··.·'............,. iII:¡iI1!:!I" ~, I ~':: ' :;(t ~~ I· II':' ~~ ~ ~f ;\j~ ! ~ !; I ! ~~ ~.~ ï ;~ ~ ~ ~.. i, 17" 26 ppf modified buttress casing PBTD 7" 5663' TD=5678' ) RECEIVED AA~~ 7 Z005 \~ Cons. Commission " A chorage I" 120" OD 133 ppf K-55 DP @ 114 ft ~i '~Î~ 11.·..,1 ~ ;:~~: ~~:1-68 ppf K-55@1508ltMDcmfdin r ~ ~ .~ It. I I I I ~ ~; ~ ~ 7" by 9 5/8" Liner Hanger and ZXP Packer, minimum 6.00" ID @ 5150' Pool 6, C-1 Peñs: 5330-5370' MD 4433'-4460' TVD 12 spf, 60 degree phase (2 runs wI 3-3/8" HSC 6spf) Pool 6, C-2 Peñs: 5572-5630' MD 4598-4637; TVD 12 spf, 60 deg phase (4-1/2" HSC 6spf + 3-318" HSC 6spf repeñ) Apr-OS-05 02:39pm , From-MARATHON OIL ) +915564648Ð T-655 P.Ol/02 F-111 Alaska ASSb') eam Marathon on Company ~s P.O. Box 196168 .C12/~ Ancho(age, AK 99519-61ea ¡¡Ph ,,' "~l' Telephone 907/561.5' IT ... t",J Qf,~ G ZOOS FAX COY" E"R LE,~" E~, "~""""""""\,,~,,,,..,~lIJ:$' I>"'e; ~~v T '" ':1 ... - ..- .-. -.... ..... ., _..- ··n..n. __ . I I. DA~~,: Lf A~I fl~~' :f:d.SGr;:;. _,." ,. PLEASE DELIVER. THE FOLLOWING TO: N- ..~--.-. ...-. . ... . Name:.. Jì ~ R.2jj ~, ~.~mpan!:, ,4f16_ r ë _", " Fax No.: ;).,.7{g- 75'12- Number of Pa'Jes (inc::ludingcover page): ~ -...-.-...,., ". ----- .... FROM: ~~~~~~fo~~~~~~~07~ S~:i~303' -.- ---." -_.....~---' .- NOTE: -....-...-- .-....--" . JJI1!1 -- n_., I l~a--ÎL-J¡1A-<J_~ of t~ WßÞ_df>l.Uf5-t#· L~AÆJ¿; .., ' GIÍ.~J"'~-Ij ~ .. .".""-,.,,, ".. ...---.- -------. . ..u_.,~GANNEr: tí PI) '" . ·2Gor~ -. ' . W \I ~ '::~ ' 'J , ----..-.., -- ... -. . ... .--.----., . _--wt~- If transmission is not complete, please call 907/561-5311 Apr-Oe-05 02:39pm From-MARATHON 0 II.> ) Kenai Gas Field Well: KU31·1x , Pad 14·6 KB: 21 RB to c;L API: 50-133-20495..00 - - - 17" 26 ppf m~i bl~~ess -èásing 7" 26 ppfmõdi1iãd1üttress Îiner . cemented in plaCE! .........--- .... PI~Tb r 5655' (float collar @ 5632') ~e.sI8'1 OD 40 ppf Lo8Ö «D 5787' Me I çm1'd i~ 12-1/4" HOIQ , .. +9155646489 ) T-655 P.02/02 F-111 M IUlATlOII 1 _.., ~ [~,~" OD 13~ PPf'~-55 DP @ 114_~ 13~3/8" 00' a 1-68' ppf K~5~' @ 15Ò8 ft MD ¿-m1'd in' 17-1/2" Hole ?,''l:>ÿ 9 5/8" L.iner I-ïanger and ZXP 'Packer, minimum 6.00" ID @ 6150' pooi' 6, C-1 peñS: 5330-5370' -MD 4433'-4460' TVD 12 spf. 60 (h~grne pha5Et (2 runs wi 3..3/8" HSC 6spf) Pool 6. C-2 Perfs: 5572·5630' MO 4598-4637; TVD 12 $pf, 60 deg phasa (4~1/2" HSC 6¡¡¡pf + ~3/8" HSC 6spf reperf) ~:- ~~...-r~J ...-. .."-'7\. ... ~, . . . . - . MICROFILMED 04/01/05 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:\LaserFiche\CvrPgs _ Inserts\Microfilm_ Marker.doc ~ ~oo " I 4~ " Winton, In the process of working over KU 31-7x, we have reason to suspect casing problems at our C-1 perforations. Because this is a primary wellbore objective, we would like to ensure pipe stability in this zone. Our initial completion proposal was to land 7" tailpipe between the C-1 and C-2 perfs. Our new proposal is to run the 7" to TD and to pump cement around the backside. The 7" will be tied back to surface at the liner hanger and packer as originally planned. Please give me a call if you have any questions or comments regarding this proposed change. Thanks, Denise Titus Marathon Oil Company 907-564-6303 907-394-1324 «ku31-7x 7inch proposed WBD.xls» «ku31-7x 7in proposed WBD cementxls» : Content-Description: ku31-7x 7inch proposed WBD.xls I ku31-7x 7inch proposed WBD.xls I Content-Type: application/vnd.ms-excel ¡ : Content-Encoding: base64 ------ - - ---- - - - - -- - -- - - -------~-- - - ---- - ------ - --- --- - - - --- -- ----- -- ------- --------------------- --------------------- ------- ---------- - - - - - ------ .ku31-7x 7in proposed WBD cementxls Content-Description: ku31-7x 7in proposed WBD cementxls Content-Type: application/vnd.ms-excel Content-Encoding: base64 -- ------------ ___On ---- -- - - -- ---- - -----_u_----------- _n____- --------- - ---------- ---- ----- - -- u- - -------. ~.. Kenai Gas Field Well: KU 31-7x Pad 14-6 KB: 21' RB to GL API: 50-133-20495-00 Proposed 7" Casing/Tubing completion. 9-5/8" 00 40 ppf L-80 @ 5767' MO cmfd in 12-1/4" Hole ~ 120" 00 133 ppf K-55 OP @ 114ft 13-3/8"" 00 61-68 ppf K-55 @ 1508 ft MO cmfd in 17-112" Hole Pool 6, C.1 Peñs: 5330-5370' MO 4433'-4460' TVD 17" 26 ppf modified buttress casing 14.562" PX Profile Nipple @ 5530' Pool 6, C.2 Peñs: 5572-5630' MD 4598-4637; TVD Well Name & Number: I KU 31-7X I Lease: County or Parish: Kenai Peninsula Borough I State/Provo AK I Country: IUSA Peñorations (MD) (TVD) Angie/Perfs I Angle @ KOP and Depth IBHP: I I 1400 BHT: I I Comoletion Fluid: I Dated Completed: I Kenai Gas Field Well: KU 31-7x Pad 14-6 KB: 21' RB to GL API: 50-133-20495-00 Proposed 7" Casing/Tubing completion. 9-5/8" OD 40 ppf L-80 @ 5767' MD cmt'd in 12-1/4" Hole , 20"OD133PPfK-55DP@114ft 13-3/8"" OD 61-68 ppf K-55 @ 1508ft MD cmt'd in 17-1/2" Hole . , Pool 6, C-1 Peñs: 5330-5370' MD ..."" ..- 4433'-4460' TVD 17" 26 ppf modified buttress casing I 4.562" PX Profile Nipple @ 5530' Pool 6, C-2 Peñs: 5572-5630' MD 4598-4637; TVD Well Name & Number: I KU 31-7X I Lease: County or Parish: Kenai Peninsula Borough I State/Provo AK I Country: IUSA Peñorations (MD) (TVD) Ang!efPerts I Angle @ KOF' and Depth BHP: I I 1400 BHT: I I Completion Fluid: Dated Completed: I r"\ r'\ ~ M ~ Marathon MARATHON Oil Company Alaska Business Unit Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 , April 7, 2004 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W yth Ave Anchorage, Alaska 99501 RECEIVED APR - 8 2004 Reference: Application for Sundry Approvals Field: Kenai Gas Field Well: KU 31-7X Alaska Oil & Gas Cons, Commission Anchorage Dear Mr. Aubert: Enclosed is the 10-403 Application for Sundry Approvals for Marathon well KU 31- 7x. r' The proposed work is optimize production by pulling the current 3.5" tubing and packer completion with annular production and replace it with a 7" 26 ppf casing string with packer for production tubing. Modeling indicates 7" casing for production tubing may allow the well to sustain unload rates with maximum deliverability. /' Due to height limitations we will drop the single gate off our normal BOPE stack as This well produces from the C-1 and C-2 Sterling Sands with a very low BHP of 197 psi. --A normally pressured reservoir and a methane gradient to surface would produce a surface pressure of 1750. /' The Glacier Drilling Rig # 1 will commence work after completion of the KBU 11-8X well in the Kenai Gas field pending your approval. If you need any additional information, I can be reached at 907-283-1333 or bye-mail at DEEynon@MarathonOil.com. Sincerely, lÀM f--- Donald Eynon Production Engineer Enclosures BOPE Sketch Sundry Application Detailed Procedure Current wellbore diagram Proposed wellbore diagram 0 RIG I N A L 1. Type of Request: Abandon U Suspend U Operational shutdown U Perforate U . Waiver U Annular Dispos. U Alter casing 0 Repairwell 0 Plug Perforations 0 Stimulate 0 Time Extension 0 Other 0 Change approved program 0 Pull Tubing 0 Perforate New Pool 0 Re-enter Suspended Well 0 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Marathon Oil Company Development 0 Exploratory 0 200-148 / 3. Address: Stratigraphic 0 Service 0 6. API Number/, PO Box 196168, Anchorage, Alaska 99519-6168 50-133-20495-00 7. KB Elevation (ft): 9. Well Name and Number: KB 87' Elevation from MSL KU 31-7X /' 8. Property Designation: 10. Field/Pools(s): A-028142 Kenai Gas Field, Sterling Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 5790 4749 5682 4673 N/A NIA Casing Length (ft) Size (inch) MD (ft) TVD (ftr Burst (psi) Collapse (psi) Structural Conductor 93 20 93 93 N/A N/A Surface 1508 13318 1508 1483 3090 1540 Intermediate Production 5690 9518 5690 i 4679 5750 3090 Liner Perforation Depth MD (fth Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 3~ 4433 3.5" L-80 4907' Packers and SSSV Typ~ Packers and SSSV MD (ft): Baker Model D 4406' 12. Attachments: Description Summary of Proposal U 13. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0 Service D 14. Estimated Date for APril~004 15. Well Status after proposed work: Commencing Operations: Oil 0 Gas 0 Plugged 0 Abandoned 0 16. Verbal Approval: Date: WAG 0 GINJ 0 WINJ 0 WDSPL D Commission Representative: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Donald Eynon Title Petroleum Engineer Signature .L1. ,9..-1' ...?/. Phone 907-561-5311 2~-/?37 Date q-/-¡/~ ~ /' COMMISSION USE ONLY / Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 301- //~ Plug Integrity D BOP Test 0 Mechanical Integrity Test D Location Clearance 0 Other: rl~{.,£ h-O~fv¡ ~ r!o",^~ ~~.~ w~ pwf j £(~ tt.l' e.. Vß~e9á'.VED APR - 8 2004 SubsequentFor~re . I" 40 tf Alaska Oil & Gas Cons. Commission OQtG1NAL Anchorage ~ Deie I/¡;;/o~ ~/' BY ORDER OF Approve 'll' ~ COMMiSSiONER THE CûiviiviiSSiûN F~-40~ ~d 12/2003 INSTRUCTIONS ON REVERSE S~bmit{n DuPI;cate STATE OF ALASKA ALASv-1IL AND GAS CONSERVATION COMMIr"\:)N . APPLICATION FOR SUNDRY APPROVAL 20 AAC 25.280 IN- "'t""' "t I , ) I ¿.,.IHl"'t ()/:j +1 );)J ~ RBDMS BFL Aft t4 200\ r---.. /'\ Marathon Oil Well KU 31.7X WO BOP Stack I Flow Nipple I -----. ¡Flow Line I 13 5/8" 5M Annular Preventer / ~ 13 5/8" 5M Double Ram Preventer 12.875-5.5" VBR I / ------. 21/16" 5M Manually Operated Valves ¡Blind Ram I / 31/8" 5M Hydraulically Operated Valve ~~ [IJ1]IIII0J]J[JI0]] Œ[] 1135/8"5MCross I ~ I Choke I JI OJ@II][JI0]] t 31/8" 5M Manually ~ Operated Valve 113 5/8"3M Tubing Head 135/8 5M by 13 5/8" 3M DSA Blow Out Prevention Equipment " ~ Well KU 31-7x Pad 14-6 Current Completion 4/7/2004 / 'yo Block Pool 3 Perfs: 4110-4130'MD\3644'-3657'TVO 4182-4222'MD\3689'-3715'TVO Punch Tubing Shear out Ball Sub @ 4907' 3 1/2", 9.3ppf, L-80 tubing 9-5/8" 00 40 ppf L-80 @ 5767' MO cmt'd in 12-1/4" Hole ::., : " . o°'L r..'!" ] .", i.~ "'11 ;j '~ r"\ ~ 120" 00 133 ppf K-55 OP @ 114 ft 13-3/8"" 00 61-68 ppf K-55 @ 1508 ft MO cmt'd in 17-1/2" Hole Sliding Sleeve for 3-1/2" tubing w/2.813" 10 @ 4329' ~ ¡Baker Permanent Packer Set @ 4406 ..:; , 'o!:; ;t. '.;" ,~~ I ;J,; 2.813" 10 'X' nipple @ 4458 ~~~ j¡¿~ ;l,~ þ' ~.~ ~;. ii; '" ,.. Jt #151 perforated wI 110 tubing punch holes 4465'-4492' 0.3" entrance, 4spf, Odeg phase :.,: "" ,"'1 '- , ~?~)c-l " Pool 6, C-1 Perfs: 5330-5370' MO oj: 4433'-4460' TVO' .," ~." .'. " ", Pool 6, C-2 Perfs: 5572-5630' MO 4598-4637; TVO .< . 'r' '..' '::~ " r"\ ~ / ~ ~ Kenai Gas Field Well: KU 31-7x Pad 14-6 KB: 21' RB to GL API: 50-133-20495-00 120" OD 133 ppf K-55 DP @ 114 ft Proposed 7" Casing/Tubing completion. 13-3/8"" OD 61-68 ppf K-55 @ 1508 ft MD cmt'd in 17-1/2" Hole .., ;¡.'. ..; ,." " 17" 26 ppf modified buttress casing / Pool 6, C-1 Perfs: 5330-5370' MD 4433'-4460' TVD ./ 14.562" PX Profile Nipple @ 5530' "-, :.! .', ., "~' Pool 6, C-2 Perfs: 5572-5630' MD 4598-4637; TVD 9-5/8" OD 40 ppf L-80 @ 5767' MD cmt'd in 12-1/4" Hole :' .. Well Name & Number: I KU 31-7X I Lease: County or Parish: Kenai Peninsula Borough I State/Provo AK I Country: IUSA Perforations (MD) (TVD) Angle/Perfs I Angle @ KOP and Depth IBHP: I I 1400 BHT: I I Completion Fluid: I Dated Completed I .' r'\ r"\ Marathon Oil Company Alaska Region KU 31-7X Kenai Gas Field, Pad 14-6 Workover Procedure History: KBU 31-7 was originally drilled as a Annular Producer with one 3.5" EUE 8rd string for pool 6 production and 33/8" Y-block guns across the pool 4 interval to be shot if needed. /' The y-block guns were never fired and are still live on the annulus. /' Objective: Pull current 3.5" tubing completion and run 7" casing/tubing completion to allow high rate production. Procedure: 1. Contact Kenai Gas Field Office daily for work permit, discuss safety and environmental concerns. 2. Remove flow lines to storage and PLC control panel to the electrical shop. 3. Contact ABB Vetco wellhead representative, bleed off strings to flow back tank and top off with 50/50 methanol. Set BPV (3" type "H") in the tubing hanger and 4" VR plug in the tubing head annulus valves. 4. MIRU Glacier Drilling rig #1. a. Remove BPV and pump high viscosity Flo-vis pill with sized Calcium Carbonate in 3 % KCL brine to seal off sands with permeability of 347 md. Pump adequate pill to isolate all sands in first attempt. While bull heading and circulating well DO NOT allow well to build pressure, circulate down 3.5" production tubing, constantly monitor pump pressure to ensure WHP does not exceed 1000 psi. This well has very low BHP <300 psi. Y-Block perforating guns are set-up to fire ~ 2440 psi applied surface pressure with casing full of3% KCL on the annulus. Circulate well to remove all trapped gas. Install two way check. b. ND tree. Inspect and verify hanger threads are 312" Buttress, 312" Buttress landing joint approx 22' long will be needed.) (13 5/8" 3M by 13 5/8" 5M DSA is needed to NU 13 5/8" stack, Weatherford verified availability 3/25/2004) NU 13 5/8" 5M Weatherford BOPE equipped wit~ 7/8" -5.5" VBR 5M rams in upper ram cavity, and test BOPE to 75/2000 psi. Pull two way check. 5. Rig up Weatherford Tubing services with 3 12" x 2 7/8" dual slips, single 3 12" elevators and hydraulic tongs for single string. Dual equipment and a dog collar for 3 3/8" OD is needed to lay down 120' long Y-block perforating assembly. ~ ~ 6. RU Alaska Pipe Recovery Service. Packer was set with anchor seal assembly. Tubing will need to be jet cut to allow retrieval. a. RU lubricator with pump in sub and pack off. RIH with free point tool and utilize to establish free point. b. RU jet cutter with lubricator, pump in sub and pack off. c. Rill with 2.70" jet cutter and severe 3.5" tubing based on free point analysis and fishing hand recommendation. (If free to packer BOT recommends leaving 20' of first full joint above packer in the hole to aécommodate overshot, do not anticipate tubing to be stuck above sliding sleeve, well has produced out of if annulus and Y -block guns have never been fired.) 7. TOOH laying down tubing while checking for NORM. 8. Install wear bushing in Vetco Gray multi-bowl. 9. PU the following recommended fishing assembly after consultation with fishing hand on location: 8 1/8" 150 Overshot wi Double Bowl w/3 Yz Grapple & MCP 8 1/8" Top Extension 61/4" OD Bowen Bumper Jar 6 1/4" OD Bowen Oil Jar 6 1/4" Drill Collars with 5" drill pipe to surface. Wash over jet cut. A Baker size 80-40 E anchor attaches 3.5" tubing to the Baker SB-3 packer, 8 to 12 turns at the tool will release the anchor. POOH anchor and fishing assembly. 10. Rill with fishing assembly as per Baker fishing hand recommendation o~dril1 pipe, to mill up 9 5/8" SB-3 packer size 194-40. (Packer dimensions are attache~ p~ocedure; confirm PRT spear needed to pluck packer.) Recommended assembly as follows: 8 1/2" MM Mill wi 3 1/8 PRT Spear wi 4" Grapple w/5.3' ofExt. Tripp1e Conn. Sub 3- 7" OD Boot Col1ar Baskets 1- 4 1/2" Reg Box x 4 1/2" IF Box Sub 1- 61/4" OD Bowen Bumper Jar 1- 61/4" OD Bowen Oil Jar 12-18 6 1/4" OD Drill Collars 1-6 1/4" OD Bowen Acc Jar a. Establish pick up and slack offweights prior to commencing milling operations, correlate drill pipe to packer top measurements (packer depth was correlated to open hole e-line depths.) b. Mill packer per BOT recommendations, after packer moves Till and push packer a minimum of 30' prior to picking up and POOH. . c. Lay down packer and tailpipe while checking periodical1y for naturally occurring radioactive material. ~ r"\ 11. Rill with 8.5" bit and casing scraper with in line magnets to pick up additional metal cuttings on 5" drill pipe to top offill. Circulate well clean to 5682' with 3% KCL. 12. RU Weatherford with hydraulic tongs and slips for 7" casing. 13. Prepare to run the following 7" casing completion (cxn 7" modified buttress): Please see attached Baker Oil Tools running procedure and equipment requirements. a. 7" wire line re-entry guide. b. 7" buttress pin by 5 W' buttress box changeover. c. 5 W' buttress box by pin 4.562" ill X nipple.(May be run with PX plug in place.) d. ~" dified buttress box by 5 W' buttress pin changeover. e. 30' of 7" modified buttress casing. ,,/ f. ' by 9 5/8" liner hanger, ZXP liner hanger packer and tie back extension on hydraulic setting tool with 5" drill pipe. g. Establish PU and SO weights when approaching packer setting depth. Set packer with wire line re-entry guide at 5530' and bottom ofliner hanger above 5230' . h. Apply 3000 psi to drill pipe to set liner hanger and ZXP packer, release liner running tool. i. POOH laying dpWll drill pipe~ , ". I 1 t ~ CJ~.QA.\~ "g {<.. TO ClCU?ÍI'1~~Î~ 1 t£t c:;~ "1. ~ fe So 14. MU bullet seals for BOT tie back sleeve to 7" modified buttress casing. a. Rill with 7" buttress casing. b. Establish PU and SO weights when approaching packer. c. Circulate into packer to establish seal insertion. d. Tag top of tie back and mark pipe to space out casing. e. Lay down required joints of casing and PU subs and hanger to casing in Vetco Gray multi-bowl. f. Test void in hanger to 2000 psi. g. Test 7" by 95/8" casing annulus to 1500 psi. v-ltlr to ~OOO rçi. 15. RU Pollard slickline. a. Rill with 4.562 " PX plug on running tool. b. Rill with prong to isolate plug. c. RDMO Pollard wire line. 16. Set BPV and nipple down BOPE. 17. NU bonnet and 7" 3M master and secondary master. 18. Pull BPV, set two way check, PT to 2000 psi. 19. RDMO Glacier Rig # 1 20. RU ABB Vetco, pull BPV. '- ¡I""""-.. ~ 21. RU changeover/CT hanger spool from 7" 3M to 41/16" 10M above 7" tree valves. 22. RU flow back tank, 2" chiksan and choke skid for CT operations. 23. RU BJ services to tree. a. RU CT with 41/16" 10M BOPE stack and 1.75" CT. b. PT BOPE to 7512000 psi. c. MU BHA with no check valves to reverse circulate out 6% KCL. d. Rill to PBTD, reverse circulate out by pumping nitrogen down CT annulus. e. POOH, pressure up on wellbore leaving 250 psi of nitrogen on casing. £ RD BOPE to 7" master valves. Stand aside BJ Coiltech. 24. RU Pollard slickline services a. RU 7" 3M master valve to Pollard 7" lubricator and BOPE. b. PT lubricator and BOPE to 7512000 psi. c. Rill with PX pulling tool and retrieve PX prong. POOH d. Rill with x-line pulling tool and retrieve PX plug body. POOH. 25. Open well to flow back tank and attempt to flow. lfno flow is obtained a static BHP run may be made and or RU BJ CT and jet in well. When flow stream turns to methane turn well over to production and establish rate. IF flow is unacceptable re-perforate well. 26. MI Expro Americas electric line unit. a. RU 7" BOPE with 51/2" lubricator. b. Pressure test lubricator and BOPE to 7512000 psi. c. Re-perforate C-2 interval with 3 3/8" hollow steel carries at 6 spf. d. Flow test well to production facility recording rates and FTP. e. Re-perforate C-1 interval utilizing 4.5" hollow steel carriers at 5 spf. f. Flow test well to production facility. g. Run BHP gauges to record static BHP. 27. RU changeover/CT hanger spool from 7" 3M to 4 1/16" 10M above 7" tree valves. 28. RU BJ services to tree. a. RU CT with 41/16" 10M BOPE stack and 1.75" CT. b. PT BOPE to 75/2000 psi. c. MU BHA with jetting nozzle and double check valves to jet in well. d. Strap flow back tank to monitor fluid return volumes. Rill to PBTD, jetting in well to flow back tank. POOH 29. RD BOPE to 7" 3M master valves. 30. RD BJ Coiltech. 31. Should the well be unable to obtain a sustained flow rate without loading problems a separate procedure and sundry application will be written for a concentric CT velocity string installation. .' . " '" '" Contacts: Drilling Operations Geologist Reservoir Eng ~ Will Tank Don Eynon David Brimberry Denise Titus ~ Work Phone Pa2er 564-6310 268-4374 283-1337 398-9954 564-6402 529-0527 (cell) 564-6303 394-2733 Permit to Drill 2001480 MD 5790~" -I-VD DATA SUBMITTAL COMPLIANCE REPORT 8/712003 Well Name/No. KENAI UNIT 31-07X Operator MARATHON OIL CO 4749 .-'" Completion Dat 3/31/2001 APl No. 50-133-20495-00-00 Completion Statu 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Sample N._9o Directional Survey DATA INFORMATION Types Electric or Other Logs Run: Well Log Information: Log/ Data Digital Digital Type Media Fret (data taken from Logs Portion of Master Well Data Maint) Name Log Scale Interval Log Run OH / Dataset Media No Start Stop CH Received Number Comments RFT/GR 5 TVD 5 DenlNeulSoniclGRICal TVD GR/CaI/PEX 2 GR/Cal 2 Array Induct/GR/Cal 2/5 Den/Neu/Sonic/GPJCal 2/5 Dipole Sonic Imager 215 -N~'b']I Report FINAL 1248 5782 Case 2/21/2001 09890 CH 2/21/2001 9890 FINAL 4120 5120 CH 2/21/2001 FINAL 1500 5782 CH 2/21/2001 1248-5782 Open Sonic/Mud Log Digital Dat 4120-5120 Color Print 1500-5782 Color Print FINAL 1500 5782 CH 2/21/2001 1500-5782 Color Print FINAL 1500 5782 CH 2/21/2001 1500-5782 Color Print FINAL 1500 5782 CH 2/21/2001 1500-5782 Color Print FINAL 1500 5782 CH 2/21/2001 1500-5782 Color Print FINAL 1500 5782 CH 2/21/2001 1500-5782 Color Print FINAL 2121/2001 Bound copy of Well Report Well Cores/Samples Information: Interval Dataset Name Start Stop Sent Received Number Comments Cuttings 3000 5790 / ~ 3 ~ j ADDITIONAL INFORMATION Well Cored? Y/(~ Chips Received? ~ Analysis ~ R P.c.R. ivP. d? Daily History Received? ~ / N Formation Tops (~/N Comments: Permit to Drill 2001480 MD 5790 ']'VD DATA SUBMITTAL COMPLIANCE REPORT 8/712003 Well Name/No. KENAI UNIT 31-07X Operator MARATHON OIL CO 4749 Completion Dat 3/31/2001 Completion Statu 1-GAS APl No. 50-133-20495-00-00 Current Status 1-GAS UIC N Compliance Reviewed By: Marathon OilCompany Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 9071561-5311 Fax 9071564-6489 May 31, 2001 Tom Maunder State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 1000 Anchorage, AK 99501 Reference: KU 31-7X Dear Mr. Maunder: Attached is a Form 410-407 WELL COMPLETION OR RECOMPLETION REPORT for well KU 31-7X. If you have any questions or need additional information, I can be reached at 564-6302. Sincerely, Don Eynon Production Engineer Intern STATE OF ALASKA .3KA OIL AND GAS CONSERVATION C(~ .... AISSION WELL COMPLETION OR REOOMPLETION REPORT AND LOG 1. Status of Well OILF-1 GAS~] SUSPENDEDF-1 ABANDONEDF] SERVICE~-~ 2. Name of Operator 7. Permit Number MARATHON OIL COMPANY 200-148 3. Address 8. APl Number P. O. Box 196168, Anchorage, AK 99519-6168 50-133-20495-00 Classification of Service Well 4. Location of Well at Surface 320' FSL & 1325' FWL, Sec. 6, T4N, R1 lW, S.M. At top of Producing Interval 734' FNL & 3160' FWL, Sec. 7, T4N, R11W, S.M. At Total Depth 997' FNL & 3366' FWL, Sec. 7, T4N, R11W, S.M. 5. Elevation in feet (indicate KB, DF, etc.) 16. Lease Designation and Serial No. 87' A-028142 I KB 12. Date Spudded 113. Date T.D. Reached 12/25/2000 I 1/10/2001 18. Plug Back Depth (MD+TVD) 5682' MD, 4673' TVD 17. Total Depth (MD+TVD) 5790' MD, 4749' TVD 22. Type Electric or Other Logs Run Density, Neutron, Sonic, Gamma Ray, Caliper, RFT 9. Unit or Lease Name Kenai Unit 10. Well Number KU 31-7X 11. Field and Pool Kenai Gas Field, Sterling Pool 14. Date Comp., Susp. or Aband. 15. Water Depth, if offshore 16. No. of Completions 3/31/2001 I N/A feet MSLI one 19. Directional Survey 120. Depth where SSSV set 121. Thickness of Permafrost 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD CASING SIZE WT. PER FT. GRADE TOP BOTTOM HOLE SIZE CEMENTING RECORD AMOUNT PULLED 20" 133 K-55 0 93' Driven Driven N/A 13 3/8" 61-68 K-55 0 1508' 17-1/2" 514 sks N/A 9 5/8" 40 L-80 0 569o' 12 1/4" 1150 sks N/A N/A 25. TUBING RECORD 24. Perforations open to Production (MD+TVD of Top and Bottom and interval, size and number) MD TVD Sterling C-1 5330 - 5370 6SPF (03/06/01) 14433-4460 Sterling C-2 5573 - 5630 6SPF (03/06/01) 1 4598-4637 SIZE DEPTH SET (MD) PACKER SET (MD) 3 1/2" 9.3# 4907' 4406' 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED 27. Date First Production 1-Apr-01 Date of Test Hours Tested 4/7/2OO 1 24 Flow Tubing Pres. 127 psia Casing Pressure N/A 28. none PRODUCTION TEST I Method of Operation (Flowing, gas lift, etc.) flowing IPRODUCTION FOR TEST PERIOD CALCULATED 24-HOUR RATE OIL-BBL GAS-MCF WATER-BBL 0 2,548 0 OIL-BBL 0 GAS-MCF 2,548 WATER-BBL 0 J CHOKE SIZE JGAS-OIL 64/64 I N/A OIL GRAVITY-APl (corr) N/A RATIO Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. Interbedded gas beadng sandstone, shale and coal. Form 10-407 Rev. 7-1-eo CONTINUED ON REVERSE SIDE N:\drlg\kgfl,wells\Ktu32-TC, ogcompl KU S1-7X.XLS Submit in Triplicate 29. 30. GEOLOGIC MARKERS FORMATION TESTS Include interval tested, pressure data, all fluids recovered NAME MEAS. DEPTH TRUE VERT. DEPTH and gravity, GOR, and time of each phase. Sterling Gas 3960' 3550' Interbedded sandstone, silt shale and thin coals Beluga 5639' 4595' Interbedded sandstone, silt shale and thin coals ?" I'" ?' 'Vi '~( '" '" ""' ' ~ 'r 31. LIST OF ATTACHMENTS Daily operations summaw, wellbore schematic, directional su~ey 32. I hereby certi~ that the foregoing b true and correct to the best of my knowledge Signed ~ ¢~ Don Eynon Title Prod,orion Engineer Intern Date 5/31/2001 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.) Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other- explain. Item 28: If no cores taken, indicate "none". Form 10-407 N:\drlg\kgfwells\ktuS2-7/Aogcompl KU 31-7X.XLS Marathon Oil Company Alaska Region KU 31-7x Well History API: KB: GL: SURFACE LOC: INTERVAL LOC: BOT HOLE LOC: SPUD: COND. CSG: SURFACE CSG: PROD. CSG: 50-133-20495-00 87' 66' 320' FSL & 1325' FWL, Sec. 6, T4N, R1 lW, S.M. 734' FNL& 3160' FWL, Sec. 7, T4N, R1 lW, S.M. 997' FNL & 3366' FWL, Sec. 7, T4N, R1 lW, S.M. Dec, 05,2000 20" 133 ppf, K-55 driven to 93 feet 13 3/8" 61-68 ppfK-55 ~ 1,508 ft w/514 sacks 9 5/8" 40 ppfL-80 ~ 5,767 ft w/1150 sacks Dec, 25,00 Jan, 19,01 Feb, 01,01 Spud well. Drill w/17 ½" bit to 1,520'. Run 13 3/8" 61-68 ppfK-55 casing to 1,508' and cement with 514 sacks. Make up BHA, drill out shoe and 20' of new formation with 12 bit. Perform leak off test to 14.6 EMW. Directionally drill with 12 IA" bit to 5,790'. RU Schlumberger Logging Service and make two OH logging hms, # 1-Platform Express, #2- RFT. Run 9 5/8" 40 ppfL-80 casing to 5,767' and cement with 1150 sacks of Class G cemem. Lost returns about 30 barrels from having displacemem complete. Bump plug and check floats-ok. RIH with 9 5/8" casing scraper and 8 ½" bit and tag up at 5,682'. Circulate hole clean with 3% KCL water and TOOH. Pressure test casing to 2000 psi. RU Schlumberger Logging Service and nm CBL, found cemem top in 9 5/8" annulus at 3,640'. RIH with shear out ball sub, 2.81 X nipple, Baker permanent packer with mill-out extension, Baker CMU sliding sleeve with 2.81" X profile, 3 ½" Mod Y Block 3 3/8" Perforating guns low side 6 SPF loaded with DP 22 gram charges, and 3 ½" 9.3 ppf L-80 IBT tubing to surface. Land tubing hanger in bowl. RU Schlumberger Logging Service to correlate guns to OH logs. Add two pump joims to place guns on depth. Run additional log to confirm perforating guns are on depth. Pressure test seals on tubing hanger to 3000 psi, OK. Drop ball and pressure up on tubing to 1000 psi. Increase pressure to 2800 and then 3200 psi to shear out ball. Attempt to pressure tubing but had circulation around packer. RU Pollard Slickline and RIH PX plug and set at 4,458'. RIH with PX prong and pressure up on tubing to 3400 psi. Bleed off pressure and unseat PX prong. Pressure up below packer to 3000 psi - OK. POOH with PX prong and seat. Re-pressure to 2500 psi to verify packer setting, held with no communication to annulus. Back out landing joint and install back pressure valve. Install Production tree and pressure test. Released Glacier Drilling Rig # 1 on January 15th, 2001. RU Pollard WI, Service, pull BPV, RIH with B shifting sleeve and open sleeve at 4346 KB. RD Pollard WL Service. RU Dowell nitrogen pump to annulus. Pressure test to 2000 psi. Pump 2650 gals N2 to unload 314 barrels of 3% KCL water. RD Dowell N2 Service. Mar, 06,01 RU Schl _.ger WL Service, pressure test lubricator, flow ..~.~s to 1500 psi and perforate with 2 ½" HSD 6 SPF 60° phasing loaded with 2506 HMX charges as shown below: Mar, 08,01 Mar, 08,01 Mar, 30,01 Run 1: Sterling C-2 from 5610 - 5630 fi. 8 psi on well. Run 2: Sterling C-2 from 5590 - 5610 fi. 8 psi on well. Run 3: Sterling C-2 from 5573 - 5590 fl. 8 psi on well. Run 4: Sterling C-1 from 5350 - 5370 fl. 19 psi on well. Run 5: Sterling C-1 from 5330 - 5350 fi. 19 psi on well. All shots fired on all runs. Total Footage - 98'. RD Schlumberger WL Service. Well would not flow. Secure wellhead and shut down for nigh[ RU Pollard WL Service, RIH Tandem Electronic Gauges to obtain static BHP, POOH, RD Pollard WL Service. RU Pollard WL Service, RIH with B shifting sleeve to 4,329' and closed sleeve. POOH with shifting tool. RD Pollard WL Service. RU BJ Coiled Tubing and Dowell N2 Services. Pressure test to 2500 - OK. Purge Coiled robing, RIH with CT and pumping 400-650 scfm of N2. Tag at 5,670'. Make numerous passes across perforations to clean out well. POOH with CT and shut down N2. Shut in well and rig back injector head. Apr, 01,01 SITP 240 psi. Flowwellto gas buster at 150psiFTP. Tumwell over to Production. MARATHON OIL COMPANY ALASKA REGION DRILLING REPORT SUMMARY AKR/Kenai PeninsulalKU 31-7X 23-Dec-00 24-Dec-00 25-Dec-00 26-Dec-00 27-Dec-00 28-Dec-00 29-Dec-00 Rig mob. Spotted equipment. Raised sub. Set doghouse. Raised derrick. Rig up. Rig mob. Changed pump liners. Installed trip tank, beaver slide, rotary motor, stairs driller's console, and carrier tarps. Scoped up derrick and secured guy wires. Rig up. Too windy to install wind walls. Rig mob. Hooked up water. Fired boiler. R/U camp. N/U diverter. Installed top drive rail. Installed top drive and wind walls. R/U solids van. R/U to P/U drill pipe. Mix spud mud. Accepted rig to well work at 21:00 hours, 12/25/00. P/U drill pipe and BHA. Drilled from 45' to 255'. CBU. POOH. Removed mud pump engine radiator for repair. Wait on parts. Sent radiator core for repair. Strap and drift 13 3/8" casing. R/U cementing equipment. Perform miscellaneous rig work. Finished radiator repair. RIH with drilling assembly. Drilled from 255'-497'. MARATHON OIL COMPANY ALASKA REGION DRILLING REPORT SUMMARY AKR/Kenai PeninsulalKU 31-7X 30-Dec-00 31-Dec-00 1-Jan-01 2-Jan-01 3-Jan-01 4-Jan-01 5-Jan-01 Drilled from 497'-1520'. Made wiper trip. CBU. POOH, Ran and cemented 13 3/8" casing. Started N/D Diverter. N/D Diverter. N/U wellhead. N/U BOPE. Changed annular element, Tested BOPE. Tested BOPE. RIH. Drilled out and tested shoe to 14.6 ppg EMW. Drilled from 1520' to 2150'. Drill and survey 2150'- 2632'. Wiper trip to casing shoe, Drill and survey2632' - 3360'. Drill from 3360' to 4350'. MARATHON OIL COMPANY ALASKA REGION DRILLING REPORT SUMMARY AKR/Kenai PeninsulalKU 31-7X 6-Jan-01 7-Jan-01 8-Jan-01 9-Jan-01 lO-Jan-01 11-Jan-01 12-Jan-01 CBU. Tripped for bit. Drilled from 4350' - 4698'. Drilled 4699'-4713'. CBU. Tripped for mud motor. Drilled 4713'-4940'. Drilled from 4940'- 5590'. Drilled 5590'to 5661'. CBU. POOH. Tested BOPE. RIH. Drilled to 5702'. Drilled 5702' - 5790'. Circulated and conditioned mud for logging. Back reamed to shoe. CBU at shoe. RIH to 5790'. CBU. POOH for logging. POH for logs, Rig up Schlumberger and run wireline logs. RIH with bit. RIH. CBU. POOH. Ran 9 5/8" casing to 5787'. MARATHON OIL COMPANY ALASKA REGION DRILLING REPORT SUMMARY AKR/Kenai PeninsulalKU 31-7X 13-Jan-01 14-Jan-01 15-Jan-01 16-Jan-01 17-J a n-O 1 CBU. Cemented 9 5/8" casing. Changed rams. RIH with bit and scraper. Displaced with KCL. Finished displacing with KCL. LID drillpipe. Ran USI/CBL. Started running 3 1/2" completion. Finished running 3 1/2" completion. N/D BOPE. N/D BOPE. N/U and pressure test production tree. Rig released to demob. Rig down drilling equipment in preparation for rig move. Survey Report Company: Marathon Oil Company Field: Kenai Gas Field Site: Pad 14-6 Well: Ku 31-7 Wellpath: OH Original hole Date: 5/15/2001 Time: 09:28:22 Page: 1 Co-ordinate(NE) Reference: Well: Ku 31-7, True North Vertical (TVD) Reference: SITE 87.0 Section (VS) Reference: Well (0.00N,0.00E, 122.54Azi) Survey Calculation Method: Minimum Curvature Db: Sybase Field: Kenai Gas Field Kenai, Alaska usa Map System:US State Plane Coordinate System 1927 Geo Datum: NAD27 (Clarke 1866) Sys Datum: Mean Sea Level Map Zone: Alaska, Zone 4 Coordinate System: Well Centre Geomagnetic Model: Wmm_95 Site: Pad 14-6 Centered on KU 13-6 Site Position: Northing: 2382476.39 ft Latitude: 60 27 38.317 N From: Map Easting: 272204.34 ff Longitude: 151 15 43.267 W Position Uncertainty: 0.00 ft North Reference: True Ground Level: 0.00 ft Grid Convergence: -1.10 deg Well: Ku 31-7 Slot Name: Well Position: +N/-S -96.08 ft Northing: 2362379.62 ft Latitude: 60 27 37.370 N +E/-W 37.21 ft Easting: 272239.70 ft Longitude: 151 15 42.525 W Position Uncertainty: 0.00 ft Wellpath: OH Original hole Drilled From: Surface Tie-on Depth: 0.00 ft Current Datum: SITE Height 87.00 ft Above System Datum: Mean Sea Level Magnetic Data: 0/0/2000 Declination: 21.37 deg Field Strength: 0 nT Mag Dip Angle: 0.00 deg Vertical Section: Depth From (TVD) +N/-S +E/-W Direction ff ft ff deg 0.00 0.00 0.00 122.54 Survey: Survey #1 Start Date: 12/29/2000 Company: Marathon Oil Company Engineer: Craig Young Tool: MWD/GYRO, Tied-to: From Surface Survey: Survey #1 iMD ':.: ' Incl : · Azini: :' :" TVD: :. +N/.s .. "+E/-W' VS. DLS .'Build TUrn' TOol/Comment '.' .'".. : ":fi: '::' deg..."':': d~g'~:::.i.''''::'.ft':.'~.:: ': '"ft.. ff ' :ft.. ' .;:deg?lOOft:deg/l:OOffdeg/iooft. .." .".'.''. .. . . . . .... .. . 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 MWD/GYRO 136.00 0.35 83.00 136.00 0.05 0.41 0.32 0.26 0.26 0.00 MWD/GYRO 225.00 0.44 61.30 225.00 0.25 0.98 0.69 0.19 0.10 -24.38 MWD/GYRO 317.00 0.42 53.90 316.99 0.62 1.56 0.99 0.06 -0.02 -8.04 MWD/GYRO 374.00 0.69 62.90 373.99 0.90 2.04 1.24 0.50 0.47 15.79 MWD/GYRO 463.00 1.07 64.40 462.98 1.50 3.26 1.95 0.43 0.43 1.69 MWD/GYRO 553.00 2.22 54.10 552.94 2.88 5.43 3.03 1.31 1.28 -11.44 MWD/GYRO 643.00 3.59 56.30 642.82 5.47 9.19 4.81 1.53 1.52 2.44 MWD/GYRO 733.00 4.95 54.10 732.57 9.31 14.68 7.37 1.52 1.51 -2.44 MWD/GYRO 822.00 7.59 56.20 821.03 14.83 22.68 11.14 2.98 2.97 2.36 MWD/GYRO 917.00 10.25 58.30 914.88 22.77 35.08 17.33 2.82 2.80 2.21 MWD/GYRO 1015.00 12.25 58.30 1010.99 32.81 51.35 25.64 2.04 2.04 0.00 MWD/GYRO 1108.00 13.80 55.60 1101.59 44.26 68.90 34.27 1.79 1.67 -2.90 MWD/GYRO 1203.00 15.49 55.70 1193.50 57.81 88.73 43.70 1.78 1.78 0.11 MWD/GYRO 1298.00 17.48 56.40 1284.59 72.86 111.09 54.46 2.11 2.09 0.74 MWD/GYRO 1391.00 19.51 58.10 1372.79 88.80 135.91 66.82 2.26 2.18 1.83 MWD/GYRO 1464.00 20.21 59.30 1441.44 101.68 157.11 77.75 1.11 0.96 1.64 MWD/GYRO 1517.00 19.74 60.00 1491.26 110.83 172.73 86.00 0.99 -0.89 1.32 MWD/GYRO 1610.00 23.55 60.30 1577.68 127.89 202.48 101.90 4.10 4.10 0.32 MWD/GYRO 1705.00 25.22 59.90 1664.21 147.45 236.48 120.05 1.77 1.76 -0.42 MWD/GYRO 1831.00 24.98 60.00 1778.31 174.21 282.74 144.65 0.19 -0.19 0.08 MWD/GYRO 1955.00 24.72 60.30 1890.83 200.15 327.94 168.80 0.23 -0.21 0.24 MWD/GYRO 2079.00 24.68 59.90 2003.48 225.98 372.86 192.78 0.14 -0.03 -0.32 MWD/GYRO 2176.00 24.05 66.20 2091.86 244.11 408.47 213.04 2.76 -0.65 6.49 MWD/GYRO Survey Report Company: Marathon Oil Company Date: 5/15/2001 Time: 09:28:22 Page: Field: Kenai Gas Field Co-ordinate(NE) Reference: Well: Ku 31-7, True North Site: Pad 14-6 Vertical (TV'D) Reference: SITE 87.0 Well: Ku 31-7 Section (VS) Reference: Well (0.00N,0.00E,122.54Azi) Wellpath: OH Original hole Survey Calculation Method: Minimum Curvature Db: Sybase Survey: Survey #1 MD Incl Azim TVD +N/-S +E/-W VS DLS Build Turn Tool/Comment ft deg deg ft ft ft ft deg/100ft deg/100ft deg/100ft 2268.00 23.57 73.30 2176.04 256.97 443.25 235.45 3.16 -0.52 7.72 MWD/GYRO 2361.00 22.77 79.60 2261.55 265.56 478.76 260.77 2.80 -0.86 6.77 MWD/GYRO 2455.00 22.38 84.70 2348.36 270.50 514.48 288.22 2.12 -0.41 5.43 MWD/GYRO 2549.00 23.04 90.70 2435.08 271.93 550.69 317.98 2.56 0.70 6.38 MWD/GYRO 2642.00 24.29 96.80 2520.27 269.44 587.89 350.68 2.95 1.34 6.56 MWD/GYRO 2734.00 26.09 102.80 2603.54 262.71 626.42 386.77 3.39 1.96 6.52 MWD/GYRO 2831.00 27.83 108.40 2690.01 250.84 668.71 428.82 3.17 1.79 5.77 MWD/GYRO 2925.00 29.50 113.90 2772.50 234.53 710.70 472.99 3.32 1.78 5.85 MWD/GYRO 3018.00 31.66 117.70 2852.56 213.91 753.26 519.95 3.12 2.32 4.09 MWD/GYRO 3111.00 33.68 122.90 2930.86 188.55 796.53 570.07 3.72 2.17 5.59 MWD/GYRO 3205.00 36.01 127.10 3008.01 157.71 840.47 623.70 3.56 2.48 4.47 MWD/GYRO 3298.00 37.63 131.90 3082.48 122.25 883.41 678.98 3.55 1.74 5.16 MWD/GYRO 3393,00 40.14 133.90 3156.42 81.64 927.07 737.63 2.95 2.64 2.11 MWD/GYRO 3486.00 42.10 136.20 3226.48 38.35 970.26 797.32 2.66 2.11 2.47 MWD/GYRO 3580.00 44.70 137.10 3294.78 -8.62 1014.58 859,95 2,84 2,77 0.96 MWD/GYRO 3672.00 47.35 138.70 3358.65 -57.75 1058.94 923.77 3.14 2.88 1.74 MWD/GYRO 3764.00 49.20 140.40 3419.88 -110.01 1103.48 989.42 2.44 2.01 1.85 MWD/GYRO 3890.00 49.20 140.80 3502.21 -183.71 1164.02 1080.10 0.24 0.00 0.32 MW D/GYRO 4014.00 49.72 142.20 3582.81 -257.46 1222.67 1169.22 0.95 0.42 1.13 MWD/GYRO 4140.00 51.1 6 143.10 3663.06 -334.68 1281.60 1260.43 1.27 1.14 0.71 MWD/GYRO 4264.00 50.82 143.20 3741.11 -411.78 1339.38 1350.62 0.28 -0.27 0.08 MWD/GYRO 4392.00 50.44 143.10 3822.31 -490.97 1398.73 1443.23 0.30 -0.30 -0.08 MWD/GY RO 4519.00 50.00 141.90 3903.57 -568.40 1458.14 1534.97 0.80 -0.35 -0.94 MWD/GYRO 4644.00 49.71 142.60 3984.16 -643.95 1516.64 1624.92 0.49 -0.23 0.56 MWD/GYRO 4769.00 50.10 141.70 4064.67 -719.45 1575.31 1714.99 0.63 0.31 -0.72 MWD/GYRO 4893.00 49.73 142.60 4144.51 -794.36 1633.52 1804.36 0.63 -0.30 0.73 MWD/GYRO 5020.00 49.16 142.00 4227.09 -870.71 1692.53 1895.17 0.57 -0.45 -0.47 MWD/GYRO 5145.00 48.48 141.80 4309.39 -944.74 1750.58 1983.93 0.56 -0.54 -0.16 MWD/GYRO 5270.00 48.07 142.40 4392.58 -1018.36 1807.89 2071.84 0.49 -0.33 0.48 MWD/GY RO 5391.00 47.61 142.30 4473.80 -1089.37 1862.67 2156.23 0.39 -0.38 -0.08 MWD/GYRO 5518.00 46.79 142.30 4560.09 -1163.10 1919.66 2243.92 0.65 -0.65 0.00 MWD/GYRO 5608.00 46.29 141.40 4621.99 -1214.47 1960.01 2305.57 0.91 -0.56 -1.00 MWD/GYRO 5737.00 45.64 142.00 4711.66 -1287.25 2017.49 2393.17 0.60 -0.50 0.47 MWD/GYRO 20" OD 133 ppf K-55 DP ~ 114 fl 13-3/8"" OD 61-68 ppf K-55 @ 1508 fi MD creed in 7- 2Hoe IBaker Permaf~ent Packer Set @ 4406 2 813" ID 'X' nipple @ 4458 ~Shear out Ba~l Sub @ 4907' Dated Comp eted: 9-5f8" OD 40 ppf L-80 @ 5767t MD cmfd in 12~1t4"I Alask'~i gion Domeshc Production Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 February 2, 2001 Alaska Oil & Gas Association Attn: Lisa 333 W. 7th Ave., Ste. 100 Anchorage, AK 99501 LETTER OF TRANSMITTAL Hand Delivered ~w~ Marathon Oil Company KU 31-7 Dry Samples Enclosed are the following samples collected from Marathon's KU 31-7 well. Dry Samples Depth From Depth To (Feet) (Feet) Box No. 3,000 3,800 1 3,800 4,400 2 4,400 4,830 3 4,830 5,080 4 5,080 5,300 5 5,300 5,560 6 5,560 5,790 7 Please sign and return confirming you have received this data. you, Kaynell Z emaXn~ Exploration Aide Enclosures Hand Delivered Received by: Date: / C{ A subsidiary of USX Corporation Environmentally aware for the long run. Alask~ zion Dome~roduction Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 January 22,2001 Alaska Oil & Gas Conservation Commission Attn: Library - Lisa 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 LETTER OF TRANSMITTAL VIA AIRBORNE EXPRESS The following well data are enclosed: Marathon Oil Company KU 31-7X C~ ~ ~- / (-/~ Final Mud Logging Report by Epoch, which includes Formation Log - 2"=100' MD & 2"=100' TVD and Drilling Dynamics Log - Paper Copies DAeUd Log Data- CD Rom~ ay Induction, Gamma-Ray, Caliper *Platform Express* - Paper Copy nsity, Neutron, Sonic-Gamma Ray, Caliper - Paper Copy Dipole Sonic Imager - Paper Copy Repeat Formation Tester-Gamma Ray - Paper Copy Gamma Ray, Caliper *Platform Express* - Paper Copy Array Induction, Gamma, Ray, Caliper *Platform Express* - Paper Copy Density, Neutron, Sonic, Gamma Ray, Caliper - Paper Copy Open Sonic Data - CD Rom Marathon Oil Company KU 32-7 Sonic Data - CD Rom Marathon Oil Company KU 14-32 I ~ oD-~1 ~ Completion Record 4.72" HSD, 12 SPF - Paper Copy & Reproducible Correlation Log - Paper Copy & Reproducible Please sign and return confirming you have received this data. Thank you, MARATHON OIL COMPANY Kabell Zema~ Exploration Aide Enclosures ~: 5333594~ Received by:~~ Date: A subsidiary of USX Corporation Environmentally aware for the long run. Alaska .~' ~n Domestic, roduction Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7th Ave Suite 100 Anchorage, AK 99501 January 23, 2001 RE: Annular-flms.~from...KU 31-7X (Previously KU 31-7) Mr. Tom alVIh-fi'-ffder, Pursuant to our telephone conversation, attached is an analysis outlining annular flow from well KU 31- 7X. Please note that our log evaluation, tied to nodal analysis, indicates the erosional velocity cannot be reached by the proposed Sterling Pool 6 or Pool 3 completions. Feel free to contact me for any additional information. We plan to perforate Feb 01,2001. I can be reached at 564-6303 or e-mailed at rjaffinito~marathonoil.com. Sincerely, Ralph J. Ai'finito Production Engineer Marathon Oil Company 3201 'C' Street Anchorage, AK 99519 A subsidiary of USX Corporation Environmentally aware for the long run. Re: KU 31-7X (PTD 200-148) Subject: Re: KU 31-7X (P'rD 200-148) Date: Thu, 18 Jan 2001 16:55:59 -0900 From: Tom Maunder <tom_maunder@admin.s~ate.ak. us> To: Ralph J Affinito <RJAffinito@marathonoil.com> CC: John Hartz <jack._hartz@admin.state.ak. us> Ralph, Jack Hartz and I have looked at the proposed completion and work on the 31-7Y~ You are correct that several wells in your Kenai fields have been approved for LP gas production via the annulus. The caveat has always been that the reservoir fluids are not corrosive and that sand production is minimal to avoid erosion. Our file research shows that on previous wells an analysis of the potential of erosion and/or corrosion has been provided and we feel that same analysis should be provided for this well. Jack noted that in at least 2 cases those wells could deliver rates that exceeded the erosional velocity. Please contact either Jack or myself with any questions. Tom Maunder Ralph J Affinito wrote: > Tom, > Please find attached the proposed completion procedure for the subject well. Our objective was to have the through tubing completion target the Pool 5.1 and 5.2 sands at approximately 5000', but due to questionable log response we have elected to pursue the Pool 6 sands beginning at 5330' KB. Please advise following your review as we would like to commence perforating (Pool 6) next week. Thanks, Ralph J. Affinito Marathon Oil Company 907-564-6303 Nan'e: KU317C~I.DOC KU317C~l. DOC Type: Microsoft Word Document (application/msword) Eno~ding: base64 ,,, Tom Maunder <tom maunder~,admin.state.ak, us> Petroleum Engineer Alaska Oil and Gas Conservation Commission 1 of 1 1/18/01 4:57 PM <L131 Subject: KU 31-7X Date: Thu, 18 Jan 2001 17:25:26 -0600 From: "Ralph J Affinito" <RJAffinito@marathonoil.com> To: tom_maunder@admin.state.ak, us Tom, Please find attached the proposed completion procedure for the subject well. Our objective was to have the through tubing completion target the Pool 5.1 and 5.2 sands at approximately 5000', but due to questionable log response we have elected to pursue the Pool 6 sands beginning at 5330' KB. Please advise following your review as we would like to commence perforating (Pool 6) next week. Thanks, Ralph J. Affinito Marathon Oil Company 907-564-6303 ~KU317C~1.DOC Type: Microsoft Word Document (application/msword)! Encoding: base64 .I 1 of 1 1/18/01 2:37 PM MARATHON OIL COMPANY ALASKA REGION Kenai Gas Field KU 31-7 Completion Procedure AFE # 9205500 Sterling Completion Procedure Pools 6 and 3 Note: This procedure commences with the 9-518" casing cemented. . . . Haul to location: · 4,500 ft of 3-1/2" 9.3 Ibm/ft L-80 Improved Buttress Tubing Modified with seal ring. · 425' of 3-1/2" 9.3 Ibm/ft N-80 Improved Buttress Tubing Modified with seal ring Mix 450 bbls of 3% KCI water. PU bit and scraper for 9-5/8" 40 Ibm/ft casing. RIH wi5" Hevi- wate and 4" DP from derrick. Clean out casing to desired DOD from logging. Close annular and pressure test wellbore to 2,500 psig. Mix a 40 bbls pill of SafeKleen and preceed rolling the hole with 3% KCl water. Use only 3% KCl water throughout remainder of procedure. TOH while laying down 4" DP, 5" Hevi-wate, and BHA. Change out upper pipe rams to 3-1/2". Test BOPE to 250/5000 psig. TIH with the following as per the attached: a. 3-1/2" IBT Mod Shear out ball sub ( beveled with m-entry profile) b. 3-1/2" 9.3 Ibm/ft N-80 IBT mod tbg as tailpipe (estimated 400') c. 3-1/2" 9Cr 'X' nipple with 2.813" min ID wi/6' & 4' pups on top and bottom respectively d. 1 jt 3-1/2" 9.3 Ibm/ft L-80 IBT mod tbg e. cross-over MOE f. Mill out extension g. Baker SB-3 Packer Size 194-40 for set in 9-5/8" 40 Ibm/ft csg h. Baker E Anchor Size 80-40 for packer i. 2 jts 3-1/2" 9.3 Ibm/ff L-80 IBT mod tbg j. 3-1/2" IBT-Mod Baker CMU sliding sleeve w/2.81" 'X' profile wi6' & 4' pups on top and bottom respectively. k. 3-1/2" 9.3 Ibm/fl: L-80 IBT mod tbg to reach Pool 3 perforations -~,~,~"~-- I. 3-'1/2" IBT-Mod Y-block for perforating guns wiG' & 4' pups on top and bottom respectively ~'~ m. 3-1/2" 9.3 Ibm/ft L-80 IBT-Mod tbg. Place RA tag in collar, c~k-k-c~¢V,~O ~ ~, n. 3-1/2" IBT-Mod CM-2 Mandrel w/CV-2 Check valve wi6' & 4' pups on top and bottom respectively (@ approximate 2,000 ft) o. 2000' of ¼" OD 0.049" wall 316 SS coil tubing strapped to 4-1/2" string with stainless steel bands every other joint p. 3-1/2" 9.3 Ibm/ft L-80 IBT-Mod tbg to surface w/necessary pups for space out Note all OD's and ID's along with serial numbers on all components being run downhole. Precise depths will vary depending upon perforation intervals. All ID's are to be checked for verification that 2.80" or greater exists. Run equipment in the hole while maintaining 1,500 psig on the ¼" capillary string to verify integrity. Locating packer above the Pool 5.1 interval at approximately 4344'. KU 31-7 Completion Procedure-001 RJA 1/18/01 2:37 PM . RU Schlumberger logging service w/pump in sub and pack-off. RIH w/1-11/16" OD GR/CCL and correlate depth. Stand back Schlumberger. Determine required space out for placing annular guns on depth. Make up necessary space out pups and mandrel hanger (Full set of 3-1/2" IBT-Mod pups is at Tuboscope). Land hanger w/control line through top. Re run Schlumberger GR/CCL to verify space out and perf gun placement. Pressure test hanger seals. Drop ball and set Baker SB-3 packer by pressuring up with 3%KCI water to 3000 psig. Continue pressuring up to 3,500 and shear out ball. Pressure test packer from below by pressuring up to 2,500 psig DOWN TUBING. CLOSELY MONITOR ANNULAR PRESSURE. ANNULUS MUST NOT BE PRESSURED ABOVE 1,000 PSIG AS PERFORATING GUNS WILL FIRE. Flange up tree. Pressure test tree and seals. Install BPV. Release rig an~ commence rig down. _ ~.------ ~ TEST OF STE.U. .OOL 3 NOTE: The SBHP of the Sterling Pool 3 is approximately 290 psia. . RU Pollard Slickline Service. Install full lubricator. Pressure test lubricator to 2,000 psig, RIH w/2.75" GR to tbg tail then to DOD. RIH w/shifting tool for Baker 3-1/2" CMU sliding sleeve w/2.81" OD 'X' profile. Shift sliding sleeve open. RD Pollard Slickline. . Set open top tank w/gas buster. RU Marathon 3" 5K choke to 3" 5K SSV. RU chicksan and iron from choke to open top tank. Strap tanks. RU nitrogen pumping service. Hook nitrogen pumping lines to 4" 3K casing valve. Commence pumping nitroge.n down the annulus while taking returns out the choke on wing of tree. Should unload approximately 314 bbls of 3% KCI water yielding the fluid level at approximately 4329'. Leave nitrogen pumping equipment on location. , RU Pollard Slickline Service. Install full lubricator. Pressure test lubricator to 2,000 psig. RIH w/shifting tool for Baker 3-1/2" CMU sliding sleeve w/2.81" OD 'X' profile. Shift sliding sleeve closed. RD Pollard Slickline. , Have on location 4,000 gal of nitrogen. Locate 4" 3K x 3" 5K adapter flange with studs on rent from Vetco. Dump 21 bbls of 3% KCI water down the annulus to have liquid level 100' over the guns at time of perforating. RU Marathon choke to annular valve. Close annular valve. Resume operation of nitrogen pumping equipment. Pressure up annulus with nitrogen to 2700 psig to fire annular perforating guns. Monitor pressure fall off to verify guns have fired. RD Nitrogen pumping equipment 9. Flow test the Pool 3 annular completion to gas buster. Following clean gas flow to surface shut Pool 3 in pending hookup to Iow pressure flowline. Remove choke and adapter flange. TEST OF STERLING POOL 6 SANDS NOTE: The SBHP of the Sterling Pool 6 is approximately 360 psia. 10. RU Marathon 3" 5K choke to 3" 5K SSV. RU chicksan and iron from choke to open top tank. 11. Fluid level should be at 4329' KB which corresponds to 304 psig of BHP; thus a 56 psi underbalance. 12. RU SLB WL service w/0.23" wire, full lubricator (pump in sub and flow tubes), and pressure control equipment. Pressure test to 2,000 psig. Prepare to perforate with 2.5" HSD guns loaded 6 SPF 60 degree phased with PJ 2506 HMX 10.7 gram charges. Schlumberger SPAN analysis indicates an average formation penetration of 10.671 inches with an average th ~ entrance hole of 0.26 inches. The APl 5 Edition Section 1 performance is 0.32 entrance KU 31-7 Completion Procedure-001 RJA 1/18/01 2:37 PM 13. 14. hole and 25.2"penetration. Gun system is Schlumber,qer's SAFE system thus radio silence is not necessary. Note Baker CMU sliding sleeve with an 2.813" 'X' profile above packer and an 'X' nipple with a 2.813" ID in 3-1/2" tubing below packer. Fluid level should be at Baker CMU sliding sleeve at approximately 2,900' KB. Correlate depth to Schlumberger open hole logs. Perforate the Sterling intervals noting change in surface pressure and fluid level. RD Schlumberger. Flow test well to establish deliverability and obtain gas samples to determine gas analysis. Consult engineering for flow rate specification following clean up. RU Slickline company. Pressure test lubricator to 2,000 psi. RIH w/tandem electronic gauges and perform transient tests as per engineering direction. Contact Anchorage office for testing and production criterion. CONTACTS Ralph Affinito: Craig Young: Wayne Cissell: Ben Schoffmann: David Brimberry: 907-564-6303 (w) 907-336-4548 (h) 907-231-3775 (p) 907-564-6310 (w) 907-348-8189 (h) 907-231-3937 (p) 907-283-1308 (w) 907-564-6471 (w) 907-564-6402 (W) KU 31-7 Completion Procedure-001 RJA 1/18/01 2:37 PM MARATHON OIL COMPANY KU 31-7X KENA I GA S FIELD Section 6 T4N RI ~W, SM Kenai Peninsula, Alaska January 9, 2001 EPOCH TABLE OF CONTENTS MARATHON OIL COMPANY KU 31-7X · WELL RESUME m DRILLING SUMMARY 1 DAILY CHRONOLOGY m LITHOLOGY REVIEW RIG ACTIVITIES SUMMARY Sm MUD RECORD 1 BIT RECORD am SURVEY RECORD (INTEQ) Sm MORNING REPORTS 10. FINAL LOGS WELL RESUME MARATHON OIL COMPANY WELL NAME: KU 31-7X FIELD: KENAI GAS FIELD REGION: KENAI PENINSULA, ALASKA LOCATION: 365' FSL, 1361' FWL SEC 6 - T4N - RllW, SM BOROUGH: STATE: KENAI BOROUGH ALASKA ELEVATION: KB: 87.0' AMSL I GL: 66.0' AMSL APl NUMBER: #50-133-20495-00 OPERATOR: Operator Representatives: Company Geologist: CONTRACTOR: MARATHON OIL COMPANY DARRELL GREEN, RICK GIDEON DAVID BRIMBERRY INLET DRILLING DRILLING RIG: Toolpusher: GLACIER DRILLING #1 GEORGE BREWSTER, MIKE LESLIE MUDLOGGING COMPANY: Logging Geologists: EPOCH WELL SERVICES, INC. CRAIG SILVA, RALPH WINKELMAN NICK ATKINSON MUD COMPANY: Mud Engineers: M-I ROD MABEUS, BOB WILLIAMS MWD COMPANY: MWD Engineer: BAKER HUGHES INTEQ STEVE STURGES DIRECTIONAL COMPANY: Directional Driller: BAKER HUGHES INTEQ JASON LONG, TOM DUNN CEMENT COMPANY: WIRELINE COMPANY: Logging Engineer: BJ SERVICES SCHLUMBERGER MARATHON OIL COMPANY KU 31-7X DRILLING SUMMARY PROSPECTUS The purpose of KU 31-7X was to evaluate gas producing sands within the Sterling Formation of the Tertiary Kenai Group. A limited section of the Beluga Formation was encountered at total depth. BRIEF REVIEW OF ACTIVITY Epoch Well Logging provided a RIGWA TCH 2000TM Digital Drilling Monitoring System and DML (Digital Mudlogging) Service. The drilling rig was MARATHON Glacier #1. The well was spudded on December 26, 2000, and reached a Total Depth of 5790' M.D. (4748' TVD) on January 09, 2001. 17 W' hole was drilled from surface to 1520'MD, and 13 3/8"Casing was set at 1508'. 12 ¼" hole was drilled from 1520' to 5790'MD, and 9 5/8" Casing was set at TD. BRIEF DIRECTIONAL REVIEW 17 %" hole was drilled vertically to 463' an a directional build to Kick Off Point at 463', where azimuth was established to the northeast, and angle was built to a maximum angle of 51 degrees at 4140'. A gradual drop to 45 degrees commenced at 4140 to TD. Azimuth bearing progressed from east to southeast with a final inclination of 45 degrees bearing 140 degrees azimuth at TD. LOGGING PROCEDURES Hydrogen flame ionization Total Gas Detection and Gas Chromatograph detectors were employed to detect and analyze formation gases. Continuous mud gas was generated by an air motor driven gas trap located at the shale shaker header box and extracted continuously from the trap to the unit by sample pumps. The gas trap was frequently cleaned and positioned to obtain optimum sampling, and the gas system was tested and calibrated on a regular basis. Cuttings samples were collected at regular 20' and 10' intervals as directed by Marathon's sampling program. MARATHON OIL COMPANY DAILY CHRONOLOGY 0110112001: Attempt to work Vetco Gray test plug past 13 5/8" 5K packing element, "NO GOOD", will not relax enough to let test plug pass. Nipple down flow line, fill up line, riser, and turnbuckles - Pull out hoist beam. Hammer bolts to remove lid on 13 5/8" 5K annular. Change out packing element- Reinstall lid and tighten up bolts. Attempt to test stack -4 1/16" manual valve leaked on tubing spool at 250 psi. Install bell nipple, flow nipple, fill up lines and scaffolding. Test choke manifold valves no. 10,11,12 while testing against blind rams at 250psi and 3000 psi.- Blind ram door seal leaked, tighten up and retest- Held pressure for 7 min. - Heard a loud bang and lost pressure to 0 psi. - Checked out well head and surface equipment. Attempted to pressure up again :NO GOOD". Attempt to screw into test plug. Drain BOP and pull lock down stud. Test plug appeared to be installed upside down. Nipple down BOP and related equipment at "A" section of wellhead. Test plug was installed upside down. Install cross over and dog collar clamp on stub of test plug. Install 5' pup joint for leverage, rig up two hydraulic hoists with snatch blocks and pull back straight. Install 4" drill pipe into pup joint and hoist to rig floor. Dress "A" section profile and remove outer section of two-part test plug. Install new inner section on test plug and change all o-ring seals. 0110212001: Nipple up BOP and related equipment. Pick up cellar area of tools and equipment. Install Vetco Gray test plug. Test BOP and related equipment at 250 psi for Iow and 3000 psi for high. Pressure test BOP. Dress wear ring. Pressure test casing 1500 psi / 30 minutes. Set wear ring. Lay down test joint. Perform Koomey function test. Pick up BHA. Test mud motor and MWD tool. RIH with HWDP. RIH f/879' to cement top at 1464'. Drill float collar, cement, float shoe, and 20' new formation. Circulate bottoms up. Perform leak off test. 450 psi with 8.75 mud = 14.6 EMW. Blow down lines and build mud spacer. Displace well with 8.6 ppg Flo-Pro mud. Directional drill 1540' - 1750'. 0110312001: Directional drill 1750'- 2632'. Circulate bottoms up. Wiper trip to casing shoe, no problems. Drill and survey 2632'- 3006'. 0110412001: Directional drill and survey 3006'- 3693'. Backream 3693'- 3631'. Tight at 3663'. Drill 3693'- 4004'. Change out geolograph line. Drill 4004'-4178'. 0110512001: Drill and survey 4178'-4350'. Circulate bottoms up. POOH with bit. Change out bit. Test mud motor and MWD tool. RIH to 3195'. Wash and ream 3195' - 4350'. Drill and survey 4350'- 4548'. 0110612001 Drill and survey 4548'-4713' Circulate bottoms up and pump dry job. POH to check bit and mud motor. Mud motor tested weak. Lay down mud motor. Change out MWD probe. Pick up new mud motor. Change out pulser sub. Test MWD tools. Trip in hole. Wash and ream tight spots @ 4163' and 4342'. Drill 4713'- 4721' Lost rig power. Power breaker blew. Drill 4721' - 4821' 0110712001: Drill and survey 4821' - 4995'. Repair mud pump pop off. Drill 4995' - 5071'. Repair hydraulic leak on #1 pump motor. Drill and survey 5071'- 5400'. 0110812001: Drill and survey 5400'- 5661'. Circulate bottoms up. POH with bit. Pull wear bushing and set test plug. Pressure test BOP. Pull test plug and set wear bushing. Make up bit. Load probe. Test MWD tool and RIH with BH^. 0110912001: Continue trip in hole. Wash and ream tight spots at 3508'- 3570', 4130'- 4254', 4381'-4509', 4699'- 5661'. Drill 5661'- 5790'. Circulate and condition mud for logs. Back ream 5790'- 1508'. Circulate bottoms up. Trip in hole. Ream solid bridge 3714'- 3754'. 0111012001: Circulate and condition hole for logs. POH for logs. SI_M. Lay down MWD tool and mud motor. Rig up Schlumberger and run wireline logs. #1 platform express, #2 RFT. Hole taking about 2 bph mud. 0111112001: Complete RFT log. Rig down Schlumberger. Pick up bit and bit sub. Trip in hole. Circulate bottoms up. Pump pill. POH. Change out rams and test. Pick up casing tools. RIH with 9 5/8" casing. Repair fill up tool. 0111212001 Continue repair fill up tool. Finish RIH with 9 5/8" casing. Circulate bottoms up. Pump cement. MARATHON OIL COMPANY KU 31-7,)( LITHOLOGY REVIEW SAND (3000' - 3200') = DARK GREENISH GRAY, WITH STRONG GREENISH BLACK SECONDARY HUES; LOCALLY IS MORE GRAYISH BLACK WITH STRONG GREENISH GRAY SECONDAY HUES; FINE UPPER TO COARSE LOWER, SMALL (<5%) FRACTIONS OF VERY FINE OR COARSE UPPER AND LARGER GRAINS; MODERATELY WELL TO WELL SORTED IN FINE UPPER TO MEDIUM UPPER RANGE; 90% SUBANGULAR AND SUBDISCOIDAL; 10% OTHER GROUPS OF RDDNESS AND SHAPE, MOSTLY SUBROUND AND SUBSPHERICAL; APPEARS SOME GRADUAL FINING UPWARD THROUGH VERY MASSIVE SECTIONS; SUBTLE IMPROVEMENT OF GRAIN SPHERICITY DOWNWARD; ENTIRELY DISAGGREGATED; RARE CONSOLIDATED PIECES HAVE WEAK SOLUBLE TUFF CLAY MATRIX SUPPORT; ONLY TRACES OF CALCITE; COMPOSITIONAL GRAYWACKE (>30% LITHICS); EST 35 60% QUARTZ AND VOLCANICANIC GLASS, TRACE FELDSPAR, 5 10% CHALCEDONY/QUARTZITE/JASPER AND OTHER FORMS OF SILICA, 30 60% LITHICS AND MAFICS; OVER 70% OF ALL LITHICS ARE GREEN TO MOTTLED GREEN TO GRAYISH GREEN LOW GRADE META GREENSTONE ROCK FRAGMENTS; I 2% OF ENTIRE SAMPLE IS ORANGE TO ORANGISH RED TO REDDISH ORANGE LITHIC VOLCANICANIC GRAINS (VERY DISTINCTIVE, WITH ORANGE ON GREEN BACKGROUND COLOR); QUARTZ IS COLORLESS TO PALE GRAY TO MOTTLED WHITE AND 75% TRANSLUCENT/25% TRANSPARENT; VERYCOMMON TO ABUNDANT VOLCANIC GLASS iS COLORLESS TO VERYPALE SMOKEY GRAY AND TRANSPARENT; COMMON CLASTIC LITHIC GRAINS OF CALCAREOUS TUFF; APPROX 30% OF LITHICS FRACTION IS BLACK MAFIC MINERALS AND DARK GRAY TO BLACK ARGILLITE PHYLLITE ROCK FRAGMENTS. TUFFACEOUS CLAYSTONE (3010' - 3320') = LIGHTGRAYISH BROWN TO GRAYISH BROWN, PALE BROWN, YELLOWISH GRAY; MANY FAINT VARIATIONS OF GRAY, BROWN, BROWNISH GRAY AND GREENISH BROWN SECONDARY HUES; SOFT TO SLIGHTLY FIRM TO SLIGHTLY BRITTLE; ASHY TO CLAYEY TO SOFT MATTE TEXTURES; DULL TO SOFT GLASSY TO MICROSPARKLY LUSTRE; SPOTTY TO ABUNDANT VISIBLE GLASS SHARDS; MOSTLY GRADATIONAL TO ARGILLACEOUS CLAYSTONE. ARGILLACEOUS CLAYSTONE (3010' - 3320') = LIGHT GRAYISH BROWN TO GRAYISH BROWN TO MEDIUM GRAY; GENERALLY STRONG GREENISH GRAY TO GRAYISH GREEN SECONDARY HUES; OCC STRONG YELLOWISH GRAY SECONDARY HUE; MODERATELY TO VERY FIRM TO MODERATELY BRITTLE; MOST IS MASSIVE, BUT OFTEN HAS SUBSPLINTERY HABIT AND IS SHALEY IN PART; ALSO GRADES TO TUFFACEOUS CLAYST; COMMON HAS MICROTHIN CARB LAMS AND PARTICLES. SAND (3200'- 3500') = DARK GREENISH GRAY, WITH STRONG GREENISH BLACK SECONDARY HUES; LOCALLY IS MORE GRAYISH BLACK WITH STRONG GREENISH GRAY SECONDAY HUES, OR MEDIUM GRAY WITH STRONG BROWNISH GRAY AND FAINT GREENISH GRAY SECONDARY HUES; ALSO NOTE THAT COARSER CONGLOMERATIC ZONES ARE DK GREENISH GRAY WITH FNT YELISH BRN SEC HUES; VERY FINE UPPER TO GRANULE; MOSTLY MODERATELY SORTED IN FINE UPPER TO COARSE LOWER RANGE, LOCALLY POOR SORTING IN MED TO VERYCOARSE RANGE; 90% SUBANGULAR AND SUBDISCOIDAL, 10% WITH BETTER DEVELOPED RDDNESS AND SHAPE, TRACE WELL RDD CGL CLASTS; SUBTLE FINING UPWARD THRU MOST SECTIONS; NEARLY ALL DISAGGREGATED, TR CLAY MATRIX SUPPORTED SS; COMPOSITIONAL GRAYWACKE IN GENERALLY SAME FRACTIONS AS DESCRIBED ABOVE; NOTE LITHICS ARE BECOMING MORE DIVERSE; ALSO NOTE THAT THE SANDS APPARENTLY HAVE MORE THIN INTERBEDS SINCE THERE IS A DIVERSE GROUP OF ALL THE OTHER LITHOLOGIES COAL (3460'- 3465') = BLACK WITH DARK BROWN TO DARK DUSKY BROWN SECONDARY HUES; HARD; DENSE; PLATY TO BLOCKY; DOMINANTLY PLANAR FRACTURE WITH SCATTERED BIRDEYE FRACTURE; SMOOTH TO DENSE MATTE TEXTURE; SLIGHTLY RESINOUS TO EARTHY LUSTRE; OCCASIONALY GRADING TO DARK BROWN CARBONACEOUS SHALE; NO VISIBLE OUT GASSING BUBBLES PRESENT. TUFFACEOUS CLAYSTONE (3460'-3600') = LIGHT BROWNISH GRAY TO LIGHT GRAY WITH LIGHT BROWN TO LIGHT GRAY SECONDARY HUES SLIGHTLY FIRM TO FIRM, OCCASIONALLY SLIGHTLY BRITTLE; ASHY TO CLAYEY TEXTURE; DULL TO MICROSPARKLY LUSTRE; SPOTTY TO ABUNDANT VISIBLE SHARDS; POOR ADHESIVENESS; FAIR COHESIVENESS; COMMON MICRO THIN CARBONACEOUS LAMINATIONS AND PIECES; NON TO SLIGHTLY CALCAREOUS. SAND (3520' - 3650') = VARICOLORED WITH MEDIUM TO DARK GRAY AND SALT AND PEPPER OVERALL APPEARANCE; INDIVIDUAL GRAINS DOMINANTLY LIGHT TO MEDIUM GRAY, FROSTED WHITE, MEDIUM GRAYISH GREEN, DARK GREEN TO GREENISH BLUE WITH SCATTERED RED TO REDDISH BROWN LITHS AND LIGHT RED TO PINK LITHS; FINE LOWER TO COARSE LOWER, DOMINANTLY MEDIUM LOWER; ANGULAR TO SUBANGULAR; MODERATELY WELL SORTED; UNCONSOLIDATED TO VERY LOOSELY CONSOLIDATED WITH ASHY/CLAYEY SUPPORTING MATRIX; COMMON BLACK CARBONACEOUS MATERIAL. TUFFACEOUS CLAYSTONE (3600'- 3700') = LIGHT BROWN TO LIGHT BROWNISH GRAY WITH LIGHT GRAY TO GRAYISH BROWN SECONDARY HUES; SOFT TO SLIGHTLY FIRM; OCCASIONALY SLIGHTLY BRITTLE TO FRAGILE; IRREGULAR SHAPED CUTTINGS; CLAYEY TO ASHY TEXTURE; DOMINANTLY DULL TO EARTHY LUSTRE, OCCASIONALLY MICROSPARKLY; SPOTTY VISIBLE GLASS SHARDS; COMMON BLACK, MICROTHIN CARBONACEOUS LAMINATIONS AND PIECES PRESENT; SLIGHTLY TO MODERATELY CALCAREOUS; TRACE MEDIUM GRAY, WAXY TUFFS. SAND (3650' - 3750') = MEDIUM TO DARK GRAY OVERALL APPEARANCE; INDIVIDUAL GRAINS DOMINANTLY LIGHT TO MEDIUM GRAY, LIGHT GREENISH GRAY, WHITE, TRANSPARENT, RARE RED TO PINK LITHS; FINE LOWER TO RARE VERY COARSE UPPER, DOMINANTLY MEDIUM LOW ANGULAR TO SUBANGULAR; POORLY TO MODERATELY SORTED; UNCONSOLIDATED TO VERY LOOSELY CONSOLIDATED WITH CLAYEY/ASHY SUPPORTING MATRIX; TRACE BLACK CARBONACEOUS MATERIAL; TRACE CALCITE PIECES. SAND (3750'- 3850') = MEDIUM TO DARK GRAY OVERALL APPEARANCE; INDIVIDUAL GRAINS DOMINANTLY LIGHT TO MEDIUM GRAY, LIGHT GREENISH GRAY, WHITE, TRANSPARENT, RARE RED TO PINK LITHS; FINE LOWER TO RARE VERY COARSE UPPER, DOMINANTLY MEDIUM LOW ANGULAR TO SUBANGULAR; POORLY TO MODERATELY SORTED; UNCONSOLIDATED TO VERY LOOSELY CONSOLIDATED WITH CLAYEY/ASHY SUPPORTING MATRIX; NON TO SLIGHTLY CALCAREOUS; TRACE BLACK CARBONACEOUS MATERIAL; TRACE CALCITE PIECES. COAL (3600' - 3950') = PRESENT AS THIN BEDS IN DOMINANTLY SAND AND CLAYSTONE FORMATION; BLACK WITH DARK BROWN TO DARK DUSKY BROWN SECONDARY HUES; MODERATELY HARD TO BRITTLE; DENSE; TOUGH; BLOCKY TO PLATY, OCCASIONALY ELONGATED CUTTINGS; DOMINANTLY PLANAR FRACTURE; TRACE BIRDEYE FRACTURE; SMOOTH TO DENSE TEXTURE; RESINOUS TO OCCASIONALY DULL LUSTRE; OCCASIONALY GRADING TO A VERY DARK, DUSKY BROWN SILTY, CARBONACEOUS SHALE/SILTSTONE. SAND (3850'- 4000') = CONTINUED SAME CHARACTERISTICS AS DESCRIBED ABOVE WITH INCREASE IN THIN INTERBEDDED COALS. TUFFACEOUS SlLTSTONE (3800'-4000') = LIGHT BROWN TO LIGHT BROWNISH GRAY WITH LIGHT GRAY SECONDARY HUES; SOFT TO SLIGHTLY FIRM; ROUNDED, IRREGULAR CUTTINGS; CLAYEY TO SILTY TEXTURE; DULL TO EARTHY LUSTRE; NON CALCAREOUS; COMMON BLACK, MICROTHIN CARBONACEOUS LAMINATIONS AND PIECES. SAND (3890'-4005') = VARICOLORED INDIVIDUAL GRAINS; LIGHT TO MEDIUM GRAY, GREENISH GRAY, WHITE, COLORLESS, YELISH GREEN, RED TO REDDISH BROWN LITHS; FINE LOWER TO COARSE LOWER, DOMINANTLY MEDIUM LOWER; SUBANGULAR TO ANGULAR; MODERATELY WELL SORTED; DISAGGREGATED TO VERY LOOSELY CONSOLIDATED WITH LIGHT GRAY, ASHY SUPPORTING MATRIX; MODERATELY CALCAREOUS; COMMON TO ABUNDANT BLACK, CARBONACEOUS MATERIAL. VOLCANIC ASH (3950' - 4250') = LIGHT GRAY TO VERY LIGHT GRAY, OCC WITH GRAYISH ORANGE PINK SECONDARY HUES; LOCAL YELLOWISH GRAY VARIATION; SOFT; VERY ASHY TO CLAYEY TO SOFT MATTE TEXTURES; DULL GLASSY TO DULL LUSTRE; COMMON TO ABUNDANT VISIBLE GLASS SHARDS; OBVIOUS VITRICLASTIC ORIGIN DESPITE REDEPOSITION; LESS REWORKED AND REMIXED THAN ASSOCIATED TUFFACEOUS CLAY; HAS SPARSE BUT EVENLY DISTRIBUTED BLACK SUBMETALLIC MAFIC MINERALS; OCC WITH MICROTHIN CARB LAMS. TUFFACEOUS SHALE (4030'-4100') = LIGHT GRAYISH BROWN TO GRAYISH BROWN; SLIGHTLY TO MODERATELY FIRM, SLIGHTLY TO MODERATELY BRITTLE; SUBPLATEY TO SUBSPLINTERY HABIT; MODERATELY TO POORLY DEVELOPED FISSILITY; CLAYEY TO MOTTLED CLYEY ASHY TEXT; DULL LUSTRE. TUFFACEOUS CLAYSTONE (4010'-4300') = LIGHTGRAYISH BROWN TO GRAYISH BROWN, PALE BROWN, YELLOWISH GRAY; MANY FAINT VARIATIONS OF GRAY, BROWN, BROWNISH GRAY AND GREENISH BROWN SECONDARY HUES; SOFT TO SLIGHTLY FIRM TO SLIGHTLY BRITTLE; ASHY TO CLAYEY TO SOFT MATTE TEXTURES; DULL TO SOFT GLASSY TO MICROSPARKLY LUSTRE; SPOTTY TO ABUNDANT VISIBLE GLASS SHARDS; VERY CLOSELY GRADATIONAL TO THE LESS REWORKED "MIXED, MOTTLED" TEXTURE & OFTEN SILTY. SAND (4005'-4500') = LIGHT MEDIUM TO MEDIUM GRAY WITH VERY STRONG GREENISH GRAY SECONDARY HUES; LOCALLY DARK GREENISH GRAY; COMMON "DIRTY" SALT AND PEPPER APP; VERY FINE UPPER TO VERY COARSE LOWER, AND TRACE GRANULES; MOSTLY MODERATE SORTING IN FINE UPPER TO COARSE LOWER RANGE; APPEARS SOME FINING UPWARD IN THE MOST MASSIVE SECTIONS; MODERATELY WELL SORTED AT TOP OF SECTION AND POOR SORTING AT BASE; ENTIRE RANGE OF ROUNDEDNESS AND SHAPE, BUT DOM SUBANGULAR TO ANGULAR AND SUBDISCOIDAL TO SUBSPHERICAL; LARGER GRAINS/CLASTS ARE MORE OFTEN ROUNDED; ENTIRELY DISAGGREGATED; RARE CONSOLIDATED PIECES HAVE WEAK SOLUBLE TUFF CLAY MATRIX SUPPORT; RARE CALC CMTD SS; COMPOSITIONAL GRAYWACKE (>30% LITHIC LITHICS); EST 50 70% QUARTZ AND VOLCANIC GLASS, TR FELDSPAR, TR 10% CHALCEDONY/ QUARTZITE/JASPER/OTHER FORMS OF SILICA, 30 50% LITHICS AND MAFICS; 60 70% OF LITHICS ARE GREEN TO MOTTLED GREEN TO GRAYISH GREEN LOW GRADE META GREENSTONE ROCK FRAGMENTS, 20 40% BLACK MAFIC MNRLS AND MED GRADE META ARGILLITE PHYLLITE ROCK FRAGMENTS; 1 2% OF TOTAL SAMPLE IS ORANGE TO ORANGISH RED TO REDDISH ORANGE VOLCANIC LITHIC ROCK FRAGMENTS, VERY DISTINCTIVE AGAINST GRY/GREEN BACKGROUND; QUARTZ IS COLORLESS TO PALE GRAY, 75% TRANSLUCENT/25% TRANSPARENT; COMMON ABUNDANT COLORLESS AND TRANSPARENT VOLCANIC GLASS. TUFFACEOUS CLAYSTONE (4350'- 4425') = LIGHT GRAY TO LIGHT GRAYISH BROWN WITH LIGHT BROWN TO LIGHT BROWNISH GRAY SECONDARY HUES; SOFT TO SLIGHTLY FIRM TO SLIGHTLY BRITTLE AT TIMES; IRREGULAR SHAPED CUTTINGS; ASHY TO CLAYEY TO SILTY TEXTURE; DULL TO MICROSPARKLY LUSTRE; COMMON TO ABUNDANT VISIBLE GLASS SHARDS; NON CALCAREOUS; COMMON BLACK, MICROTHIN CARBONACEOUS LAMINATIONS AND PIECES; TRACE CALCITE PIECES. COAL (4380'-4470') = BLACK WITH DARK DUSKY BROWN SECONDARY HUES; MODERATELY HARD TO BRITTLE; PLATY TO BLOCKY; DOMINANTLY PLANAR FRACTURE; COMMON BIRDEYE FRACTURE; TRACE CONCHOIDAL FRACTURE; SMOOTH TO DENSE MATTE TEXTURE; SLIGHTLY RESINOUS TO SLIGHTLY DULL EARTHY LUSTRE; RARE TRACE VISIBLE OUTGASSING BUBBLES; PRESENT AS THIN BEDS IN DOMINANTLY CLAYSTONE AND SAND FORMATION. VOLCANIC ASH (4250'-4550') = LIGHT GRAY TO VERY LIGHT GRAY, OCC WITH GRAYISH ORANGE PINK SECONDARY HUES; LOCAL YELLOWISH GRAY VARIATION; SOFT; VERY ASHY TO CLAYEY TO SOFT MATTE TEXTURES; DULL GLASSY TO DULL LUSTRE; COMMON TO ABUNDANT VISIBLE GLASS SHARDS; OBVIOUS VITRICLASTIC ORIGIN DESPITE REDEPOSITION; LESS REWORKED AND REMIXED THAN ASSOCIATED TUFFACEOUS CLAY; HAS SPARSE BUT EVENLY DISTRIBUTED BLACK SUBMETALLIC MAFIC MINERALS; OCC WITH MICROTHIN CARB LAMS. SAND / SANDSTONE (4500'- 4700') = MEDIUM TO DARK GREENISH GRAY, LIGHT MEDIUM TO MEDIUM GRAY WITH VERY STRONG GREENISH GRAY SECONDARY HUES; "DIRTY GREENISH" SALT AND PEPPER APPEARANCE; VERY FINE UPPER TO TRACE GRANULE; APPEARS ROUGH FINING UPWARD IN MASSIVE SAND SECTIONS; MODERATE TO MODERATELY WELL SORTED IN UPPER SECTIONS, AND MODERATE TO POOR SORTING IN BASAL SECTIONS; ABUNDANTLY WITHIN FINE UPPER TO MEDIUM UPPER RANGE; ALL CATEGORIES OF ROUNDEDNESS AND SHAPE PRESENT, BUT DOM SUBANGULAR ANGULAR AND SUBDISCOIDAL; DISAGGREGATED, MINOR SMALL CONSOLIDATED PIECES OF CLAY MATRIX SUPPORTED SS; ONLY RARE PIECES OF LOOSE XLN CALCITE; COMPOSITIONAL GRAYWACKE (>30% LITHICS) TO OCC LITHIC ARENITE; QUARTZ IS 80 90% COLORLESS TO VERYPALE GRY OR GRAYISH BROWN AND TRANSLUCENT, 10 20% TRANSPARENT; NOTE THAT 20 40% OF TOTAL SILICA FRACTION IS COLORLESS TRANSPARENT (VOLCANIC) GLASS; EST 50 70% QTZ AND GLASS, TR 5% FELDSPAR, TR 10% CHALCEDONY CHERT JASPER, 25 50% LITHICS AND MAFIC MNRLS; 60 80% OF LITHICS ARE VARI GREEN TO GRAYISH GREEN GREENSTONE ROCK FRAGS; ABUNDANT BLACK MAFICS, AND ARGILLITE ROCK FRAGS; NOTE SPARSE (1 2%) EVENLY DISTRIBUTED VERY DISTINCTIVE ORANGE TO ORANGISH RED LITHIC VOLCANIC ROCK FRAGS. COAL (4720'- 4750') = BLACK WITH DARK DUSKY BROWN SECONDARY HUES; MODERATELY HARD TO BRITTLE; PLATY TO BLOCKY; DOMINANTLY PLANAR FRACTURE: COMMON BIRDSEYE FRACTURE; TRACE CONCHOIDAL FRACTURE; SMOOTH TO DENSE MATTE TEXTURE; SLIGHTLY RESINOUS TO SLIGHTLY DULL EARTHY LUSTRE; PRESENT AS THIN BEDS IN DOMINANTLY SAND AND CLAYSTONE FORMATION. SAND/SANDSTONE (4700' - 5000') - MEDIUM TO DARK GREENISH GRAY, LIGHT MEDIUM TO MEDIUM GRAY WITH VERY STRONG GREENISH GRAY SECONDARY HUES; SALT AND PEPPER APPEARANCE; VERY FINE UPPER TO TRACE GRANULE; APPEARS ROUGH FINING UPWARD IN MASSIVE SAND SECTIONS; MODERATE TO MODERATELY WELL SORTED IN UPPER SECTIONS AND MODERATE TO POOR SORTING IN BASAL SECTIONS; ABUNDANTLY WITHIN FINE UPPER TO MEDIUM UPPER RANGE; ALL CATEGORIES OF ROUNDNESS AND SHAPE PRESENT, BUT DOM SUBANGULAR ANGULAR AND SUBDISCOIDAL; DISAGGREGATED, MINOR SMALL CONSOLIDATED PIECES OF CLAY MATRIX SUPPORTED SS; ONLY RARE PIECES OF LOOSE XLN CALCITE; COMPOSITIONAL GRAYWACKE(>30% LITHICS) TO OCC LITHIC ARENITE; QUARTZ IS 80 90% COLORLESS TO VERYPALE GRAY; 20 40% SILICA FRACTION IS COLORLESS (VOLCANIC) GLASS; EST 50 70% QTZ AND GLASS,TR 5% FELDSPAR, TR 10% CHALCEDONY CHERT JASPER,25 50% LITHICS AND MAFIC MNRLS; 60 80% LITHICS ARE VARIGREEN TO GRAYISH GREEN GREENSTONE ROCK FRAGMENTS, 1 2% EVENLY DISTRIBUTED ORANGE TO ORANGISH RED LITHIC VOLCANIC ROCK FRAGS. TUFFACEOUS CLAYSTONE (4695' - 5000') GRAY TO LIGHT GRAYISH BROWN; SOFT TO SLIGHTLY FIRM; IRREGULARLY SHAPED; ASHY TO CLAYEY TO SILTY TEXTURE; DULL LUSTRE; SLIGHTLY CALCAREOUS. SAND (4950' - 5050') = LIGHT TO MEDIUM GRAY WITH SCATTERED SALT AND PEPPER OVER ALL APPEARANCE; INDIVIDUAL GRAINS DOMINANTLY LIGHT GRAY TO LIGHT GREENISH GRAY AND COLORLESS QUARTZ FRAGMENTS, OTHER LITHS ARE BLACK, WHITE, PALE RED TO PALE REDDISH ORANGE, AND DARK GREENISH GRAY; FINE LOWER TO RARE VERY COARSE UPPER, DOMINANTLY MEDIUM UPPER TO MEDIUM LOWER; ANGULAR TO SUBANGULAR, RARE SUBROUNDED; MODERATELY WELL SORTED; DOMINANTLY UNCONSOLIDATED TO VERY LOOSELY CONSOLIDATED WITH VERY LIGHT GRAY TO LIGHT GRAYISH WHITE CLAYEY/ASHY SUPPORTING MATRIX; VERY SOLUBLE; NON TO SLIGHTLY CALCAREOUS TRACE CALCITE PIECES; TRACE BLACK CARBONACEOUS MATERIAL. TUFFACEOUS CLAYSTONE (5000' - 5120') = LIGHT GRAY TO LIGHT BROWNISH GRAY WITH LIGHT GRAYISH BROWN SECONDARY HUES; VERY SOFT TO SLIGHTLY FIRM; IRREGULAR SHAPED CUTTINGS; VERY SILTY IN PART; CLAYEY TO ASHY TO SILTY TEXTURE; DULL EARTHY TO SLIGHTLY MICROSPARKLY LUSTRE; COMMON VISIBLE GLASS SHARDS PRESENT; POOR ADHESIVENESS; POOR TO FAIR COHESIVENESS; PRESENT AS SUPPORTING MATRIX FOR SAND; VERY SOLUBLE; NON CALCAREOUS; TRACE BLACK CARBONACEOUS MATERIAL. SAND (5100' - 5200') = SAME GENERAL CHARACTERISTICS AS DESCRIBED ABOVE WITH INCREASE IN RED TO REDDISH ORANGE LITHS AND INCREASE IN VERY LIGHT GRAY TO LIGHT GRAYISH WHITE TUFFS; VERY SOFT; ASHY; NON CALCAREOUS; OCCASIONAL MOTTLED TUFFS AS SUPPORTING MATRIX FOR VERY LOOSELY CONSOLIDATED SANDS. SAND (5200' - 5240') = VARICOLORED INDIVIDUAL GRAINS WITH LIGHT TO MEDIUM GRAY OVERALL APPEARANCE WITH SLIGHT SALT AND PEPPER; INDIVIDUAL GRAINS DOMINANTLY LIGHT TO MEDIUM GRAY TO LIGHT GREENISH GRAY AND COLORLESS QUARTZ/VOLCANIC GLASS PIECES, COMMON BLACK LITHS, SCATTERED REDDISH ORANGE TO REDDISH BROWN LITHS; FINE LOWER TO SCATTERED VERY COARSE UPPER FRAGMENTS, DOMINANTLY MEDIUM UPPER TO MEDIUM LOWER; ANGULAR TO SUBANGULAR, OCCASIONAL SUBROUNDED, LARGER PIECES; MODERATELY WELL SORTED; DISAGGREGATED TO VERY LOOSELY CONSOLIDATED WITH VERY SOLUBLE, ASHY/CLAYEY, SUPPORTING MATRIX; NON TO SLIGHTLY CALCAREOUS; TRACE CALCITE FRAGMENTS; COMMON BLACK CARBONACEOUS MATERIAL. COAL (5265' - 5300') = BLACK WITH VERY DARK BROWN TO DARK BROWNISH DARK GRAY SECONDARY HUES; MODERATELY HARD; OCCASIONALLY BRITTLE; PLATY TO BLOCKY CUTTINGS; DOMINANTLY PLANAR FRACTURE WITH SCATTERED BIRDEYE FRACTURE; SMOOTH TO DENSE MATTE TEXTURE; SLIGHTLY RESINOUS TO EARTHY LUSTRE; TRACE, FAINT VISIBLE OUTGASSING BUBBLES PRESENT; COAL PRESENT AS THIN BEDS IN SAND/SANDSTONE FORMATION TUFFACEOUS CLAYSTONE (5320' - 5350') = LIGHT GRAY TO LIGHT BROWNISH GRAY WITH LIGHT GRAYISH BROWN SECONDARY HUES; VERY SOFT TO SLIGHTLY FIRM; IRREGULAR SHAPED CUTTINGS; VERY SILTY IN PART; CLAYEY TO ASHY TO SILTY TEXTURE; DULL EARTHY TO SLIGHTLY MICROSPARKLY LUSTRE; COMMON VISIBLE GLASS SHARDS PRESENT; POOR ADHESIVENESS; POOR TO FAIR COHESIVENESS; PRESENT AS SUPPORTING MATRIX FOR SAND; VERY SOLUBLE; NON CALCAREOUS; TRACE BLACK CARBONACEOUS MATERIAL. TUFFACEOUS CLAYSTONEB (5350' - 5410') = LIGHT GRAY TO LIGHT BROWNISH GRAY WITH LIGHT GRAYISH BROWN SECONDARY HUES; VERY SOFT TO SLIGHTLY FIRM; IRREGULAR SHAPED CUTTINGS; VERY SILTY IN PART; CLAYEY TO ASHY TO SILTY TEXTURE; DULL EARTHY TO SLIGHTLY MICROSPARKLY LUSTRE; COMMON VISIBLE GLASS SHARDS PRESENT; POOR ADHESIVENESS; POOR TO FAIR COHESIVENESS; PRESENT AS SUPPORTING MATRIX FOR SAND; VERY SOLUBLE; TRACE BLACK CARBONACEOUS MATERIAL; SLIGHTLY CALCAREOUS. SAND (5240' - 5500') = VARICOLORED INDIVIDUAL GRAINS WITH LIGHT TO MEDIUM GRAY OVERALL APPEARANCE WITH SLIGHT SALT AND PEPPER; INDIVIDUAL GRAINS DOMINANTLY LIGHT TO MEDIUM GRAY TO LIGHT GREENISH GRAY AND COLORLESS QUARTZ/VOLCANIC GLASS PIECES, COMMON BLACK LITHS, SCATTERED REDDISH ORANGE TO REDDISH BROWN LITHS; FINE LOWER TO SCATTERED VERY COARSE UPPER FRAGMENTS, DOMINANTLY MEDIUM UPPER TO MEDIUM LOWER; ANGULAR TO SUBANGULAR, OCCASIONAL SUBROUNDED, LARGER PIECES; MODERATELY WELL SORTED; DISAGGREGATED TO VERY LOOSELY CONSOLIDATED WITH VERY SOLUBLE, ASHY/CLAYEY, SUPPORTING MATRIX; NON TO SLIGHTLY CALCAREOUS; TRACE CALCITE FRAGMENTS; COMMON BLACK CARBONACEOUS MATERIAL. SAND (5500' - 5530') = LIGHT TO MEDIUM GRAY WITH SCATTERED SALT AND PEPPER APPEARANCE; INDIVIDUAL GRAINS LIGHT GRAY TO LIGHT GREENISH GRAY, WITH COLORLESS QUARTZ FRAGS; OTHER LITHS ARE BLACK, WHITE, LIGHT GREEN, ORANGE, YELLOW; FINE LOWER TO RARE COARSE UPPER, DOMINANTLY MEDIUM LOWER; ANGULAR TO SUBANGULAR; TRACE BLACK CARBONACEOUS MATERIAL, DOMINANTLY UNCONSOLIDATED. TUFFACEOUS CLAYSTONE (5550' - 5630') = LIGHT GRAY TO LIGHT BROWNISH GRAY WITH LIGHT GRAYISH BROWN SECONDARY HUES; SOFT TO FIRM; IRREGULAR SHAPED CUTTINGS; VERY SILTY; CLAYEY TO ASHY TEXTURE; DULL EARTHY TO MICROSPARKLY LUSTRE; VISIBLE GLASS SHARDS PRESENT; POOR TO FAIR COHESIVENESS, POOR ADHESIVENESS; PRESENT AS SUPPORTING MATRIX FOR SAND, VERY SOLUBLE; NON CALCEROUS; TRACE BLACK CARBONACEOUS MATERIAL. SAND (5600' - 5660') = LIGHT TO MEDIUM GRAY WITH SCATTERED SALT AND PEPPER APPEARANCE; INDIVIDUAL GRAINS LIGHT GRAY TO LIGHT GREENISH GRAY, WITH COLORLESS QUARTZ FRAGS; OTHER LITHS ARE BLACK, WHITE, LIGHT GREEN, ORANGE, YELLOW; FINE LOWER TO RARE COARSE UPPER, DOMINANTLY MEDIUM LOWER; ANGULAR TO SUBANGULAR; TRACE BLACK CARBONACEOUS MATERIAL, DOMINANTLY UNCONSOLIDATED WITH DISTINCTIVR INCREASE IN ASHY/CLAYEY SUPPORTING MATRIX. SAND (5660' - 5720') = LIGHT TO MEDIUM GRAY WITH SCATTERED SALT AND PEPPER APPEARANCE; INDIVIDUAL GRAINS LIGHT GRAY TO LIGHT GREENISH GRAY, WITH COLORLESS QUARTZ FRAGS; OTHER LITHS ARE BLACK, WHITE, LIGHT GREEN, ORANGE, YELLOW; FINE LOWER TO RARE COARSE UPPER, DOMINANTLY MEDIUM LOWER; ANGULAR TO SUBANGULAR; INCREASE IN COMMON BLACK CARBONACEOUS MATERIAL; DOMINANTLY UNCONSOLIDATED; ASHY/CLAYEY SUPPORTING MATRIX. TUFFACEOUS CLAYSTONE (5630' - 5720') = LIGHT GRAY TO LIGHT BROWNISH GRAY WITH LIGHT GRAYISH BROWN SECONDARY HUES; SOFT TO FIRM; IRREGULAR SHAPED CUTTINGS; VERY SILTY; CLAYEY TO ASHY TEXTURE; DULL EARTHY TO MICROSPARKLY LUSTRE; VISIBLE GLASS SHARDS PRESENT; POOR TO FAIR COHESIVENESS, POOR ADHESIVENESS; PRESENT AS SUPPORTING MATRIX FOR SAND, VERY SOLUBLE; NON CALCEROUS; TRACE BLACK CARBONACEOUS MATERIAL. SAND (5720' - 5740') = LIGHT TO MEDIUM GRAY WITH SCATTERED SALT AND PEPPER APPEARANCE; INDVDL GRAINS LIGHT GRAY TO LIGHT GREENISH GRAY WITH COLOR LESS QUARTZ FRGMNTS; OTHER LITHS ARE BLACK, WHITE, YELLOW, ORANGE, LIGHT GREEN, DARK GREEN; FINE LOWER TO COARSE UPPER, DOM MEDIUM LOWER; ANGULAR TO SUBANGULAR; PRESENCE OF BLACK CARBONACEOUS MATERIAL. SAND (5750' - 5790') = LIGHT TO MEDIUM GRAY OVERALL APPEARENCE WITH INDIVIDUAL GRAINS DOMINANTLY LIGHT TO MEDIUM GRAY, LIGHT GREENISH GRAY, COLORLESS QUARTZ, ABUNDANT BLACK LITHS, WHITE, AND TRACE REDDISH BROWN AND RARE LIGHT BLUISH GREEN LITHS; FINE LOWER TO COMMON VERY COARSE UPPER, DOMINANTLY MEDIUM UPPER; ANGULAR TO SUBANGULAR; MODERATELY WELL SORTED; DISAGGREGATED TO VERY LOOSELY CONSOLIDATED WITH LIGHT GRAY, CLAYEY/ASHY SUPPORTING MATRIX; NON CALCAREOUS; TRACE CALCITE FRAGMENTS; ABUNDANT BLACK CARBONACEOUS MATERIAL. I RIG ACTIVITIES SUMMARY MARATHON KU 31-7X n -- w ~ ~ D ~ ,, ~ ~ z ~ o ~ ~ ~ - - - ~ ~ ~ 01/02 3.0 2,0 0.5 3.5 10.0 3.0 0.5 1.5 24.0 01/03 21.5 0.5 2.0 24.0 01/~ 22.5 0.5 0.5 0.5 24.0 01/05 12.5 6.0 2.5 1.0 0.5 1.5 24.0 01/06 12.0 6.0 1.5 0.5 4,0 24.0 01/07 23.0 1.0 24.0 01/08 9.5 6.0 1.0 3.0 3,5 1.0 24.0 01109 5.0 3.5 12.5 3.0 24.0 01110 5.5 2.0 14.5 2.0 24.0 01111 0.0 01112 0.0 01/13 0.0 01/14 0.0 01115 0.0 01116 0.0 01/1~ 01118 0.0 01/19 0.0 01120 0.0 , 01/21 0.0 01122 0.0 01123 0.0 01124 0.0 .. 01/25 0.0 01/26 0.0 01127 0.0 01/28 0,0 01129 0.0 01130 0.0 01/31 0.0 0~01 0,0 0~02 0.0 0~03 0.0 0~04 0.0 0~05 0.0 02106 0~07 0.0 0~08 0.0 0~09 0.0 0~10 0.0 02/11 0.0 0~12 0.0 0~13 0.0 ~O~A[ lO9.O 27,0 ~5.5 ] ].5 2.5 o,0 ].5 0.0 ].0 ~4.5 0.0 0.0 0.0 0.0 0.0 32.0 ~3.5 3.0 0.0 0.5 0.o 2.0 0.0 2.5 216 , , 10.~ 2.62 1.50 1.11 0.24 0.00 0.15 0.00 0.10 1.41 0.00 0.00 0.00 0.00 0.00 1.16 1.31 0.29 0.00 0.05 0.00 0.19 0.00 0.24 20.93 MARATHON KU 31-7X RIG TIME DISTRIBUTION MISCELLANEOUS SAFETY MEETING DIR. WORK FISHING LEAK OFF TEST TEST CASING NIPPLE DOWN/UP DRILL CIRCULATING TEST LINES/BOPE HA [] DRILL [] TRiP [] REAM [] CIRCULATING [] SHORT TRIP [] RIG SERVICE []RIG REPAIRS []SLIP DRILL LINE []SURVEY []LOGGING []TOP DRIVE []RUN CASING []CMTINGACTIVITY []DRILL CEMENT []RIG UP/DWN EQUIP []BHA []TESTLINES/BOPE []NIPPLE DOWN/UP •TEST CASING [] LEAK OFF TEST •FISHING [] DIR WORK [] SAFETY MEETING •MISCELLANEOUS MUD REPORT RECORD M I MARATHON OIL COMPANY KU 31-7X KENAI GAS FIELD GLACIER DRILl.lNG RiG #1 APl Number: 50-133-204954X) Depths: 1520' to 5790' DATE DEPTH ~ VIS PV YP ~ELS FL FC SOL OIL SD MBT pH AIk CI- Ca+ MD I TVD 0110110~-- 1520/1478 I 8.70 [ 43 5 I 16 ~--~'11-7~'"r I I 3.0 I 0/97 }' 0.00 I 0.00 I 7.5 ] 29000 / 80 01/02/0-T 1895/1846 8.85 38 5 I 18 I 9/12J131 8.6 I I / 5.0 I 0/951 0.25; 2.50 I 7.5 ~ 0.00 28000i 100 01103/013162 / 2999 --~.05 41 7 23 1'~'~'~*~/1-'~~----------'~--'~-~---0~-~--~"-~-~-~'-~-'-~'~-~---0.00 27000 1 480 01/041014145 / 3517- 9.10 40 S .... 2'~3--"] 1~17-'~---~-.0---I -~---~-- 6.0 t 0~95 I mR ~5.00 1 7.5 ~-.~ 29(X)0 520-- 01/051014627 / 39709.30__ 44 9 26 -~*--1-0.2-~-~---~'---'T ~ '07~' TR --~7.~-~---~ ~ 0.05 30500 520 01107101 5468/4523 _,L 9.50 47 11 31 18J32/36 - 10.-----~--t~__.~ 9'0 1.0/90 '---~E 12.50 9.0 0.05 28500 ~.01/0~5~ __,-~/~--/ 9.40 46 10 24 '1-sr~"-7/33 12.4 6.0 1.0/91 TR 13.75 6.5 0.0S I. 27O0O ,~0 0~109/01 57~0/4749 / 9.40 50 10 32 17/22/23 7.6 2 6.0 1.5/~0.5 TR 10.00 S.0 0.00 / 300OO 240 01110101 5790 / 4749b 9.25 46 9 23 14120/20 9.9 I 7.0 1.5/91.5 mR 10.00 9.0 0.05t 28000 280 -~1/11/01 5790 / 4749 9.30 45 8 20 11/16/17 12.0 2 7.0 ~-.5/91.5 TR 10.0~-- 8.0 0.00 29000 320 I *~- _ - ................................... _. I --- __ --"~_ ......... _ ........ I __ ........................... i .............. . ....... -- _- ................ !._ .......... :_.:_____ ............... .... ............................... ............. ................................................................... ............ ............................... ~ .................................. ............ ................ .......... _ , __ __ ............................................. ............... ~ .......... r. .................................................... I ................... I ........... ....................................... ................. .__ .............. ....................... .... --- ....... ' __-_~ .... -, BIT RECORD KU 31-7X MARATHON KENAI GAS FIELD IKENAI PENNINSULA, AK IJanuary 01, 2001 to January 09, 2001 BAKER HUGHES INTEQ SURVEY REPORT MARATHON OIL COlt KU 31-7X KENAI GAS FIELD MWD Survey reference Criteria ~ ~i' -i_~i, ' I ,, !Reference G ,xxxx. O0 mGal 1APl Number ] ~ ........ ~ i i ............................ i Last survey date, (Magnetic date) I l Kenai BoroUgh, Alask~a', ...... ~_Reference H j_xxxx.xx HCNT Survey Interval (MD) 136.0' to 5790.0' ]GLACIER DRILLING RIG #t I Reference Dip i xx. xx degrees ...... Method:Svy ca culation, ~ Minimum curvature I J Tolerance of G -- 'i (+/-) x.00 mGal ',. i~i iTolerance of H !(+/-) x.00 HCNT .......[Method for DLS I Minimum curvature i IDepth Reference Permanent datum: MSL, Depth: Driller's, GL: ', RT ' ~ Tolerance of Dip (+/-) 0.x0 deg._r~s Vertical section origin t [ [ __~ Corrections Latitude(+N/S-) 0.00' Departure(+E/VV GeOmagnetic data ~ Magnetic dec (+ENV-) xx.xx degrees ~roject-~ Platform reference point ............ Magnetic model]_ ............................ - Gdd convergence (+E/W 0.00 degrees iurvey ~Latitude (+N/S-) Magnetic field strength Total Azi corr (+ENV-) xx.xx degrees T.D. Departure (+E/VV-) Magnetic dec (+E/VV-) _(Total Azi corr = magnetic dec - grid conv) Magnetic dip Sag applied (Y/N) No degree: 0.00 -- Survey Measured Incl Azimuth Course TVD Vertical Displ Displ DLS Build Walk # depth angle ' --- angle length depth section +N/S- +E/W- deg/lO~') Rate Rate {ft) {de~) (deg) (ft) (ft) (ft) (ft) (ft) (+) (-) (+) (-) 1 136.00 0.35 83.00 136 136.00 0.40 0.05 0.41 0.26 0.26 ___ - 2 225.00 0.44 61.30 89 225.00 0.94 0.25 0.98 0.19 0.10 3 317.00 0.42 53.90 92 316.00 1.46 0.62 1.56 0.06 -0.02 4 374.00 0.69 62.90 57 373.99 1.89 0.90 2.04 0.50 0.47 5 463.00 1.07 64.40 89 462.98 3.01 1.50 3.27 0.43 0.43 6 553.00 2.22 54.10 90 552.94 4.96 2.88 5.43 1.31 1.28 7 643.00 3.59 56.30 90 642.82 8.29 5.47 9.19 1.53 1.52 8 733.00 4.95 54.10 90 732.57 13.16 9.31 14.68 1.52 1.51 9 822.00 7.59 56.20 89 821.03 20.27 -- 14.83 22.68 2.98 2.97 2.~(~- 10 917.00 10.25 58.30 9~ 914.88 31.38 22.77 35.08--- 2.82 2.80 2.21 11 1015.00 12.25 58.30 98 1010.99 46.01 32.81 51.35 2.04 2.04 0.00 12 1108.00 13.80 55.60 93 1101.59 61.69 44.26 68.90 1.79 1.67 -2.90 13 1203.00 15.4--~- .......... 55.70 95 1193.50 ---79.33 57.81 ~8.73 1.78 1.78 0.11 14 1298.00 17.48 56.40 95 1284.59 99.26 72.86 111.09 2.11 2.09 0.74 ........ 15 1391.00 19.51 58.10 93 1372.79 121.00 88.80 135,91 2126 2,18 1.83 16 1464.00 20,21 59.30 73 1441.44 140.57 101.68 157.11 1.11 0.96 1.64 17 1517.00 19.74 60.00 53 1491.25 154.69 110.83 172.73 0.99 -0.99 1.32 18 1610.00 23.55 60.30 -- 93 1577.68 181.63 127.89 202.48 4.10 4.10 0.32 19 1705.00 25.22 59.90 '-95 1664.20 212.41 147.45 - 236148 1.77 1.76- -0.42- 20 1831.00 ....... -~'~,~-9-8--- 60.00 ..... :~2--~ ...... 1778.30 254.26 174.21 282.75 ........ -~.~ ....... --~.19 0.08 21 1955.00 24.72 60.30 124 1890.82 295.19 200.15 327.94 0.23 -0.21 0.24 22 2079.00 24.68 59.90 124 2003.48 335.85 225.98 372.86 0.14 -0.03 -0.32 23 2176.00 24.05 66.20 97 2091.85 368.43 244.12 408.47 2.76 -0.65 6.49 24 2361.00 22.77 79.60 93 2261.55 434.84 265.56 478.77 2.80 -0.88 6.77 25 2455.00 22.38 84.70 94 2346.36 469.45 270.50 514.48 2.12 -0.41 5.43 26 2549.00 23.04 90.70 94 2435.08 505.07 271.93 550.70 2.56 0.70 6.38 27 2642.00 24.29 96,80 93 2520.27 542.23 269.44 587,80 2.95 1.34 6.56 28 2734.00 26.09 102.80 92 2603.53 581.32 262.72 626.42 3.39 1.96 6.52 29 2831.00 27.83 108.40 97 2690.00 624.90 250.84 668.72 3.17 1.79 5.77 -- 30 2925.00 29.50 113.90 94 2772.49 668.82 234.53 710.71 3.32 1.78 5.85 31 3018.00 31.66 117.70 93 2852,56 713.93 :~;13.91 753.91 3.12 2.32 4.0~- 32 3111.00 33.68 122.90 ~3 2930.86 760.45 188.55 796.53 3.72 2.17 5.59 33 3205.00 36.01 127.10 94 3008.01 808.41 157.71 840.47 3.56 2,48 4.47 34 3298.00 37.83 131.30 93 3082.37 856.35 122.39 883.71 3.34 1.96 4.52 35 3393.00 40.14 133.90 95 3156.21 905.75 81.92 927.67 2.98 2.43 2.74 36 3486.00 42.10 136.20 93 3226.27 954.80 38.63 970.85 2.66 2.11 2.47 37 3580.00 44.70 137.10 94 3294.57 1005.50 -8.34 1015.18 2.84 2.77 0.96 38 3672.00 47.35 138.70 92 3358.44 1056.57 -57.47 1059.54 3.14 2.88 1.74 39 3764.00 49.20 140.40 92 3419.67 1108.26 -109.72 1104.07 2.44 2.01 1.85 40 3890.00 49.20 140.80 126 3502.01 q178.92 -183.43 1164.61 0.24 - 0.00 0.32 41 4014.00 49.72 142.20 124 3582.61 1247.72 -257.18 1223.27 0.95 0.42 1.13 --. 42 4140.00 51.16 143.10 126 3662.85 1317.29 -334.40 1282.19 1.27 1.14 0.71 43 4264.00 50.82 143.20 124 3740.90 1385.72 -411.50 1339.98 0.28 -0.27 0.08 44 4392.00 50.44 143.10 128 3822.10 1455.99 -490.68 1399.32 -- 0.30 -0.30 -0.08 --~-5-- 4519.00 50.00 141.90 127 3903,36 1526.08 -568.11 1458.73 0.80 ..... -0.--~- .......... ~). 94 --~--~ ....... 4644.00 49.71 142.60 125 3983.95 1594.98 -643.66 1517.23 0.49 -0-.2~- 0.5~- , , '47 _~ 4769.00 50.10 141.70 125 4064.46 ] 1664.06 I-719.17 1575.91 0.63 __1. 0.31 i -0.72' 4893.00 49.73 142.60 124 4144.31 1732.59 I -794.08 1634.12 0.63 [ -0.30 ']' 0.73 49 I 5020.00 49.16 142.00 , 127 4226.88 18.2.11 1 -870.42 I 1693.12 0.57 I -0.45 !-0.47 _~o !__~.oo ~.~ t ~.~o I ~ t ~o~.~ ~ ~o.~ ! -~.~ I ~.~ i o.~ ~ -o.~ -o.~ ~--5~ 530~.005270'00] 48.0747.S~~ ~42.30a42'40 ~ 12~ ~73.5~ ~ 2002.38 -~080.38 ~ ~8~3.27 ~ 0.3¢ [ -38.00 ~ -0.08 ~ ' 5790.00 45.37...... 142.00 i ~' ~ 47~ [ ~) ~~ / 2~3.~6 0.51 j -0.51 0.00 57 58 59 .................................... 60 .......... 61 ...... 62 63 ....................... 65 ................................................................................... 66 67 ........... 68 .... 69 70 71 ........................... 72 ..................... 73 74 75 ....... 76 77 78 ................................................................................................................................................ 79 ............................. ............................ 80 .............................................................................................................................................................. 81 ....................................................................................................................................................................................... 82 ............................................................................................................................................................. 83 m m Daily Report Page 1 of 1 MARATHON OIL COMPANY KU 31-7X REPORT FOR RICK GIDEON DATE Jan 12, 2001 TIME 00:00:00 i CAStNG tNFORMATION 13 3/8" ~ 1508' DEPTH SURVEY DATA 5790' BIT INFORMATION NO. SIZE TYPE SIN 4 12.25 RB~ C1LRGSP BZ335 iiii DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.25 VIS 46 PV FC 1 SOL 7 SD i MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) HIGH DITCH GAS 39 CUTTING GAS 0 METHANE(C-I) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT LITHOLOGY DAILY WELLSITE REPORT EPOCH DEPTH 5T90 YESTERDAY 5790 24 Hour Footage 0 iii INCLINATION 45.37 INTERVAL JETS IN OUT 18,18,20 5661 5790 HIGH 21.8 @ 5790 21.8 0 @ 5790 0 28 @ 5790 28 0 @ 5790 0 2168 @ 5790 2168 DEPTH: 5790 9 YP 23 TR O~L 'l.5/91.5 PRESENT OPERATION= RUN 9 5/8" CASING FOOTAGE 129 LOW @ 5790 @ 5790 @ 5790 @ 5790 @ 5790 i i iii AZIMUTH 142.0 HOURS 5 AVERAGE 1.$ -1.$ 1.$ -1.$ 1.$ iii IEI IIII IIII IIII IIII VERTICAL DEPTH 4748.6' CONDITION REASON T/B/C PULLED 2,2,ER,A,E,0~,N,TD TD CURRENT AVG ' 21.8 ft/hr 0.0 amps 28.1 Klbs 0 RPM 2168 psi i ii i ii ii iii ,111 ,ill, ,111111 FL 9.9 Gels 14/20/20 CL- 28000 MBL 10 pH 9 Ca+ 280 ii LOW AVERAGE 5790 39 @ 5790 1.$ TRIP GAS= 51 5790 0 @ 5790 -1.$ WIPER GAS= , CHROMATOGRAPHY(ppm) SURVEY= 7541 @ 5790 7541 @ 5790 1.$ CONNECTION GAS HIGH= 0 @ 5790 0 @ 5790 -1.$ AVG= 0 @ 5790 0 @ 5790 -1.$ CURRENT 0 @ 5790 0 @ 5790 -1.$ CURRENT BACKGROUND/AVG 0 @ 5790 0 @ 5790 -1.$ LITHOLOGY/REMARKS GAS DESCRIPTION DALLY ACTIVITY SUMMARY FINISH LOG RFT; RIG DOWN SCHLUMBERGER; RIH WI BIT; CBU; POH; CHANGE RAMS; RIH W/9 518" CSG. Epoch Personel On Board= 1 Report by: RALPH WINKELMAN Dally Cost 2270 file://C:~marathonL2001011 l.htm Daily Report 1/11/01 Page 1 of 1 MARATHON OIL COMPANY KU 31-7X REPORT FOR RICK GIDEON DATE, JANUARY 11,201 TIME 00:00:00 CASING INFORMATION 13 3/8" @ 1508' DEPTH SURVEY DATA 5790' i ii BIT INFORMATION NO. SIZE TYPE SIN 3 12.25 RBI C1LRGSP BZ335 DALLY WELLSITE REPORT DEPTH 5850 YESTERDAY 5850 24 Hour Footage 0 INCLINATION AZIMUTH 45.37 142.0 JETS 18,~8,20 INTERVAL IN OUT FOOTAGE 5661 5790 129 EPOCH DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9,4 VIS FC 2 SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH gAS CUTTING GAS METHANE(C-I) ETHANE(C-2) PROPANE(C~3) BUTANE(C-4) PENTANE(C-5) iii HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT LITHOLOGY 50 PV 8 SD HIGH 0.0 @ 5850 0 @ 5850 o @ 585o 0 @ 5850 0 @ 5850 DEPTH: 5790 10 YP TR O~L LOW AVERAGE 0 @ 5850 -1.$ 0 @ 5850 -1.$ 0 @ 5850 -1.$ 0 @ 5850 -1.$ 0 @ 5850 -1.$ 32 FL 7.6 Gels 1.5/90.5 MBL 10 pH High LOW AVERAGE 0 @ 5850 0 @ 5850 -1.$ 0 @ 5850 0 @ 5850 -1.$ CHROUATOGRAPHY(ppm) 0 @ 5850 0 @ 5850 -1.$ 0 @ 5850 0 @ 5850 -1.$ 0 @ 5850 0 @ 5850 0 @ 5850 0 @ 5850 -1.$ 0 @ 5850 0 @ 5850 -1.$ LITHOLOgY/REMARKS PRESENT OPERATION= LOG W/RFT HOURS 4.7 VERTICAL DEPTH 4748.6' CONDITION 'I'/B/C CURRENT AVG REASON PULLED TD fi/hr amps Klbs RPM psi 17/22/23 CL- 30000 8 Ca+ 240 CCi TRIP GAS= WIPER GAS= 43 SURVEY= CONNECTION GAS HIGH= AVG= CURRENT 0 CURRENT BACKGROUND/AVG 0 GAS · DESCRIPTION DALLY ACTIVITY SUMMARY FINISH WIPER TRIP; POH; RIH W/SCHLUMBERGER, LOG DIPOLE; LOG RFT Epoch Personel On Board= 1 Report by: RALPH WINKELMAN Daily Cost 2270 file://C 5marathonL20010109.htm Daily Report 1/9/01 Page 1 of 1 MARATHON OIL COMPANY KU 31-7X REPORT FOR RICK GIDEON DATE JAN 10,2001, TIME 00:00:00 CASING INFORMATtON 13 3/8" (~. 1508' DALLY WELLSITE REPORT SURVEY DATA BIT INFORMATION NO. SIZE TYPE 3R 12 1/4"' RBI C05LRGSP SIN BZ 334 .18,18,20 4350 DEPTH 5790 YESTERDAY 5661 24 Hour Footage 129 DEPTH INCLINATION 'AZIMUTH 5608' 46.29 141.4 5737' 45.64 142.0 5790' 45.37 142.0 INTERVAL JETS IN OUT 5661 12 114" ":~. RBI C05LRGSP ' BZ 335 95.8 364 31 0 2268 DRILLING pARAMETERS RATE OF PENETRATION SURFACE TORQUE ,::::' WEIGHT ON BIT:' ROTARY RPM ":"~, ' PUMP PRESSURE DRILLING MUD REPORT , ,, MW 9.4 VIS FC 2 SOL MWD SUMMARY FOOTAGE HOURS 1311 42.6 18,18,20 5661 5790 129 4.7 " HIGH LOW @ 5667 8.6 @ 5721 ~ ' 5661 364 @ 5661 @ 5757 18 @ 5734 @ 5850 0 @ 5850 @ 5702 1562 @ 5662 DEPTH: 5661 46 PV 10~., ~ YP 24 FL 12.4 Gels ,, 8 SD TR OIL 1/91 MBL 13.75 pH LOW AVERAGE 5757 15 @ 5721 19.9 @ 0. CHROMATOGRAPHY(ppm) 5757 3344 @ 5721 4401.3 5661 1 @ 5731 5.8 5699 1 @ 5762 3.1 INTERVAL TO TOOLS GAS SUMMARY(units) HIGH DITCH GAS 53 CUTTING GAS METHANE(C-I) 10783 ETHANE(C-2) 57 PROPANE(C-3) 15 BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGYIREMARKS LITHOLOGY * SAND, TUFFACEOUS CLAYSTONE, MINOR COALS PRESENT LITHOLOGY N/A iii i ii1! i i i DAILY ACTIVITY SUMMARY FINISH TIH, DRILL TO TD, BACK REAM OUT TO SHOE; CBU; TIH. Epoch Personel On Board= 4 Dally Cost 2760 lin AVERAGE 21.4 1.9 17.5 0.0 1479.6 EPOCH PRESENT OPERATION= TIH VERTICAL DEPTH 4621.79 4711,45 4748.60 e, CONDITION REASON T/B/C PULLED 6,6,BT,A,F, 1/16,WT,TQ STALLING IN HOLE CURRENT AVG N/A ft/hr N/A: .~ ,, amps N/A Klbs NIA RPM N/A psi 15/27133 CL- 27000 8.5 Ca+ 560 CCI TRIP GAS= WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENT BACKGROUND/AVG GAS DESCRIPTION , . i i iii i il · Report by: RALPH WINKELMAN Daily Report Page 1 of 1 MARATHON OIL COMPANY KU 31-7X REPORT FOR RICK GIDEON DAILY WELLSITE REPORT EPOCH DATE Jan 0g, 2001 TIME 24:00 / 00:00 DEPTH 5661 YESTERDAY 5400 PRESENT OPERATION= TRIPPING IN CASING INFORMATION 13 3/8" ~ 1508 DEPTH SURVEY DATA BIT INFORMATION NO. SIZE. TYPE 3 12.25 . RBI C05LRGSP 3R1 12.25 : RBI C05LRGSP DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM ~ PUMP PRESSURE DRILLING MUD REPORT MW VIS FC SOL iiii i MWD SUMMARY 5145.00 5270.00 5391.00 551&00 5608.00 S/N BL 334 BZ 334 24 Hour Footage 261 ii INCLINATION AZIMUTH VERTICAL DEPTH 48.48 141.80 4309.18 48.07 142.40 4392.38 47.61 142.30 4473.59 46.79 142.30 4559.88 46.29 141.40 4621.79 INTERVAL CONDITION REASON JETS IN OUT FOOTAGE HOURS T/B/C PULLED 18,18,20 4350 5661 1304 42.6 HOURS ON BIT 16,18,20 5661 IN HOLE ' i i HIGH LOW AVERAGE CURRENT AVG @ @ ft/hr @ @ amps @ @ Klbs @ @ -, RPM @ @ :, ,i, psi DEPTH: 'i:i'.i:, '~! ::'~" '~V YP FL :!. Gels CL- SD OIL MBL pH Ca+ CCI INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1 ) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL H~ HIGH LOW AVERAGE @ @ TRIP GAS= 11 WIPER GAS= CHROMATOGRAPHY(ppm) SURVEY= 17 @ @ CONNECTION GAS HIGH= 22 @ @ AVG= 20 @ @ CURRENT @ @ CURRENT BACKGROUND/AVG LITHOLOGY/REMARKS GAS DESCRIPTION , LITHOLOGY MAJOR SAND, TUFFACEOUS CLAYSTONE, TUFFACEOUS CLAY, VOLCANIC ASH, CONGLOMERATIC SAND ' PRESENT LITHOLOGY N/A ::'': DAILY ~CT~VITY SUMMARY DRILLED TO 5661', TRIPPED OUT OF HOLE, REPLACED BHA, TRIPPING IN.. ? ' ' Epoch Personel On Board= 4 Report by: NICK ATKINSON file://C:~narathonL20010107.htm Daily Report 1/8/0'1 Page 1 of 1 MARATHON OIL COMPANY KU 31-7X REPORT FOR RICK GIDEON DATE Jan 08, 2001 TIME 24:00100:00 ! CASING INFORMATION 13 3/8" @ 1508 SURVEY DATA BIT INFORMATION NO. SIZE TYPE S/N 2 12.25 RBI C05RVLRG BL 225 3 12.25 RBI C05VLRGSP BL 334 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.5 VIS 47 PV FC 2 SOL 9. 0 SD MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS 272 CUTTING GAS DEPTH 5020.00 5145.00 5270.00 5391.00 5518.00 L DALLY WELLSITE REPORT DEPTH 5400 YESTERDAY 4821 24 Hour Footage 579 INCLINATION 49.16 48.48 48.07 47.61 46.70 INTERVAL JETS IN OUT 18,18,20 1520 4350 18,18,20 4350 HIGH 335.1 @ 5010 10.4 783 @ 5188 -1788 34 @ 4986 8 48 @ 5368 -32 2168 @ 5307 1448 DEPTH: ~,. .. 11 YP 31 TR OIL 1/90 HIGH LOW @ 4968 15 @ 5244 CHROMATOGRAPHY(ppm) FOOTAGE 2830 1050 LOW AZIMUTH 142.00 141.80 142.40 142.30 142.30 HOURS 37.46 53.78 5152 5367 5136 5367 5033 EPOCH METHANE(C-I) 56842 @ 4968 3226 @ 5244 ETHANE(C-2) 72 @ 4972 1 @ 5351 PROPANE(C-3) 48 @ 4972 3 @ 4996 BUTANE(C-4)'. 0 @ 5400 0 @ 5400 PENTANE(C-5): 15 @ 5379 1 @ 5355 ii i i i i i! HYDROCARBON SHOWS INTERVAL PRESENT OPERATION= DRILLING CONDITION T/B/C 3-3ER-A-E-2/16-N-HR IN HOLE AVERAGE 56.2 185.2 22.7 0.3 2034.8 i VERTICAL DEPTH 4226.88 4309.18 4392.38 4473,59 .. 4559.88 . REASON PULLED HOURS ON BIT CURRENT AVG 22.4 ;':: ,'..,,.&' fi/hr 347.4 ./i:' ;,amps 21.7 .... :.,,' Klbs 0 RPM 2093 psi i i FL 10.8 Gels 18132/36 CL- 28500 MBL 12. 5 pH 9.0 Ca+ 460 CCI AVERAGE 69.4 13889.5 7.8 1.4 0.0 0.8 TRIP GAS= NIA WIPER GAS= N/A SURVEY= 120 CONNECTION GAS HIGH= 20 AVG= 20 CURRENT 37 CURRENT BACKGROUND/AVG 37 125u @ 4904', 263u @ 4970', 122u @ 5018', 120u @ 5073' LITHOLOGY/REMARKS GAS DESCRIPTION LITHOLOGY' ' ' MAJOR SAND, TUFFACEOUS CLAY, TUFFACEOUS CLAYSTONE, VOLCANIC ASH, CONGLOMERATIC SAND, PRESENT LITHOLOGY SAND, TUFFACEOUS CLAYSTONE, DAILY~AC'FIVITY SUMMARY DRILL AHEAD FROM 4821' TO 5400'. Epoch Personel On Board= 4 Daily Cost 2760 : Report by: NICK ATKINSON Daily Report Page 1 of 2 MARATHON OIL COMPANY KU 31-7X DALLY WELLSITE REPORT EPOCH REPORT FOR RICK GIDEON DATE Jan 07, 2001 TIME 24:00100:00 DEPTH 4821 YESTERDAY 4548 PRESENT OPERATION= DRILLING 24 Hour Footage 273 CASING INFORMATION 13 3/8" @ 1508' SURVEY DaTA DEPTH 4264.00 4392.00 451'9.00 4644.00 4769.00 BIT INFORMATION NO. SIZE TYPE S/N 2 12.25 RBI C05RVLRG BL225 3 12.25 RBI C05VLRGSP BL334 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ' ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW. = 9.4 VIS 52 PV FC I SOL 7 SD JETS 18,18,20 18,18,20 INCLINATION 50.82 50.44 50.00 49.71 50.10 INTERVAL IN OUT 1520 4350 435O HIGH 208.8 @ 4569 418 @ 4643 29 @ 4571 1973 @ 4724 DEPTH: 42' ., YP TR OtL AZIMUTH 143.20 143.10 1'41.g0 142.60 141.70 VERTICAL DEPTH 3740.90 3822.10 3g03.36 3983.95 4t)64.46 CONDITION FOOTAGE HOURS T/B/C 2830 37.46 3-3-ER-A-E-2/16-N-HR 471 29.78 iN HOLE LOW AVERAGE CURRENT AVG 5.9 @ 4717 36.7 16.4 @ 4821 0 @ 4796 14.3 0.0 67 @ 4720 1793.9 1897 37 FL 9.2 Gels 20130132 "CL-~, 31500 1/92 MBL 10 pH 9. 5 Ca+ 300 REASON PULLED HOURS ON BIT ft/hr amps Klbs RPM psi COt MWD SUMMARY :'. : , INTERVAL TO TOOLS "]!'" GAS SUMMARY(units) DITCH GAS CUTTING GAS METHANE(C-1 ) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT : LITHOLOGY DAILY ACTIVITY SUMMARY i HIGH LOW AVERAGE 94 @ 4603 10 @ 4713 40.7 TRIP GAS= 1 @ @ WIPER GAS= CHROMATOGRAPHY(ppm) SURVEY= 20 18813 @ 4603 2099 @ 4713 8272.4 CONNECTION GAS HIGH= 25 20 @ 4603 1 @ 4811 6.9 AVG= 25 0 @ 4821 0 @ 4821 0.0 CURRENT 21 8 @ 4794 1 @ 4810 0.7 CURRENT BACKGROUND/AVG 22 9 @ 4718 1 @ 4801 0.8 NONE LITHOLOGY/REMARKS GAS DESCRIPTION Major Sand, Tuffaceous Clay, Volcanic Ash, Tuffaceous Claystone, Coal, Tuffaceous shale, TraceCo~glomeratic Sand, Consolidated Sandstone. ' SAND, TUFFACEOUS CLAYSTONE, TUFFACEOUS SILTSTONE, VOLCANIC ASH DRILL FROM 4696' TO 4714'. CHANGE OUT BIT. DRILL FROM 4714' TO 4821'(REPORT DEPTH). SURVEY AND SLIDE AS DIRECTED. Daily Report Page I of 2 MARATHON OIL COMPANY KU 31-7X REPORT FOR RICK GIDEON DATE Jan 06, 2001 TIME 24:00100:00 CASING INFORMATION 13 3/8" @ 1508' DEPTH SURVEY DATA i BIT INFORMATION NO. SIZE TYPE 2 12.25 RBI C05RVLRG 3 12.25 RBI C05VLRGSP DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.3 VIS FC I SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS ' 44 130 DALLY WELLSITE REPORT DEPTH 4548 YESTERDAY 4178 24 Hour Footage 370 METHANE(C-I) ETHANE(C-2) PROPANE(C-3). BUTANE(C-4) PENTANE(C.-5). HYDROCARBON SHOWS INTERVAL INCLINATION 4014 49.72 4264 50.82 4519 50.00 INTERVAL SIN JETS IN OUT FOOTAGE BL225 18,18,20 1520 4350 2830 BZ334 18,18,20 4350 198 H~GH LOW 167.6 @ 4259 7.6 488 @ 4357 219 26 @ 4402 3 1825 @ 4505 1483 @ DEPTH: 4627 / 3970TVD PV 9 YP 26 FL SD TR OIL 0 MBL ii iii EPOCH 4545 4263 4546 4378 HIGH LOW AVERAGE ~ 4259 14 {~ 4545 44.4 CHROMATOGRAPHY(ppm) PRESENT OPERATION= DRILLING 2934 @ 4545 ~ @ 4546 @. _ NONE 26137 @ 4259 31 @ 4258 O ~' 42~ AZIMUTH 142.20 143.20 .141.90 HOURS 37.46 5.78 i i CONDITION T/B/C 3-3-ER-A-E-2/16-N-HR In Hole VERTICAL DEPTH 3582.61 3740.90 3903.36 REASON PULLED HOURS ON BIT AVERAGE CURRENT Avg 46.4 13.9 229.5 285.0 i7.§ t7.1 1608.7 1060 10.2 Gels 13/17120 CL- 30500 7.5 pH 9.0 Ca+ 520 fi/hr amps Klbs RPM' psi CCI 8893.8 7.5 0:2 TRIP GAS=- 95 WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENT BACKGROUNDIAVG 18 ! 36 LITHOLOGYIREMARKS GAS DESCRIPTION II I I I II II II II I II I I II Major Sand, Tuffaceous Clay, Volcanic Ash, Tuffaceous Claystone. Minor Coal, Tuffaceous Shale. Trace Conglomeratic LITHOLOGY Sand, Consoll~fated S~andstOne. PRESENT ,LITHOLOGY SAND, TUFFACEOUS CLAYSTONE, TUFFACEOUS SILTSTONE, VOLCANIC ASH i iiii i ii / i . DALLY ACTIVITY .: ' DRILL. FROM 4178' TO 4350'. CBU. CHANGE OUT BIT. RIH. WASH AND REAM FROM 3195' TO 4350'. DRILL FROM SUMMARY" 4350' TO REPORT DEPTH. SURVEY AND SLIDE AS DIRECTED, Epoch..Pers0nel On Board= 4 Daily Cost 2760 Report by: Craig Silva .............. ' "'' ..... 1/6/01 .. . , Daily Report .': Page 1 of 1 MARATHON OIL COMPANY KU 31-7X REPORT FOR RICK GIDEON DATE Jan 05, 2001 TIME 24:00100:00 CASING INFORMATION 13 3/8"/1508' SURVEY DATA BIT INFORMATION NO. SIZE 2 12.25 , DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 9.1 . VIS FC 1 SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS TYPE RBI C05RVLRG 40 METHANE(C-1 ) ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY PRESENT LITHOLOGY DEPTH 3298 3580 3890 DALLY WELLSITE REPORT EPOCH SIN BL225 376.6 33 1666 PV DEPTH 417'8 YESTERDAY 3006 24 Hour Footage 1172 i INCLINATION 37.83 44.70 49.20 INTERVAL JETS IN OUT 18,18,20 1520 HIGH LOW @ 3845 4.7 ~ 3752 0 ~;~ 4164 10~9 DEPTH: 414513517TVD 8 YP 23 FL TR OIL 0 MBL HIGH LOW 158 ~ 3884 8 ~ 3390 C, HROMATOGRAPHY(ppm) AZIMUTH 131.30 137.10 140.80 FOOTAGE 2658 . 3553 3062 HOURS 32.34 AVERAGE 118.8 PRESENT OPERATION= DRILLING 16.0 7.0 Gels 5.0 pH iii ii VERTICAL DEPTH 3082.37 3294.57 3502.01 CONDITION T/B/C" In Hole CURRENT AVG 89.5 15.7 REASON PULLED '1 GGO 12/14117 CL- 29000 7.5 Ca+ ' 520' fi/hr amps Klbs RPM CCI 31907 @ 3884 23 @ 3882 ii i J L I IIII I,111 I AVERAGE 48.4 1710 @ 3390 9676.8 @ 2.6 ,@ @ NONE LITHOLOGY/REMARKS TRIP GAS= WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENT BACKGROUNDIAVG 30152 GAS DESCRIPTION Major Sand. Minor Volcanic Ash, Tuffaceous Clay, Tuffaceous Silstone, Coal. Trace Conglomeratic Sand I Conglomerate, · Tuffaceous Shale SAND, VOLCANIC ASH, TUFFACEOUS CLAYSTONE, TUFFACEOUS 81,1rTSTONE DALLY ACTIVI'~ SUMMARY DRILL FROM 3006' TO REPORT DEPTH, SURVEY AND SLIDE AS DIRECTED. Epoch Personel On Board= 4 Daily Cost 2760 Report by: Craig Silva tile://C:~narathonX2001 t) 1 o_~.lltln Daily Report Page 1 of' 1 MARATHON OIL COMPANY KU 31-7X DALLY WELLSlTE REPORT EPOCH REPORT FOR RICK GIDEON DATE Jan 04, 2001 TIME 24:00 / 00:00 DEPTH 3006 YESTERDAY 1750 PRESENT OPERATION= DRILLING CASING INFORMATION 13 318" @ 1508' DEPTH SURVEY DATA BIT INFORMATION NO. SIZE TYPE 2 12,25 RBI C05RVLRG DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE i ii DRILLING MUD REPORT MW 9.05 ViS 41 FC 1 SOL 5.0 i iii i i i i i MWD SUMMARY 2079 2642 3205 SIN BL225 333.4 24 1365 PV SD 24 Hour Footage 1256 INCLINATION AZIMUTH 24.68 059.90 24.29 096.80 36.01 127.10 . JETS 18,18,20 HIGH INTERVAL IN 1520 OUT LOW 2292 12.8 2836 0.5 3OOO 737 DEPTH: 3162 / 2973TVD 7 YP 23 FL TR OIL 0 MBL FOOTAGE 1486 HOURS 10.69 2343 AVERAGE 118.4 2790 9.4 2229 1013.7 7.6 Gels 2.5 pH VERTICAL DEPTH 2003.48 2520.27 3008.01 CONDITIDN T/B/C In Hole CURRENT AVG 146.4 ii REASON PULLED 10.9 1295 13/15/17 CL- 27000 7.5 Ca+ 480 fi/hr amps Klbs RPM psi CCI INTERVAL TOOLS TO GAS SUMMarY(units) HIGH DITCH Gas 41 @ CUTTING GAS METHANE(C-1) 8277 ETHANE(C-2) PROPANE(C-3) BUTANE(C-4) PENTANE(C-5) HYDROCARBON SHOWS INTERVAL LITHOLOGY Major Sand PRESENT LITHOLOGY SAND L LOW AVERAGE 2854 5 @ 2343 21.9 CHROMATOGRAPHY(ppm) 2854 1030 @ 2343 4322.9 NONE LITHOLOGY/REMARKS TRIP GAS= WIPER GAS= 16 SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENT BACKGROUND/AVG 15 / 25 GAS DESCRIPTION DAILY ACTIVITY SUMMARY DRILL FROM 1750' TO REPORT DEPTH. SURVEY AND SLIDE AS DIRECTED. Epoch Personel On Board= 4 ,~,,~ Report by: Craig Silva ,,, Daily Cost 2760 Daily Report Page 1 of 1 MARATHON OIL COMPANY KU 31-7X REPORT FOR RICK GIDEON DATE Jan 03, 2001 TIME 24:00100:00 CASING INFORMATION 13 3/8"@ 1508' SURVEY DATA BIT INFORMATION NO. SIZE 2 12.25 DRILLING PARAMETERS RATE OF PENETRATION SURFACE TORQUE WEIGHT ON BIT ROTARY RPM PUMP PRESSURE DRILLING MUD REPORT MW 8.85 VIS FC 1 SOL MWD SUMMARY INTERVAL TO TOOLS GAS SUMMARY(units) DITCH GAS CUTTING GAS DALLY WELLSITE REPORT DEPTH 1750 YESTERDAY 1520 24 Hour Footage 230 i i i DEPTH INCLINATION AZIMUTH 1517 19.74 060.00 1705 25.22 059.90 1955 24.72 060.30 INTERVAL TYPE S/N JETS IN OUT FOOTAGE HOURS RBI C05RVLRG BL225 18,18,20 1520 230 1.65 HIGH LOW AVERAGE 406.0 @ 1573 26.5 @ 1554 256.0 31 @ 1571 11 @ 1524 28.1 1024 @ 1676 659 @ 1529 1065.6 DEPTH: 1895 / 1846TVD 38 PV 5 YP 18 FL 8.6 Gels . 5.0 SD 0.25 OIL 0 MBL 2.5 pH i i i HIGH LOW AVERAGE 37 @ 1715 6 @ 1544 32.6 CHROMATOGRAPHY(ppm) 1715 1197 @ 1544 NONE LITHOLOGY/REMARKS EPOCH METHANE(C-I) 7411 @ ETHANE(C-2) @ PROPANE(C-3) @ BUTANE(C-4) @ PENTANE(C-5) @ iii ii iii i i i i i i HYDROCARBON SHOWS INTERVAL LITHOLOGY N/A PRESENT LITHOLOGY NIA ii iiii i i DALLY ACTIVITY SUMMARY PRESENT OPERATION= DRILLING VERTICAL DEPTH 1491.25 1664.20 1890.82 CONDITION T/B/C In Hole ,,, CURRENT AVG 213.6 22.0 966 REASON PULLED E/hr amps Klbs RPM psi 9/12/t3 CL- 28000 7.5 Ca+ 100 CCI 6522 TRIP GAS= WIPER GAS= SURVEY= CONNECTION GAS HIGH= AVG= CURRENT CURRENT BACKGROUND/AVG 7 / 25 GAS DESCRIPTION i TEST BOPE, CASING, KOOMEY. MAKE UP BHA. TEST MWD. RIH. TAG FLOAT COLLAR AT 1464°. DRILL FLOAT COLLAR, CEMENT, SHOE. WASH/REAM TO 1520'. DRILL 20' NEW HOLE TO 1540'. PERFORM LEAK OFF TEST (14.6ppg EMW). DISPLACE OLD MUD WITH NEW FLO-PRO MUD. DRILL FROM 1540' TO REPORT DEPTH, SURVEY AND SLIDE AS DIRECTED. Epoch 15ers0hol On Board= 2 Daily Cost 2270 Report by: Craig Silva Alaska r{, Domestic r-roduction Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Mr. Tom Maunder Alaska Oil and Gas Conservation Commission 333 West 7t~ Ave Suite 100 Anchorage, AK 99501 RE: Annular flow from KU 31-7X (Previously KU 31-7) Property Designation: A-028142 Mr. Tom Maunder, We have commenced drilling the KU 31-7X well in the Kenai Gas Field. This well is intended to have 3- 1/2" tubing and a packer (refer to attached well bore diagram). Production will be from the Sterling reservoirs Pool 5.2 and Pool 3. The completion is planned to be a dual with flow up the 3-1/2" tubing from Pool 5.2 and annular flow from Pool 3. The approximate SBHP's are Pool 3 - 296 psia and Pool 5.2 - 1,400 psia. Annular flow from the low-pressure reservoirs such as Sterling Pool 3 is currently approved in the Kenai Gas Field. A wellhead specifically designed for annular flow will be installed. This wellhead has dual 4" 3,000 psig valves on each side of the tubing head. These 4 valves will tie into a common 6" tee and be controlled by a 6" 3,000 psig surface safety valve. This installation is very similar to our existing annular producers aside from the larger inside diameters exiting the tubing head. A conventional 3" 3,000 psig tree will be installed on the tubing head (refer to the attached wellhead schematic). The through tubing Pool 5.2 completion is contingent upon data acquired from the open hole logs. The contingency plan will be to complete the well in Pool 6 and not Pool 5.2. Pool 6 flow would then be via 3-1/2" tubing or if Pool 3 is not perforated, production will be via tubing and annulus. The SBHP of Pool 6 is approximately 360 psia. A Form 10-407 Well Completion Report will follow the in February 2001. Please feel free to call for any additional information or to discuss any required changes 907-564-6303. Since~rely, Ralph J. Affinito Production Engineer Marathon Oil Company 3201 'C' Street Anchorage, AK 99519 RECEIVED JAN 0k 2_00t Alaska Oil & Gas Cons. Commission Anchorage A subsidiary of USX Corporation Environmentally aware for the long run. 20" OD 133 ppf K-55 DP @ 100 fl( 13-3/8"" OD 64 ppf K-55 ~ 1500 ~ MD cmt'd in Baker Permanent Packer Set above Pool 5 1 Zone IShearout Ball Sub } , 17 10 17 17 27 ]0 O0 ]0 13 5/8~ 3000~ ,5O 13 5/8' 3000# O0 44 3 1/2' TUBING BUTTRESS TUBING --13 3/8' nD CASING 9 5/8' 0I] CASING ADD 0,3125 PER RTi",JG GASKET CBNNECTIBN STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS n:\drlg\kgfl,43-6xrdWOG CC01 .xls 1. Type of Request Abandon Suspend Operation Shutdown Alter Casing Repair Well Plugging Change Approved Program Pull Tubing Variance Re-enter Suspended Well Time Extension Stimulate , , Perforate Other X 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 365' FSL& 1361' FWL, Sec. 6, T4N, R11W, SM At top of Productive Interval 150' FSL & 2484' FWL, Sec. 6, T4N, R1 lW, S.M. At Effective Depth At Total Depth 1070' FNL& 3369' FWL, Sec. 7, T4N, R11W, S.M. 5. Type of Well: Development X Exploratory Stratigraphic Service 6. Datum Elevation (DF or KB) 87' KB above MSL feet 7. Unit or Property Name Kenai Unit 8. Well Number KU 31-7X 9. Permit Number 200-148 lO. APl Number 50-133-20495-00 11. Field/Pool Kenai Gas Field/Sterling 12. Present Well Condition Summary Total Depth: measured true vertical Effective Depth: measured true vertical Casing Structural Conductor Surface Intermediate Production Liner Perforation Depth: measured Length 100 true vertical Tubing (size, grade, and measured depth) Packers and SSSV (type and measured depth) 255 255 feet feet feet feet Size 20" Cemented Driven Measured Depth 100 DEC 2 2000 Alaska Oil & Gas Cons. Commission Anchorage True Vertical Depth 100 13. Attachments Description Summary of Proposal X Detailed Operations Program BOP Sketch 15. Status of Well Classification as: 14. Estimated Date for Commencing Operation 12/25/00 16. If Proposal was Verbally Approved Name of Approver Date Approved Oil Gas X Suspended Service 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Signed y/~//~ P.K. B erga Title Drilling Superintendent phOne: 564-6319 Date 12/28/00 FOR COMMISSION USE ONLY Conditions of Approval: Notify Commission so representative may witness Plug Integrity BOP Test Location Clearance Mechanical Integrity Test Subsequent Form Required 10- Approved by Order of the Commission '":~tGINAL SIGNED BY · 'r~ylor Seamoun[ IA,:,,:,rov,,, NO. ,,~ -3~).q Commissioner Date ~)//O~ ~../~/ S~fbmit in ~iplicate Form 10-403 Rev. 06/15/88 ORIGINAL Marathon OilCompany Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 9071561-5311 Fax 9071564-6489 December 28, 2000 Tom Maunder AOGCC 333 West 7th Ave. Suite 100 Anchorage, AK 99501 Re: Well re-naming Dear Mr. Maunder: Marathon Oil Company requests that Well KU 31-7 be re-named as KU 31-7X. This will help to eliminate confusion with another well (KBU 31-7) on the same pad. If you have any questions concerning this matter, please contact me at 564-6319. Sincerely, Peter K. Berga Drilling Superintendent MARATHON OIL COMPANY ALASKA REGION KENAI GAS FIELD WELL KU 31-7X ANNULAR FLOW EVALUATION · The KU 31-7X was designed, drilled, and completed to facilitate annular flow from the Iow-pressure (less than 400 psig) Kenai Gas Field Sterling reservoirs. · The tubing head has dual 4", 3,000 psig working pressure outlets each with dual 4", 3,000 psig WP valves tied to a common 6" surface safety valve. · Flow is expected to be from the Pool 6 interval initially, then solely Pool 3 depending upon the Pool 6 testing. Log analysis indicates a greater flow potential from Pool 6 thus the annular flow evaluation is based upon Pool 6 annular flow. · Based upon log evaluation, the Pool 6 reservoir's maximum predicted deliverability via annular flow is 10 MMCFGPD. TOPIC DISCUSSION Erosional Velocity Corrosion Surface Safety Controls Burst/Collapse of Casing The highest potential for erosive flow exists at the 4-1/16", 3M flanged outlets of the tubing head. · Flow will be out both outlets of the tubing head to reduce velocity. · The valve recovery threads inside these outlets have an ID of 3.219" as the smallest restriction. · The erosional velocity at the VR threads is reached at rates greater than 24 MMCFGPD from both outlets (based upon APl RP14E). · Nodal analysis indicates that neither Pool 3 or 6 are capable of production of 24 MMCFGPD. · Marathon plans to produce the well below erosive limits. · Marathon will conduct periodic UTT inspection of the wellhead and flowlines for signs of unusual wear. · The partial-pressure of CO2 is less than 1.0 psi. If the partial pressures of CO2 is less than 7 psi the gas is generally considered noncorrosive. · There is no H~S gas produced in the Kenai Gas Field. · Corrosion of the casing is highly unlikely. · The annulus will be produced via a separate flowline from the existing tubing completion. · Surface safety controls will be similar to that of other Kenai Gas Field completions. Pressures imposed on the 9-5/8" casing during this procedure will not compromise the integrity of the casing. Worst-case forces will not exceed 53% of the rated casing burst or collapse. 9 5/8" OD 40 ppf k-80 4 Hoe ',e'~ KU 31'~7-Reply Subject: Re: KU 31-7 -Reply Date: Fri, 01 Dec 2000 13:30:47-0900 c~ 0" ~ L-~ ~'- From: Tom Maunder <tom_maunder@admin.state.ak. us> To: Craig E Young <ceyoung@marathonoil.com> CC: AOGCC North Sope Office <aogcc_prudhoe_bay@admin.state.ak. us> Craig, Thanks for your note. As discussed, 2 rams and an annular is allowable under the regulations. The one question I have is with regard to this "Escape" perf technology. Will your procedure to be to run these charges on the casing, then cement per usual and then thread these control lines out the side outlet?? ~ ~.,.% ~.~ Thanks in advance for the information. Tom ~ ~\ ~ ~J [ ~..~-,.~_~ Craig E Young wrote: > Tom, > Sorry about that. Yes pitting was noticed in the single gate BOP, however, we have not seen the problem in the double gate preventer. We will be examining it more closely when we install casing rams for the MGO #1 well. What we would like to do is send the single gate to a repair shop. This will probably take about 3-4 weeks with shipping. Another problem coming up on the KBU 42-7 well is the use of Excape perforating technology. This is where the perforating guns are run on the outside of the casing string with Y blocks. Control of the guns is thru two control lines back to the surface. Our problem is we cant pick up the stack high enough to run the (x)ntrol lines out a side outlet with the single in the stack. So we will be requesting a change in BOPE for this well also. ~ · > If you have any questions or need any additional information, please let me know. Also if this is approved, could you send me an email that I can send to the rig so when the inspector gets there, the approval will be documented. > Again, thanks for your help. > · > Craig Young > Marathon Oil Company > >>> Tom Maunder <tom_maunder~admin. state, ak. us> 11/29/00 10:1 '/am >>> > Craig, > Got your email. It would be helpful if you included a little narrative regarding the reason for the change. In our discussion you mentioned the pitting experienced on the single. Is there a risk of the same occurring on the double? Thanks. > Tom > Craig E Young wrote: > > > Tom, > > We have an AOGCC permit # 200-'/48 to drillthe subject well. We have changed plans and would like to revise the BOP Equipment. We plan on using an annular preventor and a double ram preventer. In the approved drilling program, we had an additional single ram BOP below the mud cross. > > Attached is the revised BOPE drawing. Let me know if I need to do anything else to revise this program. > > Thanks for your help. > > Craig .Young t nf ~ 1/18/01 3:57 PIV ~: ~KU 31-7 -Reply > > Marathon Oil Company > > Narre: BOPRI.XLS > > BOPR1.XLS Type: Microsoft Excel Worksheet (application/vnd. ms-excel) > > En(z)ding: base64 Tom Maunder <tom maunder~admin.state.ak, us> Petroleum Engineer Alaska Oil and Gas Conservation Commission '~ ",f ~ 1/18/01 3:57 PM ALASKA OIL AND GAS CONSERVATION CO~I~IISSION TONY KNOWLES, GOVERNOR 3001 PORCUPINE DRIVE ANCHORAGE, ALASKA 99501-3192 PHONE: (907) 279-1433 FAX: (907) 276-7542 Peter K. Berga Drilling Superintendent Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Re: Kenai Unit KU 31-7 Marathon Oil Company Permit No: 200-148 Sur Loc: 365' FSL, 1361' FWL, Sec. 06, T04N, R11W, SM Btmhole Loc. 1070' FNL, 3369' FWL, Sec 07, T04N, R11W, SM Dear Mr. Berga: Enclosed is the approved application for permit to drill the above referenced well. The permit to drill does not exempt you from obtaining additional permits required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permitting determinations are made. Exception to 20 ACC 25.035(c)(1)(b) to drill a 17 iA" hole using a 16" diverter line is approved. Blowout prevention equipment (BOPE) must be tested in accordance with 20 AAC 25 035. Sufficient notice (approximately 24 hours) must be given t° allow a representative of the Commission to witness a test of BOPE installed prior to drilling new hole. Notice may be given by contacting the Commission at 279-1433. 'Daniel T. Se3(nount, Jr. Commissioner ov co mss o DATED this / day of November, 2000 ljt/Enclosures cc: Department of Fish & G,'unc, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. KBU 31-7 Diverter System Subject: KBU 31-7 Diverter System Date: Mon, 13 Nov 2000 20:25:16 -0600 From: "Craig E Young" <CEYoung@marathonoil.com> To: Tom_Maunder@admin.state.ak. us CC: PKBerga@marathonoil.com Tom, Marathon is requesting a waiver from AOGCC Regulation 20 ACC 25.035 (c)(1)(b) which requires a vent line diameter at least as large as the hole to be drilled. The rig is outfitted with a 16" diverter line and the plan isto drill a 17 %" hole. This well is being drilled from Pad 14-6 with the surface hole to a depth of 1463' TVD. In drilling 8 other wells from this pad, no gas has been seen above this TVD. A geologic review indicates the sands down to 1500' are water saturated and do not pose a risk, and certainly not a risk with a 16" diverter line outlet. If you need any additional information, or have any questions, please give me a call at 564-6310. Craig Young Senior Drilling Engineer Marathon Oil Company Anchorage, Alaska 1 of 1 11/14/00 10:43 AM DRILLING AND COMPLETION PROGRAM MARATHON OIL COMPANY ALASKA REGION WELL: KU 31-7 PAD: 14-6 SLOT: NA REVISION NO.: 0 SURFACE LOCATION: TARGETS:' Sterling FIELD: Kenai Gas Field AFE No.: 9205500 TYPE: Development. DATE: 9/14/00 365' FSL, 1361' FWL, Sec. 6, T4N, R11W, S.M. 150' FSL, 2484' FWL, Sec. 6, T4N, R11W, S.M. BOTTOMHOLE LOCATION: 1070' FNL, 3369' FWL, Sec. 7, T4N, R11W, S.M. KB ELEVATION: GL ELEVATION: 87 ft. mean S.L. (est.) 66 ft. mean S.L. I. IMPORTANT GEOLOGIC HORIZONS: FORMATION DEPTH(MD) DEPTH(TVD) Sterling 3866 3517 Beluga 5700 4647 I1. ESTIMATED FORMATION TOPS AND CONTENT: FORMATION DEPTH(MD) DEPTH(TVD) Sterling A8 3866 3517 Sterling A9 3931 3557 Sterling Al0 3980 3587 Sterling A11 4110 3667 Sterling B1 4191 3717 Sterling B2 4321 3797 Sterling B3 4394 3842 Sterling B4 4524 3922 Sterling B5-Lower 4954 4187 Sterling C1 5303 4402 Sterling C2 5571 4567 Upper Beluga 5701 4647 TD 5788 4700 POTENTIAL CONTENT gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water gas/water page 1 n:drlg\clu\clu-6\317prog.xls '? STATE OF ALASKA AL~,,A OIL AND GAS CONSERVATION CO~,,,,SSION PERMIT TO DRILL 210 AAC 25.005 g:\cmn\drlg~sterling~su44-10kAOGCCPTD.x~___.~ la. Type of Work Drillr'~ Re-Drillr---I lb. Type of well. ExploratoryFI Stratigraphic TestD Development OilD Re-EntryD DeepenD ServiceD Development GasE~] Single Zone ~] MulUple ZoneE~ 2. Name of Operator 5. Datum Elevation (DF or KB) 10. Field and Pool MARATHON OIL COMPANY 87' KB feet Kenai Gas Fiel~ · 3. Address 6. Property Designation P. O. Box 196168, Anchorage, AK 99519-6168 A-028142 4. Location of Well at Surface 7. Unit or Property Name 11. Type Bond (see 20 AAC 25.025) 365'FSL, 1361'FWL, Sec. 6, T4N, R11W, S.M. Kenai Unit Blanket Surety At top of _P.~roductive Interval 8. Well Number Number 150'F~..t~,2484'FWL, Sec. 6, T4N, R11W, S.M. KU 31-7 5194234 At Total De'pR 9. Approximate Spud Date Amount 1070'FNL, 3369'FWL, Sec. 7, T4N, R11W, S.M. 12/01/00 $200,000 12. Distance to Nearest 13. Distance to Nearest Well 14. Number of Acres in Property 15. Proposed Depth (MD andTVD) Property Line(unit boundary) 7300 feet 800 feet 6000 5788' MD/4700' TVD feet 16. To be Completed for Deviated Wells 17. Anticipated Pressure (see 20 AAC 25.038 (e) (2)) Kickoff Depth 200 feet Maximum Hole Angle 52 o Maximum Surface 1659 paig at Total Depth (TVD) 4700 18. Casing Program SeBng Depth Size Specifications Top Bottom Quantity of Cement Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 133 K-55 PE 80-100' 0' 0' 80-100' 80-100' (=~[) ~.,lr, ~ ~ .~,,~. 17-1/2" 13 3/8" 61 K-55 BTC 1500' 0' 0' 1500' 1463' ~ sx 12 1/4" 9 5/8" 40 L-80 BTC 5788' 0' 0' 5788' 4700' 1150 sx (~--'~ RFP ~ ~') ,Anch0mge ,, Kenai Unit well KU 31-7 will be directionally drilled to an estimated total depth of 5788' md, 4700' tvd from the existing Kenai Gas Field pad 14-6.The primary production interval will be cased with 9 5/8" casing cemented in place and run to surface. Marathon's drilling rig will be used to drill and complete this well. The following documents are attached: Drilling Program, Area Maps, Location Map, Structure Map, Surface use plan, Directional Maps, Mud pit drawing and Blowout Prevention Equipment drawings.ORIGINAL 20. Attachments Filing FooE~ Property Plat~'~ BOP Sketch~'~ Diverter Sketch~'~ Drilling Program~'] Drilling Fluid Program~'] Time vs Depth PlotO . Refraction AnalysisE~ Seabed Reportr-~ 20 AAC 25.050 RequirementsD 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Signed P.K. Berga ,~~.¢/~"' ~ Title Drilling Superintendent Date 9/18/2000 Commission Use Only Permit Number IAPI Number IApproval Date ISee Cover Letter ~ '~/~/'~I 50-/_~:3-- .2_-~ c///e.~--~ J ~ ~ ../',7~ .¢, ~) (.) IFor Other Requirements Conditions of Approval Samples Required DYes ['~No Mud Log Required ['-']Yes ['~']No Hydrogen Sulfide Measures FIYes [~No DirectionalSurvey Required r~Yes DNo Other: D 'TayJo,' Se;amoul',t by order of Approved by Commissioner the Commission Date Form 10-401 Rev. 12-1-8S Submit in Triplicate III. WELL CONTROL EQUIPMENT DIVERTER SYSTEMS The diverter system will consist of a 20" X 3000 psi annular preventer and a 16" O.D. nonbifurcated vent line. The vent line valve will be full opening and integrated with the annular in the fail safe design as stipulated in 20AAC 25.035. The vent line will be a minimum of 75' from any source of ignition. BLOWOUT PREVENTERS The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top, a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets, and a 13-5/8" x 5000 psi single gate ram type preventer with pipe rams. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor- boy gas buster and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mudpits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. WELLHEAD SYSTEM STARTING HEAD: 20 3/4" 3 M flange top x 20" weld on bottom. CASING HEAD: 13 5/8" 5M x 13 3/8" SOW with base plate for 20". CASING HEAD: None TUBING HEAD: 11" 5M x 13 5/8" 5M CHRISTMAS TREE: 7" - 5000 psi christmas tree including two master valves, one flow tee, one wing valve and one swab valve. page 2 n:drlg\clu\clu-&317prog.xls IV. CASING PROGRAM: TYPE SIZE CONDUCTOR: 20" SURFACE: 13 3/8" PRODUCTION: 9 5/8" CASING DESCRIPTION SET SET HOLE WT. GRADE THREAD FROM TO SIZE (md/tvd) (md/tvd) 133 ppf K-55 PE Surf +/-100 Driven 61 ppf K-55 BTC Surf 1500'/1463' 17 1/2" 40 ppf L-80 BTC Surf 5788'/4700' 12 1/4" CASING DESIGN SIZE WEIGHT GRADE 13 3/8" 61 ppf K-55 9 5/8" 40 ppf L-80 SETTING FRAC GRD FORM PRSS DESIGN FACTORS DEPTH,TVD @ SHOE @ SHOE MASP TENS COLL BURST 1463 12.5 680 513 12.62 1.88 3.71 4700' 13.5 2200 1660 5.66 3.12 3.30 All tubulars are new. page 3 n:drlg\clu\clu-6\317prog.xls V. CEMENTING PROGRAM SURFACE: 13 3/8" 1500'md/1463' tvd LEAD SLURRY: Class "G" + required additives. TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME: TAIL SLURRY: Class "G" + required additives. TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME: SURFACE 11.5 ppg. 2.38 cu. ft./sk gal/sk hrs:min 50 % in open hole. z~.sks. ft. PPg. cu. ft./sk gal/sk hrs:min % in open hole. 0 sks. RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED ! 1. Remove thread protectors and visually inspect connections. 2. Make up float shoe and 1 shoe joint. Check float. Fill pipe until circulating. 3. M/U stab-in float collar. (Baker-lok all connections to top of float collar) 4. Fill pipe until circulating. 5. Run remaining casing and centralizers. Run inner cementing string. 6. Circulate until no gains in circulating efficiency are made. 7. Pump spacer. 8. Mix and pump cement. 9. Displace cement. 10. Check floats. 11. POOH with cementing string. 12. WOC. 13. N/D diverter. Weld on tubing head and N/U blowout preventers. 14. Test BOPE. Run wear bushing. page 4 n:drlg\clu\clu-6\317prog.xls V. CEMENTING PROGRAM (continued) Intermediate None LEAD SLURRY: Class "G" + required additives. TOP OF CEMENT: ft. WEIGHT: ppg. YIELD: cu. ft./sk WATER REQ.: gal/sk PUMPING TIME: hrs:min EXCESS (%): % over caliper log. ESTIMATED VOLUME: sks. TAIL SLURRY: Class "G" + required additives. TOP OF CEMENT: ft. WEIGHT: ppg. YIELD: cu. ft./sk WATER REQ.: gal/sk PUMPING TIME: hrs:min EXCESS (%): % over caliper log. ESTIMATED VOLUME sks. RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED! 1.Remove thread protectors and visually inspect connections. 2.Make up float shoe and 2 shoe joints. Check float. Fill pipe until circulating. 3.M/U float collar. (Baker-lok all connections to top of float collar) 4.Fill pipe until circulating. 5.Run remaining casing. M/U cementing head and test all lines. 6.Cimulate and reciprocate until no gains in circulating efficiency is made. 7.Drop bottom plug and begin pumping spacer. 8. Pump spacer as follows: To be designed. 9. Drop bottom plug. 10. Mix and pump tail slurry. Drop top plug. 11. Displace cement with water or brine. 12. Bump plug w/500 psi over final circulating pressure. Check floats. 13. WOC 14. P/U BOP stack. Set slips. N/U casing spool and test. N/U BOP stack. 15. Test BOPE. page 5 n:drlg\clu\clu-6\317prog.xls V. CEMENTING PROGRAM (continued) PRODUCTION 9 5/8" @ 5788'md/4700' tvd LEAD SLURRY: Class "G" + required additives. TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME: 1500 ft. 12.8 ppg. 2.00 cu. ft./sk gal/sk hrs:min 25 %(use 25% over caliper log.) 450 sks. TAIL SLURRY: Class "G" + required additives. TOP OF CEMENT: WEIGHT: YIELD: WATER REQ.: PUMPING TIME: EXCESS (%): ESTIMATED VOLUME 3300 ft. 15.8 ppg. 1.15 cu. ft./sk gal/sk hrs:min 25 % over caliper log. 700 sks. RUNNING AND CEMENTING DETAILS: ENSURE WEAR BUSHING IS REMOVED! 1. Remove thread protectors and visually inspect connections. 2. Make up float shoe and 2 shoe joints. Check float. Fill pipe until circulating. 3, M/U float collar. (Baker-lok all connections to top of float collar) 4. Fill pipe until circulating. 5. Run remaining casing and centralizers. M/U cementing head and test all lines. 6. Circulate until no gains in circulating efficiency is made. 7. Drop bottom plug. 8. Pump spacer. 9. Mix and pump tail slurry. Drop top plug. 10. Displace cement. 11. Bump plug with 500 psi. over displacement pressure Check floats. 12. WOC. page 6 n:drlg\clu\clu-6\317prog.xls VI. MUD PROGRAM MUD PROPERTIES DEPTH DEPTH WEIGHT VISCOSITY WATER MUD FROM TO TVD ppg sec/qt LOSS TYPE 0' 1459' 8.6-9.0 80-250 15-30 Freshwater gel 1452' 4700' 9.0-9.5 50-70 <5 FLO PRO/KCL MUD EQUIPMENT The solids control equipment will consist of two flowline cleaners and the MI centrifuge van. Included will be equipment to dewater the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. VII. LOGGING, TESTING, AND CORING PROGRAMS LOGGING PROGRAM CONDUCTOR: No logging is planned for this interval. SURFACE: PRODUCTION: No logging is planned for this interval. RUN #1: AIT/DSI/LDT/CNL/GR. COMPLETION: Gammaray/CCL. MUD LOGGING The well will be mud logged from 3200' md to TD at 5788' md. CORING PROGRAM No coring planned. TESTING PROGRAM No open hole tests are planned for this well. page 7 n:drlg\clu\clu-6\317prog.xls VIII. OTHER INFORMATION DESC DIRECTIONAL PLAN MD TVD NORTH INCL AZIM COORD EAST VERT COORD SECTION RKB 0 0 0 0 0 0 0 KICKOFF HOLD 200 200 0.0 60.0 0 build @ 2.0deg/100ft 1162 1144 19.2 60.0 80 0 0 138 123 Build HOLD 2136 2063 build @ 3.0deg/100ft 3875 3522 19.2 60.0 240 52.0 142.9 -193 416 370 1127 1143 Total Depth 5788 4700 52.0 142.9 -1396 2035 2242 POTENTIAL INTERFERENCE: WELL DISTANCE (ft.) DEPTH (MD) page 8 n:drlg\clu\clu-6\317prog.xls IX. DRILLING PROGRAM CONDUCTOR: Drive 20" conductor to +-100 ft. RKB. Weld starting head to drive pipe. Move in and rig up rotary drilling rig. Nipple up 20" diverter, 16" diverter valve and 16" diverter line. Function test diverter and diverter valve. SURFACE: Drill a 17 1/2" hole to 1500' md/1463' tvd per the directional plan. Run and cement 13 3/8" casing. WOC. Cutoff 13 3/8" and 20". Weld on 13 5/8" SOW by 13 5/8" 5M wellhead and test. N/U 13 5/8" 5M BOP'S. Test BOP'S and choke manifold to 250/3000 psi. Set Wear bushing. Test surface casing to 1500 psi. INTERMEDIATE PRODUCTION: Drill float equipment and 20' of new formation w/12 1/4" bit. CBU. Test shoe to leak off. Estimated EMW 12.5 ppg. Drill a 12 1/4" directional hole from 1520'md/1482' tvd to 5788' md/4700' tvd' per the directional program. Log. Pull wear bushing. Run and cement 9 5/8" casing. Test casing to 2000 psi. COMPLETION: Complete well as per comletion program. page 9 n:drlg\clu\clu-6\317prog.xls X. POTENTIAL HAZARDS Well KU 31-7 To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake(driller or relief driller) is responsible for shutting the well in(BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No. H2S is anticipated. Gas sands will be encountered from +/-3500'tvd/3866'md to total depth of the well. These sands should be normally pressured to slightly depleted and no lost cimulation or differential sticking hazards are anticipated. No well interference hazards exist in this well. page 10 n:drlg\clu\clu-6\317prog.xls Xl. NOTES MASP CALCULATIONS: Surface casing: 13 3/8" MASP = Injection pressure at shoe + S.F. - Hydrostatic pressure of gas column. MASP -- (12.5 ppg + 1.0 ppg) x .052 x 1463'- (.115 x 1463') MASP - 1027 psi - 168 psi MASP = 859 psi. ~ .. L~%~ ~,.~, ~_~N ~:_~,.~ t-~ ~. r,. ~-,,c:~L ~ '5 Intermediate casing: None. MASP = Injection pressure at shoe + S.F. - Hydrostatic pressure of gas column. MASP = MASP = MASP = Production casing: 9 5/8". MASP - Formation pressure(producing zone) - Hydrostatic pressure of gas column. MASP = 9.0 ppg x .052 x 4700' - (.115 x 4700') MASP - 2200 psi - 541 psi MASP = 1659 psi. Cementing The 13 3/8" casing must be cemented to surface. Contact AOGCC and BLM in advance to see if they want to witness the cement job. BOP/Diverter Tests. Contact AOGCC and BLM a minimum of 24 hrs prior to tests to see if they wish to witness. Tubulars All tubulars are new. page 11 n:drlg\clu\clu-6\317prog.xls Marathon Oil Well KU 31-7 Diverter Flow line 20 3/4" 3M Diverter IDiverter Spool 6" Automatic Hydraulic Valve 6" Diverter Line Marathon Oil Well KU 31-7 BOP Stack J FIow Nipple J J13 5/8" 5M Annular J ,,.. Preventer "' J FIow Line J I J135/8" 5M Double J Ram Preventer .. I Pipe Ram J JBlind Ram J 3 1/8" 5M Manually Operated Valves ~> I _ ¢'"--..,~ 1~/8 ~rvJc,.o~ I J13 5/8" 5M Single Ram Preventer J Pipe Ram J J3 1/8" 5M Hydraulically J Operated Valve Operated Valve il Marathon Oil Well KU 31-7 Choke Manifold Gas Buster ITc Blooey Line IBleed off Line to Shakers 3" 5M Valves 2 9/16" 1 OM Swaco Hydraulically Operated Choke IFrom BOP Stack 3 1/8" 5M Manually Adjustable Choke GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT MARATHON Oil Company Structure: Pad 14-6 Well: KU 31-7 Fleld: Kenai Gas Reid Location: Kena! Peninsula, Alaska 250 500 750 1000 1250 1500 r' 2000 2250 t,.. 2500 q) 2750 I 3ooo V 5250 5500 5750 4000 4250 4500 4750 o.oo KOP 2.00 4.00 6,00 DIS: 2.00 deg per 100 ft 8.00 10.00 12,00 14.00 16.00 18.00 ~9.25 End of Build/Turn East (feet) -> 0 250 500 750 1000 1250 1500 1750 2000 2250 I I I I I I I I I I I I I I I I I I I I '~et 1 TANGENT ANGLE 19.23 DEG End of Hold ' ' T 19.23 19.05 19.15 19.68 DIS: 3.00 deg per 100 ft 20,65 21,95 25.54 25.58 27.41 29.60 31.91 34.32 56,80 39.55 41.94 44.58 47.25 Target 1 TARGET ANGLE 51.99 DEG WELL PROFILE DATA ..... I~lnt ..... ' I~D Ine ~ T~g Narth Eo~ V. ~ 49.96 51.99 End of Build/Turn 98.60 AZIMUTH 2242' TO TARGET/TD ***Plofle of Proposal*** TRU~ Target 2 i i i i i i i i i i ii i ii i i i i i ! 0 250 500 750 1000 1250 1500 1750 2000 22.50 2500 VerticalSection (feet)-> Azimuth 98,60 with reference 0,00 N, 0,00 E from slot #KU 31-7 500 250 250 0 c' 500 750 I 1000 1250 1500 MARATHON Oil Company Pad 14-6 KU 31-7 slot ~KU 31-7 Kenai Gas Field Kenai Peninsula, Alaska PROPOSAL LISTING by Baker Hughes INTEQ Your ref : KU 31-7 Versions Our ref : prop4043 License : Date printed : 13-Sep-2000 Date created : 7-Sep-2000 Last revised : 12-Sep-2000 Field is centred on n60 27 33.151,w151 16 7.223 Structure is centred on n60 27 33.151,w151 16 7.223 Slot location is n60 27 37.591,w151 15 41.903 Slot Grid coordinates are N 2362401.390, E 272271.300 Slot local coordinates are 450.90 N 1269.71 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North MARATHON Oil Company Pad 14-6.KU 31-7 Kenai Gas Field,Kenai Peninsula, Alaska Measured Inclin. Azimuth True Vert R E C T A N G U L A R Depth Degrees Degrees Depth C 0 0 R D I N A T E S PROPOSAL LISTING Page 1 Your ref : KU 31-7 Version#2 Last revised : 12-Sep-2000 Dogleg Vert Deg/lOOft Sect 0.00 0.00 59.98 0.00 0.00 N 0.00 E 0.00 0.00 200.00 0.00 59.98 200.00 0.00 N 0.00 E 0.00 0.00 300.00 2.00 59.98 299.98 0.87 N 1.51 E 2.00 1.34 400.00 4.00 59.98 399.84 3.49 N 6.04 E 2.00 5.37 500.00 6.00 59.98 499.45 7.85 N 13.59 E 2.00 12.07 600.00 8.00 59.98 598.70 13.95 N 24.14 E 2.00 21.43 700.00 10.00 59.98 697.47 21.77 N 37.68 E 2.00 33.46 800.00 12.00 59.98 795.62 31.32 N 54.21 E 2.00 48.13 900.00 14.00 59.98 893.06 42.57 N 73.68 E 2.00 65.42 1000.00 16.00 59.98 989.64 55.52 N 96.09 E 2.00 85.32 1100.00 18.00 59.98 1085.27 70.14 N 121.41 E 2.00 107.80 1161.71 19.23 59.98 1143.75 80.00 N 138.46 E 2.00 122.94 1500.00 19.23 59.98 1463.15 135.75 N 234.96 E 0.00 208.62 2000.00 19.23 59.98 1935.24 218.15 N 377.58 E 0.00 335.26 2135.57 19.23 59.98 2063.25 240.50 N 416.25 E 0.00 369.59 2200.00 19.05 65.85 2124.12 250.11 N 435.04 E 3.00 386.49 2300.00 19.15 75.03 2218.64 261.03 N 465.78 E 3.00 414.94 2400.00 19.68 83.91 2312.97 267.05 N 498.38 E 3.00 446.05 2500.00 20.63 92.18 2406.86 268.16 N 532.73 E 3.00 479.72 2600.00 21.93 99.63 2500.06 264.37 N 568.76 E 3.00 515.87 2700.00 23.54 106.20 2592.30 255.67 N 606.36 E 3.00 554.40 2800.00 25.38 111.93 2683.34 242.09 N 645.42 E 3.00 595.19 2900.00 27.41 116.89 2772.92 223.67 N 685.84 E 3.00 638.15 3000.00 29.60 121.19 2860.80 200.46 N 727.51 E 3.00 683.14 3100.00 31.91 124.94 2946.73 172.52 N 770.32 E 3.00 730.06 3200.00 34.32 128.22 3030.49 139.94 N 814.14 E 3.00 778.76 3300.00 36.80 131.12 3111.84 102.79 N 858.86 E 3.00 829.11 3400.00 39.35 133.70 3190.56 61.18 N 904.35 E 3.00 880.99 3500.00 41.94 136.00 3266.44 15.23 N 950.49 E 3.00 934.24 3600.00 44.58 138.09 3339.26 34.94 S 997.16 E 3.00 988.71 3700.00 47.25 139.99 3408.82 89.19 S 1044.22 E 3.00 1044.27 3800.00 49.96 141.73 3474.94 147.38 S 1091.55 E 3.00 1100.76 3874.73 51.99 142.94 3522.00 193.33 S 1127.02 E 3.00 1143.48 Target 1 5787.73 51.99 142.94 4700.00 1396.11 S 2035.39 E 0.00 2242.14 Target 2 All data is in feet unless otherwise stated. Coordinates from slot #KU 31-7 and TVD from Estimated RKB (87.00 Ft above mean sea level). Bottom hole distance is 2468.19 on azimuth 124.45 degrees from wellhead. Total Dogleg for wellpath is 71.41 degrees. Vertical section is from wellhead on azimuth 99.73 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ MARATHON Oil Company Pad 14-6.KU 31-7 Kenai Gas Field,Kenai Peninsula. Alaska PROPOSAL LISTING Page 2 Your ref : KU 31-7 Version#2 Last revised : 12-Sep-2000 Comments in wellpath MD TVD Rectangular Coords. Comment 3874.73 3522.00 193.33 S 1127.02 E Target 1 5787.73 4700.00 1396.11 S 2035.39 E Target 2 Targets associated with this wellpath Target name Geographic Location T.V.D. Rectangular Coordinates Revised ........Target ~ .............~]~]~]~]~]~"~]~ ....... ~]~ ..... ~]~'"~] ~] ~ ....... Target 2 274279.340,2360966.390,0.0000 4700.00 1396.11S 2035.39E 7-Sep-2000 TOP SSTVD TVD KU 31-7 ESTIMATED TOPS AND PRESSURES* 9/13~2000 LOWEST HIGHEST PRESSURE LOWEST PRESSURE GRAD. PRESSURE GRAD. HIGHEST PRESSURE CONTROL STERLING A8 343O 3517 A9 3470 3557 Al0 35OO 3587 A11 358O 3667 B1 3630 3717 B2 3710 3797 B3 3755 3842 B4 3835 3922 B5 Upper - missing 4065 4152 B5 Lower 4100 4187 Cl 4315 4402 C2 4480 4567 Beluga 4560 4647 Total Depth 4613 4700 0.08 281 0.08 285 0.08 287 0.08 293 0.08 297 0.08 3O4 0.08 307 0.08 314 0.34 1412 0.34 1424 0.08 352 0.08 365 0.08 372 0.25 0.11 981 511 Used this horizons structure tv ii Tie to KBU 31-7 Top Beluga o:\KGF~ku31-7~ku31-7tops.xls DLB 9/13/2000 KENAI GAS FIELD DIAGRAMMATIC CROSS SECTION t4-6 Pad 41 7 Pad A' we KDU-7 X UNiT X 4- 0 la i 0 C.I.: 100' 1 MILE MARATHON OIL COMPANY ALASKA REGION ~U 317 Location KENAI FIELD COOK INLET, ALASKA September 2000 SURFACE USE PLAN FOR KENAI UNIT KU 31-7 Surface Location: SW 1/4 of SW 1/4, Sec. 6, T4N, R11W, S.M. 1. Existing Roads Existing roads that will be used for access to Kenai Unit KU 31-7are shown on the attached map. Kenai, Alaska, is the nearest town to the site and is also shown on the map. 2. Access Roads to be Constructed or Reconstructed No new roads will be required to access KU 31-7. 3. Location of Existing Wells Well KU 31-7 will be drilled on pad 14-6. A pad drawing is attached that shows existing wells and the proposed location for KU 31-7. 4. Location of Existing and/or Proposed Facilities The location of existing production facilities in the Kenai Unit are shown on the attached pad drawing. These facilities will be upgraded to handle the additional gas production. 5. Location of Water Supply . The location of the water well is shown on the pad drawing. Water will be used to make and maintain the drilling mud. Construction Materials . No road or pad modifications or improvements are planned. Method of Handling Waste Disposal a) Mud and Cuttings Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to Pad 41-18 of the Kenai Gas Field for disposal into Well KU 11-17, a Class II disposal well (AOGCC Disposal Injection Order No. 9, Permit #81-176). \~,LARS0 I\COMMON\DRLG\KG ~W ELLS\KU31-7\SURFUSE.doc Surface Use Plan Kenai Unit KBU 33-6 Page 2 . . 10. b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) Completion Fluids Clear fluids will be hauled to Pad 34-31 of the Kenai Gas Field and injected in Well WD #1, an approved disposal well (AOGCC Permit #7-194). d) Chemicals Unused chemicals will be returned to the vendor who provided them. Efforts will be made to minimize the use of all chemicals. e) Sewage Sewage will be hauled to the Kenai sanitation facility. Ancillary Facilities A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose, Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. Town & Country will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. Plans for Reclamation of the Surface Kenai Unit KU 31-7 will be drilled from an existing pad. Reclamation of the pad will occur after abandonment of KU 31-7 and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from CIRI Native Corporation prior to any reclamation work beginning. Surface Ownership The surface owner of the land in the Kenai Unit is the CIRI Native Corporation. 11. Operator's Representative and Certification Surface Use Plan Kenai Unit KBU 33-6 Page 3 I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that l am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: Name & Title: Mar'ath~n Oil Company P. O. Box 196168 Anchorage, Alaska 99519-6168 (907) 561-5311 (ENAI B-4 ]UADNANOLE ,11, ,//, PAD ELEVA~lONw85.6' M.S.L FiLm 'Il, '1I, '1I, )pll~ KU 31-7 11~4 GLO/liLt4 meeument laurel thl. eur4y. 0 Faunal1/2' rebm eFound 2 1/2' bra.~ capped manument ~ Ught Pab ~ Sq~U= rant 8 7 + "I BY I1~1~, L ! I I ~1 KENAI OAS FIELD PAD AS-BUILT SURVEY KBIIAI GAl FIELD PAD 14-~B lC~t~''"DAw I I'"T-I'" I"~1~' I --""' r"'~ RE ~'-~cm~.,~,m~ '1 ~'lSl°l°° I°1 ~ I ~ I s/ o I~,P.....,.,.,o~w I I I .I I/ I l I Coastal Project Questionnaire and Certification Statement Please answer all questions. To avoid a delay in processing, please call the department if you answer "yes" to any of the questions related to that department. Maps and plan drawings must be included with your packet. An incomplete packet will be returned. · APPLICANT INFORMATION 1. Marathon Oil Company 2. Robert J. Menzie, Jr. Name of Applicant P.O. Box 196168 Agent (or responsible party if other than applicant) P.O. Box 196168 Address Address Anchorage Alaska 99519-6168 Anchorage City/State Zip Code City/State State 907-561-5311 907-564-6372 Daytime Phone Daytime Phone 907-564-6489 907-564-6489 Fax Number E-mail Address Fax Number Alaska 99519-6168 Zip Code Zip Code rjmenzie@marathonoil.com E-mail Address · PROJECT INFORMATION Yes No 1. This activity is a: X new project [] modification or addition to an existing project If a modification, do you currently have any State, federal or local approvals related to this activity? .......................................................................................................................... [] [] Note: Approval means any form of authorization. If "yes," please list below: Approval Type Approval # Issuance Date Expiration Date 2. If a modification, has this project ever been reviewed by the State of Alaska under the ACMP? ........... [] [] Previous State I.D. Number: AK Previous Project Nalne: · PROJECT DESCRIPTION 1. Provide a brief description of your entire project and ALL associated facilities and land use conversions. Attach additional sheet(s) as needed. Marathon Oil Company is proposing to drill and complete a directionally drilled natural gas development well, KU 31-7, at the surface location described as 365 ft from the south line, 1228 ft from the west line of Sec. 6, T4N, R11W, Seward Meridian from existing gravel pad 14-6 in the Kenai Gas Field. The bottom hole location is 1028 ft from the north line, 3397 ft from the west line of Sec. 7, T4N, R11W, Seward Meridian. Pad 14-6 is located 6.5 miles south of Kenai, Alaska. This project consists of drilling, groundwater use, and temporary waste storage. Proposed starting date for project: December 1, 2000 Proposed ending date for project: Ja~ J~,~l~ ~L~ ~. Revised 1/99 Page 1 . Attach the following: · a detailed description of the project, all associated facilities, and land use conversions, etc. (Be specific, including access roads, caretaker facilities, waste disposal sites, etc.); · a project timeline for completion of all major activities in the proposal; · a site plan depicting property boundary with all proposed actions; · other supporting documentation that would facilitate review of the project. Note: If the project is a modification, identify existing facilities as well as proposed changes on the site plan. · PROJECT LOCATION 1. Attach a copy of the topographical and vicinity map clearly indicating the location of the project. Please include a map title and scale. 2. The project is located in which region (see attached map): [] Northern X Southcentral [] Southeast [] within or associated with the Trans-Alaska Pipeline corridor 3. Location of project (Include the name of the nearest land feature or body of water.)9 miles north of Ninilchik, Alaska Township: IN Range:13W Section: 23 Meridian: S Latitude/Longitude N 60°8'/W151° USGS Quad Map Kenai (A-4) . Is the project located in a coastal district? Yes X No [] If yes, identify: Zone 17 Kenai Peninsula Borough (Coastal districts are a municipality or borough, home rule or first class city, second class with planning, or coastal resource service area.) Note: A coastal district is a participant in the State's consistency review process. It is possible for the State review to be adjusted to accommodate a local permitting public hearing. Early interaction with the district is important; please contact the district representative listed on the attached contact list. 5. Identify the communities closest to your project location: Kenai, Alaska . The project is on: [] State land or water* [] Federal land X Private land [] Municipal land [] Mental Health Trust land *State land can be uplands, tidelands, or submerged lands to 3 miles offshore. See Question #1 in DNR section. Contact the applicable landowner(s) to obtain necessary authorizations. · DEPARTMENT OF ENVIRONMENTAL CONSERVATION (DEC) APPROVALS Yes 1. Will a discharge of wastewater from industrial or commercial operations occur? .................................. [] Will the discharge be connected to an already approved sewer system? ................................................. [] Will the project include a stormwater collection/discharge system? ....................................................... [] . Do you intend to construct, install, modify, or use any part of a wastewater (sewage or greywater) disposal system? .............................................................................................................. [] a) If so, will the discharge be 500 gallons per day or greater? .............................................................. [] b) If constructing a domestic wastewater treatment or disposal system, will the system be located within fill material requiring a COE permit? ................................... ~ ................... [] If you answered yes to a) or b), answer the following: 1) What is the distance from the bottom of the system to the top of the subsurface water table? 2) How far is any part of the wastewater disposal system from the nearest surface water? No X X X X [] Revised 1/99 Page 2 Yes 3) Is the surrounding area inundated with water at any time of the year? ............................................. [] 4) How big is the fill area to be used for the absorption system? (Questions I & 2 will be used by DEC to determine whether separation distances are being met; Questions 3 & 4 relate to the required size of the fill if wetlands are involved.) o Do you expect to request a mixing zone for your proposed project? .................................................... [] (If your wastewater discharge will exceed Alaska water quality standards, you may apply for a mixing zone. If so, please contact DEC to discuss information required under 18 AAC 70.032.) . a) Will your project result in the construction, operation, or closure of a facility for the disposal of solid waste? .................................................................................................................. [] (Note: Solid waste means drilling wastes, household garbage, refuse, sludge, construction or demolition wastes, industrial solid waste, asbestos, and other discarded, abandoned, or unwanted solid or semi-solid material, whether or not subject to decomposition, originating from any source. Disposal means placement o. f solid waste on land.) b) Will your project result'in the treatment of solid waste at the site? ................................................. [] (Examples of treatment methods include, but are not limited to: incineration, open burning, baling, and composting.) c) Will your project result in the storage or transfer of solid waste at the site? .................................... X d) Will the project result in the storage of more than 50 tons of materials for reuse, recycling, or resource recovery? ...................................................................................................................... [] e) Will any sewage solids or biosolids be disposed of or land-applied to the site? ............................. [] (Sewage solids include wastes that have been removed from a wastewater treatment plant system, such as a septic tank, lagoon dredge, or wastewater treatment sludge that contain no free liquids. Biosolids are the solid, semi-solid, or liquid residues produced during the treatment of domestic septage in a treatment works which are land applied for beneficial use.) 5. Will your project require the application of oil, pesticides, and/or any other broadcast chemicals? ............................................................................................................................................. [] a) Will you have a facility with industrial processes that are designed to process no less thanfive tons per hour and needs air pollution controls to comply with State emission standards? ........................................................................................................................ [] b) Will you have stationary or transportable fuel burning equipment, including flares, with a total fuel consumption capacity no less than 50 million Btu/hour? ...................................... [] c) Will you have a facility with incinerators having a total charging capacity of no less than 1,000 pounds per hour? ........................................................................................................... [] d) Will you have a facility with equipment or processes that are subject to Federal New Source Performance Standards or National Emission Standards for hazardous air pollutants? ...... [] i) Will you propose exhaust stack injection? ............................................................................... [] e) Will you have a facility with the potential to emit no less than 100 tons per year of any regulated air contaminant? ............................................................................................................... X f) Will you have a facility with the potential to emit no less than 10 tons per year of any hazardous air contaminant or 25 tons per year of all hazardous air contaminants? ......................... [] g) Will you construct or add stationary or transportable fuel burning equipment of no less than 10 million Btu/hour in the City of Unalaska or the City of St. Paul? ...................................... [] h) Will you construct or modify in the Port of Anchorage a volatile liquid storage tank with a volume no less than 9,000 barrels, or a volatile liquid loading rack with a design throughput no less than 15 million gallons? ................................................................................... [] i) Will you be requesting operational or physical limits designed to reduce emissions from an existing facility in an air quality nonattainment area to offset an emission increase No X X X [] X X X X X X X X X X X Revised 1/99 Page 3 Yes from another new of modified facility? ................................................................................................... [] 7. Will you be developing, constructing, installing, or altering a public water system? .............................. [] . a) Will your project involve the operation of waterborne tank vessels or oil barges that carry crude or non-crude oil as bulk cargo, or the transfer of oil or other petroleum products to or from such a vessel or a pipeline system? ................................................. [] b) Will your project require or include onshore or offshore oil facilities with an effective aggregate storage capacity of greater than 5,000 barrels of crude oil or greater than 10,000 barrels of non-crude oil? ............................................................................. [] c) Will you be operating facilities on the land or water for the exploration or production of hydrocarbons? .............................................................................................................................. X If you answered "NO" to ALL questions in this section, continue to next section. If you answered "YES" to ANY of these questions, contact the DEC office nearest you for information and application forms. Please be advised that all new DEC permits and approvals require a 30-day public notice period. DEC Pesticide permits take effect no sooner than 40 days after the permit is issued. Based on your discussion with DEC, please complete the following: Types of project approvals or permits needed Date application submitted No X X X X 9. Does your project qualify for a general permit for wastewater or solid waste? ....................................... [] Note: A general permit is an approval issued by DEC for certain types of routine activities. X If you answered "YES" to any questions in this section and are not applying for DEC permits, indicate reason: X Laura Ogar (DEC contact) told me on 9/6/00 that no DEC approvals are required on this project because a temporary waste storage plan (4c) is already on file at ADEC-Solid Waste X Other: (6e) Title V Operating Permit Application-Pad 14-6 (submitted October 28. 1997) · DEPARTMENT OF FISH & GAME (DFG) APPROVALS Will you be working in, removing water or material from, or placing anything in, a stream, river or lake? (Zhis includes work or activities below the ordinary high water mark or on ice, in the active flood plain, on islands, in or on the face of the banks, or, for streams entering or flowing through tidelands, above the level of mean lower low tide.) Note: If the proposed project is located within a special flood hazard area, a floodplain development permit may be required. Contact the affected city or borough planning department.for additional information and a floodplain determination.) ................. [] Name of waterbody: X Will you do any of the following: ........................................................................................................... [] Please indicate below: [] Build a dam, river training structure, other instream impoundment, or weir [] Use the water [] Pump water into or out of stream or lake (including dry channels) X [] Divert or alter the natural stream channel [] Change the water flow or the stream channel [] Introduce silt, gravel, rock, petroleum products, debris, brush, trees, chemicals, or Revised 1/99 Page 4 other organic/inorganic material, including waste of any type, into the water [] Alter, stabilize or restore the banks of a river, stream or lake (provide number of linear feet affected along the bank(s) [] Mine, dig in, or remove material, including woody debris, from the beds or banks of a waterbody [] Use explosives in or near a waterbody [] Build a bridge (including an ice bridge) [] Use the stream, lake or waterbody as a road (even when frozen), or cross the stream with tracked or wheeled vehicles, log-dragging or excavation equipment (backhoes, bulldozers, etc.) [] Install a culvert or other drainage structure [] Construct, place, excavate, dispose or remove any material below the ordinary high water of a waterbody [] Constmct a storm water discharge or drain into the waterbody [] Place pilings or anchors [] Construct a dock [] Construct a utility line crossing [] Maintain or repair an existing structure [] Use an instream in-water structure not mentioned here Yes Is your project located in a designated State Game Refuge, Critical Habitat Area or State Game Sanctuary? ........................................................................................................................... [] 4. Does your project include the construction/operation of a salmon hatchery? ......................................... [] 5. Does your project affect, or is it related to, a previously permitted salmon hatchery? ............................ [] 6. Does your project include the construction of an aquatic farm? ............................................................. [] If you answered "No" to ALL questions in this section, continue to next section. If you answered "Yes" to ANY questions under 1-3, contact the Regional or Area DFG Habitat and Restoration Division Office for information and application forms. If you answered "Yes" to ANY questions under 4-6, contact the DFG Commercial Fisheries Division headquarters for information and application forms. Based on your discussion with DFG, please complete the following: Types of project approvals or permits needed Date application submitted No X X X If you answered "YES" to any questions in this section and are not applying for DFG permits, indicate reason: [] (DFG contact) told me on that no DFG approvals are required on this project because [] Other: · DEPARTMENT OF NATURAL RESOURCES (DNR) APPROVALS 1. Is the proposed project on State-owned land or water or will you need to cross State-owned land for access? ("Access" includes temporary access for construction purposes. Note: In addition to State-owned uplands, the State owns almost all land below the ordinary high water line of navigable streams, rivers and lakes, and below the mean high tide line seaward for three miles.) ......................................................................................................... [] a) Is this project for a commercial activity? ........................................................................................... X 2. Is the project on Alaska Mental Health Tmst land (AMHT) or will you need to cross AMHT land? X [] Revised 1/99 Page 5 Note: Alaska Mental Health Trust land is not considered State land for the purpose of ACMP reviews .................................... [] Do you plan to dredge or otherwise excavate/remove materials on State-owned land? .......................... [] Location of dredging site if different than the project site: Township__ Range__ Section__ Meridian__ USGS QuadMap . Do you plan to place fill or dredged material on State-owned land? ....................................................... [] Location of fill disposal site if other than the project site: Township__ Range__ Section__ Meridian__ USGS Quad Map Source is on: [] State Land [] Federal Land [] Private Land [] Municipal Land 5. Do you plan to use any of the following State-owned resources: ............................................................ [] [] Timber: Will you be harvesting timber? Amount: [] Materials such as rock, sand or gravel, peat, soil, overburden, etc.: ............................................... Which material? Amount: Location of source: [] Project site [] Other, describe: Township_ Range__ Section__ Meridian__ USGS Quad Map Yes 6. Are you planning to divert, impound, withdraw, or use any fresh water, except from an existing public water system or roof rain catchment system (regardless of land ownership)? ............................... Amount (maximum daily, not average, in gallons per day): 42,000 Source: existing water well Intended Use: drilling mud maintenance If yes, will your project affect the availability of water to anyone holding water rights to that water? ... [] 7. Will you be building or altering a dam (regardless of land ownership)? ................................................. [] 8. Do you plan to drill a geothermal well (regardless of land ownership)? ................................................. [] 9. At any one site (regardless of land ownership), do you plan to do any of the following? ....................... [] [] Mine five or more acres over a year's time [] Mine 50,000 cubic yards or more of materials (rock, sand or gravel, soil, peat, overburden, etc.) over a year's time [] Have a cumulative unreclaimed mined area of five or more acres If yes to any of the above, contact DNR about a reclamation plan. If you plan to mine less than the acreage/amount stated above and have a cumulative unreclaimed mined area of less than five acres, do you intend to file a voluntary reclamation plan for approval? ..... [] 10. Will you be exploring for or extracting coal? .......................................................................................... [] 11. a) Will you be exploring for or producing oil and gas? ......................................................................... X b) Will you be conducting surface use activities on an oil and gas lease or within an oil and gas unit? X 12. Will you be investigating, removing, or impacting historical or archaeological or paleontological resources (anything over 50 years old) on State-owned land? ................................................................. [] 13. Is the proposed project located within a known geophysical hazard area? .............................................. [] Note: 6 AAC 80.900(9) defines geophysical hazard areas as "those areas which present a threat to life or property from geophysical or geological hazards, including flooding, tsunami run-up, storm surge run-up, landslides, snowslides, .faults, ice hazards, erosion, and littoral beach process." "known geophysical hazard area" means any area identified in a report or Revised 1/99 Page 6 X X X X No X X X X X X X map published by a federal, state, or local agency, or by a geological or engineering consulting firm, or generally known by local knowledge, as having known or potential hazards from geologic, seismic, or hydrologic processes. 14. Is the proposed project located in a unit of the Alaska State Park System? ............................................ [] If you answered "No" to ALL questions in this section, continue to Federal Approvals section. If you answered "Yes" to ANY questions in this section, contact DNR for information. Based on your discussion with DNR, please complete the following: Types of project approvals or permits needed AOGCC Permit to Drill KU31-7 Date application submitted pending (9/15/00) X If you answered "YES" to any questions in this section and are not applying for DNR permits, indicate reason: [] (DNR contact) told me on that no DNR approvals are required on this project because. X Other: Temporary Water Use Permit (TWUP A99-23) is in effect for the existing water well. · FEDERAL APPROVALS Yes U.S. Army Corps of Engineers (COE) 1. Will you be dredging or placing structures or fills in any of the following: tidal (ocean) waters? streams? lakes? wetlands*? ................................................................................... [] If yes, have you applied for a COE permit? ...................................................................................... [] Date of submittal: (Note: Your application for this activity to the COE also serves as application for DEC Water Quality Certification.) *If you are not certain whether your proposed project is in a wetlands (wetlands include muskegs), contact the COE, Regulatory Branch at (907) 753-2720for a wetlands determination (outside the Anchorage area call toll free 1-800-478-2712). No X [] Bureau of Land Management (BLM) 2. Is the proposed project located on BLM land, or will you need to cross BLM land for access? .............[] If yes, have you applied for a BLM permit or approval? ................................................................... X Date of submittal: Permit to Drill KU 31-7, approximately 9/15/00 (pending) X [] U.S. Coast Guard (USCG) 3. a) Will you be constmcting a bridge or causeway over tidal (ocean) waters, or navigable rivers, streams or lakes? ............................................................................................................................... [] b) Does your project involve building an access to an island? .............................................................. [] c) Will you be siting, constructing, or operating a deepwater port? ...................................................... [] If yes, have you applied for a USCG permit? ............................................................................. [] Date of submittal: X X X [] U.S. Environmental Protection Agency (EPA) 4. a) Will the propos.ed project have a discharge to any waters? .............................................................. [] b) Will you be disposing of sewage sludge (contact EPA at 206-553-1941)? ...................................... [] If you answered yes to a) or b), have you applied for an EPA National Pollution Discharge Elimination System (NPDES) permit? ....................................................................................... [] Date of submittal: (Note: For information regarding the need for an NPDES permit, contact EPA at (800) 424-4372.) c) Will construction of your project expose 5 or more acres of soil? (this applies to the total amount of land disturbed, even if disturbance is distributed over more than one season, and also applies to areas that are part of X X Revised 1/99 Page 7 Yes a larger common plan of development or sale.) ....................................................................................................... [] No d) Is your project an industrial facility which will have stormwater discharge which is directly related to manufacturing, processing, or raw materials storage areas at an industrial plant? ............ [] If you answered yes to c) or d), your project may require an NPDES Stormwater permit. Contact EPA at 206-553-8399. Federal Aviation Administration (FAA) 5. a) Is your project located within five miles of any public airport? ........................................................ [] b) Will you have a waste discharge that is likely to decay within 5,000 feet of any public airport? ............ [] If yes, please contact the Airports Division of the FAA at (907) 271-5444. X X X Federal Energy Regulatory Commission (FERC) 6. a) Does the project include any of the following: 1) a non-federal hydroelectric project on any navigable body of water .......................................... [] X 2) a location on federal land (including transmission lines) ........................................................... [] X 3) utilization of surplus water from any federal government dam .................................................. [] X b) Does the project include construction and operation, or abandonment of natural gas pipeline facilities under sections (b) and (c) of the Federal Power Act (FPA)? ............................................. [] X c) Does the project include construction for physical interconnection of electric transmission facilities under section 202 (b) of the FPA? ..................................................................................... [] X If you answered yes to any questions under number 6, have you applied for a permit from FERC? ....................................................................................................................................... [] [] Date of submittal: (Note: For information, contact FERC, Office of Hydropower Licensing (202) 219-2668; Office of Pipeline Regulation (202) 208-0700; Office of Electric Power Regulation (202) 208-1200.) U.S. Forest Service (USFS) 7. a) Does the proposed project involve construction on USFS land? ...................................................... [] X b) Does the proposed project involve the crossing of USFS land with a water line? ............................ [] X If the answer to either question is yes, have you applied for a USFS permit or approval? ......... [] [] Date of submittal: 8. Have you applied for any other federal permits or authorizations? ......................................................... [] AGENCY APPROVAL TYPE DATE SUBMITTED X Please be advised that the CPQ identifies permits subject to a consistency review. You may need additional permits from other agencies or the affected city and/or borough government to proceed with your activity. Revised 1/99 Page 8 Certification Statement The information contained herein is tree and complete to the best of my knowledge. I certify that the proposed activity complies with, and will be conducted in a manner consistent with, the Alaska Coastal Management Pro Signaiure ot7 Appli~ ~r~; ' Date INote: Federal agencies conducting an adtivity that will affect the coastal zone are required to submit a federal I cons~stency detenmnat~on, 15 CFR 930, rather than th~s certification per Subpart C, statement. IDGC has developed a guide to assist federal agencies with this requirement. Contact DGC to obtain a copy. This certification statement will not be cOmplete until all required State and federal authorization requests have been submitted to the appropriate agencies. :1 To complete your packet, please attach your State permilt applications and copies of your federal permit applications to this questionnaire. Revised 1/99 Page KBU 31-7 Surface Cement Volume Subject: KBU 31-7 Surface Cement Volume Date: Mon, 13 Nov 2000 18:07:39 -0600 From: "Craig E Young" <CEYoung@marathonoil.com> To: Tom_Maunder@admin.state.ak. us CC: PKBerga@marathonoil.com Tom, This is to confirm our phone conversation today regarding the surface casing cement job for the subject well. Marathon will circulate cement to surface and will pump approximately 660 sacks of 12.0 PPG slurry with a yield of 2.39 cu.ft./sack. We will use stab-in float equipment for the surface job and cut to displacement only after good cement returns have been observed at the surface. If you need any other information, or any additional information, please give me a call. Craig Young 1 of 1 11/13/00 3:23 PM 2583-ri't16-7306 Mr"qRE® ©1997 D'~',rityBandsTM Pal. ~"%, 4,227,720: 4)~d.180; 5,340,159 --d other pals, per'a;"e .~aska ,..Oil.& Gas Conservation Commission , .3OD'I., Por. cupine .D.r ive '..Ancho=,age,....AK .. 99.501,3192 , , p,.;~, . ,' , ': 1252 MATCH AMOUNT IN I '. WORDS WITH NUMBERS I ~ .-..-...~.....-,.;..' .~-.-.:...-_-.: .'_-.' .........-_-;..'......-.....,.,..-...-.:,. · .-,.,... -.. . ~ I ' ;.r ' ..'::' :-'.' .'.'.;' .':.'.' .".:'..: :.-. .";'..--.":.":.' .'~.;.;" '.;'.' .'.'~' .,.-..': ~ .$.'::.: .:.~:?:.-:1:.~.-2....~.~!.:-: :~:.-'...'..'::.--.:'.~:"~!.T:.~:.':.::v :-,, Il:-.;::'::;.:::::;::,~:.:".~'.:;f~:6~a.~.:~..¢ ::::.':-.::?'.:.:..':.~::.:'":~:'.::';..:..": .:::' . :.."':.-:." .::::" ..!:.". .-::". ;:.:"::,:.-'.." .-!;." /" '.:.:':: :?' :.-.:? ;!::'.' .:~::..' .:7 :...' .!...' :?.: ..:::';~..' .'.7.'.:.;5;:;.."::~:.'?:"??:::.'~!,.:?.:"':-:~:..::~::" :'.~:.'--.!! N ATI O NAL ............ BANK OF ALASKA By/..);/~--//~~. ~/~n ~;~.~ · ~/// ANCHORAGE, ALASKA - .... ~¢~%~,.4~ ~~~ .......... ,'00;508,' ':~5800057~:0;,'07~5g 9205500 Marathon Oil Company P.O. Box 196168 ANCHORAGE, ALASKA 99519-6168 O9 O0 OPERATOR CITY STATE _ _ _ -- OR NON-REPORTING 100% REPORTABLE INTEREST IF REPORTABLE RENTS INDICATE TYPE OF PAYMENT KU 31-7 ~.-~ :WELL PERMIT CHECKLIST COMPANY /~['Zz-~-'t'//'~O'~ WELL NAME .~ / - '? FIELD & POOL ~/~//~ ~-'~ ~i INIT CLASS ~-~ ADMINISTRATION 1. Permit fee attached ....................... 2. Lease number appropriate ................... 3. Unique well name and.number .................. 4. Well located in a defined pool .................. 5. Well located proper distance from drilling unit boundary .... 6. Well located proper distance from other wells .......... 7. Sufficient acreage available in drilling unit ............ 8. If deviated, is wellbore plat included ............... 9. Operator only affected party ................... 10. Operator has appropriate bond in force ............. 11. Permit can be issued without conservation order ........ 12. Permit can be issued without administrative approval ...... 13. Can permit be approved before 15-day wait ........... ENGINEERING 14. 15. 16. 17. 18. 19. 20. 21. 22. 23. 24. 25. . D~TE 26. It[I'~ 27. 28. 29. Conductor string provided ................... Surface casing protects all known USDWs ........... CMT vol adequate to circulate on conductor & surf csg ..... CMT vol adequate to tie-in long string to surf csg ........ CMT will cover all known productive horizons .......... Casing designs adequate for C, T, B & permafrost ....... Adequate tankage or reserve pit ................. If a re-drill, has a 10-403 for abandonment been approved... Adequate wellbore separation proposed ............. If diverter required, does it meet regulations .......... GEOLOGY A~k,~ DATE Drilling fluid program schematic & equip list adequate ..... BOPEs, do they meet regulation ................ BOPE press rating appropriate; test to '~(~(~%_~ psig. Choke manifold complies w/APl RP-53 (May 84) ........ Work will occur without operation shutdown ........... Is presence of H2S gas probable ................. PROGRAM: exp , dev ¢/reddl serv wellbore seg GEOL AREA ann. disposal para req UNIT# ~,_.,~'-//~ ON/OFF SHORE 30. Permit can be issued w/o hydrogen sulfide measures ..... ~ N 31. Data presented on potential overpressure zones ....... ~:~ ~ 32. Seismic analysis of shallow gas zones ........... '.~AJ; Y N 33. Seabed condition survey (if off-shore) ....... . .~<~...- Y N 34. Contact name/phone for weekly progress reports [exlSIoratory only] Y N ANNULAR DISPOSAL35. With proper cementing records, this plan (A) will contain waste in a suitable receiving zone; ....... APPR DATE (B) will not contaminate freshwater; or cause drilling waste... to surface; (C) will not impair mechanical integrity of the well used for disposal; (D) will not damage producing formation or impair recovery from a pool; and (E) will not circumvent 20 AAC 25.252 or 20 AAC 25.412. Y N ',,5 %\c~. ,x i GEOLOJ~: ENGINEERING: UICIAnnula~r COMMISSION: Comments/Instructions: c:\msoffiCe\wordian\diana\checklist (rev. 02/17/00)