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Home My WebLink About204-161Kyle Wiseman Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 03/17/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230317 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU L-57 50029236090000 218072 3/7/2023 READ CaliperSurvey SRU 23-33 50133101630000 161019 2/16/2023 AK E-LINE Jet Cut CLU-9 50133205440000 204161 2/24/2023 HALLIBURTON PPROF CLU-15 50133206870000 220003 2/26/2023 HALLIBURTON PPROF END 1-11 50029221070000 190157 2/19/2023 HALLIBURTON MFC END 1-11 50029221070000 190157 2/25/2023 HALLIBURTON PLUG-PERF KU 14X-06 50133203420000 181092 3/1/2023 HALLIBURTON LDL Please include current contact information if different from above. CLU-9 50133205440000 204161 2/24/2023 HALLIBURTON PPROF Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Date: 07/11/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL Well API # PTD # Log Date Log Company Log Type Notes BCU 18RD 50133205840100 222033 6/11/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/18/2022 Yellowjacket GPT-PERF + Report BCU 18RD 50133205840100 222033 6/7/2022 Yellowjacket GPT-PLUG + Report BCU 24 50133206390000 214112 6/16/2022 Halliburton PPROF BCU 24 50133206390000 214112 5/23/2022 Yellowjacket GPT-PERF + Report BCU 24 50133206390000 214112 5/26/2022 Yellowjacket GPT-PERF + Report BCU 7A 50133202840100 214060 6/21/2022 Yellowjacket CBL BCU 7A 50133202840100 214060 6/15/2022 Yellowjacket GAMMA RAY + Report BRU 232-26 50283200770000 184138 5/25/2022 Yellowjacket CBL CLU 01RD 50133203230100 203129 5/19/2022 Yellowjacket PERF + Report CLU 01RD 50133203230100 203129 5/24/2022 Yellowjacket PERF + Report CLU 09 50133205440000 204161 5/27/2022 Yellowjacket PERF + Report CLU-1RD 50133203230100 203129 5/28/2022 Halliburton PPROF + Report END 1-17A 50029221000100 196199 5/26/2022 Halliburton LDL END 1-45 50029219910000 189124 5/23/2022 Halliburton LDL + Report END 3-17F 50029219460600 203216 6/15/2022 AK E-Line PLUG CUT FALLS CREEK 3 50133205240000 203102 6/4/2022 Yellowjacket PERF + Report HVB B-16 50231200400000 212133 6/14/2022 AK E-Line CIBP KALOTSA 1 50133206570000 216132 7/7/2022 Yellowjacket PERF + Report KBU 11-07 50133205560000 205165 6/16/2022 Yellowjacket GPT-PERF + Report KBU 11-07 50133205560000 205165 6/20/2022 Yellowjacket GPT-PERF + Report KBU 33-06X 50133205290000 203183 6/22/2022 Yellowjacket CBL MPU B-28 50029235660000 216027 5/27/2022 Halliburton LDL MPU B-28 50029235660000 216027 5/27/2022 Halliburton MFC + Report MPU B-30 50029235710000 216153 5/18/2022 Halliburton PERF MPU E-06 50029221540000 191048 5/28/2022 Halliburton MFC + Report Kaitlyn Barcelona Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: MPU E-35 50029236150000 218152 6/15/2022 Halliburton MFC + Report MPU L-50 50029235550000 215132 6/24/2022 Read COIL FLAG PAXTON 10 50133206910000 220064 5/27/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton PPROF + Report PBU C-24B 50029208160200 212063 5/28/2022 Halliburton RBT PBU GNI-03 50029228200000 197189 6/25/2022 Read CALIPER PBU GNI-03 50029228200000 197189 6/25/2022 Read TEMP-PRESS PBU K-01 50029209980000 183121 6/21/2022 Halliburton PPROF + Report PBU M-13A 50029205220100 201165 5/27/2022 Halliburton TMD3D-WFL + Report PBU NGI-05 50029201960000 176014 6/7/2022 Halliburton CAST PBU W-01A 50029218660100 203176 6/8/2022 Halliburton RBT SRU 241-33 50133206630000 217047 6/13/2022 Yellowjacket PERF SRU 241-33B 50133206960000 221053 5/25/2022 Halliburton TEMP-PRESS SRU 32A-33 50133101640100 191014 6/11/2022 AK E-Line PPROF Please include current contact information if different from above. BCU 18RD PTD:222-033 T36747 BCU 24 PTD:214-112 T36748 BCU 7A PTD:214-060 T36749 BRU 232-26 PTD:184-138 T36750 CLU 01RD PTD:203-129 T36751 CLU 09 PTD: 204-161 T36752 CLU1RD PTD:203-129 T36751 END 1-17A PTD:196-199 T36753 END 1-45 PTD:189-124 T36754 END 3-17F PTD:203-216 T36755 Falls Creek 3 PTD:203-102 T36756 HVB B-16 PTD:212-133 T36757 Kalosta 1 PTD:216-132 T36758 KBU 11-7 PTD:205-165 T36759 KBU 33-06X PTD:203-183 T36760 MPU B-28 PTD:216-027 T36761 MPU B-30 PTD:216-153 T36762 MPU E-06 PTD: 191-048 T36763 MPU E-35 PTD:218-152 T36764 MPU L-50 PTD:215-132 T36765 Paxton 10 PTD:220-064 T36766 PBU C-24B PTD:212-063 T36767 PBU GNI-03 PTD:197-189 T36768 PBU K-01 PTD:183-121 T36769 PBU M-13A PTD:201-165 T36770 PBU NGI-05 PTD:176-014 T36771 PBU W-01A PTD:203-176 T36772 SRU 241-33 PTD:217-047 T36773 SRU 241-33B PTD:221-053 T36774 SRU 32A-33 PTD: 191-014 T36775 Kayla Junke Digitally signed by Kayla Junke Date: 2022.07.12 12:56:51 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 05/17/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL CLU 9 (PTD 204-161) Pressure/Temperature 04/22/2022 Please include current contact information if different from above. PTD:204-161 T36620 Kayla Junke Digitally signed by Kayla Junke Date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ϴ͕ϮϱϳΖ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aSVL1$ 3 W B V )RUP5HYLVHG$SSURYHGDSSOLFDWLRQLVYDOLGIRUPRQWKVIURPWKHGDWHRIDSSURYDO By Meredith Guhl at 12:54 pm, May 06, 2022 'LJLWDOO\VLJQHGE\'DQ0DUORZH '1FQ 'DQ0DUORZH RX 8VHUV 'DWH 'DQ0DUORZH '65'/% %-0 ; -/& Jeremy Price Digitally signed by Jeremy Price Date: 2022.05.17 05:39:02 -08'00' RBDMS SJC 052022 tĞůůWƌŽŐŶŽƐŝƐ tĞůů͗>hϬϵ ĂƚĞ͗ϱͬϲͬϮϬϮϮ tĞůůEĂŵĞ͗>hϬϵW/EƵŵďĞƌ͗ϱϬͲϭϯϯͲϮϬϱϰϰͲϬϬͲϬϬ ƵƌƌĞŶƚ^ƚĂƚƵƐ͗&ůŽǁŝŶŐ'ĂƐtĞůů>ĞŐ͗Eͬ ƐƚŝŵĂƚĞĚ^ƚĂƌƚĂƚĞ͗ϱͬϭϲͬϮϬϮϮZŝŐ͗Ͳ>ŝŶĞ ZĞŐ͘ƉƉƌŽǀĂůZĞƋ͛Ě͍ϭϬͲϰϬϯĂƚĞZĞŐ͘ƉƉƌŽǀĂůZĞĐ͛ǀĚ͗ ZĞŐƵůĂƚŽƌǇŽŶƚĂĐƚ͗ŽŶŶĂŵďƌƵǌϳϳϳͲϴϯϬϱWĞƌŵŝƚƚŽƌŝůůEƵŵďĞƌ͗ϮϬϰͲϭϲϭ &ŝƌƐƚĂůůŶŐŝŶĞĞƌ͗ŚĂĚ,ĞůŐĞƐŽŶ;ϵϬϳͿϳϳϳͲϴϰϬϱ;KͿ;ϵϬϳͿϮϮϵͲϰϴϮϰ;Ϳ ^ĞĐŽŶĚĂůůŶŐŝŶĞĞƌ͗ZǇĂŶZƵƉĞƌƚ;ϵϬϳͿϳϳϳͲϴϱϬϯ;KͿ;ϵϬϳͿϯϬϭͲϭϳϯϲ;Ϳ &EƵŵďĞƌ͗ϮϮϮͲϬϬϲϰϰ Current Bottom Hole Pressure: 3,187 psi @ 7,059’ TVD Based on A-13 RFT data of LB 2C sand on 2/2015 Maximum Expected BHP: 2,882 psi @ 7,018’ TVD Based on A-14 RFT data of LB 2B sand on 7/2019 Maximum Potential Surface Pressure: ~2,180 psi @ 7,018’ TVD Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) ƌŝĞĨtĞůů^ƵŵŵĂƌǇ >hϵǁĂƐĚƌŝůůĞĚŝŶϮϬϬϰĂŶĚĐŽŵƉůĞƚĞĚǁŝƚŚĂŶĞƐĐĂƉĞĐŽŵƉůĞƚŝŽŶǁŝƚŚϭϲŵŽĚƵůĞƐ͘&ƌĂĐƚƵƌĞƐƚŝŵƵůĂƚĞĚƚŚĞ ǁĞůůŝŶEŽǀĞŵďĞƌϮϬϬϰ͘/ŶϮϬϬϲŵŽĚƵůĞƐϭϮͲϭϲǁĞƌĞƐƋƵĞĞǌĞĚǁŝƚŚĐŽŝůƚƵďŝŶŐƚŽŝƐŽůĂƚĞǁĂƚĞƌƉƌŽĚƵĐŝŶŐ ƐĂŶĚƐ͘/ŶϮϬϬϴĂĐĂƉŝůůĂƌǇƐƚƌŝŶŐǁĂƐƌƵŶƚŽϴ͕ϭϳϱ͛͘dŚĞĐĂƉƐƚƌŝŶŐǁĂƐƉƵůůĞĚŝŶϮϬϮϬ͘ dŚĞƉƵƌƉŽƐĞŽĨƚŚŝƐǁŽƌŬͬƐƵŶĚƌǇŝƐƚŽƉĞƌĨŽƌĂƚĞ>ŽǁĞƌĞůƵŐĂĂŶĚhƉƉĞƌĞůƵŐĂ^ĂŶĚƐ͘dŚĞƚŽƉƉƌŽƉŽƐĞĚƉĞƌĨ ŝŶƚŚŝƐĂƉƉůŝĐĂƚŝŽŶŝƐϭϳϳ͛dsĨƌŽŵƚŚĞďŽƚƚŽŵŽĨ/E'^^ƚŽƌĂŐĞWŽŽů͘ EŽƚĞƐZĞŐĂƌĚŝŶŐtĞůůďŽƌĞŽŶĚŝƚŝŽŶ xDĂǆŝŵƵŵŶŐůĞŝƐϰϱ͘ϱΣΛϯ͕ϲϯϭ͛D x^>dĂŐŐĞĚďŽƚƚŽŵĂƚϴ͕ϭϯϭ͛ǁͬϮ͘Ϯϱ͟>/ŽŶϰͬϮϮͬϮϮ x/E'^WŽŽůďŽƚƚŽŵʹϲ͕ϮϬϬ͛D;ϱ͕ϭϰϵ͛dsͿ Ͳ>ŝŶĞWƌŽĐĞĚƵƌĞ ϭ͘D/ZhĞͲůŝŶĞĂŶĚƉƌĞƐƐƵƌĞĐŽŶƚƌŽůĞƋƵŝƉŵĞŶƚ Ϯ͘WdůƵďƌŝĐĂƚŽƌƚŽϮϱϬ>Žǁͬϯ͕ϱϬϬƉƐŝ,ŝŐŚ ϯ͘WhZ/,tͬƉĞƌĨŐƵŶƐ͘WĞƌĨŽƌĂƚĞĞĂĐŚŝŶƚĞƌǀĂůǁŝƚŚϲƚŽϭϮ^W&ϲϬĚĞŐƌĞĞƉŚĂƐŝŶŐ,ŐƵŶƐ ϰ͘WƌŽƉŽƐĞĚWĞƌĨŽƌĂƚĞĚ/ŶƚĞƌǀĂůƐ͗ WŽŽůEĂŵĞ^ĂŶĚDdŽƉDŽƚƚŽŵ dŽƚĂů &ŽŽƚĂŐĞ ;DͿ ĞůƵŐĂ'ĂƐhϯцϲ͕ϯϴϭ͛цϲ͕ϯϵϯ͛ϭϮ͛ ĞůƵŐĂ'ĂƐhϰцϲ͕ϰϮϭ͛цϲ͕ϰϮϴ͛ϳ͛ ĞůƵŐĂ'ĂƐhϰцϲ͕ϰϱϴ͛цϲ͕ϰϲϲ͛ϴΖ /E'^WŽŽůďŽƚƚŽŵʹϲ͕ϮϬϬ͛D;ϱ͕ϭϰϵ͛dsͿ dŚĞƚŽƉƉƌŽƉŽƐĞĚƉĞƌĨ ŝŶƚŚŝƐĂƉƉůŝĐĂƚŝŽŶŝƐϭϳϳ͛dsĨƌŽŵƚŚĞďŽƚƚŽŵŽĨ/E'^^ƚŽƌĂŐĞWŽŽů͘'/% '/% tĞůůWƌŽŐŶŽƐŝƐ tĞůů͗>hϬϵ ĂƚĞ͗ϱͬϲͬϮϬϮϮ ĞůƵŐĂ'ĂƐ>ϭ>ŽǁĞƌцϳ͕ϲϵϱ͛цϳ͕ϳϬϱ͛ϭϬ͛ ĞůƵŐĂ'ĂƐ>ϭцϳ͕ϴϬϬ͛цϳ͕ϴϬϲ͛ϲΖ ĞůƵŐĂ'ĂƐ>ϭ&>ŽǁĞƌцϳ͕ϴϱϮ͛цϳ͕ϴϳϬΖϭϴΖ ĞůƵŐĂ'ĂƐ>Ϯцϴ͕ϬϳϰΖцϴ͕ϬϳϵΖϱΖ Ă͘3URSRVHGSHUIVDUHDOVRVKRZQRQWKHSURSRVHGVFKHPDWLFLQUHGIRQW E )LQDO3HUIVWLHLQVKHHWZLOOEHSURYLGHGLQWKHILHOGIRUH[DFWSHUILQWHUYDOV F &RUUHODWHXVLQJ2SHQ+ROH&RUUHODWLRQ/RJSURYLGHGE\*HRORJLVW6HQGWKHFRUUHODWLRQSDVV WRWKH2SHUDWLRQV(QJLQHHU5HVHUYRLU(QJLQHHU&KULV.DQ\HUDQG*HRORJLVW'DQLHO <DQFH\IRUFRQILUPDWLRQ d. 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Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Pull Capstring Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 9,100 feet N/A feet true vertical 8,042 feet ±7943 & 8257 feet (fish) Effective Depth measured 9,016 feet N/A feet true vertical 7,958 feet N/A feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)3-1/2" L-80 9,052' MD 8,006' TVD Packers and SSSV (type, measured and true vertical depth)N/A; N/A N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 1,325 Water-Bbl MD 130' 2,053' 14 Oil-Bbl measured true vertical Packer 3-1/2"9,052' 4,938' 7,994' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Cannery Loop Unit / Beluga GasN/A measured TVD Tubing Pressure 8020 Cannery Loop Unit (CLU) 09 N/A ADL0002397 5,980' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 204-161 50-133-20544-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. N/A 86 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 2 Authorized Signature with date: Authorized Name: 3 Casing Pressure Liner 1,499 0 Representative Daily Average Production or Injection Data 109' 2032' 5,959' 9,031' Conductor Surface Intermediate Production 10,540psi Casing Structural 20" 13-3/8" 9-5/8" Length 5,750psi 5,020psi Collapse 1,500psi 2,260psi 3,090psi tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 3,060psi 10,160psi 130' 1,903' t Fra O 6. A G L PG , R g Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 9:06 am, May 26, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.05.22 17:05:29 -08'00' Taylor Wellman Pull Capstringg gls 5/26/20 RBDMS HEW 5/26/2020 DSR-5/26/2020 Rig Start Date End Date Cap String Truck 4/29/20 4/29/20 04/29/2020 - Wednesday PTW, JSA. RU Cap string truck. Attempt to pull 8,175' of 3/8" cap string. Pulled 5,100 lbs and string started moving. Continued to pull heavy for 120' and then weight dropped back down to 1,600-1,800 lb normal string weight. 232' cap string remains in hole. 7,943' recovered. Install Bowen cap. Well secure. Rig down Cap string truck. Well online. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name CLU-09 50-133-20544-00-00 204-161 NOTE: Sundry was not required . GLS Surface Casing 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 2,053' TVD 0' 1,901' 16" hole Cmt w/ 215 sks (49 bbl) of 15.0 ppg, Type-1, lead and 550 sks (246 bbl) of 15.0 ppg, class G, tail Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,980' TVD 0' 4,948' 12-1/4" hole Cmt w/ 136 sks (51 bbl) of 12.5 ppg, class G, lead and 212 sks (44 bbl) of 15.8 ppg, class G tail Production Casing 3-1/2" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control line protectors Top Bottom MD 0' 9,052' TVD 0' 8,006' 8.5" hole Cmt w/ 1,392 sks (286 bbl) 15.8 ppg, class G Excape System Details - 16 Excape modules placed -Yellow control line fires top 8 modules -Red contol line fires middle 7 modules -Green control line fires bottom 1 module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Mod 16 - 6,290-6,300' Sqz (12/10/06) Mod 15 - 6,332-6,342' Sqz (12/10/06) Mod 14 - 6,638-6,648' Sqz (12/10/06) Mod 13 - 6,740-6,750' Sqz (12/10/06) Mod 12 - 7,026-7,036' Sqz (12/10/06) Mod 11 - 7,271-7,281' Mod 10 - 7,509-7,519' Mod 9 - 7,679-7,689' Mod 8 - 7,739-7,749' Mod 7 - 7,812-7,822' Mod 6 - 8,112-8,122' Mod 5 - 8,170-8,180' Mod 4 - 8,404-8,414' Mod 3 - 8,521-8,531' Mod 2 - 8,622-8,632' Mod 1 - 8,720-8,730' Excape System Details - 15 Conventional flappers - Mod 1 - no flapper - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Mod 16 - 6,310' Mod 15 - 6,351' Mod 14 - 6,657' Mod 13 - 6,759' Mod 12 - 7,045' Mod 11 - 7,291' Mod 10 - 7,528' Mod 9 - 7,699' Mod 8 - 7,759' Mod 7 - 7,832' Mod 6 - 8,132' Mod 5 - 8,190' Mod 4 - 8,424' Mod 3 - 8,541' Mod 2 - 8,642' Mod 1 - N/A CLU-9 Pad 1 204' FSL, 547' FEL, Sec. 7 , T5N, R11W, S.M. Permit #: 204-161 API #: 50-133-2054400 Prop. Des: ADL-02397 KB elevation: 42' (21' AGL) WBS #: DD.04.10614.CAP.DRL Latitude: 60°31'58.155'N Longitude: 151°15'48.901'W Spud: 09-03-2004 TD: 09-15-2004 Rig Released: 09-24-2004 @ 18:00 hrs. Top of Cement CBL est. @ 5,680' MD ( 300' above 9-5/8" shoe ) Drive Pipe 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 129' Tree crossing = 4-3/4" Otis Squeezed TD 9,100' MD 8,052' TVD PBTD 9,016' MD 7,970' TVB Tagged fish @ 8,257' MD (11/19/09) ~ 133 ' of 3/8" capillary string & BHA Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Cannery loop Unit #9 Kenai Peninsula Borough 7,270' - 8,730' 2.8°/ 100' @ 500 ft MD 11/3/2004 Donna Ambuz Lease: State: Perf (TVD): Cannery Loop Unit Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 6,224' - 7,684' 0° RKB:42' (AMSL)21' (AGL) 05-18-20 Sterling C1 Interval: 5942-6195 ft MD SCHEMATIC Top of Fish @ ±7,943' MD 04-29-20 -tag needed to verify depth (232’ of 3/8” cap string and nozzle remain in the hole) NOTE ( CAPSTRING POOH) · . Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. cQ Q if - j h L Well History File Identifier Organizing (done) D Two-sided 1111111111111111111 D Rescan Needed '" 11111111" 11/11/ RE~AN \V'?IOr Items: ~ Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, No/Type: D Poor Quality Originals: OVERSIZED (Non-Scannable) D Other: D Logs of various kinds: NOTES: D Other:: BY: ~ Date: I d.- / I / / I'J (p I /5/ øãP Scanning Preparation BY: ~ x 30 = 1111111111111' "III /5/ Y11f Project Proofing BY: ~ + ~3 = TOTAL PAGES 8.3 (Count does not include cover sheet) /5/ Date: Production Scanning 11111111111111 ,,11/ Stage 1 Page Count from Scanned File: ~ Lf- (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ES ~ Date: J a../II /06 If NO in stage 1, page(s) discrepancies were found: YES NO /5/ WlP NO BY: Stage 1 BY: Maria Date: /5/ 11I11111111I" 1/11/ Scanning is complete at this point unless rescanning is required. ReScanned 11111111111111" III BY: Maria Date: Is/ Comments about this file: Quality Checked 1IIIIIII11111111111 10/6/2005 Well History File Cover Page. doc Marathon Alaska Production LTC /� �l../►� Alaska Asset Team Marathon 1l P.O. Box 1949 Kenai, AK 99611 Telephone (907) 283 -1371 Fax (907) 283 -1350 April 2, 2012 RECEIVED Cathy Foerster APR 0 4 2012 Alaska Oil & Gas Conservation Commission 333 W 7 Ave Anchorage, Alaska 99501 Alaska Oil £ Gas Cons. Commission Anchorage Reference: 10 -404 Report of Sundry Well Operations by' _ /6 Field: Cannery Loop Field ` Well: Cannery Loop Unit #9 Dear Ms Foerster, 5kiiiMEDAPR Attached for your records is the10 -404 Report of Sundry Well Operations for CLU -9 well. ✓ This report covers the MIT testing work performed in preparation for gas injection into the CINGSA Gas Storage project. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, .12/tJ'V� v Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10 -404 Report of Sundry Well Operations cc: Houston Well File MIT Test form Kenai Well File (2) KJS _- RECEIVED - STATE OF ALASKA 1-----TREC �.,.l VA OIL ND GAS CONSERVATION COMMMION - 0 4 2012 • REPORT O SUNDRY WELL OPERATIONS APP 0 4 2012 AOGCC 1. Operations Abandon U Repair Well LJ Plug Perforations U Stimulate Other U MIT Test Performed: „, ',Iter Casi c Cons. CB CI Perforate New Pool ❑ Waiver Time Extension El Change Approved Program n Atrat. Shut Perforate ❑ Re -enter Suspended Well ❑ 2. Operator 1 4. Well Class Before Work: 5. Permit to Drill Number: Name: `Marathon ATasTia Production LLG Development 0 Exploratory - 204 - 161 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. API Number: Kenai Alaska, 99611 - 1949 50 133 - 20544 - 00 - 00 7. Property Designation (Lease Number): , 8. Well Name and Number: ADL - 02397 Cannery Loop Unit #9 9. Field /Pool(s): Cannery Loop Field / Beluga Pool 10. Present Well Condition Summary: Total Depth measured 9,100' feet Plugs measured NA feet true vertical 8,042' feet Junk measured 8,257' feet Effective Depth measured 9,016' feet Packer measured NA feet true vertical 7,958' feet true vertical NA feet Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060 psi 1,500 psi Surface 2,032' 13 -3/8" 2,053' 1,903' 5,020 psi 2,260 psi Intermediate 5,959' 9 -5/8" 5,980' 4,938' 5,750 psi 3,090 psi Production 9,031' 3 -1/2" 9,052' 7,994' 10,160 psi 10,540 psi Liner Perforation depth: Measured depth: 7,271' - 8,730' feet True Vertical depth: 6,225' - 7,684' feet Excape 3 -1/2" L -80 9,052' MD 8,006' TVD Tubing (size, grade, MD & TVD): Capillary String 3/8" 2205 Stainless Steel 8,175' MD 7,129' TVD SSSV: NA NA MD NA TVD Packers and SSSV (type, MD & TVD): Packers: NA NA MD NA TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): Performed MIT test in preparation for the CINGSA gas storage project. Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas -Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,720 6 1 700 Subsequent to operation: 0 2,140 9 1 675 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory ❑ Development 0 — Service ❑ Stratigraphic ❑ Daily Report of Well Operations 15. Well Status after work: Oil ❑ Gas U . WDSPL ❑ GSTOR❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG 16. 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: 312 - 030 Contact Kevin Skiba (907) 283 -1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Signature µ,V • 5 Phone (907) 283 -1371 Date April 2, 2012 1313D 4S APR 0 6 2012 * 1--/-612,- � v Form 10 -404 Revised 10/2010 Submit Original Only • • • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test Submit to: jim.regq(@alaska.gov; doa .aogcc.prudhoe.bav(8alaska.gov; phoebe.brookso{�alaska.gov; tom.maunder(Walaska.gov OPERATOR: Marathon Oil Co. FIELD 1 UNIT / PAD: KGF /Cannery Loop DATE: 02/29/12 OPERATOR REP: Mike Sulley AOGCC REP: Matt Herrera Packer Depth Pretest Initial 15 Min. 30 Min. 45 Min. 60 Min. Well CLU 9 Type Inj. NA TVD 4948" Tubing 680 680 680 680 Interval 0 P.T.D. 204 -161 Type test P Test psi 500 Casing 20 575 570 570 P/F P Notes: "9 - 5/8" shoe OA NA NA NA NA Took 29 gas to fill. Recovered 23 gals. Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA Well Type Inj. TVD Tubing Interval P.T.D. Type test Test psi Casing P/F Notes: OA TYPE INJ Codes TYPE TEST Codes INTERVAL Codes D = Drilling Waste M = Annulus Monitoring I = Initial Test G = Gas P = Standard Pressure Test 4 = Four Year Cycle I = Industrial Wastewater R = Internal Radioactive Tracer Survey V = Required by Variance N = Not Injecting A = Temperature Anomaly Survey T = Test during Workover W = Water D = Differential Temperature Test 0 = Other (describe in notes) This well is a producer. Testing 3 -1/2 X 9 -5/8" annulus. Test was performed in accordance w/ Storage Injection Order NO. 9, Rule 5 Sundry Number 312 -030 Form 10 -426 (Revised 06/2010) MIT CLU - 02 29 12.xls MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission DATE: Monday, March 12, 2012 TO: Jim Regg ,---, n sJ 13)1Z! P.I. Supervisor SUBJECT: Mechanical Integrity Tests MARATHON OIL CO 09 FROM: Matt Herrera CANNERY LOOP UNIT 09 Petroleum Inspector Src: Inspector Reviewed By P.I. Supry .g--- NON - CONFIDENTIAL Comm Well Name: CANNERY LOOP UNIT 09 API Well Number: 50 -133- 20544 -00 -00 Inspector Name: Matt Herrera Insp Num: mitMFH120307101152 Permit Number: 204 - 161 - Inspection Date: 2/29/2012 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well ' 09 - Type Inj. N ' TVD IA 20 575 - 570 570 PTD 2041610 - TypeTest SPT Test psi 500 - OA Interva OTHER - P/F ( P ' Tubing 680 680 680 680 Notes: Monobore completion NO OA. MIT performed for CINGSA order no. 9,Sundry 312 -030. o t M D JUN .r 2 alt_ Monday, March 12, 2012 Page 1 of 1 • 0 r r n / SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMIIIISSION ANCHORAGE, ALASKA 99501 -3539 PHONE (907) 279 -1433 FAX (907) 276 -7542 Kevin J. Skiba 161 Regulatory Compliance Representative O L' V Marathon Alaska Production, LLC P.O. Box 1949 Anchorage, AK 99611 -1949 Re: Cannery Loop Field, Beluga Pool, Cannery Loop Unit #9 Sundry Number: 312 -030 Dear Mr. Skiba: l ' , Z` y Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, __ 0 / ..._ Daniel T. Seamount, Jr. t 4 Chair DATED this r ( day of February, 2012. Encl. Marathon Alaska Production LLC /f Al Alaska Asset Team Marathon Oil t M P.O. Box 1949 (, Kenai, AK 99611 Telephone (907) 283 -1371 Fax (907) 283 -1350 RECEIVED January 19, 2012 JAN 2 3 2012 ska r ii & G8R !A . COMMi5S10 Mr. Daniel Seamount fir- !..rr:o Alaska Oil & Gas Conservation Commission 333 W 7 Ave Anchorage, Alaska 99501 Reference: 10 -403 Application for Sundry Approvals Field: Cannery Loop Field Well: Cannery Loop Unit #09 Dear Mr. Seamount, Submitted for your approval is the10 -403 Application for Sundry Approvals for CLU -09 well. Marathon proposes to perform a Mechanical Integrity Test of the wellbore to comply with the Storage Injection Order No. 9, Rule 5: Demonstration of Mechanical Integrity. Please find attached the Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) Mechanical Test Plan which provides a summary and background for the test, the details that relate to the subject well, and a current wellbore schematic, depicting the Sterling C1 interval depths. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, T 9 - r \Q.:1) . � ] Kevin J. Skiba Regulatory Compliance Representative Enclosures: 10 -403 Application for Sundry Approvals cc: AOGCC CINGSA SIO 9 Mechanical Integrity Test Plan Houston Well File Current Well Schematic Kenai Well File (2) KJS ' STATE OF ALASKA \1» / r � '" ��,,( ALASIOIL AND GAS CONSERVATION COMMISS x , . „%S1” APPLICATION FOR SUNDRY APPROVALS JAN �t71�� /a 20 AAC 25.280 .i. r:;+ `a; CiaS. Lank I';nnyritsifl[ 1. Type of Request: Abandon ❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair well ❑ Change appj yec(1program ❑ Suspend ❑ Plug Perforations ❑ Perforate ❑ Pull Tubing ❑ Specify: Time Extension ❑ Operational shutdown ❑ Re -enter Susp. Well ❑ Stimulate ❑ Alter casing ❑ Other: Perform MIT Test . El 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Marathon Alaska Production LLC Development 0 , Exploratory ❑ 204 -161 - 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. API Number: Kenai Alaska, 99611 -1949 50- 133 - 20544 -00 -00 - 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Cannery Loop Unit #9 - Spacing Exception Required? Yes ❑ , , No El 9. Property Designation (Lease Number): 10. Field / Pool(s): ADL - 97 Cannery Loop Field / Beluga 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): 9,100' • 8,042' ' 9,016' - 7,958' ' NA 8,257' Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060 psi 1,500 psi Surface 2,032' 13 -3/8" 2,053' 1,903' 5,020 psi 2,260 psi Intermediate 5,959' 9 -5/8" 5,980' 4,938' 5,750 psi 3,090 psi Production 9,031' 3 -1/2" 9,052' 7,994' 10,160 psi 10,540 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 7,270' - 8,730' 6,224' - 7,672' Excape 3 -1/2" L -80 9,052' Capillary 3/8" 2205 Stainless Steel 8,175' Packers and SSSV Type: SSSV: NA Packers and SSSV MD (ft) and TVD (ft): SSSV: NA Packers: NA Packers: NA 12. Attachments: Description Summary of Proposal is 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development ei Service ❑ 14. Estimated Date for 15. Well Status after proposed work: February 1, 2012 Commencing Operations: Oil ❑ Gas 0 , WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: GSTOR ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283 - 1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Representative Signature one (907) 283 -1371 Date January 19, 2012 vvv COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ?t Z' c)3� , Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test le Location Clearance ❑ Other: ,t spa / / l 1 Subsequent Form Required: AA— YO 1 APPROVED BY Approved by: • J COMMISSIONER THE COMMISSION Date: 2 / ? / 1 2___ R DMS FEB 21 209 76' 2. 10 .1 i F��' ORIGINAL 1,77.02 Form 10 -403 Revised 1/2010 Submit in Duplicate • • Cook Inlet Natural Gas Storage Alaska, LLC Proposed Mechanical Integrity Test Plan Cannery Loop Sterling C Gas Storage Pool Cook Inlet Natural Gas Storage Alaska, LLC (CINGSA) requested by application dated July 27, 2010, a storage injection order from the Alaska Oil and Gas Conservation Commission (AOGCC) authorizing injection for the underground storage of natural gas in the Sterling C Gas Storage Pool of the Cannery Loop Unit. The AOGCC held a public hearing on October 19 -20, 2010 during which CINGSA presented oral and written testimony concerning the project. By Order, the AOGCC issued Storage Injection Order No. 9 (SIO 9) dated November 19, 2010, granting CINGSA the authority to commence the injection of gas for underground storage subject to certain Conclusions and Rules, all as more fully outlined in SIO 9. Two of the key requirements imposed on CINGSA as a condition of SIO 9 are that CINGSA 1) demonstrate the mechanical integrity of all storage injection wells and existing pool wells before injection commences (Rule 5 Demonstration of Mechanical Integrity), and 2) maintain surveillance of operating parameters for storage and offset wells to provide continued assurance that gas remains confined to the Sterling C Gas Storage Pool (Conclusion 8). Following, is the methodology CINGSA proposes to employ to demonstrate the mechanical integrity of all existing pool wells and maintain continued surveillance of the Pool to assure that gas remains confined to the Sterling C Pool. All new gas storage wells will be tested in accordance with 20 AAC 25.412 (c)(d). CINGSA proposes to satisfy the requirements of Conclusion 8 and Rule 5 of SIO 9 through routine monitoring of the annulus pressure of existing wells, and via pressure testing the annulus of certain wells to demonstrate their mechanical integrity, plus the tubing string of certain other wells. Table 1 provides a summary of the scope of CINGSA's proposed measures to satisfy the requirements of Conclusion 8 and Rule 5. The rationale for monitoring pressure of certain annuli and performing a mechanical integrity test is more fully summarized for each individual well below. Table 2 provides a depth reference to the Sterling C1 interval, from Sterling C1 Top to U. Beluga Top, by well. Routine monitoring and recording of annulus pressure will help identify whether any gas may be leaking from the Sterling C Pool or other formations. CINGSA proposes a monthly monitoring and reporting frequency to satisfy the requirements of Conclusion 8. CINGSA proposes to conduct a mechanical integrity pressure tests on the annulus of the wells listed in Table 1 to satisfy the requirements of Rule 5. CINGSA proposes a maximum test pressure of 500 psi for 30 minutes since most of the wells are not completed with tubing set on a packer, and thus, are not in the same configuration contemplated in 20 AAC 252. • • Table 1 Proposed Routine Monitoring and Mechanical Integrity Test Plan Cook Inlet Natural Gas Storage Alaska, LLC Well Name Current Status Annulus for MIT Routine Monitor Annulus CLU 1RD Producing 4 1/2 x 7 4 1/2 x 7 and 7 x 9 5/8 CLU 3 Inactive 3 1/2 x 9 5/8 3 1/2 x 9 5/8 CLU 4 Inactive 3 1/2 x 13 5/8 3 1/2 Tbg, 3 1/2 x 13 5/8, and 13 5/8 x 20 CLU 5 Inactive 3 1/2 Tbg x 9 5/8 3 1/2 Tbg, 3 1/2 x 9 5/8, and 9 5/8 x 13 3/8 CLU 6 P& A Sterling C 4 1/2 Tbg 4 1/2 tbg and 4 1/2 x 7 CLU 7 Producing 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 8 Producing 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 9' oducing 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 10 Planned P & A 3 1/2 Tbg and 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 11 Producing 3 1/2 x 9 5/8 3 1/2 x 9 5/8 and 9 5/8 x 13 3/8 CLU 12 P & A'd Sterling C None 9 5/8 Csg Table 2 Cannery Loop Wells, Sterling C interval, Sterling C1 Top to U. Beluga Top Well Name Sterling C depth interval. MD Sterling C depth interval. TVDSS CLU 1RD 5815 -6155 -4927 to -5155 CLU 3 5313 -5574 -4963 to -5205 CLU 4 5171 -5409 -4971 to -5198 CLU 5 6063 -6300 -4856 to -5081 CLU 6 7782 -8114 -4876 to -5099 CLU 7 7700 -7965 -4858 to -5095 CLU 8 6690 -6945 -4871 to -5101 - CLU 9 5942 -6195 -4860 to -5102 " CLU 10 5372 -5614 -4883 to -5125 CLU 11 6281 -6537 -4876 to -5113 CLU 12 7264 -7522 -4920 to -5158 • CLU 9 CLU 9 is currently completed to the Beluga via a 3 -1/2" Excape type completion, with the 3 -1/2" monobore having been cemented in place, in the open hole with cement being brought up above the 9- 5/8 shoe, which is at a depth of 5980 ft MD. The Sterling interval extends from 5942 -6195 ft MD, thus, the 9 5/8" casing shoe is set approximately 38 ft below the top of the Sterling C. Marathon has indicated the well is currently producing at a high water rate making sustaining production challenging and has a capillary string installed. Proposed Annuli to configure for routine pressure monitoring: • 3- 1/2 "x9 -5/8" tubing head • 9 -5/8 "x13 -3/8" casing head Proposed Mechanical Integrity Test Procedure: • Perform a 500 psi pressure test of the 3 -1/2" x 9 -5/8" annulus being mindful of the low pressure on the inside of the tubing and of collapse. CINGSA proposes a 30 minute test duration with no more than a 10 percent change in pressure during that time interval being required for a valid test. • The proposed pressure test will apply an approximate differential of 2142 psi at 5980 ft MD/4948 ft TVD, per the following assumptions: an approximate 500 psi internal tubing pressure at TVD; a fresh water hydrostatic gradient in the annulus, and the 500 psi of applied surface pressure. (Assumed intermediate casing shoe depth for differential calculation.) • A test of the 9 5/8" x 13 3/8" annulus is not recommended since it would most likely serve as a leak off test of the surface casing shoe at 2053 ft MD. • • • • CLU -9 sfa'W/ Permit #: 204 -161 Pad 1 Marathon Oil API #: 50 -133- 2054400 204' FSL, 54T FEL, Alaska Production LLC Prop. Des: ADL -02397 Sec. 7 , T5N, R11 W, S.M. KB elevation: 42' (21' AGL) WBS #: DD.04.10614.CAP.DRL Drive Pipe 20" K -55 133 ppf Latitude: 60° 31'58.155'N To�1 Bottom Longitude: 151 Spud: 09 -03 -2004 MD 0' 130' TD: 09 -15 -2004 1 TVD 0' 129' Rig Released: 09 -24 -2004 @ 18:00 hrs. I l Surface Casing 13 -3/8" K -55 68 ppf BTC __ lop Bottom MD 0' 2,053' TVD 0' 1,901' bbl Tree crossing = 4 -3/4" Otis 16" hole Cmt w/ 215 sks (49 bbl) of 15.0 ppg, Type-1, lead and 550 sks (246 bbl) of 15.0 ppg, class G, tail ' 'u' Sterling C1 Top of Cement 1., Interval: CBL est. @ 5,680' MD .. 5942 -6195 ft MD Intermediate Casing ( 300' above 9 - /8" shoe ) " ,. 9 -5/8" L -80 40 ppf BTC a, - 1:)p Bottom MD 0' 5,980' TVD 0' 4,948' Capillary String (Installed 11/20/2008) 12 -114" hole Cmt w/ 136 sks (51 bbl) of 12.5 ppg, class 3/8" 2205 Stainless Steel 11 '' G, lead and 212 sks (44 bbl) of 15.8 ppg, class G tail Top Bottom MD 0' 8,175' i - r TVD 0' 7,129' Inspected 08- 04 - -10 ._ I i Squeezed Production Casing 3 -1/2" L -80 9.3 ppf EUE s, 0 1 "' • 8rd w/ 6.25" OD control line protectors Excape System Details „ Lop Bottom - 15 Conventional flappers , lly MD 0' 9,052' Mod 1 - no flapper ' t • 111 C " ; TVD 0' 8,006' Ceramic flapper valves below f 8.5" hole Cmt w/ 1,392 sks (286 bbl) 15.8 ppg, class G each module as follows: 11 Flappers MD (RKB): Mod 16 - 6,310' tt - Excape System Details Mod 15 - 6,351' - 16 Excape modules placed Mod 14 - 6,657' ' control line fires top 8 modules Mod 13 - 6,759' . contol line fires middle 7 modules Mod 12 - 7,045' i ., - i - Green control line fires bottom 1 module Mod 11 - 7,291' 11f ,. - Ceramic flapper valves below each Mod 10 - 7,528' 1 module except for module 1 Mod 9 - 7,699' ►7 , Mod 8 - 7,759' 1 f Perfs MD (RKB): Mod 7 - 7,832' ' 7 Mod 16 6,200 6,300' Sqz (12/10/06) Mod 6 - 8,132' ill f Mod 15 6,332 6,342' Sqz (12/10/06) Mod 5 - 8,190' Mod 14 6,638 6,648' Sqz (12/10/06) Mod 4 - 8,424' ])1 Mod 13 6,740 6,750' Sqz (12/10/06) Mod 3 - 8,541' 7 Mod 12 7,026 7,036' Sqz (12/10/06) Mod 2 - 8,642' I Mod 11 - 7,271- 7,281' ' Mod 1 - N/A ' ' Mod 10 - 7,509 - 7,519' Mod 9 - 7,679 - 7,689' I - Mod 8 - 7,739- 7,749' LJ Mod 7 - 7,812- 7,822' • lot Mod 6 - 8,112- 8,122' Mod 5- 8,170 - 8,180' Mod 4 - 8,404 - 8,414' Tagged fish @ 8,257' MD (11/19/09) TD PBTD Mod 3 - 8,521 - 8,531' Mod 2 - 8,720 8,730' 133' of 3/8" capillary string & BHA 9,100' MD 9,016' MD Mod 1 - 8,720 - 8,730' 8,052' TVD 7,970' TVB Well Name & Number: Cannery loop Unit #9 Lease: Cannery Loop Unit Municipality: Kenai Peninsula Borough State: Alaska I Country: USA Perforations (MD): 7,270' - 8,730' Perf (TVD): 6,224' - 7,684' Angle @ KOP & Depth: 2.8° / 100' @ 500 ft MD Angle @ Perfs: Cr Date Completed: 11/3/2004 Ground Level: 42' (AMSL) 1 RKB:I 21' (AGL) 0... ,:. -...A L., ll..•.:.. eLa... o... ,:. -i.... n..1... 11 inninn • Alaska Assam Kaynell Zeman Engineering Technician Marathm P. O. Box 3128 e�aaasNar� AI ska Pmduc'tion uc Houston, TX 77253 Telephone 713/296-2384 FAX 713499-8504 October 28, 2010 Alaska Oil & Gas Conservation Commission Federal Express Attn: Howard Okland 333 W. 7 Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon Oil Company Cannery Loop Unit 9 API 50 -133- 2054400 -00 MFT Digital Well Log Data Dear Mr. Okland: ANN NG'J 2��0 Enclosed is a CD containing digital MFT well log data for the Cannery Loop Unit 9, as listed below: Name Res Currently on the CD ` CLt14 MFT ALL .pdf Vclu9_mft log.dpk Please indicate your receipt of this data by signing below and returning one copy to me by fax to 713- 499 -8504 or email: kjzeman@marathonoil.com Sincerely, 11�6 , Kaynell Zeman 010 Engineering Technical , S1 .dstoo$.LOMA 1D Received by: Date: Enclosure Ml on Alaska Production LLC Marathon Alaska Asset Team P.O. Box 1949 (M.Alaska Production LLC Kenai, AK 99611 Telephone 907/283 -1371 Fax 907/283 -1350 RECEIVED November 25, 2009 DECO i (l!" Mr. Winton Aubert Alaska Oil & Gas Cons. Connmisslc=, Alaska Oil & Gas Conservation Commission Anchorage 333 W 7 th Ave Anchorage, Alaska 99501 1 Reference: 10 -404 Report of Sundry Well Operations Field: Cannery Loop Unit Well: Cannery Loop Unit #9 Dear Mr. Aubert: Attached for your records is the10 -404 Report of Sundry Well Operations for CL -9 well. This report covers the work performed to adjust the capillary string setting depth to 8,175' MD. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10 -404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS �[C`lr.I V Wi( STATE OF ALASKA DE C 01 1 Qg9- t ALASKARI AND GAS CONSERVATION COMMISON REPORT OF SUNDRY WELL 0PE RATION SAIaska Oil & Gas Cons. Commission Anchors e 1. Operations Abandon Ll Repair Welli I Plug Perforations L Stimulate Other ✓ Adjust Capillary Performed: Alter Casing ❑ Pull TubinF] Perforate New Pool ❑ Waiver❑ Time Extension ❑ String setting Change Approved Program ❑ Operat. Shutdowr❑ Perforate ❑ Re-eNQ ter Suspended Well ❑ depth 2. Operator 4. Well Class Before Work: . Permit to Drill Number: Name: Marathon Oil Company Development ❑✓ Exploratory❑ 204 -161 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ N kAPI Number: Kenai Alaska, 99611 -1949 50- 133 - 20544 -00 -00 7. KB Elevation (ft): 1 9 , Well Name and Number: 42' 21' AGL Cannery Loop Unit #9 8. Property Designation: 10. Field /Pool(s): ADL - 02397 Cannery Loop Unit / Beluga Pool 11. Present Well Condition Summary: Total Depth measufed 9,100' feet Plugs (measured) NA true verti 8,042' feet Junk (measured) 8,257' Effective Depth measured 9,016' feet true vertical 7,958 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060 psi 1,500 psi Surface 2,032' 13 -3/8" 2,053' 1,903' 5,020 psi 2,260 psi Intermediate 5,959' 9 -5/8" 5,980' 4,938' 5,750 psi 3,090 psi Production 9,031' 3 -1/2" 9,052' 7,994' 10,160 psi 10,540 psi Liner Perforation depth: Measured depth: 7,270' - 8,730' True Vertical depth: 6,224' - 7,672' Excape Tubing 3 -1/2" L -80 9,052' Tubing: (size, grade, and MD) Capillary String 3/8" 22 Stainless Ste el 8,175' Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): Raised 3/8" stainless steel capillary string to 8,175' MD. 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 3,640 11 1 607 Subsequent to operation: 0 3,210 - 0 550 14. Attachments: 1 Well Class after work: Copies of Logs and Surveys Run Exploratory ❑ Development Q Service ❑ Daily Report of Well Operations X Well Status after work: Oil ❑ Gas ❑✓ WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: NA Contact Kevin Skiba (907) 283 -13 Printed Name Kevin J. Skiba A Title Regulatory Compliance Technician Signature Phone (907) 283 - 1371 Date November 25, 2009 Form 10 -404 Revised 04/2006 �� 1 Submit Original Only C Marathon Operations Summary Report Oil Company Well Name: CANNERY LOOP UNIT 09 Report Date: 11/11/2009 Job Category: R &M MAINTENANCE 24 Hr Summary Hold safety meeting, review JSA's, receive safe work permit, remove wellhouse, rig up coil unit, attempt to pull 318" capillary string. Pull up to 3200 # and moved string up 7 feet. Can't go up or down. Received approval to increase pull to 3800 #. Moved string up another 2 feet. Made 6 attempts to pull free by pulling up to 3800 #. Can't go up or down. Ops Trouble Start Time Erd Time Dur his 0 s Code Activity Code Status Code Comment 07:30 08:30 1.00 SAFETY MTG AF Arrive location - PJSM - topics discussed - review JSA's, assign jobs, simultaneous operations, overhead loads, pinch points, buddy rule, three second rule, muster areas, active gas production pad, red lights for fire, blue lights for gas emission, sirens for audible, eye wash station, emergency vehicles, emergency numbers. Receive safe work permit 08:30 09:30 1.00 RURD RIG AF Rig up crane over wellhouse, Remove wellhouse 09:30 12:00 2.50 RURD COIL AF Rig up coiled tubing unit, disconnect foamer pump, pick up injector, install DynaCoil into injector head, set injector head onto tree. 12:00 12:30 0.50 PULL EQIP AF Pull cap string installed at 8525' MD. Weight pulling off bottom 3200 #. Exceeds max pull allowed by crew. Calling in for instructions and approvals. 12:30 1400 1.50 WAITON ORDR AF Pull on capstring exceeds max. pull allowed. Waiting on orders requesting additional pull. Received approval to pull up to 3800# max. 14:00 14:30 0.50 RUNPUL COIL AF Slack of tension on cap string, pull up to 3800 #, move string 2 feet. Slack off tension. Make total of 6 attempts. Can't go up or down. 14:30 1500 0.50 RURD COIL AF Rig down injector head bak onto cradle on truck, rig down crane 1500 1530 0.50 SECURE WELL TA MDCT Secure wellhead for evening . Bottom of capillary string stuck at 8516' MD. Maximum pull on string is 3800 #from surface. Will review path forward with MOC 1 BJ first thing in morning before proceeding further. Report Date: 11/12/2009 Job Category: R &M MAINTENANCE 24 Hr Summary wait on orders Os Trouble Start Time End Time Dur hrs O s Code Activity Code Status Code Comment 06:00 06:00 1 24.00 IWAITON JORDIR ITA IMDCT Iwait on orders Report Date: 11/13/2009 Job Category: R &M MAINTENANCE 24 Hr Summary Rig up on well to pull / fish cap string, string weight 1660 #- attempt to put 1000# overpull and string came loose. pull string out of well. something appears to be dragging coming out of well Ops Trouble Start Time End Time Dur hrs 0 s Code Aotivity Code Status Code Comment 07:30 08:30 1.00 SAFETY MTG TA MDCT Arrive location, sign in, obtain work permit, hold PJSM - topics discussed - reviewed JSA's, assigned jobs,pinch points, overhead loads, slips trips and falls. active gas production pad, red lights for fire, blue lights for gas emission, sirens for audible, buddy rule, three second rule, simultaneous operations 08:30 11&00 1.50 1 RURD COIL TA IMDCT RIG up coiled tubing unit, set injector head onto well, release packoff pressure 10:00 13:00 3.00 RUNPUL COIL AF attempt to overpull 1000# over string weight. String moving at approx. 2000 #. Continue pulling out of hole. String dragging pulling up out of well. 133 feet of cap string and fluid control valve with centralizer left in hole. 13:00 14.30 1.50 RURD COIL CS Rig down coiled tubing unit, set injector head back into cradle. pull adapter and packoff off wellhead, replace with night cap. 14:30 1500 0.50 SECURE WELL CS secure wellhead for evening, turn in work permit, leave location www.peloton.com Report Printed: 11/25/2009 r Marathon Operations Summary Report w�aTM� ail Company Well Name: CANNERY LOOP UNIT 09 Daily Operations Report Date: 11/142009 Job Category: R &M MAINTENANCE 24 Hr Summary Ran slickline with 2.55" OD LIB . Set down at 8142' MD. RDMO slickline unit. Wait on unit to run cap string back into well. Ops Trouble Start Time End Time Dur hrs Ops Code Activity Code Status Code Comment 07:30 08:00 0.50 SAFETY MTG TA MDCT Arrive location, sign in, obtain work permit, hold PJSM- topics discussed - JSA's, assign jobs, review work to be performed today, overhead loads, pinch points, hand safety, active gas production pad, red lights for fire, blue lights for gas emission, sirens for audible, muster areas, emergency numbers, emergency vehicle, buddy rule, three second rule. 08:00 09.30 1.50 WAITON EQIP TA LOWE Wait on slickline equipment being trucked in. 09:30 11 30 2.00 RURD SLIK TA MDCT rig up Pollard Wireline offshore slickline unit. Rig up lubricator with Spang jars, hydraulic jars and 2.75" OD lead impression block, LIB. Pressure test lubricator to 1500 # - test good. 11:30 13:00 1.50 RUNPUL SLIK TA MDCT Run in hole with slick line tool string with 2.75" OD LIB to tag top of 3/8" capillary string approx 133 feet long left in hole. Slickline assembly set down at 6345' MD (flapper depth on Module 15). Pull assembly out of hole and inspect LIB. No marks inside the circumference of the LIB. Module 12 -16 were cement squeezed on 10 Oct. 2006. Change out LIB with 2.55" OD, LIB. Run back into hole. Tool string stopped at 8142' MD. Set down solid three attempts. Pull tool out of hole to inspect LIB. Marks only around circumference of LIB. No marks within circumference. If tool set down on top offish, cap string in up against casing wall and may not be round anymore as no round marks were found as impressions in the lead. 13:00 11330 1 0.50 RURD ISLIK ITA JMDCT IRig down Pollard slickline skid unit, load unit on flatbed. 1330 14.00 0.50 1 SECURE WELL TA MDCT Secure wellhead, turn well over to production, turn in work permit, leave location. Report Date: 11/202009 Job Category: R &M MAINTENANCE 24 Hr Summary I� Run 318" capstring back into well. Tagged fish at 8257' MD. Pulled up to 8175' MD. Set capstring packoff and RDMO coiled tubing unit. Re -set wellhouse over wellhead, Turn in workpermit. Leave location Ops Trouble Start Time End Time Dur hrs _ Ops Code Activity Code Status Code Comment 07:30 08:00 0.50 SAFETY MTG AF Arrive location, obtgain work permit, hold PJSM - topics discussed - review JSA's, assign jobs, emergency phone numbers, emergency vehicle, eye wash station, muster areas, red lights for fire, blue lights for gas emiwssion, siren for audible, slips, trips, falls, icy cojnditions, cold, warming areas,hand safety, overhead loads, pinch points etc. 08:00 1200 . 4.00 RURD COIL AF Rig up BJ Chemical DynaCoil unit to run 318" control line into well. Set flow control valve to 3350 #, insert control line into injector head, set injector head onto wellhead. Perform pressure test to 1500 # - test successful. Temperature on pad is -1 deg. F at noon 12:00 1700 5.00 RUNPUL COIL AF Run 3B" cap string into well to a depth of 8257' MD. Set down on fish. Pulled back up to 8175' MD. Set packoff and hung off 318" capstring. RDMO coiled tubing unit. 17:00 17:30 0.50 1 SECURE WELL AF I Secure wellhead, move coiled tubing unit off location, rig crane up to set wellhouse over well. RE -set wellhouse, turn in work permit, leave location www.peloton.com Report Printed: 11252009 l cLu -9 - 4 Permit #: 204 -161 Pad 1 MABATNOM API #: 50 -133- 2054400 204' FSL, 547' FEL Di Prop. Des: ADL -02397 Drive Pipe KB elevation: 42' (21' AGL) S ec. 7 , T5N, R11 W , S.M. 20" K -55 133 ppf WBS #: DD.04.10614.CAP.DRL T- Bottom Latitude: 60° 31'58.155'N MD 0' 130' Longitude: 151 °15'48.901'W I TVD 0' 129' Spud: 09 -03 -2004 TD: 09 -15 -2004 Surface Casing Rig Released: 09 -24 -2004 @ 18:00 hrs. 13 -3/8" K -55 68 ppf BTC LOP Bottom MD 0' 2,053' TVD 0' 1,901' 16" hole Cmt w/ 215 sks (49 bbl) of 15.0 ppg, Type -1, Tree crossing = 4 -3/4" Otis lead and 550 sks 246 bbl of 15.0 ( ) ppg, class G, tail Intermediate Casing Too of Cement 9 -518" L -80 40 ppf BTC CBL est. @ 5,680' MD �• LOP Bottom ( 300' above 9 -5/8" shoe ) MD 0' 5,980' TVD 0' 4,948' 12 -1/4" hole Cmt w/ 136 sks (51 bbl) of 12.5 ppg, class Capillary String (Installed 1112012008) " G, lead and 212 sks (44 bbl) of 15.8 ppg, class G tail 318" 2205 Stainless Steel + >� Top Bottom MD 0' 8,175' I)1 TVD 0' 7,129' - > Production Ip r M Squeezed uction Cas 3 -1/2" L -80 9.3 ppf EUE j1 1 [ r 8rd wl 6.25" OD control line protectors Excape System Details ? } ?* i22 Bottom - Ceramic flapper valves below U )[ TV 0' 9,052' each module as follows: TVD 0' 8,006' D� 8.5" hole Cmt w/ 1,392 sks (286 bbl) 15.8 ppg, class G Flappers MD (RKB): DI ' Mod 16- 6,303' !' i Excape System Details Mod 15- 6,345' D )C 16 Excape modules placed Mod 14- 6,651' 1 r r control line fires top 8 modules Mod 13- 6,752' ? Mod 12- 7,040' 1 Red contol line fires middle 7 modules Mod 11 - 7,283' ?` Green control line fires bottom 1 module Mod 10- 7,523' (� Ceramic flapper valves below each ? module except for module 1 Mod 9- 7,693' 1 Mod 8- 7,754' Perfs MD (RKB): Mod 7- 7,827' Mod 6 - 8,126' ?� � ' Sqz (12/10/06) hi Sqz (12/10/06) Mod 5- 8,184' " . z �� r Sqz (12/10/06) Mod 4- 8,418' 534' � r Sqz (12/10/06) Mod 3- 8,534' Sqz (12/10/06) Mod 2- 8 Mod 1 - ,63 35' I) � Mod 11 - 7,270- 7,280' Mod 10 - 7,510- 7,520' Mod 9- 7,680 - 7,690' ' Mod 8- 7,740 - 7,750' Mod 7- 7,814- 7,824' Mod 6- 8,112- 8,122' Mod 5- 8,170- 8,180' Tagged fish @ 8,257' MD (11/19109) TD PBTD Mod 4- 8,404 - 8,414' - 133' of 318" capillary string & BHA 9,100' MD 9,016' MD Mod 3- 8,520 - 8,530' 8,052' TVD 7,970' TVB Mod 2- 8,622 - 8,632' Mod 1 - 8,720 - 8,730' Well Name & Number: Cannery Loop Unit #9 Lease: Cannery Loop Unit County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 7,270' - 8,730' (TVD): 6,224' - 7,684' Angle @ KOP and Depth: 2.8° / 100' @ 500' Angle /Perfs: 0° Dated Completed: 1113/2004 Completion Fluid: 6% KCL Revised By: Kevin Skiba Last Revison Date: 11/25/2009 Maunder, Thomas E (DOA) From: Skiba, Kevin J. (kskiba@marathonoil.com] Sent: Wednesday, December 24, 2008 10:23 AM To: Maunder, Thomas E (DOA) Subject: RE: CLU #9 (204-161) Attachments: CLU-09 Operations Summary 111808.ZIP Tom, Page 1 of 1 Your observation pertaining to the capillary string installation date was correct. We inadvertently submitted the sundry without a page of the Operations Summary. Attached is the missing Operations Summary page for 11/18/08. This page has the information pertaining to the initial capillary string installation. ~ 4~h~~~~~ ~~~~.,~~y There is also a correction to the production data. The gas production rate, subsequent to the capillary string installation, should have been 3,250 mcf. We have also completed a well test on CLU-9 since the 10-404 was submitted which provides us with the water production data. CLU-9 is now producing 17 bbls of water. I apologize for the incomplete /incorrect data and the confusion it caused, Kevin Slaba Engineering Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 From: Maunder, Thomas E (DOA) [mailto:tom.maunder@alaska.gov] Sent: Tuesday, December 23, 2008 2:22 PM To: Skiba, Kevin J. Subject: CLU #9 (204-161) Kevin, I am reviewing the sundry recently submitted for the capillary string installation in this well. It appears that the cap. string was already in the hole when the work was begun on 11/19. Is that correct? Did the first run fail so it was pulled and rerun? 1 seem to remember possibly speaking with you regarding a cap. string that became plugged. Also, would you please have a look at the production #s. Is the 246 mcf "after" number correct? Base on the production record 1 can access, I think the number needs another "digit°. Thanks in advance. Tom Maunder, PE AOGCC 12/24/2008 M Marathon MARATHON Oil Company December 10, 2008 Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Mr. Tom Maunder ~ Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Cannery Loop Unit Well: Cannery Loop Unit #9 ~ 1 r_ `t" Dear Mr. Maunder: Attached for your records is the Report of Sundry Well Operations, 10-404, for CLU 9 well. This report covers the work performed to run a 3/8" capillary string to mitigate water loading. The capillary string was installed on 11-20-08 and set at a depth of 8,525' MD. All work was completed under Sundry # 308-396. CLU 9 is presently flowing at 246 mcf at 700 psi. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~~ . Kevin J. Skiba Engineering Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Operations Summary Kenai Well File Current Well Schematic KJS STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMON REPORT OF SUNDRY WELL OPERATIONS - ~~ /~/,~-03 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ - Install Performed: Alter Casing ^ Pull Tubing^ Perforate New Pool ^ Waiver^ Time Extension^ Capillary String 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 ^Q - Exploratory^ 204-161 3. Address: p0 Box 1949 Stratigraphic ^ Service^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20544-00-00- 7. KB Elevation (ft): 9. Wel- Name and Number: 42' (21' AGL) - Canne Loo Unit #9 - 8. Property Designation: 10. Field/Pool(s): ADL-02397' Cannery Loop UnitJBeluga 11. Present Well Condition Summary: Total Depth measured 9,100' - feet Plugs (measured) NA true vertical 8,p42' - feet Junk (measured) NA Effective Depth measured 9,016' - feet true vertical 7,858' - feet Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060 psi 1,500 psi Surface 2,032' 13-3/8" 2,053' 1,903' 5,020 psi 2,260 psi Intermediate 5,959' 9-5/8" 5,980' 4,938' 5,750 psi 3,090 psi Production 9,031' 3-1/2" 9,052' 7,994' 10,160 psi 10,540 psi Liner Perforation depth: Measured depth: 6,290' - 8,730' (gross) True Vertical depth: 5,237' - 7,672' (gross) Tubing: (size, grade, and MD) 3-1/2" L-80 9,052' Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): Installed a 3/8" Capillary String to a depth of 8,525' MD. 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 3,100 16 0 680 Subsequent to operation: 0 ''~~$ ' a } 1 700 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ~ ~ Service ^ Daily Report of Well Operations X 16. Well Status after work: 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: 308-396 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technician - Signature ~ ~ Phone 907-283-1371 Date December 10, 2008 Form 10-404 Revised 04/2006v ~ ~~~ f~~~l ~~~^ ~`~~ Submit Original Only Maradwn operations Summary Report ,~~ ~~~~ Comp~~Y Well Name: CANNERY LDDP UNIT 09 Daily Operations Report Date: 71M8t2008 Job Category : R&M MAIHTEHAHCE 21 HrS~mmary MIRU BJ DynaCoil to run 318" Capillary string to 8525' ItB. Plugged up DynaCoil while filling. Suspect corrtaminated surface line. ops StartTlne ErtlTlne Drr 0 COtle AG'W COtl! SraEra TroebkCaOe Canme~t 09:00 09:45 0.75 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, and emergency response. Discussed operations, safety hazards around the well head, cold work hazards overhead hazards workin with man-lift. Obtained work ermit. 09:45 10:33 0.80 KURD COIL AF Spot equipment and warm up equipment. Attemp to bleed tree cap. Swab vavle leaking. Call for rousabout to grease swab. 10:33 11:03 0.50 KURD COIL AF Bleed tree cap and install tree cap adapter. PU injector. 11:03 11:33 D.50 RK COIL AF RU injector and stab coil. Set BHA to 3800 psi. Install BHA on coil and pull est BHA to 500 lbs. 11:33 12:00 0.45 Rtt COIL AF Carry injector to well head. MU pack-off into tree cap adapter. PTest tree ca connections to 2500 si. Good test. 12:00 13:30 1.50 RUNPUL COIL AF RIH wt 3r'8" coil and BHA to 8525' t(B. 13:30 14:15 0.75 INSTAL SEQP AF Lan 'I Install mechanical slips to land coil. Set hydraulic pack-off ~ 3000 psi. and set Rattigon. Reel off additiona1250' of coil. Roll up and tie off to WN. Install DH fitter and check valve. Plumb to 1 ~2" buried line from foamer skid on CLU 6. 14:15 16:1 S 2.00 SECURE LL AF RU pump on coil unit to fill Dyna-Coil w7 foamer. Begin filling lines. 16:1 S 16:45 0.50 PUMP TRET AF Set well house over well head. Secure well head. Electrian restores ower to WH and foamer skid. Continue um in . 18:45 19:45 3.00 PUMP TRET TS MSOT Experience pluaaina problems while gumgina. Believe that the surface line is plugged! damaged. Switch to DynaCoil line. tt plugs, then blows clear, eventually to plug again. Find dirt in surface manifold. Discuss options going forward. Shut down for the night. 19:45 20:00 0.25 SECURE LL Secure well head and location. RD equipment. Sign out and leave loc. www.peloton.com Report Printed: 12C14d200ti Marathon Qil Cortrtp~nll operations Summary Report Well Name: CANNERY LDP UNIT 09 sort Date: 11M98008 Job Category: rearm mnrn ~ ~~+.+~•~~ r Srmmary U BJ DynaCal to pull plugged 318" Capillary string from 8525' KB. Remove BHA. Flush w/clean oamer. ops Cpnme rt irtTlne 60Trne Orr 0 COtle RlYal OGe $tdpa TrorbkCoOe DO 09:00 1.00 SAFETY MTG AF Hold PJSM. Discuss alarms, muster area, and emergency response. Discussed operations, safety hazards around the well head, cold work hazards overhead hazards workin with man-lift. V~ladin on SVVPermi. 00 10:00 1 .00 RURD OIL AF Spot equipment and warm up equipment. Check DynaCoil for pressure. None. Pressure DynaCal to 3000 .psi. Still plugged. Electrician arrives to disconnect well house. Waiting on crane to be mobiNzed into lease. 9:30 m.., nnoratnr arrives to insure permit. „ . - crew. Discuss job scope. 0.90 URD 1:45 12:39 OL AF arryrryctaw ru ••~^.,~°° . - --- - assure. Back-off ydrat,iic line to hydraulic pack-off. Check hyrauFe pr attigun actuator screws 1 f2 turn. AF w1 318" coil and BHA to 8525' KB. 2:39 14:39 2.00 UNPUL OL Production immediately increases erations r o f k 4:39 15:24 0.75 URD . p o s OL. AF .Drop 2 soap stic 0 3.2 MMCF/d. Remove BHA. A milky whRe liquid streams from DynaCoil. A sample thawed on the dash of a d rum. soon freezes on top of the k looked Gke soapy water. Take a sample from the coil. R looks ike 'cku p. chemical but i soon freezes. Presst,a'e tested BhIA. K pressured up 0 5200 psi. and held pressure. On disassembly, the BHA contained a me solids d . so ax substance i looked lice ear wax which containe U pump on coil unit to fiN DynaCoil w/foamer. Begin flushing the hrre. Initial 1.50 15:24 16:54 PUMP TRET ~ oulating pressure is 500 psi, but is soon drops to 200 psi.Cordinue umpirxJ until we have pumped 1 / 2 of 55 gal drum (the approximate vaume f the coi - 27 auons erience plugging problems whie pumping• Pressure is fluctuating from x 16:54 18:54 2.00 PUMP p TRET p pa 750 o to 3000 psi. At 18:00 pressure drops from 5000 psi t p v ~ ve cleared a restriction in the coil C~rtinue pumping. (most 30 gaions irRo coi. Chemical returns look "clearer" and not as frothy s earNer n the day. - -• , -- ~ ,~. ~ ,,,,, +mmeiy BJ DynaCoil to re-run 318" Capillary string to 8525' KB. ~ Code ~= T Canmert rme ErGTme Drr o ~ old PJSM. Discuss alarms, muster area, and emergency response. i 08:45 0.75 SAFETY MTG AF ~scussed operations, safety hazards around the well head, cold wor azards overhead hazards work'n wRh man-lift. Obtained work rrr i 09:33 0.80 RURD Crl. Spot equipment and warm up equipment. Attemp to bleed tree cap. Sw vavle leaking. Call for rousabout to grease swab. .., ~~ n ~n RI IRr) Ol. AF Bleed tree cap and install tree cap adapter. PU injector. _. ~~ ou n .,, aRnn .,~i Install BHA On coil and F to well head. MU pack-off into tree cap 1 .00 INSTAL SEQP AF and con ~wooca n~,. •,~••-" •••~--.._...-- - pack-off ~ 3000 psi. and set Rarttigon. Reel off addiional 250' of coi. Rob up and tie off to V1Rf. Install DH filter and check valve. 2.00 RURD OIL AF Blow down 112" berried line. 0.50 PREP OC AF Set well house over wei head. Secure wep head. Electrian restores power to WH and foamer skid. Continue pumping. _. . _... __:_ ~ ~:__ ...r r.acnr-1 rnnnvr`t to foamer skid on CLU 6. Begin Report Prirrted: 11/268008 www.peloton.com #: 50-133-2054400 p. Des: ADL-02397 elevation: 42' (21' AGL) S #: DD.04.10614.CAP.DRL nude: 60° 31'S8.155'N ig nude: 151 °15'48.901'V11 id: 09-03-2004 09-15-2004 Released: 09-24-2004 @ 18:00 hrs. Tree crossing = 4-3/4" Otis Too of Cement (CBL est.) at 300' above 9-5/8" shoe 3/8" 2205 Stainless Steel Top Bottom MD 0' 8,525' CLU #9 Pad 1 204' FSL, 547' FEL, Sec. 7 , T5N, R11 W, S.M. w Squeezed - Ceramic flapper valves below each module as 16 - 6,303' 15 - 6,345' 14 - 6,651' 13 - 6,752' 12 - 7,040' 11 - 7,283' 10 - 7,523' 9 - 7,693' 8 - 7,754' 7 - 7,827' 6 - 8,126' 5 - 8,184' 4 - 8,418' 3 - 8,534' 2 - 8,635' 1 - N/A TD PBTD 9,100' MD 9,016' MD 8,052' TVD 7,970' TVB • M MARATNOM Drive Piae 20" K-55 133 ppf ToQ Bottom M D 0' 130' TVD 0' 129' 13-318" K-55 68 ppf BTC Tic g Bo m MD 0' 2,053' TVD 0' 1,901' hole Cmt wl 215 sks (49 bbl) of 15.0 ppg, Type 1, lead and 550 sks (246 bbl) of 15.0 ppg, class G, tall 9-5/8" L-80 40 ppf BTC ~P Bottom MD 0' 5,980' TVD 0' 4,948' 2.25" hole Cmt wl 136 sks (51 bbl) of 12.5 ppg, class G, lead and 212 sks (44 bbl) of 15.8 ppg, class G tail 3-112" L-80 9.3 ppf EUE 8rd w/ 6.25" OD control Ifne protectors ~Qg Bo om MD 0' 9,052' TVD 0' 8,006' 8.5" hole Cmt wl 1,392 sks (286 bbl) 15.8 ppg, class G • 16 Excape modules placed - control line fires top 8 modules • Red contol line fires middle 7 modules • Green control line fires bottom 1 module • Ceramic flapper valves below each module :xceot for module 1 Sqz 10Dec06 Sqz 10Dec06 Sqz 10Dec06 Sqz 10Dec06 Sgzl0Dec06 11 - 7,270-7,280' 10 - 7,510-7,520' 9 - 7,680-7,690' 8 - 7,740-7,750' 7 - 7,814-7,824' 6 - 8,112-8,122' 5 - 8,170-8,180' 4 - 8,404-8,414' 3 - 8,520-8,530' 2 - 8,622-8,632' 1 - 8,720-8,730' Well Name & Number: CLU #9 Lease: Cannery Loop Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Count USA Perforations (MD): 7,270' - 8,730' (TVD): 6,224' - 7,684' An le KOP and Depth: 2.8° / 100' 500' A le/Perfs: 0° Dated Completed: 11/3/2004 Completion Fluid: 6% KCL Revised By: Nancy Henry Last Revison Date: 1 211 0/20 0 8 • • ~ t s ~ $...~ ~...~ s.~ ~..a ~:.-~J ~.t ~.~ E.~ ~. d~I `a..~ C,~,) ~~~0 ~~ ~i ~ SARAH PALIN, GOVERNOR ~~ OIIJ ~ ~ 333 W. 7th AVENUE, SUITE 100 COI~TSL'`RQA~I'IOI~T COMl~'IISSIOI~T ~/ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Kyle Miranda Production Engineer Marathon Oil Company PO Box 1949 ~+~~9~~~=, ~~~C,`;E 1- " ~E~C Kenai AK 99611-1949 Re: Cannery Loop Unit, Beluga Gas Pool, CLU #9 ~ ~t "' Sundry Number: 308-396 c~ b~ Dear Mr. Miranda: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, ~~~~~ f~ Daniel T. Seamount, Jr. Chair DATED this ~ day of November, 2008 Encl. • M Marathon MARATHON Oil Company October 31, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Application for Sundry Approvals Field: Cannery Loop Unit Well: Cannery Loop Unit #9 Dear Mr. Maunder: • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907!283-1371 Fax 907/283-1350 ,. ~.$~ ~.. -- e, ~, . _ i ~ ~, We propose to run a 3/8" capillary string in CLU 9 to mitigate water loading. The setting depth will be approximately 7500'. Please find attached a 10-403, current wellbore diagram, and detailed operations program. If you. have any questions or need further information please call me at (907) 283-1371. Sincerely, ,. e Kevin J. Skiba Engineering Technician Enclosures: 10-403 Application for Sundry Approvals Current Well Schematic Detailed Operations Program cc: AOGCC Houston Well File Kenai Well File MDD KJS ~~ ~~ '~ ~ ~ "O~TATE OF ALASKA /~~ '~ ,~ ~ 1~ 3 ° ALA OIL AND GAS CONSERVATION COI~I~I~OP~I ` ~ APPLICATION FOR SUNDRY APP_ RQVA~LS, _ - ~ ~~ ~ 20 AAC 25.280 n:! ' , ' ~' 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown^ Perforate Waiver ^ Other Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Capillary String ~ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ Install 2.Operator Name: Marathon Oil Company 4. Current Well Class: 5. Permit to Drill Number: ~ Development ^ Exploratory ^ 204-161 3. Address: p0 Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20544-00-00' 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: S E ^ ^~ Cannery Loop Unit #9 ' pacing xception Required? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL-02397. 42' (21' AGL) ~ Cannery Loop Unit/Beluga ~o.S~~ 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9100' - 8042' 9016' 7958' - NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3060 1500 Surface 2032' 13-318" 2053' 1903' 5020 2260 Intermediate 5959' 9-5/8" 5980' 4938' 5750 3090 Production 9031' 3-1/2" 9052' 7994' 10160 10540 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6290'-8730' (gross) 5237'-7672' (gross) 3-1/2" L-80 9052' Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program ^~ BOP Sketch ^ Exploratory ^ Development Q - Service ^ 15. Estimated Date for 16. Well Status after proposed work: November 11th, 2008 Commencing Operations: Oil ^ Gas^ - Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kyle Miranda Title Production Engineer Signature /~j ~ Phone ~- ~ ~ ~ / Date (907) 283-1370 ~ v _ ~ /, ~ rp'~ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~ ~~ 3g Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: Subsequent Form Required: ~(~ ` , APPROVED BY % / Approved by: , COMMISSIONER THE COMMISSION Date: v Form 10-403 Revised 06/2006 ti ` '~a ~ ~ A L ~ ~~~=~ ~ ~'' +` ~~d~ Submit in Duplicate 2008 Capillary String Installation Page 1 • CLU 9 Capillary String Installation WBS: Waiting to approve Obiective Install capillary string (3/8" 2205 0.049" WT) for delivering foamer to alleviate liquid loading. Installation Procedure: BJDC, UOSS (PJSM and JSA): 1. Have on site: proper spool, Wayne's Well Head Adapter (long/short both), Sundry. Well Control Standards Sheet. 2. MIRU BJ Dyna-Coil unit. 3. Shut swab valve, pull tree-cap flange, remove snap ring and OTIS blanking plug. Replace plug with WWHA (note o-ring). MU flange. 4. P/LT Dyna-Coil injector with crane; install packoff assembly into 2-7/8" female connection. 5. Set Fluid Control Valve pressure over the hydrostatic head at TVD setting depth. 6. MU BHA with centralizers and secure to 3/8" string. 7. SHUT IN WELL AT WING VALVE to prevent BHA from traveling into flow-tee and down flowline. NOTE: Operator or Company Supervisor may bring well back on after string is below flow-tee 8. RIH to approximate setting depth of 7500'. 9. Set Rattiguns. Leave 1.5 times SITP (or greater per BJDC) on hydraulic pack off. 10. Leave remaining spool of tubing outside of well in plastic tote for soap injection skid hookup. 11. Cap tubing with a Swagelok cap and valve, pressure gauge, and HP filter. 12. Lockout Swab, Upper Master, and Lower Master as per Capstring Lockout Procedure. 13. Hookup injection line to CICM. NOTE: Start foamer at 1 gpd, slowly raising the level to planned rate as the week progresses. CHECK FOR FOAM RETURNS. 14. RDMO. Cleanup site. Sign-out. 15. Replace well house NOTE: When replacing well house, be careful of the tubing "bend" as it goes back inside if it extends through the roof I: 50-133-2054400 -GL: 21.00' -THF: 21.70' 4' FSL, 547' FEL, Sec. 7 , N, R11W, S.M. ;e cxn = 4-3/4" Otis Top Of Cement (est.) @ 300' above 9-5/8" shoe Excaae System Details - Ceramic flapper valves below each module as follows: Flappers MD fRKB): Module 1 - NA Module 2 - 8635' Module 3 - 8534' Module 4 - 8418' Module 5 - 8184' Module 6 - 8126' Module 7 - 7827' Module 8 - 7754' Module 9 - 7693' Module 10 -7523' Module 11 - 7283' Module 12 - 7040' Module 13 - 6752' Module 14 - 6651' Module 15 - 6345' module 16 - 6303' CLU #9 M MARATHON Drive Piae: 20", 133 ppf, K-55 to130' Surface Casing: 13-3/8", 68 ppf, K-55, BTC @ 2053' Cmt w/ 550 sx. of class G at 15.Oppg. Performed top job w/ 212 sx Type 1 at 15.0 ppg Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5980' Cmt w/ 136 sx of class G lead at 12.5 ppg and 212 sx of class G tail at 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9052' Cmt w/ 1392 sx of class G at 15.8 ppg 16 Excape modules placed Green control line fires bottom 1 modules Red contol line fires middle 7 modules Yellow line for fires top 8 modules Ceramic flapper valves below each module xcept for module 1 ule 1 - 8720-8730' ule 2 - 8622-8632' ule 3 - 8520-8530' ule 4 - 8404-8414' ule 5 - 8170-8180' ule 6 - 8112-8122' ule 7 - 7814-7824' ule 8 - 7740-7750' ule 9 - 7680-7690' ule 10 - 7510-7520' ule 11 - 7270-7280' Sqz 10Dec06 Sqz 10Dec06 Sqz 10Dec06 Sqz 10Dec06 Sgz10Dec06 Well Name & Number: CLU #9 Lease: Cannery Loop Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): (TVD): Angle KOP and Depth: Angle/Perfs: Dated Completed: 1113/2004 Completion Fluid: 6% KCL Prepared By: Kevin Skiba Last Revison Date: 8/4/2008 TD - 9,100' PBTD - 9,016' • • ' v k ~:~=~~ ~ . MICROFILMED 03/01 /2008 .~F Fem. ~M DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE F:~L,aserFiche\CvrPgs_Tnserts\Microfilm Marker.doc . . Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1326 Fax 907/283-1350 (.~) Marathon MARATHON Oil Company December 27, 2006 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W ih Ave Anchorage, Alaska 99501 Reference: 10-404 Sundry Report Field: Cannery Loop Unit Well: Cannery Loop Unit #9 RECEIVED " JM'~ 0 2, 2uu/1 v Alaska Oil & Gas Cons. Anchorage Dear Mr. Aubert: The top 5 modules were squeezed on CLU9 well beginning December 2nd through December 5th. Final squeeze pressure was 1400 psi. The composite bridge plug was drilled out below Module 12 and the well returned to production. The well is currently flowing 4.5mm scf/day at 680 psi FWHP and 60 BWPD. If you have any questions or need further information please call me at (907) 398-9954. Sincerely, ft1/~¿~ Mictiael A. ~II~ Senior Production Engineer SCANNED JAN 082007 Enclosures: 10-404 Sundry Report Well Schematic Operations Summary cc: Houston Well File Kenai Well File KJS - \-., . .'...".,,', ., dCf-1-1& ( 1. Operations Abandon Performed: Alter Casing D Change Approved Program D 2. Operator Name: Marathon Oil Company I ·u"VL.1 V L.U . STATE OF ALASKA ..a 101 JAN 0 2 Z007 ALAS Oil AND GAS CONSERVATION COM~OtJ REPORT OF SUNDRY WELL OPERATIOr4l8ka Oil & Gas Cons. C(}fTImission Anchora e Other WaiverD Time ExtensionD Re-enter Suspended Well D 5. Permit to Drill Number:.IO A 7 6. API Number: Repair Well Pull Tubing D Operat. Shutdown D Plug Perforations .j Perforate New Pool D Perforate D 4. Well Class Before Work: Development [] Stratigraphic D 3. Address: Exploratory D Service D PO Box 1949, Kenai Alaska, 99611-1949 7. KB Elevation (ft): 50-133-20544-00-00 . 42' ,; 9. Well Name and Number: Can nee ADl 02397 11. Present Well Condition Summary: 10. Field/Pool(s): Can nee 8. Property Designation: a Total Depth measured 9100' feet true vertical 8041.5' feet Effective Depth measured 9016' feet true vertical 7957.5' feet Casing Length Size MD Structural Conductor 130' 20' 130' Surface 2053' 13-3/8 " 2053' Intermediate 5980' 9-5/8 " 5980' Production 9052' 3-1/2" 9052' Liner Plugs (measured) Junk (measured) TVD Burst Collapse 130' 1903' 4938' 7994' Perforation depth: Measured depth: 6290'-8730' (gross) True Vertical depth: 5237'-7672' (gross) Tubing: (size, grade, and measured depth) Packers and SSSV (type and measured depth) None in current completion N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Intervals squeezed: Module 12 - 7026'-7036', Module 13 - 6740'-6750', Module 14 - 6638'-6648' Module 15 - 6332'-6342', Module 16 - 6290'-6300' , Treatment descriptions including volumes used and final pressure: Squeezed all intervals to 1400 psi. _ Representative Daily Average Production or Injection Data Gas-Mcf Water-Bbl Casing Pressure 300 900 0 4WO ~ 0 15. Well Class after work: Exploratory D 16. Well Status after work: OilD Gas [] 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 13. Oil-Bbl o o Tubing Pressure 50 680 Prior to well operation: Subsequent to operation: 14. Attachments: Copies of Logs and Surveys Run Daily Report of Well Operations Development [] - Service D x WAG D GINJ D WINJ D WDSPL D Sundry Number or N/A if C.O. ~xemRt: . r-1 306.~~ 3 eÇl--:U r[) / Contact Michael A. Mullin Printed Name Michael A. Mullin Title Senior Production Engineer Signature Phone (907) 398-9954 Date Form 10-404 Revised 04/2006 OR\G\\\lAL R8DMS 8Ft. JAN l; 2007 h-'+) Submit Original Only API: 50-133-2054400 RT-GL: 21.00' RT-THF: 21.70' 204'FSL,547'FEL,Sec. 7, T5N, R11W, S.M. Tree cxn ::: 4-3/4" Otis #9 ITOC (est.) - 300' above 9-5/8" shoe Excape System Details - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 1 - NA Module 2 - 8635' Module 3 - 8534' Module 4 - 8418' Module 5 - 8184' Module 6 - 8126' Module 7 - 7827' Module 8 - 7754' Module 9 - 7693' Module 10 -7523' Module 11 - 7283' Module 12 - 7040' Module 13 - 6752' Module 14 - 6651' Module 15 - 6345' module 16 - 6303' Well Name 11 Number: County or Parish: Perforations (MD) BHP: Dated Completed: Prepared By: TD - 9100' PBTD - 9016' CLU #9 Kenai Completion Fluid: Last Revison Date: Surface Casinq: 13-3/8", @ 2053' Cmt w/ 550 sx. of class 15.0ppg. Performed top job w/212 sx Type 1 at 15.0 ppg Int. Casino: 9-5/8", 40 ppf, L-80,BTC @ 5980' Cmt w/ 136 sx of class G lead at 125 ppg and 212 sx of class G tail at 15.8 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE8rd with 6.25" OD control line protectors to 9052' Cmt w/1392 sx of class G at 15.8 ppg Excape System Details - 16 Excape modules placed - Green control line fires bottom 1 modules - Red contolline fires middle 7 mOdules - Yellow line for fires top 8 modules - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 1 - 8720-8730' Module 2 - 8622-8632' Module 3 - 8520-8530' Module 4 - 8404-8414' Module 5 - 8170-8180' Module 6 - 8112-8122' Module 7 - 7814-7824' Module 8 - 7740-7750' Module 9 - 7680-7690' Module 10 -7510-7520' Module 11 - 7270-7280' Module 12 7026 7036'Sq2:1 ODec06 Modulo 13 6710 6750'Sqz 10Dec06 Module 11 663g 6618'Sqz 10Dec06 Module 15 63326312'Sqz10Dec06 module 16 6290 6300'Sqz 10Dec06 Cannery Loop Gas Field Alaska USA (TVD) 6% KCL 12/12/2006 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date From- To 11/30/2006 07:00 - 10:30 10:30 - 10:50 10:50 - 12:30 . . >,....:...:....... -;',-,',.::- :.;>.....<...,.....; Marathon Oif Company.. . Operations Summary Report CANNERY LOOP UNIT 09 CANNERY LOOP UNIT 09 MAINTENANCE/REPAIR GLACIER DRILLING GLACIER DRILLING Hours Code ~~Je Phase 3.50 SAFETY MTG_ CTSG 0.33 RURD_ COIL CTBG 1.67 WORK COIL CTBG 12:30 - 13:30 1.00 WORK COIL CTBG 13:30 - 13:40 0.17 WORK COIL CTSG 13:40 - 14:00 0.33 WORK COIL CTBG 14:00 - 14:40 0.67 WORK COIL CTBG 14:40 - 15:00 0.33 WORK COIL CTSG 15:00 - 15:40 0.67 WORK COIL CTBG 15:40 - 16:00 0.33 WORK COIL CTBG 16:00 - 16:15 0.25 WORK COIL CTBG 16:15 - 16:30 0.25 WORK COIL CTBG 16:30 - 17:00 0.50 WORK COIL CTBG 17:00 - 17:30 0.50 WORK COIL CTBG 17:30 - 17:45 0.25 WORK COIL CTBG 17:45 - 18:10 0.42 WORK COIL CTSG 18:10 - 18:15 0.08 WORK COIL CTSG 18:15 - 18:40 0.42 WORK COIL CTBG 18:40 - 19:30 19:30 - 19:50 0.83 WORK COIL CTBG 0.33 WORK COIL CTBG Start: 11/30/2006 Rig Release: Rig Number: 1 Spud Date: 9/3/2004 End: Group: MIRU spot up coil unit, spot up flow back tank, supply tank, choke and hard line. Mixed up 290 BBLS of 6% KCL. Spot up light plants, heater and man lift. Held PJSM and discussed safety issues and concerns. PU injector, MU BHA on 1.75" COIL with dimple on connector, 1.75" X 3' staight bar, 1.75" double flapper check valve and 1.75" nozzle. Take injector to tree. Open lines to Methanol tank. Load coil. Coil loaded returns to flow Methanol tank. Perform BOPE test. Shell tested to 200 psig low/ 4400 psig high. Blinds to 220 psig low/4400 psig high, Tubing rams same. Pressure test good. Displace the Methanol in coil to Methanol tank with KCL. Open well, RIH with coil, WHP= 1805 psig, coil below 100' Start PIR at 0.3 BPM, open choke to flow back tank. Returns to flow back tank, 0.5 BPM gas cut. Coil at 2750' CTM, WHP= 1550 psig, PIP= 1580 psig, 0.3 BPM PIR. returns down to a trickle. WHP = 0 psig, coil @ 4940' CTM, PIP= 26 psig Total fluid pumped 24 bbls to well. Coil at 6140' CTM, choke line to gas buster froze off, diverted to other line to flow back tank. PIP= 18 psig. total fluid pumped= 35 bbls. very little returns to flow back tank. Tagged up on small bridge at 7487' CTM, total fluid pumped = 43 bbls. PU hole with coil to 7400', increased PIR to 13/4 BPM Coil at 8000' CTM, PU weight at 21, 000 Ibs. Total pumped in well = 121 bbls. no returns to flow back tank. PIP= 1033 psig, WHP= 0 psig. Coil below bottom perf interval at 8730', coil @ 8740' CTM, no returns to flow back tank. PIP= 1122 psig, Total fluid pumped to well= 130 bbls Coil down to 8900' PU weight 21,000 Ibs. PIp::: 1440 psig, WHP= 0 psig, 180 bbls pumped. No returns to flow back tank. Cool down N2 unit. Start N2 down coil at 750 SCFM. Coil stuck at 8900' CTM, PU to 36, 000 LBS, RIH coil would not move. No returns to tank. Work tool string, hold 35, 000 Ibs PU weight coil came free. PUH with coil, WHp::: 0 psig, no returns to surface, total pumped down well= 230 bbls, returns to flow back tank::: 21 bbls, 209 bbls to well. Continue PU hole with coil, Coil at 8345' CTM, with no returns to flow back tank. PIp::: 1960 psig, WHP= 0 psig Coil at 7525' no returns, PIP= 2450 psig. Coil at 6700' CTM, no returns to flow back tank, WHP= 0 psig, PIP= 2350 psig, N2 @ 750 SCFM. Coil stuck at 6750' while PUH. PU coil weight to 36, 000 Ibs coil would not move, no returns to flow back tank. N2 at 750 SCFM. RIH with coil 6' to stack 8000 Ibs off of PU weight. PUH with coil still stuck no movement either up or down with coil. Changed N2 rates while holding tension on the coil. Work coil up hole with no change on coil. SID N2 and start pumping the KCL at 1.0 SPM. Coil still stuck at 6713.6' CTM. RIH stack 3000 Ibs off of PU weight on coil. PUH with coil to 38, 000 Ibs. Work coil up and down couple of times. Coil came free. PIP on fluid at 400 psig, no returns to flow back tank. Continue up hole with coil, coil stuck at 6658' work coil, coil grabby while picking coil up hole. PU up weight pulling up to 37,000 Ibs and releasing back to 32, 000 Ibs like dragging something up hole with coil. PIP= 454 psig. Coil Printed: 12/22/2006 11 :25:23 AM . . Marathon()iI Compamy Operations SummarY Report Legal Well Name: CANNERY LOOP UNIT 09 Common Well Name: CANNERY LOOP UNIT 09 Event Name: MAINTENANCE/REPAIR Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING From-To Hours Code, Súb Phase Code 11/30/2006 19:30 - 19:50 0.33 WORK COIL CTBG 19:50 - 20:00 0.17 WORK COIL CTBG 20:00 - 20:40 0.67 WORK COIL CTBG 20:40 - 21 :00 0.33 WORK COIL CTBG 21 :00 - 21 :50 0.83 WORK COIL CTBG 21:50-22:15 0.42 WORK COIL CTBG 22:15 - 22:30 0.25 WORK COIL CTBG 22:30 - 23:10 0.67 WORK COIL CTBG 23:10 - 23:30 0.33 RURD - COIL CTBG 12/2/2006 08:00 - 11: 15 3.25 SAFETY MTG_ WRLN 11:15-12:15 1.00 RURD - ELEC WRLN 12:15 - 14:10 1.92 RURD - ELEC WRLN 14:10 - 14:50 0.67 WORK ELEC WRLN 14:50 - 15:25 0.58 WORK ELEC WRLN 15:25 - 16:15 0.83 WORK ELEC WRLN 16:15 - 16:45 0.50 WORK ELEC WRLN 16:45-17:10 0.42 WORK ELEC WRLN 17:10 - 18:25 1.25 WORK ELEC WRLN 18:25 - 19:15 0.83 WORK ELEC WRLN 19:15 - 20:00 0.75 RURD - ELEC WRLN 12/4/2006 07:00 - 08:00 1.00 SAFETY MTG_ CTBG 08:00 - 10:00 2.00 RURD_ COIL CTBG 10:00-11:10 1.17 WORK COIL CTBG Page Start: 11/30/2006 Rig Release: Rig Number: 1 Spud Date: 9/3/2004 End: Group: Description of Operations at 6421' When coil at 6045' CTM, shut down fluid pump, start N2 at 500 SCFM. WHP= 0 psig, Total fluid pumped to well 280 bbls. Returns to flow back tank 0.5 BPM. N2 at 750 SCFM Coil at 5414' returns to flow back tank. WHP= 11 psig, N2 at 720 SCFM, total::: 126, 000 SCF. PIP= 1875 psig. WHP up to 300 psig. WHP= 600 psig and dropping, returns at 0.5 BPM. Total fluid returns to flow back at 67 bbls WHP= 166 psig, returns total to F/B at 78.0 BBLs, PIP= 1140 psig. Continue to pump N2 at 750 SCFM. POOH with coil, PIP= 900 psig, WHP= 30 psig, total N2 pumped= 172, 000 SCFM. Shut down N2, Coil at 2300' CTM, WHP= 266 psig. Continue out of hole with coil. OOH with coil, shut in swab valve, Crane would not start, need jump. Pump Methanol accross the tree, choke and flow back lines to gas buster. Break bowen connection at tree under the injector. PU injector and move to back of coil unit. PU tree connection and connect to tree. Well secured, shut down all equipment. Total fluid recovered= 122 bbls, total of 160 bbls fluid left in well. WHP at surface = 0 psig. BJ left lease. MIRU wire line unit, extablish use of crane during wire line operations due to boom truck problems. Held PJSM and discussed operations during arming and setting of tool. RD equipment from one well on pad to CLU#9. Wait on tree crossover to be picked up at BJ shop and Baker setting tool. Tree valve had ice in valve, called out Vetco to service valve prior to going to well with lubricator. Ice cleared tree ready for procdure.. PU lubricator and go to well with tree connection. MU tool string and Baker tool string layed out but not made up to tool sting. Held PJSM prior to arming the setting tool. Went to communications Black out on pad. Pressure test lubricator to 2000 psig with fuild. Test good opened well. RIH with 1 11/16" tool string with 2.65" GR. WHP= 1800 psig Ran GR down to 7100' made repeat pass. POOH with GR. OOH with GR, MU Baker setting tool with 3.5" composite plug, 2.5" OD. Held PJSM and discussed arming gun and went to communication black out on pad. Pressure tested the lubricator with the setting tool in it to 2000 psig, held. Open well ,RIH with baker composite bridge plug. Correlate depth to CBL. Set plug at 7080' DIL. PUH 10' RIH and tagged plug. POOH with tool string. OOH with tool string, blow down lubricator. PU tool sting verifed no plug on tool string. RD equiment. Clean up around wellhead, Expro left lease Held PJSM, discussed procedure and optained work permit. Discussed safety concerns around well and work conditions. MIRU cement unit, Blow down tree cap and PU injector. Open Bowen connector and go to well with coil. Load coil with Methanol fluid to pressure test. PT shell and ground lines to 200 psig low pressure/ 5500 psig high, test good. Displace coil with fresh water to Methanol tank. 26.5 bbls to tank. Printed: 12/22/2006 11 :25:23 AM . . . ',"Marathon OH Company Operations Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: CANNERY LOOP UNIT 09 CANNERY LOOP UNIT 09 MAINTENANCE/REPAIR GLACIER DRILLING GLACIER DRILLING Phase 12/4/2006 11:10-13:30 2.33 WORK COIL CTBG 13:30 - 14:05 0.58 WORK COIL CTBG 14:05 - 14:40 0.58 WORK COIL CTBG 14:40 - 15:10 0.50 WORK COIL CTBG 12/5/2006 15:10 - 15:35 0.42 WORK COIL CTBG 15:35 - 15:56 0.35 WORK COIL CTBG 15:56 - 16:15 0.32 WORK COIL CTBG 16: 15 - 16:30 0.25 WORK COIL CTBG 16:30 - 16:40 0.17 WORK COIL CTBG 16:40 - 17:00 0.33 WORK COIL CTBG 17:00 - 17:20 0.33 WORK COIL CTBG 17:20 - 18:35 1.25 WORK COIL CTBG 18:35 - 19:00 0.42 WORK COIL CTBG 19:00 - 19:40 0.67 RURD - COIL CTBG 07:00 - 08:00 1.00 SAFETY MTG_ CTBG 08:00 - 09:30 1.50 RURD - CTBG 09:30 - 10:00 0.50 TEST_ CTBG 10:00 -11:35 1.58 RUNPU CTBG 11 :35 - 11 :50 0.25 CIRC_ CTBG 11 :50 - 12:55 1.08 RUNPU CTBG 12:55 - 13:25 0.50 RURD - CTBG 13:25 - 14:30 1.08 RURD - COIL CTBG 07:00 - 08:00 1.00 SAFETY MTG - CTBG 08:00 - 09:30 1.50 RURD_ COIL CTBG 09:30 - 10:00 0.50 TEST BOPE CTBG 10:00 - 12:10 2.17 RUNPU COIL CTBG 12:10 - 13:45 1.58 TEST_ BOPE CTBG 13:45 - 15:15 1.50 DRILL_ CMT_ CTBG 12/6/2006 Start: 11/30/2006 Rig Release: Rig Number: Spud Date: 9/3/2004 End: Group: Bring on pumps, pressure up coil to 1600 psig. Open well up to coil. WHP= 1510 psig. RIH pumping H20 @ 0.3 BPM to tag depth at 7079' CTM with coil. PUH with coil to 7060' CTM, WHP= 26 psig, increase PIR to 1.0 BPM. Returns to flow back tank at 0.4 BPM. Establish injection rate to perforations. Shut in block valve to flow back tank. Check PIP at 1.0 BPM, 1.5 BPM and 1.75 BPM. WHP= 55 PSIG. Line up pumps to deliver blended 15.8 ppg class G cement to Pump to coil. Total of 12 bbls blended. Start pumping cement to coil 5.50 bbl cement away pump loosing prime. Swapped pumps and trouble shooting problem with pumps. 12 bbls of cement in coil. Shut down pumps before pushing the H20 behind the cement. Pumps lined up start displacement of cement out of coil with fresh water. Pumped 10.0 bbls when started seeing returns to flow back tank. 15.5 bbls away cement to nozzle. PUH with coil after 20.5 bbls H20 pumped. Continue up hole with coil, SID pump after 26.5 bbls away. Coil at 6697' CTM. PUH at 75' PM, When coil at 5816' CTM, pump 1 bblof H20 trough coil. SID pump, WHP= 0 psig, no returns to flow back tanik. PU coil to 5690' CTM. RIH with coil to 5688' CTM, PUH with coil to 5700' CTM. Start pump, pumped 1 bbl of H20 to coil, SID pump. PU coil to 5500' CTM, brought on pump at 1.0 BPM to establish returns to flow back tank. Monitor returns to flow back tank. Loosing 0.6 bbls to well. WHP= 22 psig. Discussed options decide to pump another cement blend tomorrow. Shut down pump. Did not pump the Biozan, POOH with coil. OOH with coil, shut in tree. Move all water out of flow lines, pumps and hoses with vac truck. Load coil with Methanol. 26.5 bbls. SID pump coil loaded with coil. Break connection under injector, drained tree to flow back tank. PU injector move to craddle on back of coil unit. Shut down all unit, BJ coil left lease. Contact Vac services to load up supply tank with fresh water for tomorrow. Held PJSM, discussed procedure and optained work permit. Discussed safety concerns around well and work conditions. Rig up and stab injector on tree. Shell test BOP and Lines 250 / 4500 psi. Displace CT to water. RIH CT. Tag cement at 6433' (between modules 14 and 15). Circulate 1 BPM. 100% returns. Test plug to 1000 psi. Losses of about 0.15 BPM at 1000 psi. POH CT. Circulate CT to 50/50. Rig back CT for night. WOC. Held PJSM, discussed procedure and optained work permit. Discussed safety concerns around well and work conditions. Rig up and stab injector on tree. Shell test BOP and Lines 250 / 4500 psi. Displace CT to water. PU 2-1/8" motor and 2.70" mill. RIH Tag cement at 6434'. Drill sporatic green cement to 6739'. Printed; 12/22/2006 11;25;23AM . . . Marathon Oil Company Operations . Summary Report Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: Date CANNERY LOOP UNIT 09 CANNERY LOOP UNIT 09 MAINTENANCE/REPAIR GLACIER DRILLING GLACIER DRILLING Sub Code Code ,Phase 12/6/2006 12/7/2006 12/8/2006 15:15-17:45 2.50 DRILL_ CMT_ CTBG 17:45 - 18:05 0.33 DRILL - CMT - CTBG 18:05 - 19:00 0.92 RUNPU COIL CTBG 19:00 - 20:00 1.00 RURD - COIL CTBG 07:00 - 07:30 0.50 RURD - COIL 07:30 - 08:00 0.50 SAFETY MTG_ CTBG 08:00 - 09:30 1.50 RURD - COIL CTBG 09:30 - 09:45 0.25 TEST_ BOPE CTBG 09:45 - 11 :30 1.75 RUNPU COIL CTBG 11:30 - 22:15 10.75 DRILL_ CMT_ CTBG 22:15 - 22:30 0.25 TEST_ CMT_ CTBG 22:30 - 23:30 1.00 RUNPU COIL CTBG 23:30 - 00:15 0.75 RURD - COIL CTBG 10:00 - 10:30 0.50 RURD - COIL 10:30 - 11 :00 0.50 SAFETY MTG - CTBG 11 :00 - 13:30 2.50 RURD_ COIL CTBG 13:30 - 14:10 0.67 TEST BOPE CTBG 14:10 - 15:45 1.58 RUNPU COIL CTBG 15:45 - 17:50 2.08 RUNPU COIL CTBG 17:50 - 19:00 1.17 PUMP - CMT_ CTBG 19:00 - 19:35 0.58 SQUEZ CMT_ CTBG 19:35 - 21:10 1.58 SQUEZE CMT_ CTBG 21 :10 - 22:00 0.83 SQUEZE CMT_ CTBG 22:00 - 23:45 1.75 SQUEZE CMT_ CTBG 23:45 - 00:45 1.00 RUNPU COIL CTBG 00:45 - 01 :20 0.58 RURD - COIL CTBG 01 :20 - 02:00 0.67 RURD - COIL CTBG 12/10/2006 07:00 - 07:15 0.25 RURD - COIL 07:15 - 08:00 0.75 SAFETY MTG_ CTBG 08:00 - 09:00 1.00 TEST_ CMT_ CTBG 09:00 - 10:00 1.00 TEST_ BOPE CTBG 10:00 - 11 :00 1.00 RURD - COIL CTBG 11 :00 - 13:50 2.83 RURD - COIL CTBG 13:50 - 15:30 1.67 RUNPU CTBG 15:30 - 16:30 1.00 DRILL_ CTBG 16:30 - 16:50 0.33 CIRC_ CTBG 16:50 - 18:00 1.17 RUNPU CTBG 18:00 - 18:30 0.50 RURD - CTBG Start: 11/30/2006 Rig Release: Rig Number: 1 Spud Date: 9/3/2004 End: Group: Description of Operations . Drill 6739' to 6749'. Many stalls and very difficult drilling. Drill 6749' - 6760'. POH. Rig back CT for night. Total fluid pumped for day = 325. Total returns 325. Start equipment Held PJSM. discussed procedure and optained work permit. Discussed safety concerns around well and work conditions. PU 2-1/8" motor and 2.70" mill. Shell test 250 psi /4500 psi. Good. RIH Tag cement at 6759'. Drill cement from 6759' to 7050'. Full returns during drilling. Pressure up to 1000 psi. Lost 500 psi in 40 seconds, 0.2 BPM injection rate at 1000 psi. POH. Rig back CT for night. Start equipment Held PJSM, discussed procedure and optained work permit. Discussed safety concerns around well and work conditions. Rerig surface lines for reverse circulating. MU 2-1/8" nozzle and stab injector. Shell test 250 psi / 4500 psi. Good. RI H to 6000'. Reversed 15 bbls from well pumping N2. Blew down 1000 psi N2 pressure and surged perfs. Circulated bottoms up while RIH to bottom. Injection rate increased from 0.2 BPM at 1000 psi to 0.5 bpm at 400 psi. Tag bottom at 7036' (corrected to flag). Lay 12 Bbls cement up to 5700'. POH to 5500' Hold 0 pressure for 10 min. Increase pressure to 200 psi for 10 min, 500 psi for 10 min and to 800 psi. Pressure broke back to O. Keep working pressure back up to 200 psi for 90 min. Worked pressure up to 800 psi 2 more times. Slight pressure drop 3rd time up. Decide to clean out since we have 4 hours on cement and are running out of thickening time. Jet through cement with 24 Bbls biozan and circulate bottoms up. Circulate 55 bbls after biozan. Continue circulating while POH. Freeze protect CT and surface lines. Rig back CT for night and WOC. Will test cement on Saturday morning. Start equipment Held PJSM, discussed procedure and optained work permit. Discussed safety concerns around well and work conditions. Pump into well. Final injection was 0.2 BPM at 700 psi. Perform full BOP test 200 /4500 psi. Displace 50/50 out of CT. Pick up 2-118" motor and 2.70" mill. Stab on well and shell test 200/4500 psi. RIH. Tag bottom at 7025'. Drill cement from 7025' - 7055'. Circulate 20 Bbls of water. POH while circulating bottoms up. Freeze protect CT with 50/50. Printed: 12/22/2006 11 :25:23 AM .. . . .: .... Marathon Oil Company Operations Summary Report Page of 5 Legal Well Name: Common Well Name: Event Name: Contractor Name: Rig Name: CANNERY LOOP UNIT 09 CANNERY LOOP UNIT 09 MAINTENANCE/REPAIR GLACIER DRILLING GLACIER DRILLING ~W~ Phase Start: 11/30/2006 Rig Release: Rig Number: 1 Spud Date: 9/3/2004 End: Group: Descriptiolì of Operations 12/10/2006 18:30 - 19:15 0.75 RURD - COIL CTBG Rig back CT for night and WOC. 19:15 - 19:30 0.25 RURD - COIL CTBG Perform injection test to 2500 psi. Injected 2.0 BPM at 1850 psi. Will test cement on Tuesday morning. 12/11/2006 07:00 - 07:15 0.25 RURD COIL Start equipment 07:15 - 08:00 0.75 SAFETY MTG - CTBG Held PJSM, discussed procedure and optained work permit. Discussed safety concerns around well and work conditions. 08:00 - 09:00 1.00 RURD - COIL CTBG RU and stab on well 09:00 - 09:10 0.17 TEST_ BOPE CTBG Perform shell test 200 / 4500 psi. 09:10 - 09:45 0.58 RURD COIL CTBG Displace 50/50 out of CT. 09:45-11:10 1.42 RUNPU COIL CTBG RIH. Tag bottom at 7025'. 11:10 -13:30 2.33 PUMP - CMT_ CTBG Pump cement and lay from bottom to 5700'. Full returns during cement lay. 13:30 - 13:45 0.25 PUMP - CMT_ CTBG Stop CT at 5500' and increase pressure to 200 psi. 13:45 - 14:00 0.25 PUMP - CMT_ CTBG Increase pressure to 500 psi. 14:00 - 14:15 0.25 PUMP - CMT_ CTBG Increase pressure to 800 psi. 14:15 - 14:30 0.25 PUMP_ CMT_ CTBG Increase pressure to 1100 psi. 14:30 - 15:50 1.33 PUMP - CMT_ CTSG Increase pressure to 1400 psi. 15:50 - 16:15 0.42 JET_ WTR_ CTSG Reduce pressure and start biozan at 1 BPM. 16:15 - 16:45 0.50 JET_ WTR_ CTBG 23 Bbls biozan away. Biozan to nozzle. 16:45 - 17:05 0.33 JET_ WTR_ CTBG Jet from 5700' to 7054' at 1 BPM, 80 fpm. 17:05 - 17:30 0.42 JET_ WTR_ CTBG Continue circulating cement up at 1 BPM while POH to 6200' 17:30 - 17:45 0.25 JET_ WTR_ CTSG Increase pump rate to 1.5 BPM and cont circulating. 17:45 - 18:30 0.75 RUNPU COIL CTBG Circulate well while POH to surface. 18:30 - 18:50 0.33 RURD - COIL CTBG Circulate CT to 50/50. 18:50 - 20:00 1.17 RURD - COIL CTBG Rig back CT for night. Secure well. Printed: 12/22/2006 11 :25:23 AM · SARAH PALIN, GOVERNOR ALASKA OIL AND GAS CONSERVATION COlVIMISSION ,. 333 W. 7'h A VENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-75423 Ken Walsh Senior Production Engineer Marathon Oil Company PO Box 1949 Kenai, AK 9611-1949 ;J.I}~-~~t Re: Kenai Cannery Loop Unit, Beluga Gas Pool, Cannery Loop Unit #9 Sundry Number: 306-389 r~ r: Vo'.c d Dear Mr. Walsh: 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. When providing 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 this,S-day of December, 2006 Encl. . . Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1311 Fax 907/283-1350 Marathon Oil Company December 4, 2006 RECEIVED 13 ~ c.. DEC O't Z006 Alaska Oil & Gas Cons. Commission Anchorage Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W ih Ave Anchorage, Alaska 99501 Reference: 10-403 Sundry Notice Field: Cannery Loop Unit Well: Cannery Loop Unit #9 Dear Mr. Aubert: Attached and submitted for your approval is the follow-up Form 10-403 to cement squeeze several of the Beluga perforation intervals in the Cannery Loop Unit #9 wellbore. An associated procedure and a well bore diagram for this work are also included for your review. This well is currently a Beluga gas producer. Once the water is shut off, the cement and bridge plug will be drilled out before the well is returned to gas production. On December 1, 2006, you granted verbal approval to me to proceed that day with work to isolate excessive water bearing intervals in this wellbore. This sundry submission is the follow-up paperwork that you requested as a condition of the verbal approval. If you would like any other information, please contact me at 283-1311 or kdwalsh@marathonoil.com. Sincerely, Iú»--t. W~ Ken D. Walsh Senior Production Engineer Enclosures: 10-403 Sundry Well Schematic Operations Procedure cc: AOGCC Houston Well File Kenai Well File Ken Walsh 20 MC 25.280 í:I as ;om:.'" 1. Type of Request: Abandon 0 Suspend 0 Operational shutdown 0 Perforate 0 Waiver [Anchorage Other· 0 Alter casing 0 Repair well 0 Plug Perforations 0 Stimulate 0 Time Extension 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: i:fJ!'1 Marathon Oil Company Development 0 Exploratory 0 .~ ðQL-\-\1O \ 1"11 3. Address: Stratigraphic 0 Service 0 6. API Number: Il~ P. O. Box 1949, Kenai, AK 99611-1949 50-133-20544-00-00 ~ 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes 0 No 0 Cannery Loop Unit #9 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ADL 02397 42 Cannery Loop UniUBeluga 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 9100' 8041.5' 9016' 7957.5' Casing Length Size MD TVD Burst Collapse Structural Conductor 130' 20" 130' 130' 3060 1500 Surface 2053' 13-3/8" 2053' 1903' 5020 2260 Intermediate 5980' 9-518" 5980' 4938' 5750 3090 Production 9052' 3-1/2" 9052' 7994' 10160 10540 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6290'-8730' (gross) 5237'-7672' (gross) Packers and SSSV Type: Packers and SSSV MD (ft): 13. Attachments: Description Summary of Proposal 0 14. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch 0 Exploratory 0 Development 0 Service 0 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: 12/1/2006 Oil 0 Gas 0 Plugged 0 Abandoned 0 17. Verbal Approval: Granted Date: 12/1/20~ WAG 0 GINJ 0 WINJ 0 WDSPL 0 Commission Representative: Winton Aubert ' ! 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Ken D. Walsh Printed Name Ken D. Walsh Title Senior Production Engineer Signature } ~ b. uJ~ Phone Date 907-394-3060 12/4/2006 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: &Jlo -( ~RC1 Plug Integrity ~ BOP Test 'þ( Mechanical Integrity Test 0 Location Clearance 0 Othec ",",.. \,~ ~'V ~-\- ;)-SOO r" 6-'> '?Ic,....~ <...\ ~\" ~ -\- 4~\ ,,-. ~~ Subsequent Form Required: 4G(nfj )r. RBDMSSFL DeC J" 1005 'Sf-lr\ ~ APPROVED BY l-z,r/~"()Þ Approved by: _ . . ~ CqMMI~NER THE COMMISSION Date: Form 10-403 Revised 06/2006 'iJ ~11\Jf-\L Submit in Duplicate j¡ 010 0 IS 1~f'SI' lIt:.. J.z.Æ-/C'/ RECEIVED /6\11.11'(.1,,1\,.1 røa\~~ STATE OF ALASKA 't) ",1/" ~--' lI"' 11'\ ALASW'OIL AND GAS CONSERVATION COM.ON ()If' k DEC ~2~ APPLICATION FOR SUNDRY APPROVALS \?-l,,,\ Alask~ Oil & G C n ,~:J . . MARATHON OIL COMPANY ALASKA REGION Cannery Loop Unit CLU #9 2006 Cement Squeeze Procedure WBS # WO.06.14658.EXP ALL DATA RELATIVE TO THE TESTING OF THIS WELL IS CONFIDENTIAL. Notes: · This procedure covers work to cement squeeze the Excape Modules #12 through #16 to shut off excessive (800-900 BWPD) from this interval. · BJ CoilTech coiled tubing unit has been rigged up on the well following a partial coiled tubing cleanout performed on 11/29/2006. · Deliver a 500 bbl Rain-for-Rent tank and fill with fresh water. Heat water to 80 deg F. 1. Run aauae rina. MIRU Expro Wireline. Hold PJSM and review conditions of Safe Work Permit. Install crossover connection from top of BJ CoilTech BOP to 4-3/4" Otis standard tree cap connection. Install and pressure test Expro pump-in sub, wireline valve, and lubricator to 2500 psig with methanol water. PU and roundtrip a 2.65" 00 gauge ring, jars, and CCL to around 7250' MD to ensure that 2.55" 00 Baker composite BP can be run successfully. 2. Set composite BP below Module #12 perforated interval. Initiate radio silence. Arm #5 setting tool coupled to Baker 3-1/2" composite BP. RIH with 3-1/2" Baker composite BP (2.55" max running 00, 10K psi down, 8K psi up), setting sleeve, and CCL on wireline. Correlate depth with Expro CBL. Set top of BP at ~CBL MD. After releasing setting tool, RIH and tag top of BP to confirm set depth. POOH and LD setting tool. RDMO Expro Wireline. 3. RU BJ CoilTech coil tubina unit for cement squeeze with 1-3/4" 00 coil tubing and ASRC crane. MIRU BJ cement van (cement pump is already on location). Deliver tank and fill with 50:50 methanol water. Rig up injector head and lubricator with cement nozzle on end of coil tubing and make proper pull test. Make up CT injector head and lubricator to BOP's. Load coil tubing with methanol water and pressure test CT BOP pipe and blind rams to 250 low/4500 high psi. Pressure test flowback iron to 250 low/4500 high psi. Displace methanol water back to holding tank. 4. RIH with cementina nozzle on coil tubina to taa BP at 7080' loading hole with fresh water. Break circulation to surface and record pump rates, pump pressures, and wellhead pressures at 1/4 , Y2, %, 1, 1- %,1-1/2, and 1-3/4 BPM. 5. Establish iniection rate into perf intervals. SI well and establish injection rate and pressures into perf intervals in Modules 12 through 16 at the same rates in Step #4, Do not exceed max surface pressure of 1500 psi for these intervals. Open wellhead when finished pumping and recording data. Note: Using frac data from comparable TVD, max surface pressure with 8.33 ppg fresh water = 1600 psig using frac gradient of 0.75 psi/ft at squeeze perf TVD of 5250'. 6. Batch mix 58 sacks (12.0 bbls) of cement per recipe below. Perform BJ standard QAlQC tests. Batch mix 20 bbls of Biozan polvmer mud for cement contamination. Tentative cement blend is detailed below. Note that slight changes to additive concentrations may result due to lab tests results. SC9.":>~~ \JC\...:>~<C ~.<;. ~~\.~ ~4Iv1.A 15.8 ppg Class G with additives: h';j.: f-¡ Pl~\ . . Page 2 of3 0.7% FL-63 0.3% CD-32 0,5% R-3 0.3% EC-1 0.1% ASA 301 2 ghs FP-6L Density 15.8 ppg Yield 1 .158 cflsx Fluid loss 36cc/30 min Free water: 0 Pump time 7:37 hr:min 7. Pump cement slurry via CT after total cement volume has been mixed. Pump 12.0 bbls of 15.8 ppg cement and displace with 15.7 bbls of fresh water. Do not exceed a .75 psi/ft fracture gradient with surface pump pressure. Begin PUH with CT at 84 fpm pumping fresh water at % BPM to spot a balanced cement plug. Stop pumping with a total of 26.3 bbls of fresh water displacement behind the cement and the CT depth at 5900' MD. PUH to 5700' MD and cycle CT depth from 5700'·5690' four times. PUH to 5500' MD and load hole with fresh water. 8. Shut in well and applv SQueeze pressure. NOTE: Do not exceed 0.75 psilft fracture gradient. Monitor and document annulus pressure and rate during squeeze operations. Pump no more than 4.8 bbls of Biozan to squeeze the cement. Once the target squeeze pressure is obtained hold for 45 to 60 minutes to facilitate nodal development. Open wellhead and pump 11.9 bbls Biozan with CT at 5500'. Ensure nozzle does not reach TOC until Biozan has exited nozzle. 9. RIH at 75 fpm with CT spottina Biozan mud down CT at 1.0 BPM until a total of 20 bbls of Biozan has been pumped. With 20 BBL of Biozan away continue displacing Biozan to end of CT wi fresh water at a pump rate of 1 BPM and trip rate of 75 FPM. RIH at 75 FPM to 6790'. At 6790' increase RIH rate to 80 FPM and continue displacing Biozan wi fresh water at 1.0 BPM. RIH to 7080'. At 7080' hold in hole and displace remaining 10 BBL of Biozan in CT. With Biozan displaced, increase pump rate to 1.5 BPM and circulate 2X bottoms up (80.7 BBL) or until returns at surface are clean and free of cement and contaminants. With returns clean at surface, POOH pumping at 1.5 BPM to keep hole loaded. Trap 200-300 psi surface pressure on well when OOH with CT and before closing master valves. Freeze protect the CT and surface iron. RD injector head and stand back CT. 10. With well shut in, secure location for the night and WOC a minimum of 24 hrs. 11. Pressure test casina to 1000 psia with fresh water. If casing does not test, discuss with Anchorage merits of additional remedial cement work. 12. Clean out to BP at 7080' CBL with motor/mill on CT. RIH with a Baker Oil Tool BHA consisting of 2- 1/8" OD VIP motor and a 2.75 OD concave mill sized for 3-1/2" casing. RIH and drill or circulate any cement to BP at 7080' CBL with 6% KCL water and FRW-14 friction reducer at 2 BPM. CBU. 13. Mill BP set at 7080" with CT. Circulate 6% KCL water with FRW-14 at 2 BPM while milling BP. Once BP is milled, push or mill BP down to bottom. 14. Jet well clean with fluid and trap nitroaen pressure. After BP is on bottom, circulate well clean while pumping fluid at 1.25 BPM fluid and nitrogen at 500 scfm. Drop ball to open circulating port. POOH with CT and BHA pumping only nitrogen to unload the KCL and produced water from the well. RDMO BJ Coiltech coiled tubing and nitrogen units. 15. RDMO and release eQuipment. Haul off fluid from tanks to the G&I Plant for disposal. RD flowback iron. Release tanks and all rental equipment to vendors. 16. FLOW TEST WELL TO SALES. CLU #9 2006 Cement Squeeze Procedure KDW - 12/4/2006 4:33:48 PM Page 3 of3 CONTACTS Ken Walsh: Lyndon Ibele: . 907-283-1311 (w) Jennifer Enos: 907-394-3060 (c) 907-565-3042 (w) Clyde Scott: 907-748-2819 (c) KGF Operators: 907-283-1305 CLU #92006 Cement Squeeze Procedure . 713-296-3319 (w) 713- 408-3583 (c) 713-296-2336 (w) KDW - 12/4/2006 4:33:48 PM API: 50-133-2054400 RT-GL: 21,00' RT-THF: 21.70' 204'FSL,547'FEL,Sec. 7. T5N, R11W, S.M. Tree cxn = 4-3/4" Otis ITOC (est.) - 300' above 9-5/8" shoe Excape Svstem Details - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 1 - NA Module 2 - 8635' Module 3 - 8534' Module 4 - 8418' Module 5 - 8184' Module 6 - 8126' Module 7 - 7827' Module 8 - 7754' Module 9 - 7693' Module 10 -7523' Module 11 - 7283' Module 12 - 7040' Module 13 - 6752' Module 14 - 6651' Module 15 - 6345' module 16 - 6303' CLU #9 TD - 9100' PBTD - 9016' ¡Drive Pipe: 20",133 ppf, K-55 t0130' Surface Casino: 13-3/8", 68 ppf, K-55, BTC @ 2053' Cmt w/ 550 sx. of class G at 15,Oppg. Performed top job w/ 212 sx Type 1 at 15,0 ppg Int. Casinq: 9-5/8", 40 ppf, L-80, BTC @ 5980' Cmt wi 136 sx of class G lead at12.5 ppg and 212 sx of class G tail at 15.8 ppg Prod, Tubinq: 3-1/2", 9,3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9052' Cmt w/ 1392 sx of class G at 15,8 ppg Excape Svstem Details - 16 Excape modules placed - Green control line fires bottom 1 modules - Red contolline fires middle 7 modules - Yellow line for fires top 8 modules - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 1 8720-8730' Module 2 - 8622-8632' Module 3 - 8520-8530' Module 4 - 8404-8414' Module 5 - 8170-8180' Module 6 - 8112-8122' Module 7 - 7814-7824' Module 8 - 7740-7750' Module 9 - 7680-7690' Module 10 - 7510-7520' Module 11 - 7270-7280' Module 12 - 7026-7036' Module 13 - 6740-6750' Module 14 - 6638-6648' Module 15 - 6332-6342' module 16 - 6290-6300' Well Name & Number: CLU #9 I Lease: Cannery Loop Gas Field County or Parish: Kenai I State/Provo Alaska I Country: IUSA Perforations (MD) (TVD) .- - I Angl< @ KOP and Depth BHP: I BHT: I Completion Fluid: 6% KCL Dated Completed: 11/3/2004 Prepared By: J. R. Thompson 1 Last Revison Date: 10/26/2004 Re: CLU #9 Cement Squeeze Sundry Req. Z8 4~ l G,. { . Subject: Re: CLU #9 Cement Squeeze Sundry Request From: Winton Aubert <winton_aubert@admin.state.ak.us> Date: Fri, 01 Dee 2006 11 :03:53 -0900 TO: "Walsh, Ken"·<kdwalsh@marathonoH.com> Ken, This confirms AOGCC's verbal approval to commence perforation squeeze operations in well CLU 9 (PTD 204-161), as described below. Please submit appropriate documentation as required. Thank you, Winton Aubert AOGCC 793-1231 Walsh, Ken wrote: Winton. Per your recommendation during our phone conversation this morning, Marathon Oil Company requests verbal approval to isolate water bearing perforated and fracture stimulated Beluga intervals in our Cannery Loop Unit #9 wellbore. All of the perforations open in this well are in the Beluga formation. A current wellbore diagram for this well has been attached to this email for your information. The intent of this work is to shut off excessive water production of about 850 BWPD that contributed to the recent logging off of this well. A PL T run in 2005 indicated that the bulk of the gas production from this well was entering from modules below Module #12. Marathon proposes to set a composite bridge plug just below the Module #12 perforations (7026'-7036' MD) in this 3-1/2" monobore at or about 7080' MD. All of the perforations located above the bridge plug, which include Modules #12 through #16 (7036'-6290' MD gross interval), will be cement squeezed. Coiled tubing will be used to spot the cement across and above these intervals. After the coiled tubing is pulled above the cement and circulated clean. the cement will be squeezed by the bullhead method. After waiting on the cement to harden, the cement squeeze will be pressure tested, drilled out, and pressure tested again. It is possible that these intervals may require an additional cement squeeze to achieve our goal of shutting off water production from these intervals. The composite bridge plug will be drilled out with coiled tubing and the well returned as a gas producer following this proposed work. Marathon would like to secure verbal approval today to begin operations to start this work today. A Form 10-403 sundry request wm be prepared covering this work and sent in to the AOGCC next week. Ken Ken D. Walsh Senior Production Engineer Marathon 011 Company-Alaska Asset Team 907-283-1311 (office) 907 -394-3060 (cell) «CLU #9 WBD.xls» 1 of 1 12/1/200611 :04 AM 3: b-Lc- DATA SUBMITTAL COMPLIANCE REPORT 11/27/2006 Permit to Drill 2041610 Well Name/No. CANNERY LOOP UNIT 9 Operator MARATHON OIL CO ç f1u..cl 3 t}~' API No. 50-133-20544-00-00 MD 9100 TVD 8042 Completion Date 11/3/2004 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: SP/GR-IEL -Density/Neutron-Son ie-Single Arm Caliper. MFTs Well Log Information: (data taken from Logs Portion of Master Well Data Maint Log/ Data Type ED ED Digital Med/Frmt CAse C Las Electr Dataset Number Name """""'-Directional Survey ~925 Induction/Resistivity Log Log Scale Media Run No Interval Start Stop o 9100 4930 9120 OH/ CH Open Open . Received Comments 5/26/2006 Contractor UNKNOWN 5/26/2006 Plus Graphics I J Well Cores/Samples Information: Name Interval Start Stop Sent Received Sample Set Number Comments ADDITIONAL INFORMATION Well Cored? Y ~ Daily History Received? ~ CSt N Chips Received? ~ Formation Tops Analysis Received? ..:f-iJ'I- ..__.~ . Comments: =ik lr-----~---- (À3 \tl~~ Compliance Reviewed By: _ Date: . Marathon Oil Company May 24, 2006 Alaska Oil & Gas Conservation Commission Attn: Howard Oakland 333 W. 7ili Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon: Cannery Loop Unit 8 Marathon: Cannery Loop Unit 9 Marathon: Cannery Loop Unit 10 Marathon: Cannery Loop Unit 11 CONFIDENTIAL Dear Mr. Oakland: . Alaska Asset Team Northern Business Unit P.O. Box 3128 Houston, TX 77253 Telephone 713-296-2384 Fax 713-499-8504 FEDERAL EXPRESS The following confidential well data is enclosed for the above referenced wells. This digital data includes directional surveys, openhole logs (LAS format) and prints (dpk format) for each well. CLU8 ~ clu8 _dir _aogcc. dat ~ clu8_vectardepth.las fnf EMAIL _ Clu-8 ....olotted2. dpk CLU9 P IJ q,¿ç- ~ò'1..... '" I ~ du9 _dir _aogcc, dat ~ du9 Jeevesjield.las ~E-MAIL Marathon_CLU 9,dpk CLU 10 'J 0'0- - 10(0 ~ du_10_dir _aogcc,dat ~ CLU10_MAINDEPTH,las ?ær UZProgr am Files _Reeves _ WLS 7.00 _Data_Mar athon_ CLU 10 _MFT _com. dpk ?ær UZProgr am Files _Reeves _ WLS 7.00 _Data_Mar athon_ CLU 10 "plotted. dpk CLU 11 9ò<':' - O::;-y ~ du_ll_dir _aogcc.dat ~ dU_ll..prec-'as .Ias ~ du_ll"prec-'as_tvd,las ~CLUll TVD.las ~ CLUll MD,las ~ Data_Mar athon_ CLU ll"plotted, dpk Alaska Oil & Gas Association CLU 8, 9, 10, 11 Well Data May 24, 2006 Page 2 . . Please indicate your receipt ofthis data by signing below and returning one copy to me at the letterhead address or fax to 713-499-8504. Thank you, MARATHON OIL COMPANY Kaynell Z~man Geological Technician Received by: 1L-J òlL1 À~ Mj ~Ò ~ b Date: Enclosures . Marathon Oil Company . Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 January 11 , 2005 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 ~ t,( JAN 1 8 2005 Reference: Completion Report 10-407 for permit 204-161 Field: Cannery Loop Unit Gas Field / Beluga Well: CLU - 9 Dear Mr. Aubert, Enclosed please find the Well Completion Report with associated attachments for Cannery Loop Unit well No.9. This well has been completed cased hole with a 3.5" Excape monobore production string to surface. I apologize for the delay in getting this completion notice to you. Should you require further information, I can be reached at 907-529-0524 / 713-296- 2730, or bye-mail atJRThompson@MarathonOil.com. Sincerely, K~' ames R. Thompson Sr. Completions Engineer Enclosures: Completion Report Directional Survey Operations Summary Wellbore Diagram STATE OF ALASKA ALASelL AND GAS CONSERVATION COMMleN WELL COMPLETION OR RECOMPLETION R~ORT AND LOG SuspendedD WAGD 1b. Well Class: 20AAC25.110 Development 0 Exploratory 0 1 Other Service 0 Stratigraphic Test 0 5. Date Camp., Susp., or 12. Permit to Drill Number: Aband.: 11/03104 204-161 6. Date Spudded: 13. API Number: September 3, 2004 50-133-20544-00-00 7. Date TD Reached: 14. Well Name and Number: September 16, 2004 Cannery Loop No. 9 8. KB Elevation (ft): 15. FieldlPool(s): 42 9. Plug Back Depth(MD+ TVD): 9016' 17957.5' 10. Total Depth (MD + TVD): 9100' 1 8041.5' 11. Depth Where SSSV Set: NA 19. Water Depth, if Offshore: NA feet MSL MFTs 1a. Well Status: OilU Gas0 Plugged D AbandonedD 20AAC 25.105 GINJD WINJD WDSPLD 2. Operator Name: No. of Completions Marathon Oil Company 3. Address: P.O. Box 196198, Anchorage, AK 99519-6168 4a. Location of Well (Governmental Section): Surlace: 204'FSL,547'FEL,Sec. 7, T5N,R11VV,S.M. Top of Productive Horizon: 543.46' FSL, 2530.66' FWL, Sec. 8, T5N, R11W, S.M. Total Depth: 588.85' FSL, 2679.06' FWL, Sec. 8, T5N, R11W, S.M. 4b. Location of Well (State Base Plane Coordinates): Surlace: x- 272,424.39 y- 2,388,657.94 TPI: x- 275,507.87 y- 2,388,938.24 Total Depth: x- 276,657.11 y- 2,388,980.77 18. Directional Survey: Yes ~ No U Zone- 4 Zone- 4 Zone- 4 21. Logs Run: SP/GR-IEL-Density/Neutron-Sonic-Single Arm Caliper. Beluga 16. Property Designation: ADL 02397 17. Land Use Permit: NA 20. Thickness of Permafrost: NA 22. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH TVD CEMENTING RECORD AMOUNT CASING FT. GRADE TOP BOTTOM TOP BOTTOM HOLE SIZE PULLED 20" 133 K-55 0 130' 0 130' Driven NA NA 13-318" 68 L-80 0 2053' 0 1903' 16" 550 sx NA 9-518" 40 L-80 0 5980' 0 4938' 12-1/4" 136 sx lead /212 sx tail NA 3-1/2" 9.3 L-80 0 9052' 0 7994' 8-1/2" 1392 sx 85,000 23. Perlorations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): MD: 6290-6300; 6332-6342; 6638-6648; 6740-6750; 7026-7036; 7270- 7280; 7510-7520; 7680-7690; 7740-7750; 7814-7824; 8112-8122; 8170- 8180;8404-8414;8520-8530;8622-8632;8720-8730 TVD: 5237-5247; 5278-5288; 5582-5592; 5684-5694; 5969-5979; 6213- 6223; 6452-6462; 6622-6632; 6682-6692; 6756-6766; 7054-7064; 7112- 7122;7346-7356;7462-7472;7564-7574;7662-7672 24. SIZE 3-1/2" TUBING RECORD DEPTH SET (MD) PACKER SET (MD) 9052' NA 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED See No. 23 18,600 to 53,000 Ibs. 20/40 Ottawa PRODUCTION TEST Method of Operation (Flowing, gas lift, etc.): Flowing Water-BbI: 446 Water-Bbl: 446 26. Date First Production: November 4, 2004 Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: 11/13/2004 24 Test Period... NA 10,963 Flow Tubing Casing Press: Calculated Oil-BbI: Gas-MCF: Press. 1540 0 24-Hour Rate ~ NA 10,963 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Submit core chips; if none, state "none". r~Ji~\i \'. :Pl' "i¡:\7·\iì .. ."' , t ~ ~,."'. NA OR1C'¡\\! J ¡[".-;11'\ Form 1 0-407 Revised 12/2003 CONTINUED ON REVERSE Choke Size: Gas-Oil Ratio: 46164th I NA Oil Gravity - API (corr): NA RBDMS 8FL .IAN 2 0 2005 rc VI 28. GEOLOGIC MARKERS NAME TVD Sterling Beluga 6004 6227 4961 5175 30. List of Attachments: Directional Survey, Well Event Summary, Well bore Diagram 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Printed Name: James R. Thompson 29. Include and briefly s detailed supporting "None". MD 8720 8622 8404 8170 8112 7814 7740 7680 7510 7270 7026 6740 6638 6332 6290 FORMATION TESTS rize test results. List intervals tested, and attach s necessary. If no tests were conducted, state TVD 7662 7562 7346 7112 7054 6756 6682 6622 6452 6213 5969 5684 5582 5278 5237 Pressure 4033 3904 3903 3498 3366 3102 2151 3021 2613 2432 2634 2504 2406 2270 2229 Contact: /2. Title: Sr. Completion Engineer Date: 1/11/2005 Phone: 713-296-2730 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. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 20: True vertical thickness. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: If no cores taken, indicate "none". Item 29: List all test information. If none, state "None". Form 10-407 Revised 12/2003 . . 8/26/2004 130 (ft) 8/27/2004 130 (ft) 9/2/2004 130 (ft) 9/3/2004 130 (ft) 9/4/2004 720 (ft) 9/5/2004 2,063 (ft) 9/6/2004 2,063 (ft) 917/2004 2,063 (ft) 9/8/2004 2,063 (ft) 9/9/2004 2,083 (ft) 9/1 0/2004 3,550 (ft) 9/11/2004 5,286 (ft) 9/12/2004 5,994 (ft) 9/13/2004 5,994 (ft) Rig released from SD#2 @ 12:00hrs 8/26/2004. Prep for morning rig move. Move rig. Rig released to maintenance @ OO:OOhrs 8/27/2004. Rig released from maintenance 06:00hrs 09/01/2004. RlU rig. RlU rig. Mix mud N/U diverter. N/U diverter line. Test diverter. P/U DP. M/U BHA. Clean 20" cond F/30' to 130',Drill F/130' to 217', Pick up MWD, Drill F/217' to 720' Drill F/720'to 1201'. Circ. clean. POOH to shoe. Service rig. RIH. Drill F/1202' to 2063'. Circ. clean. Circ. clean. Wiper trip to shoe. RIH. Circ. clean. POOH. UD BHA. RlU CSG tools.Run Csg.lCBU CMT Csg. Unsling & circ csg clean.RlD cmt equip. POOH w/cement inner string. WOC. Run 1 5/16" top job string. Monitor well while wait on more 1 5/16"pipe and cement.N/D diverter lines,. N/D diverter/Cut 13 3/8" csg/set out annular/remove 20" wellhead.cut 20" and 133/8" csg. Cut 13 3/8" CSG. Install wellhead. N/U BOPE.fTest bop. P/U 5" dp. test csg. Test Csg, Run RTTS Test csg, test formation,handle bha,P/U DP, M/U Bha #3, TIH, Drlg out shoe tract, Drill F/2063' to 2083', Circ clean, LOT, Change out wellbore fluids, Drill F/2083' to 3550' Drill F/3550' to 4006'. Circ Clean. Wiper trip to shoe. Service rig. TIH, Drill F/4006' to 5286' Drill F/5286' to 5994'. Circ, Wiper trip.Circ clean. POOH ,UD bha. chg rams Test rams doors, Rig up to run csg, run csg, emt. csg, set 95/8" packoff, test packoff, rId csg tools chg rams, set test plug, test bop's Printed: 1/1112005 12:31 :26 PM . . 9/14/2004 6,532 (ft) 9/15/2004 7,901 (ft) 9/16/2004 9,100 (ft) 9/1712004 9,100 (ft) 9/18/2004 9,100 (ft) 9/19/2004 9,100 (ft) 9/20/2004 9,100 (ft) 9/21/2004 9,100 (ft) BOP Test.service rig,Test csg, M/U Bha, TIH, Drlg shoe tract, Drill F/5994' to 6014', Circ, LOT, Drill F/6014' to 6532' Drilled F/6532' to 7460', Circ Clean, Wiper trip to shoe, Service Rig, Slip drill line, TIH, Drilled F/7460' to 7901' CBU, wiper trip to shoe, drill 7901 - 9100, circ / wait on TD orders Cire, wiper trip to shoe, srv rig, RIH wiper trip to btm, eire, POH for Elogs, UD drctnl assy, E-Iogs RIU, run E-Iogs, POH, repair tool pads, RIH, log, work stuck tool, prepare fish for E-Iog tool. RIH 5" DP stripping over wireline, engage fish, shear rope socket, spool up wireline, POH, change bales at 9 5/8 shoe. POH with fish, layout fish / fishing tools, RIH, Circ trip gas, wt up to 10.2 ppg, POH, RIU and resume log well E-Iog, RIH, eire, POH laying dn 5" DP, RIU for completion Printed: 1/11/2005 12:31:26 PM . . 9/21/2004 9,100 (ft) 9/22/2004 9,100 (ft) 9/23/2004 9,100 (ft) 9/24/2004 9,100 (ft) 9/25/2004 9,100 (ft) 10/13/2004 9,100 (ft) 10/23/2004 9,100 (ft) 10/24/2004 9,100 (ft) 10/26/2004 9,100 (ft) RIH 5" DP, eire, POH layimg dn DP, clear rig floor RlU / run Excape completion Run 3.5" Excape completion. Circ. Correlate completion. Cement CSG. WOC. N/D BOP. Set slips and cut CSG. Set P.O. and tree. Test tree. RID rig. Rig down rig and prep for rig move. RU Expro to run CBL. Tag flapper in Module 11 at 7285' with 2.70" GR. Unable to break flapper with 1.91" swage. POOH & RD. Pressure test tubing to 3000psi. Break flapper at 7278' WLM. Drift tubing to 9009' WLM with 2.70" GR. Tagged PBTD at 9002'. Completed CBL. Prtnted: 1/1112005 12:31:56 PM . . 11/3/2004 (ft) Finished rigging up frac, flow back, and well tester lines. Perforated module one perfs. Attempted to install CT injector head without success due to high crosswinds. SOFN. 11/4/2004 (ft) Fracture stimulate 16 excape modules. RID frac lines. RlU coil tubing and RIH and broke flapper for module 16. No indication of module 15 flapper. Continue RIH. 11/5/2004 (ft) Cleaned Excape well to PBTO with coiled tubing. Jetted well in, and began flowing well. Rig down coiled tubing. Well flowing 1400 psi FTP on a 42/64" choke, at 12.4 MMSCFO w/716 BWPO. 11/17/2004 (ft) Run dummy PL T string to 8948'. Hung up in module 3, but worked clear. All modules clear. 11/19/2004 (ft) Completed memory PL Ton CLU 9 to attempt to diagnose source of 450 BPO. Printed: 1/1112005 12:32:17 PM MARATHON o!mpanY,CLU-9 Pad #1, Cannery Loop Unit,Cook Inlet, Alaska{lmported) SURVEVITING Page 1 Wellbore: CLU-9 Well path: MWD <0-9100> Date Printed: 24-Sep-2004 r&l. INTEQ Wellbore Name I Created I Last Revised CLU-9 I 27 -Aua-2004 I 24-SeD-2004 Well Name I Government ID I Lac::t R"vic::..n CLU-9 I I 17-Aua-2004 Name CLU-9 Name Pad #1 Coord S stem Name AK-4 on NORTH AMERICAN DATUM 1927 datum Coord S stem Name AK-4 on NORTH AMERICAN DATUM 1927 datum Comments All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Glacier 1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3248.93 Feet on azimuth 83.20 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON olmpanY,CLU-9 Pad #1, Cannery Loop Unit,Cook Inlet, Alaska(lmported) SURVEVITING Page 2 Well bore: CLU-9 Wellpath: MWD <0-9100> Date Printed: 24-Sep-2004 r&¡¡. ..,. INTEQ WellDath (Grid) ReDort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing rdea/10OOl Sectionrftl 0.00 0.00 0.00 0.00 O.OON O.OOE 0.00 0.00 272424.39 2388657.94 165.00 0.70 336.00 165.00 0.92N 0.41W 0.42 -0.30 272424.00 2388658.87 286.00 0.50 351 .40 285.99 2.12N 0.79W 0.21 -0.54 272423.64 2388660.08 346.00 0.50 50.40 345.99 2.54N 0.63W 0.82 -0.33 272423.82 2388660.50 407.00 1.50 66.00 406.98 3.04N 0.31E 1.68 0.65 272424.76 2388660.98 467.00 2.30 90.80 466.94 3.34N 2.23E 1.88 2.60 272426.69 2388661.24 526.00 3.00 88.90 525.88 3.35N 4.96E 1.20 5.31 272429.41 2388661.20 587.00 4.00 94.30 586.77 3.23N 8.67E 1.72 8.99 272433.13 2388661.00 648.00 5.20 96.10 647.57 2.77N 13.54E 1.98 13.77 272437.99 2388660.46 708.00 7.20 94.20 707.22 2.21N 20.00E 3.35 20.12 272444.43 2388659.77 770.00 8.60 94.80 768.63 1.53N 28.49E 2.26 28.48 272452.91 2388658.93 832.00 9.40 93.70 829.86 0.82N 38.16E 1.32 38.01 272462.57 2388658.03 895.00 10.90 92.60 891.87 0.22N 49.25E 2.40 48.95 272473.64 2388657.22 958.00 11.80 88.60 953.64 0.11N 61.64E 1.90 61.25 272486.02 2388656.87 1021.00 14.20 86.60 1015.02 O.72N 75.80E 3.88 75.38 272500.19 2388657.21 1084.00 16.30 87.20 1075.80 1.61N 92.34E 3.34 91.92 272516.75 2388657.78 1146.00 17.00 88.30 1135.20 2.31N 110.09E - 1.24 109.63 272534.50 2388658.13 1209.00 17.90 88.50 1195.30 2.83N 128.98E 1.43 128.45 272553.39 2388658.30 1273.00 21.60 87.10 1255.53 3.69N 150.58E 5.83 150.01 272575.01 2388658.74 1336.00 24.10 85.90 1313.58 5.19N 175.00E 4.04 174.44 272599.45 2388659.78 1399.00 24.60 84.30 1370.97 7.41N 200.87E 1.31 200.40 272625.36 2388661.50 1462.00 26.70 81.00 1427.77 10JI3N 227.91E 4.03 227.66 2726"2.46 2388664.50 1525.00 30.00 80.60 1483.20 15.72N 257.43E 5.25 257.54 272A82.07 2388668.72 1588.00 32.70 82.10 1537.00 20.63N 289.83E 4.46 290.29 272714.56 2388673.01 1650.00 33.50 82.90 1588.94 25.05N 323.40E 1.47 324.14 272748.20 2388676.78 1714.00 35.40 82.50 1641.71 29.65N 359.31E 2.99 360.34 272784.19 2388680.69 1778.00 37.50 81.20 1693.19 35.05N 396.94E 3.50 398.35 272821.92 2388685.37 1841.00 39.10 82.70 1742.63 40.51N 435.60E 2.94 437.38 272860.67 2388690.08 1904.00 40.00 83.10 1791.21 45.47N 475.41E 1.48 477.49 272900.57 2388694.27 1967.00 41.30 83.10 1839.01 50.40N 516.15E 2.06 518.53 272941.39 2388698.42 2007.00 43.10 82.90 1868.64 53.67N 542.82E 4.51 545.39 272968.12 2388701.18 2059.00 41.80 83.60 1907.01 57.80N 577.67E 2.66 580.49 273003.04 2388704.64 2122.00 42.40 83.80 1953.75 62.44N 619.65E 0.98 622.73 273045.10 2388708.47 2184.00 41.90 82.30 1999.72 67.47N 660.95E 1.81 664.33 273086.49 2388712.70 2247.00 41.90 82.90 2046.61 72.89N 702.67E 0.64 706.40 273128.31 238ß717.32 2310.00 41.70 84.00 2093.57 77.68N 744.39E 1.21 748.39 273170.11 2388721.31 2373.00 41.80 83.10 2140.58 82.39N 786.07E 0.96 790.34 273211.87 238ß725.22 2436.00 41.20 83.40 2187.76 87.30N 827.53E 1.00 832.08 273253.41 2388729.33 2499.00 41.10 83.40 2235.20 92.06N 868.71E 0.16 873.54 273294.67 2388733.30 2561.00 40.90 83.80 2281.99 96.59N 909.13E 0.53 914.21 273335.17 2388737.06 2625.00 40.80 84.00 2330.40 101.04N 950.76E 0.26 956.07 273376.87 2388740.71 2688.00 41.70 83.80 2377.77 105.46N 992.06E 1.44 997.61 273418.25 2388744.33 2813.00 40.50 84.20 2471.96 114.05N 1073.78E 0.98 1079.78 273500.12 2388751.35 2938.00 42.60 82.80 2565.51 123.46N 1156.14E 1.84 1162.68 273582.64 2388759.17 3001.00 42.80 82.40 2611.80 128.96N 1198.51E 0.53 1205.40 273625.11 2388763.86 3126.00 43.10 82.70 2703.30 140.00N 1282.96E 0.29 1290.56 273709.75 2388773.28 3255.00 43.60 83.20 2797.10 150.87N 1370.85E 0.47 1379.10 273797.82 2388782.46 3378.00 43.90 83.80 2885.95 160.50N 1455.35E 0.42 1464.16 273882.50 2388790.46 3504.00 44.30 83.60 2976.44 170.12N 1542.51E 0.34 1551.84 273969.82 2388798.41 3631.00 44.50 83.80 3067.18 179.87N 1630.83E 0.19 1640.70 274058.31 2388806.46 3758.00 41.90 83.90 3159.75 189.18N 1717.26E 2.05 1727.63 274144.89 2388814.11 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Glacier 1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3248.93 Feet on azimuth 83.20 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON olmpanY,CLU-9 Pad #1, Cannery Loop Unit, Cook Inlet, Alaska(lmported} SURVEylTING Page 3 Well bore: CLU-9 Well path: MWD <0-9100> Date Printed: 24-Sep-2004 r&iì. .... INTEQ .,5f1 WellDath (Grid) Re Dort MD[ft] Inc{deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing Iden/100ftl Section1ftl 3884.00 42.10 84.10 3253.38 198.00N 1801.11E 0.19 1811.93 274228.89 2388821.31 4010.00 42.30 84.40 3346.72 206.47N 1885.32E 0.23 1896.56 274313.25 2388828.17 4136.00 42.00 84.00 3440.14 215.02N 1969.44E 0.32 1981.11 274397.51 2388835.10 4263.00 40.60 83.40 3535.55 224.21 N 2052.75E 1.15 2064.92 274480.98 2388842.69 4389.00 39.80 84.10 3631.79 233.07N 2133.59E 0.73 2146.25 274561.98 2388850.00 4515.00 42.00 83.40 3727.02 242.06N 2215.59E 1.78 2228.74 274644.13 2388857.41 4641.00 40.70 82.50 3821.61 252.27N 2298.20E 1.13 2311.97 274726.92 2388866.03 4766.00 40.50 82.50 3916.51 262.88N 2378.86E 0.16 2393.31 274807.76 2388875.10 4893.00 40.30 83.20 4013.23 273.13N 2460.53E 0.39 2475.62 274889.60 2388883.77 5018.00 40.10 83.00 4108.70 282.82N 2540.62E 0.19 2556.30 274969.87 2388891.93 5143.00 40.00 82.80 4204.39 292.76N 2620.44E 0.13 2636.73 275049.86 2388900.33 5206.00 38.70 83.10 4253.10 297.67N 2660.08E 2.09 2676.67 275089.58 2388904.47 5270.00 36.90 83.40 4303.67 302.28N 2699.03E 2.83 2715.89 275128.62 2388908.34 5332.00 35.20 82.90 4353.80 306.63N 2735.26E 2.78 2752.38 275164.92 2388911.99 5394.00 33.30 82.80 4405.05 310.97N 2769.88E 3.07 2787.27 275199.61 2388915.67 5457.00 30.50 83.20 4458.52 315.03N 2802.92E 4.46 2820.56 275232.72 2388919.09 5519.00 27.90 83.60 4512.64 318.51N 2832.96E 4.21 2850.80 275262.83 2388921.99 5581.00 25.80 84.10 4567.95 321.52N 2860.80E 3.41 2878.80 275290.72 2388924.46 5645.00 24.10 85.00 4625.98 324.09N 2887.67E 2.72 2905.79 275317.63 2388926.52 5707.00 22.80 85.70 4682.86 326.09N 2912.26E 2.14 2930.45 275342.26 2388928.05 5770.00 21.30 85.40 4741.25 327.93N 2935.84E 2.39 2954.08 275365.87 2388929.43 5833.00 21.00 86.10 4800.01 329.61 N 2958.51 E 0.62 2976.79 275388.56 2388930.68 5896.00 19.80 86.20 4859.05 331.09N 2980.42E 1.91 2998.73 275410.49 2388931.73 5934.00 19.10 85.70 4894.88 331.98N 2993.04E 1.89 3011.37 275423.13 2388932.38 6023.00 18.20 84.50 4979.21 334.40N 3021.40E 1.10 3039.82 275451.53 2388934.26 6086.00 17.20 85.50 5039.23 336.08N 3040.48E 1.66 3058.96 275470.63 2388935.57 6149.00 15.70 85.10 5099.65 337.54N 3058.26E 2.39 3076.79 275488.44 2388936.69 6211.00 14.00 84.20 5159.57 339.01N 3074.08E 2.77 3092.68 275504.28 2388937.86 6274.00 12.10 81.20 5220.94 340.79N 3088.19E 3.20 3106.90 275518.42 2388939.37 6337.00 10.20 81.60 5282.75 342.62N 3100.23E 3.02 3119.07 275530.50 2388940.96 6402.00 8.40 83.40 5346.90 344.00N 3110.64E 2.80 3129.57 275540.93 2388942.15 6462.00 7.20 83.80 5406.34 344.91 N 3118.74E 2.00 3137.72 275549.04 2388942.90 6526.00 5.30 84.10 5469.96 345.65N 3125.66E 2.97 3144.68 275555.98 2388943.50 6589.00 3.60 81.60 5532.76 346.24N 3130.51E 2.72 3149.57 275560.84 2388944.00 6652.00 2.90 78.10 5595.66 346.86N 3134.03E 1.15 3153.13 275564.37 2388944.55 6715.00 2.90 76.60 5658.58 347.55N 3137.14E 0.12 3156.30 275567.49 2388945.19 6779.00 2.90 77.20 5722.50 348.29N 3140.29E 0.05 3159.52 275570.66 2388945.86 6842.00 3.20 76.50 5785.41 349.05N 3143.56E 0.48 3162.85 275573.94 2388946.56 6905.00 3.00 78.10 5848.32 349.80N 3146.88E 0.35 3166.24 275577.27 2388947.25 6968.00 3.20 74.90 5911.23 350.60N 3150.19E 0.42 3169.62 275580.60 2388947.98 7031.00 3.30 75.50 5974.12 351.51N . 3153.64E 0.17 3173.15 275584.07 2388948.83 7094.00 3.30 73.10 6037.02 352.49N 3157.14E 0.22 3176.73 275587.58 2388949.74 7157.00 3.10 73.10 6099.92 353.51N 3160.50E . . 0.32 3180.19 275590.96 2388950.70 7284.00 2.90 68.70 6226.75 355.68N 3166.78E 0.24 3186.68 275597.28 2388952.74 7410.00 2.80 65.30 6352.59 358.12N 3172.54E 0.16 3192.68 275603.09 2388955.08 7536.00 2.80 65.90 6478.44 360.67N 3178.15E 0.02 3198.54 275608.74 2388957.51 7663.00 2.20 67.90 6605.32 362.85N 3183.24E 0.48 3203.85 275613.88 2388959.60 7789.00 2.10 67.10 6731.23 364.66N 3187.61E 0.08 3208.40 275618.28 2388961.32 7914.00 2.30 63.70 6856.14 366.66N 3191.97E 0.19 3212.96 275622.67 2388963.24 8041.00 2.10 60.60 6983.05 368.93N 3196.28E 0.18 3217.50 275627.03 2388965.43 8165.00 2.10 61.60 7106.96 371.13N 3200.26E 0.03 3221.70 275631.05 2388967.54 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Glacier 1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3248.93 Feet on azimuth 83.20 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON o.mpanY,CLU-9 Pad #1, Cannery Loop Unit,Cook Inlet, Alaska(lmported) SURVEVeTING Page 4 Wellbore: CLU-9 Well path: MWD <0-9100> Date Printed: 24-Sep-2004 mi. ..,. INTEQ WellDath (Grid) Re )ort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing Idea/100ftl Sectionlftl 8290.00 2.00 66.00 7231.88 373.11N 3204.26E 0.15 3225.91 275635.09 2388969.44 8417.00 1.80 60.70 7358.81 374.98N 3208.03E 0.21 3229.86 275638.89 2388971.25 8542.00 1.90 65.10 7483.75 376.82N 3211.62E 0.14 3233.64 275642.52 2388973.01 8667.00 1.70 63.10 7608.69 378.53N 3215.15E 0.17 3237.35 275646.08 2388974.66 8792.00 1.70 61.70 7733.63 380.25N 3218.44E 0.03 3240.81 275649.40 2388976.31 8918.00 1.60 59.20 7859.58 382.03N 3221.59E 0.10 3244.15 275652.59 2388978.04 9050.00 1.70 56.90 7991.52 384.04N 3224.82E 0.09 3247.58 275655.85 2388979.99 9100.00 1.70 56.90 8041.50 384.85N 3226.06E 0.00 3248.91 275657.11 2388980.77 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Glacier 1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3248.93 Feet on azimuth 83.20 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON olmpanY,CLU-9 Pad #1, Cannery Loop Unit,Cook Inlet, Alaska(lmported) SURVEY tTING Page 5 Wellbore: CLU-9 Wellpath: MWD <0-9100> Date Printed: 24-8ep-2004 '.i. ..,. INTEQ Comments Comment Pro'ection to TO Hole Sections Diameter Start Start Start Start End End End Start Wellbore rin1 Morftl TVorftl Northrftl Eastrftl Morftl TVorftl Northrftl Eastfftl 16.000 130.00 130.00 0.57N 0.25W 2063.00 1909.99 58.10N 580.32E CLU-9 121/4 2063.00 1909.99 58.10N 580.32E 5994.00 4951.68 333.56N 3012.31E CLU-9 81/2 5994.00 4951.68 333.56N 3012.31E 9100.00 8041.50 384.85N 3226.06E CLU-9 Casinos Name Top Top Top Top Shoe Shoe Shoe Shoe Wellbore Morftl TVorftl Northrftl Eastrftl MOfftl TVOfftl Northrftl Eastrftl 20" Conductor 0.00 0.00 O.OON O.OOE 130.00 130.00 0.57N 0.25W CLU-9 13 3/8" Casinn 0.00 0.00 O.OON O.OOE 2053.00 1902.54 57.35N 573.69E CLU-9 3 1/2" Liner 0.00 0.00 O.OON O.OOE 9100.00 8041.50 384.85N 3226.06E CLU-9 All data is in Feet unless otherwise stated Coordinates are from Slot MO's are from Rig and TVO's are from Rig ( Glacier 1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3248.93 Feet on azimuth 83.20 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated CLU #9 API: 50-133-2054400 RT-GL: 21.00' RT-THF: 21.70' 204' FSL, 547' FEL, Soo. 7 , T5N, R11W, S.M. Tree cxn = 4-3/4" Otis - Ceramic flapper valves below each module as follows: Flappers MD (RKS): Module 1 - NA Module 2 - 8635' Module 3 - 8534' Module 4 - 8418' Module 5 - 8184' Module 6 - 8126' Module 7 - 7827' Module 8 - 7754' Module 9 - 7693' Module 10 -7523' Module 11 - 7283' Module 12 - 7040' Module 13 - 6752' Module 14 - 6651' Module 15- 6345' module 16 - 6303' Well Name & Number: County or Parish: Perforations (MD) BHT: 11/3/2004 J. R. Thompson Prod. Tubing: ,9.3 with 6.25" OD control line Cmt wI 1392 sx of class G at Excape System Details - 16 Excape modules placed - Green control line fires bottom 1 modules - Red contolline fires middle 7 modules - Yellow line for fires top 8 modules - Ceramic flapper valves below each module except for module 1 Perfs MD(RKS): Module 1· - 8720-8730' Module 2 , 8622-8632' Module 3 - 8520-8530' Module 4 - 8404"8414' Module 5 - 8170-8180' Module 6 - 8112-8122' Module 7 -7814-7824' Module 8 - 7740-7750' Module 9 - 7680-7690' Module 10 - 7510-7520' Module 11 - 7270-7280' Module 12 - 7026-7036' Module 13 - 6740,6750' Module 14 - 6638-6648' Module 15 -6332-6342' module 16 - 6290-6300' Can Alaska (TVD) . . MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg, ~f al J P. I. Supervisor ~1{JZJJ òk DATE: September 9,2004 THRU: FROM: Lou Grimaldi, Petroleum Inspector SUBJECT: Surface Casing Cement Job CLU #9 P"I Cähh Monday. September 9. 2004; I witnessed the cementing "Top Job" on Marathon's Cannery Loop well CLU #9. I arrived to witness the 1" CS Hydril pipe to be run between the conductor and surface pipe. All the pipe available on location was run to 157' (RKB) without tagging cement. The wash pipe was pulled up 30' and hung off. More pipe was ordered and we stood by. During this time we noticed that the fluid level in the in the Diverter stack rose from the Conductor drain to just below the flow line, indicating influx of what appeared to be fresh water. This level remained constant for 1-2 hours then started to recede. After approximately 3 hours the additional wash pipe arrived and the pipe hung in the derrick was run back down to the original level and tagged up at 155' (RKB). This was 2' higher than reached before. Many attempts were made at getting lower with no success. The wash pipe was sticking on bottom somewhat and I felt satisfied that top of cement had been reached. Class G cement was pumped in the 15 ppg weight. No returns were observed for approximately 20 bbl's and then slow return's came back gradually increasing until all the cement (47 bbl's) were pumped. I left location at this time. Attachments: NON-CONFIDENTIAL Surf Casing Cement Top Job CLU 9 09-06-04 LG.doc Top job on CLU#9 We will require a top job on CLU#9 13 3/8" surface pipe. We got 30bbls of 40bbls spacer to surface with no trace of cement. We had 100% returns during the job. I estimate cement to be 40' below ground level. Please let me know if a witness will be present. If you need to contact me I am at 907-283-1312. Rowland Lawson 1 of 1 9/7/2004 8:55 AM . ~1f~1fŒ (ill~ !Æ~~~ . A.lfA.~1iA. OIL AlO) GAS CONSERVATION COMMISSION FRANK H. MURKOWSKI, GOVERNOR 333 W. 7'" AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 27!H 433 FAX (907) 276-7542 Willard Tank Advanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, Texas 77253 Re: Cannery Loop CLU #9 Marathon Oil Company Permit No: 204-161 Surface Location: 204' FSL, 547' FEL, SEC. 7, T5N, R11 W, S.M. Bottomhole Location: 568' FSL, 2,607' FWL, SEC 8, T5N, R11 W, S.M. Dear Mr. Tank: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. 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 07 (pager). S' c BY ORDER OF THE ~~~ION DATED thisL day O~¡43004 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. . . Worldwide Drilling North America Marathon Oil Company P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 August 20, 2004 John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Cannery Loop Well: Cannery Loop Unit - CLU 9 Dear Mr. Norman Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is to drill a Beluga development well in the Cannery Loop Unit. No completion is desired in either the Sterling or Tyonek pools. Please note that Marathon is requesting a waiver for 20 ACC 25.035 (e) (1) (b) requiring a two pipe ram stack. The request is specified on page 12 of the attached drilling prognosis. / If you require further information, I can be reached at 713-296-3273 or bye-mail at wjtank@marathonoil.com. "ZIP ~ - f~(.)¡f Sinperely, )y~}~ Willard J. Tank Advanced Senior Drilling Engineer Enclosures RECEIVED AUG 2 3-2004 Ataska Oil & Gas Cons. Commission Anchorage '. '~~_:1.:::":^f--::""":'::, ..",:;-:::::;0:':'; .< G\NAL 1a. Type of Work: Drill l.::d Redrill 0 1b. Current Well Class: Exploratory 0 Development Oil ).:JI1IZÞO~t:one 0 Re-entry 0 Stratigraphic Test 0 Service 0 Development Gas 0 Single Zone 0 2. Operator Name: 5. Bond: Blanket 0 Single Well 0 11. Well Nam~d Number: Marathon Oil Company Bond No. 5194234 CLU #9 3. Address: 6. Proposed DHpth: 12. Field/Pool(s): / P.O. Box 3128, Houston, TX 77253 MD: 9,088 TVD: 8,042 Cannery Loop Unit / Beluga 4a. Location of Well (Governmental Section): / 7. Property Designation: Surface: 204'FSL,547'FEL,Sec.7,T5N,R11VV,S.M. ADL 02397 Top of Productive Horizon: / 8. Land Use Permit: 13. Approximate Spud Date: 568' FSL, 2,607' FWL, Sec. 8, T5N, R11W, S.M. September 3, 2004 ./ Total Depth: 9. Acres in Property: 14. Distance to Nearest 568' FSL, 2,607' FWL, Sec. 8, T5N, R11W, S.M. 136 Property: 100ft (AA19230) 4b. Location of Well (State Base Plane Coordinates): 10. KB Elevation 15. Distance to Nearest Well Surface: x - 272,424.393 Y - 2,388,657.944 Zone- 4 (Height above GL): (21' AGL) 42 feet Within Pool: 1,500 ft. to CLU #5 16. Deviated wells: Kickoff depth: 350 feet 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 42.34 degrees Downhole: 3,i'64 Surface: 1,946 / 18. Casing Program: Specifications Setting Depth Quantity of Cement Size Top Bottom c.f.orsacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 133 K-55 PE 109' 0' 0' 130' 130' 16" 133/8" 68 L-80 BTC 2,029' 0' 0' 2,050' 1,898' 554 sacks /' 12 1/4" 95/8" 40 L-80 BTC 5,955' 0' 0' 5,976' 4,945' 384 sacks / 81/2" 3 1/2" 9.3 L-80 EUE 9,067' 0' 0' 9,088' 8,042' .Aeorsacks / 1"378.tG-ff WG/t 19. PRESENT WELL CONDITION SUMMARY (To be completed for Bedrill and Re-Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee l.::d BOP Sketch l.::d Drilling Program ~I Time v. Depth Plot U Shallow Hazard Analysis U Property Plat 0 Diverter Sketch 0 Seabed Report 0 Drilling Fluid Program 0 20 AAC 25.050 requirements 0 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Willard J. Tank Title Advanced Senior Drilling Engineer Signature A¿ I.IM" ~ j /2. )., Phone 71 :::-296-3273 Date August 20, 2004 / '\(,h p Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: ZG" $/- /6-/ 50- /33 -.20.5' '-/"/ Date: requirements. Co",,"on, of ",p~al . ;¡;fj, ør"" Yes 0 NO~ Mud log required Yes 0 No ~ , Hydr ge su . e measures , Yes 0 No Dimctional survey required Yes;i?J No 0 Otha, Testryp £¡;¿,' 500 />1t. APPROVED BY 1~ !tV,/' Approved by: I - A fA. THE COMMISSION Date: For~evis4 06/2004 - OR'G\~JAL I I , Submit inDuplicate yJ61t'- a STATE OF ALASKA . AL~ OIL AND GAS CONSERVATION COM ."'SION PERMIT TO DRILL 20 AAC 25.005 fI2~fËe'eIVED AUG 2 a '20ó4 Alaska Oil & Gas Cons. Commission . . MARATHON MARATHON Oil COMPANY DRilliNG PROGRAM Cannery loop Unit ClU #9 Original 8/20/04 Originator: Drilling Superintendent: North America Drilling Manager: W.J. Tank ~J- P.K. Beraa B.J. Rov Page 1 of 14 . . Table of Contents General Well Data..................................................................................................................................... .............................. 3 Geologic Program Summary................................................................................................................................................... 3 Summary of Potential Drilling Hazards....................................................................................................................................4 Formation Evaluation Summary.............................................................................................................................................. 4 Drilling Program Summary........................................................... ........................................................................................... 5 Casing Program....................................................................................................................... ................................................6 Casing Design ........................................................................ .................................................................. ...............................6 Maximum Anticipated Surface Pressure................................................................................................................................. 6 BOPE Program ........................................................................................................................................................................8 Wellhead Equipment Summary .................................... .......................................................................................................... 9 Directional Program Summary................................................................................................................................................ 9 Directional Surveying Summary............................................................................................................................................ 1 0 Drilling Fluid Program Summary ........................................................................................................................................... 1 0 Drilling Fluid Specifications.................................................................................................................................................... 11 Solids Control Equipment...................................................................................................................................................... 11 Cement Program Summary................................................................................................................................................... 12 Regulatory Waivers and Special Procedures.................................................................................................................. ......12 Bit Summary.......................................................................................................................................................................... 13 Hydraulics Summary............................................................................................................................................................. 13 Formation Integrity Test Procedure....................................................................................................................................... 14 Page 2 of 14 . . General Well Data Well Name CLU #9 Lease/License Surface Location 204' FSL, 547' FEL, Sec. 7, T5N, R11W, S.M. WBS Code DD.04.10614.CAP.DRL Slot/Pad CLU Pad 1 Field Cannery Loop Unit Spud Date 9/3/04 (est.) KB Elev. 42 County/Province Kenai Peninsula API No. Ground Level Elev. 21 State I Country Alaska Well Class Development Perm. Datum KB Total MD 9,088' Rig Contractor Glacier Drilling / Water Depth N/A Total TVD 8,042' Rig Name #1 Water Protection Depth Comments: Geoloaic Proaram Summary MD - RKB TVD - RKB Pore Pressure Pore Pressure Possible Fluid Formation (ft) (ft) (psi) (ppg) Lithology Content Sterling B-2 (Not a Prod Target) 5,323 4,352 8.60 Sandstone Gas 1 Water Sterling C-1 (Not a Prod Target) 5,978 4,947 6.73 Sandstone Gas 1 Water Upper Beluga (Secondary Target) 6,176 5,137 4.04 Sandstone Gas Middle Beluga (Primary Target) 6,878 5,832 8.85 Sandstone Gas Lower Beluga (Secondary Target) 7,598 6,552 8.85 Sandstone Gas Tyonek (Not a Prod Target) 8,818 7,772 9.00 Coal, Silt, Shale Gas Comments: Surface Location Coordinates From Lease/Block Lines 204' FSL, 547' FEL, Sec. 7, T5N, R11W, S.M. Latitude 60031' 56.155" N Longitude 151015' 48.901" W UTM North (Y) 2,388,657.944' UTM East (x) 272,424.393' Tolerance Depth Horizontal Displacement (ft) MD TVD +N/-S +EI-W Tolerance Directional Target (ft) (ft) Location (Y) (X) (ft) Middle Beluga 6,878 5,832 568' FSL, 2,607' FWL, Sec. 8, T5N, R11W, S.M. 364 3,154 Circle 250' radius Comments: Page 3 of 14 . . Summary of Potential Drillina Hazards Hazard Event Lost Circulation in Low Pressure Sterling and Beluga sands Discussion Control losses by using sufficiently sized LCM. Comments: Potential Hazards Statement 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 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 +/- 5,323' MD (4,352' TVD) to total depth of the well. These sands will run from highly depleted to slightly above normal pressure. Lost circulation and differential sticking are potential hazards in some of the Sterling and Beluga sands. The Flo-Pro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. Weighting material will available on location for proper well control.. Formation Evaluation Summary Interval LWD Electric Logs Mud Logs Surface None None None 0' - 2,050' MD Intermediate None None Basic with GCA, shale density, temperature in and out, 2,050' - 5,976' MD sample collection (10' samples). Production None Reeves Quad Combo & MDT. Pull GR- Basic with GCA, shale density, temperature in and out, 5,976' - 9,088' MD Neutron to surface inside casing. sample collection (10' samples). Completion N/A GR, CCL N/A Coring Requirements: None Comments: Page 4 of 14 . . Drillina Proaram Summary CONDUCTOR: 1. Drive 20" conductor to +1-100 ft. RKB. 2. Move in and rig up rotary drilling rig. 3. Install starting head 20" SLC x 21 1/4", 2M flanged. 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. / 5. Function test diverter and diverter valve. SURFACE: 1. Drill a 16" hole to 2,050' MD (1,898' TVD) per the directional plan. 2. RIH with 13 3/8" casing and hang off in the elevators. Make up stab-in sub and centralizer on 5" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 133/8" casing. Sting out, shear out drill pipe wiper plug, and circulate drill pipe clean. TOOH with inner string. 3. Cut off 133/8" casing. ND diverter. / 4. Install 13 3/8" slip lock connection X 13 5/8" 5M flanged multibow,l.wetlne d. 5. NU 135/8" 5M BOP'S. Test BOP'S and choke manifold to 2~2,50 si. 6. Set wear bushing.' 7. Test surface casing to 2,500 psi. INTERMEDIATE: 1. Drill out float equipment and make 20' of new hole. CBU. 2. Test shoe to leak off. Estimated;; is 14.7 ppg. 3. Drill 12 1/4" directional hole t ,9 MD (4,945' TVD) as per directional program, short tripping every 1,000' or 24 hours. 4. At TD circulate hole clean. a e wiper trip. TOOH. / 5. Change out variable pipe rams with 9 5/8" casing rams. Run test plug and test casing rams to 2,500 psi. 6. Run and cement 9 5/8" casing. Land hanger in multibowl wellhead. 7. Back out landing joint. Change out 95/8" casing rams with variable pipe rams. Run test plug and test pipe rams to 250/2,500 psi. 8. Set wear bushing. Test casing to 2,500 psi. PRODUCTION: 1. Drill float equipment and 20' of new formation w/8 1/2" bit. CBU. 2. Test shoe to leak off '(i' ated EMW 13.0 ppg. 3. Drill a 81/2" hole to ,08 MD (8,042' TVD) per the directional program, short tripping every 1,000' or 24 hours. 4. At TD circulate hole n. Make wiper trip. TOOH. 5. RU logging company. Run open hole logs as per plan. RD logging company. 6. TIH w/8 1/2" bit to TD for wiper trip. TOOH to 9 5/8" shoe and circulate until log evaluation is complete for picking EXCAPE modules. After picks are made, trip to TD and circulate clean. TOOH and laydown BHA and drill pipe. Pull wear bushing. / 7. RU and run 31/2" EXCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. RD logging company. 8. Cement 3 1/2" casing while reciprocating. Bump plug with 500 psi over displacement pressure. WOC. 9. PU 3 1/2" casing. PU BOP stack. Run control and electric lines out tubing head outlet. Set slips. Cut 31/2" casing. 10. LD BOP. Set 31/2" packoff. NU 135/8" 5M X 31/8" 5M tubing head adapter and 31/8" 5M tree. Test tree to 5,000 psi. 11. Rig down and move out drilling rig. Note: Drill all hole sections with 5" drill pipe. Perforating guns will be run on the outside of the 3 1/2" production casing with a /' flapper valve just below each perforating gun. Guns to be activated by control line to surface. COMPLETION: Completion will be done without a rig. Page 5 of 14 . . Casina Proaram MD (ft) Connection API Ratings / Q) .§ ¡ Casing / Makeup Tñ::- ~= Hole Size 3 ~ .!!! ~ Size Weight a.D. Torque m...... õ...... ~ :52 (in) Top Bottom (lbsIft) Grade Type (in) (ft-Ibs ) (in) 0 -...... 13 3/8 Surface 2,050 68 L-80 BTC 14.375 N/A· 16 5,020 2,260 1,545 95/8 Surface 5,976 40 L-80 BTC 10.625 N/A· 12 1/4 5,750 3,090 979 31/2 Surface 9,088 9.3 L-BO 8rd 4.5 3,200 81/2 10,160 10,530 207 Comments: · The make up of the buttress connection will be to the proper mark. Casina Desian Casing Shoe Safety Factors Q) .§ Casing Setting Mud Wt Frac. Form Maximum Surface i Size Weight Depth When Set Grad Pressure ~ '" Press ;:¡ 8 ~ (in) (lbItt) Grade (TVD) (lblgaI) (Iblgal) (Iblga!) (psi) m 13 3/8 68 L-80 1,898 9.0 14.7 8.6 644 3.15 1.92 4.17 95/8 40 L-80 4,945 9.5 13.0 6.7 1,946 1.61 1.15 2.59 31/2 9.3 L-80 8,042 10.0 15.0 9.0 1,946 1.15 2.00 1.60 ~, ç Comments: Maximum Anticipated Suñace Pressure Setting Depth Casing Size TVD MAWp· MASP .. Mud/Gas (in) (ft) (psi) (psi) Ratio 13 3/8 1,898 3,445 644 30/70 95/8 4,945 3,896 1,946 30/70 31/2 8,042 6,903 1,946 / 30/70 · MAWP = Maximum allowable working pressure ** MASP = Maximum anticipated surface pressure Comments: MASP I MAWP CALCULATIONS: Surface casino: 133/8" (2.050' MD. 1.898' TVD) MASPfrac = «Fracture gradient at shoe + S.F.) x .052 x TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (14.7 ppg + 0.5 ppg) x .052 X 1,898' - (.1 psi/ft x 1,898') MASPfrac = 1,500 psi - 190 psi MASPfrac = 1,310 psi. Page 6 of 14 . . MASPbhP = BHP open hole td - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (6.7 ppg x .052 x 4,945') - (0.3 x 9.5 ppg x .052 X 4,945') - (0.7 x 0.1 psi/ft x 4,945') MASPbhp = 1,723 psi - 733 psi - 346 psi MASPbhp = 644 psi MASP = MASPbhp = 644 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. - Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,020) - (9.0 - 8.3) x .052 x 1,898' MAWP = 3,514 psi - 69 psi = 3,445 psi Intermediate casino: 9 5/8" (5.976' MD. 4.945' TVD) MASPfrac = ((Fracture gradient at shoe + S.F.) x .052 x TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (13.0 ppg + 0.5 ppg) x .052 X 4,945' - (.1 psi/ft x 4,945') MASPfrac = 3,471 psi - 495 psi MASPfrac = 2,976 psi. MASPbhP = BHP open hole td - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (9.0 ppg x .052 x 8,042') - (0.3 x 10.0 ppg x .052 x 8,042') - (0.7 x 0.1 psi/ft x 8,042') MASPbhP = 3,764 psi -1,255 psi - 563 psi MASPbhp = 1,946 psi / MASP = MASPbhp = 1,946 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. - Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,750) - (9.5 - 9.0) x .052 x 4,945' MAWP = 4,025 psi - 129 psi = 3,896 psi Production casino: 3 1/2" (9.088' MD. 8.042' TVD) MASPfrac = (Fracture gradient at shoe + S.F.) x .052 x TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 X 8,042' - (.1 psi/ft x 8,042') MASPfrac = 6,482 psi - 804 psi MASPfrac = 5,678 psi. MASPbhp = BHP open hole td - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhp = (9.0 ppg x .052 x 8,042') - (0.3 x 10.0 ppg x .052 X 8,042') - (0.7 x 0.1 psVft x 8,042') MASPbhp = 3,764 psi - 1,255 psi - 563 psi MASPbhp = 1,946 psi MASP = MASPbhp = 1,946 psi I MAWP = (0.7 x Casing Burst) - (Mud Wt. - Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 10,160) - (10.0 - 9.5) x .052 x 8,042' MAWP = 7,112 psi - 209 psi = 6,903 psi Page 7 of 14 . . BOPE Proaram Casing Test Test Casing Test Fluid Pressure Size MAWP MASP Press Density BOPS LowlHigh Casing (in) (psi) (psi) (psi) (Iblgal) Size & Rating (psi) (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Surface 13 3/8 3,445 644 2,500 9.0 (1) 135/8" 5M blind ram 250/2,500 (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Intermediate 95/8 3,896 1,946 2,500 9.5 (1) 135/8" 5M blind ram 250/2,500 (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Production 31/2 6,903 1,946 2,500 10.0 (1) 13 5/8" 5M blind ram 250/2,500 (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets /' ~ ,/ Comments: 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 and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-118" x 5000 psi outlets. 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 mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. Casing Test Pressures Casing test pressures are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. Page 8 of 14 . . Wellhead EauiDment Summary Component Description Casing Hanger Type Casing Head 13-5/8" 3M X 13-3/8" Slip Lac W/2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL 1, 135/8" x 9 5/8" Fluted PR1 Mandrel Tubing Head 13-5/8" 3M Studded Bottom X 13-5/8" 5M Fig Top, WI 2,2-1/16" 5M Studded Outlets, 135/8" x 31/2" Manual U,AA,PSL 1 ,PR1 Slip Adapter Flange 13-5/8" 5M X 3-1/8" 5M WI Seal Pocket and 3" H BPV Threads Comments: Control lines and electric cable for the EXCAPE system will be routed through the tubing head side outlet. Directional Proaram Summary Build Tum Coordinates Sec. MD TVD Rate Rate Dogleg Inclination Azimuth +N/-S +E/-W VS No. Description (ft) (ft) (°/100') (°/100') (°/100') (deg) (deg) (ft) (ft) (ft) 1 Tie On 0 0 0 0 0 0 0 0 0 0 2 KOP 350.00 350.00 0 0 0 0 0 0 0 0 3 Build up Section 2.50 0 2.50 83.42 4 End of Build 2,043.41 1,893.47 2.50 0 2.50 42.34 83.42 68.46 593.74 597.67 5 Hold Section 0 0 0 42.34 83.42 6 End of Hold 4,761.40 3,902.66 0 0 0 42.34 83.42 278.13 2,412.17 2,428.15 7 Drop Section -2.00 0 2.00 83.42 8 End of Drop to the 6,878.16 5,832.00 -2.00 0 2.00 0.00 83.42 363.70 3,154.34 3,175.24 Target 9 TD 9,088.16 8,042.00 0 0 0 0.00 83.42 363.70 3,154.34 3,175.24 Comments: Vertical section calculated from a reference azimuth of 83.42° taken from surface location to bottom hole location. Potential Well Interference: Well CLU #1 or CLU #1 RD CLU #8 CLU #6 CLU #5 Distance (ft) 52.96 60.53 60.95 170.03 Depth (MD) 1,257 o 1,288 1,835 No serious interference exists. See attached directional plan and anticollision analysis for more details. Page 9 of 14 ----- --~-- 200 100 200 C 100 ~ 300 C 0 ~ 0 0 U) 0 ~ 0 J:: 400 ~ 15. +' Q) :;:: CJ t ~ 0 'E 500 ~ Q) :;:: > Q) :; 2 600 0 l- (/) 700 800 -2000 -1000 0 1000 2000 3000 4000 5000 6000 0 Vertical Section at 83.42° [2500ftlin] Directional Survevina Summary 1000 2000 3000 o - 2,050' 2,050' 5,976' 5,976' - 9,088' x x x Comments: Drillina Fluid Proaram Summary 0 1,898 8.6 - 9.4 1,898 4,945 9.0 - 9.5 4,945 8,042 9.0 Comments: Gel! Gelex Spud Mud 6% Flo-Pro wI Safecarb 6% Flo-Pro wI Safecarb Gel, Gelex, Soda Ash, Caustic, Barite, Polypac Supreme UL Flo-Vis, PoluPac UL, KCI, SafeCarb F&M, Barite, Lubetex, Caustic, Conqor 404, Sodium Meta Bisulfate Flo-Vis, PoluPac UL, KCI, SafeCarb F&M, Barite, Lubetex, Caustic, Conqor 404, Sodium Meta Bisulfate See mud prognosis for details. The mud system from the intermediate section will be utilized in the production hole section instead of building a new mud for that section. Sized CaC03 (SafeCarb) will be used to controlleakoff. Page 10 of 14 . . Drillina Fluid Specifications Interval - TVD lSRV From To Density Vis 1 min PV YP Fluid loss Drill Solids (ft) (ft) (Iblgal) (seclqt) (lbJ1001f) (oP) (lbl100 If) (00) pH (%) 0 1,898 8.6 - 9.4 60 - 100 N/A 25 - 35 NC - 12 +/- 9.5 <7 1,898 4,945 9.0 - ~\ 30,000 8 - 12 7-9 +/- 9.5 +/- 5 4,945 8,042 9.0(-'10.0) 30,000 10 - 14 6-8 +1- 9.5 +/- 5 ''C/ Comments: As a standard practice for long string completions, the drilling mud that will remain above the top of cement on the 3 W' production casing will be treated with corrosion inhibitor (Conqor 303A) at a concentration of 1 drum per 100 barrels of drilling fluid. See mud prognosis for details. Solids Control Eauipment § ~ Qj ~ ~ III Qj c: & a :š' .c III f6 "0 ~ Q) ~ f/) f/) Qj õ OJ OJ is c: c: c: ::.: m III ~ "0 ë = = ~ .c Q) ::) ~ ::) ::) Interval en a :::ï: 0 0 N Comments o - 9,088' MD X X X X Closed loop System, Full Containment Equipment Specifications Item (quantity, design type, brand, model, flow capacity, ete) . Shaker 2 - Derrick ModeI2E48-90F-3TA De$8J1der N/A Desilter , 1 - Derrick Model 0522 Mud Cleaner N/A Centrifuge 2 - MI/Swaco units Cuttings Dryer N/A Cuttings Injection Marathon G&I Facility Zero Discharge N/A Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water 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. Page 11 of 14 . . Cement Proaram Summary Depth Gauge Top of Cement .Open Casing Hole Ann Vol Slurry WOC HoIé Size MD TVD Size MD TVD ToTOC Vol Time Excess (in) (ft) (ft) (In) (ft) (ft) (If) (ftS¡ (hrs ) (%) 13 3/8 2,050 1,898 16 0 0 914 1,391 8 50 95/8 5,976 4,945 121/4 4,800 3,931 368 587 8 50 31/2 9,088 8,042 81/2 5,400 4,419 355 465 N/A 35 Mix Watér Compressive Casing Slurry TOC Strength Size Density Oty Yield Vol MD Oty WL FW (IJ Ii) (in) Slurry Cement Description (Iblgal) (sx) (lf/sx) (If) (ft) (gaVsx) Typé (00) (%) 8hr 24hr 133/8 Tail Type I Cement 12.0 554 2.51 1,391 0 11.28 Fresh 812 0 500 Lead Class "G" 12.5 151 2.10 317 4,800 11.97 Fresh 95/8 Tail Class "G" 15.8 233 1.16 270 5,476 4.97 Fresh 31/2 Tail Class "G" 15.8 ~ 1.15 465 5,400 4.92 Fresh ~µ4A- Comments: i')1K See cement prognosis for details and spacer specifications. Reaulatorv Waivers and Special Procedures AOGCC Regulation 20 ACC 25.035 (e) (1) (b) Requirement for 2 pipe rams, one blind ram, and one annular for a API 5K or above BOP stack. Marathon is requesting a waiver from the above regulation for CLU #9. We are requesting that the BOP stack be configured with one pipe ram instead of two, due to rig height restrictions in the running of the 31/2" production casing. The height restriction involves having rig crew members routing control line and electrical line through one of the tubing head outlets after the 31/2" casing is cemented and the BOP stack is picked up. This is prior to setting the casing on slips and cutting the casing sticking up. These lines control firing of the perforating guns and the monitoring of downhole pressure and temperature in our EXCAPE completion system. Similar waivers have been requested for EXCAPE completion wells in the Kenai Gas Field and the Cannery Loop Unit itself and were granted. No problems were encountered while doing this operation on any of the wells. Also due to MASP below 2,000 psi, only a 3,000 psi BOP stack would be required for this work if it was economic to change out BOP stacks for this well. If a 3,000 psi BOP stack was used then no waiver would be necessary. Utilizing the 13 5/8" 5M stack currently found on the Glacier Drilling #1 rig is more than sufficient for pressures to be encountered. No ~oJ.\Ie-fŸ\fæ~rC/f{.. b-e V ~ :J,;VC1 L... S ()O f<:""):' ~((J Wl ~~;J ve"; ~ Y( d Þ-1 ) k ~to ßDPE f)ìAI~ ~ ßOP LoMe lS.O")S(e.\ Page 12 of 14 . . Bit Summary Interval - MD Type Recommended Estimated From To Size woe Rotating ROP (ft) (ft) (in) Manufacturer Model No. IADC (kips) RPM Hours (ftIhr) 0 2,050 16 Christensen MX-1 115 1 - 4 80 - 350 2,050 5,976 12 1/4 Christensen HCM-406 M333 Up to 50 Motor 5,976 9,088 81/2 Christensen HCM605 M323 Up to 25 Motor Comments: If a second bit is necessary for the 12 1j.¡" hole a MX-C3 (IADC 137) should be used to finish this section. Back up bits for the 8 W' hole section will consist of mill tooth and TCI tricone bits. See bit prognosis for additional information. Hvdraulics Summary Rig mud pumps available are shown below. Max Press @ Displacement @ Uner ID Stroke 90% WP 95% eff Max Rate Hole Sections Used Qty Make Model (in) (in) (psi) (gal/stroke) (spmlgpm) On 5 8 2,597 2.04 125/255 Surface 3 National Oil Well A600PT 5 8 2,597 2.04 125/255 Intermediate 5 8 2,597 2.04 125/255 Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Hole Standpipe Min Nozzle Depth-MD Size Pump Rate Pressure AV ECD Size (ft) (in) (gpm) (psi) (fpm) (lblgaI) (32"s) Remarks o - 2,050 16 3 - 18'5 Actual Data from CLU 8 (@ 1,821' MD) 662 1,700 70 1 - 15 2,050 - 5,976 12 1/4 662 2,000 130 6 - 13's Actual Data from CLU 8 (@ 6,722' MD) 5,976 - 9,088 81/2 376 2,300 195 5 - 15's Actual Data from CLU 8 (@ 9,777' MD) Comments: See separate hydraulics calculations. Annular velocities in the 16", 12 1j.¡", and 8 W' holes were calculated using 5" drillpipe. 5" drillpipe should be used to drill all hole sections to maximize hole cleaning, while minimizing stand pipe pressure. Page 13 of 14 . . / Formation Intearitv Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Page 14 of 14 . 121 1/4" 2M Diverter I ~ I Diverter Spool . Marathon Oil Well CLU #9 Diverter I Flow line "" / 116" Automatic ~I = ~ \ ~ 116" Diverter Line I Knife Valve / . . Marathon Oil Well CLU #9 BOP Stack I Flow Nipple I -------. I Flow Line I 13 5/8" 5M Annular Preventer / . 13 5/8" 5M Double Ram Preventer I Pipe Ram I / -----. I Blind Ram I / 3 1/8" 5M Manually Operated Valve ŒillJ I Choke I 113 5/8" 5M Cross Î 3 1/8" 5M Hydraulically Operated Valve 135/8" 5M x 13 5/8" 5M Drilling Spool ~ Bottom of mud cross must be 24-45" from ground level for Glacier 1 rig placement. ~ 13 5/8" 5M Tubing Head Flange . . Marathon Oil Well CLU #9 Choke Manifold ITa Gas Buster ITa Blooey Line I Bleed off Line to Shakers ~ ~ ~ I~P ~ q~1 C ~ ~ ~ t 13" 5M Valves i 2 9/16" 10M Swaco Hydraulically Operated Choke 31/8" 5M Manually Adjustable Choke . . Surface Use Plan for Cannery Loop Unit, well CLU #9 Surface location: 204' FSL, 547' FEL, Sec. 7, T5N, R11W, S.M. 1) Existing Roads Existing roads which will be used for access to CLU #9 are 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 CLU #9. 3) Location of existing wells Well CLU #9 will be drilled on Cannery Loop Unit pad 1. A pad drawing is enclosed that shows existing wells. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the CLU pad 1 are shown on the enclosed pad drawing. These facilities will be upgraded to handle the additional gas production. 5) Location of Water Supply A water supply well exists on the pad that CLU #9 will be drilled from. This is shown on the pad drawing. 6) Construction Materials No construction is planned on the pad. 7) Methods 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 24-7, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176). 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 vendors that provided them. Efforts will be . . made to minimize the use of all chemicals. e) Sewage The existing sewer system on the pad will be utilized. 8) 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. The camp will utilize the existing sewer system. 9) Plans for reclamation of the surface CLU #9 will be drilled on an existing pad. Reclamation of the pad will occur after the abandonment of CLU #9 and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from the U.S. Fish and Wildlife Service prior to any reclamation work beginning. 10) Surface ownership The surface owner of the land in the Cannery Loop Unit is Marathon Oil Company. 11) Operator's Representative and Certification I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that I 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: ZJZO/ð{ #JkvI »~ Willard J. Tank, Advanced Senior Drilling Engineer Marathon Oil Company P. O. Box 3128 Houston, TX 77253 (713) 296-3277 Name and Title: -~I 10 12- : 1'1 w _ I ~ ,I -' I- t~\ I , ~- 18 WCMC CORNER 3" MONUMENT N: 2388470.36 E: 271528.88 ELEV. = 22.47' , . . SECTION 7 T5N R11W SM AK , >1'= "'" CLU NO.9 AS-BUILT WELL LOCATION GRID N:2388657.944 GRID E:272424.393 LATITUDE; 60"31 '56.155"N LONGITUDE: 151°15'48.901"W ELEV. 20' CLU NO.8 / t'Ñ) WELL -' C/) u... ;.r o N _ R~RTY LINE PROPERTY LINE . . 0"' CANNERY LOOP NO.1 PAD 9 WATER WELL I BUILDING CLU NO.1 ~ GAS WEll \ wi WELL HOUSE CLU NO.5 GAS WELL wI WELL HOUSE W EXISTING GRAVEL PAD L!J ELEVATION = 21' ± ~ CLU NO.6 0 ~~~~TOR l GAS WElL WASTE WATER CONTROl wI WELL HOUSE BUILDING BUIL~NG WATERLlNEBURIED5':t" ~ ~ WL_WL_WL~ - - "'GATE "',--/......... ",,,, , CANNERY ROAD 83' R/W- -~M,P ~GA,-;-,- CHAIN LINK FENCE , \" _ KENAI CITY LIMITS """\\" ...'~ OF AI.. I, _... ~~"'''''''''~C'\ I' - ~~.., *"~1: I : *f/)/49 IIi ....!*~ ""................................... , " , , " ,. . . .. . . . .. ... ... . ........ . .. .. . .... "" , t. ". M. SCOTT MCLANE;;: .- I ~ . . - I~ "'~"" 4928-S .... - ~'. .'- .... .... - " A:.... ...... ",-ø» ~ I " 'TOFESS I OI'I~\. ,,'" ,\\""" GRID ~ \ ,N08TH) ...~ ~ - TRACT A KENAI SPIT SUBDIVISION NO.2 I ~ 547' FEL [!J o CLU NO.7 WELL - - "'''' , - SURVEY NOTES , CONTROL POINT #113 N: 2388789.503 E: 272924.618 >1'= 2" AL-C~P . .!of 10' UTILITY EASEMENT REBOtLER P & HEATER BUILDING ,- I OVERHEAD ) PIPe SYSTEM --~ ¡ OVERHEAD BUILDING I PIPE SYSTEM ~, ,~ S 1/1 COF 7 "'" --, ¡- c-"'- - , I I ~ 0::: _0 101 / w z « -' 0::: ~I ü a.. 3: o II) 7 8 18 17 SECTION CORNEF 3" MONUMENT N: 2388444.45 E: 272967.50 ELEV. = 24.66' 1) BASIS OF COORDINATES IS U.S.C. & G.S. TRI STATION AUDRY ALASKA STATE PLANE NAD27 ZONE 4. 2) BASIS OF ELEVATION IS MEAN SEA LEVEL = 0.00' FOR ELEVATIONS SHOWN. 3) BEARINGS SHOWN HEREON ARE GRID UNLESS OTHERWISE NOTED. 4) AUDRY LOCATION: N: 2382045.42 E: 269866.75 5) 3" SECTION CORNER MONUMENT IN MON. BOX SERVES AS A TBM WITH AN ELEVATION = 24.66'. SCALE 1" = 100' 100 I FEET o I ENGINEER APPROVAL BY DA 11: PRo.JECT S1RUCT. PROCESS II.""AN ELECT. INSTRUII. Mai. 200 I REVISIONS (M) Marathon IIARAlHON Oil Company . Alaska Region CANNERY LOOP UNIT PAD NO.1 KENAI, CANNERY LOOP NO. 9 WELL SURFACE LOCATION DIAGRAM SCALE DM4. __ DAlE 5/l0¡IQ4 QiKD. DAlE 1".100' APP.D. _ DAlE n..... ALASKA FlI.£ NO.1YPI ORG IIOD DISC S"IST BCJ SDOD 000 DWG NO. 0001 SHTNC REV 1 o P.C. Bex 46B SCLDCTNA, AK 99669 ~ Consulting c;roup ~ Testing DAlE OF SUR'ÆY:e/1e/04 No. DAlE BY APP. __ BOOK No.: 04-15 EL 907.263.4216 FAX 907.263.3265 PRo.ECT NO.: 043085 DRAIMNG NO.: 043085...<:101 $CALE 1"·100' DRAM4 BY: 11511 Marathon Oil Company Project: Cannery Loop Unit No.9 R r-----' I , brNTRIF'lÐi I UNIT I 14' X 10" I I I I I I I I I DlJ4P I ,-\ I I ..." I I I 1._____..1 I f I L_______ I I I I I I I I I I I --... , , I,~\ IIEGASSO) I' I , " ....-- I ~-----i ~-----_R r f I..__.J U I f I ..--, 11 I I I I II I : I I II ! I · I I ¡III t 111I I II I I I II 1 I I I II I ~ I ~: M H: S I I J!í II I r~-====d__,L.-----~1 I ,.,,., I I ~ -\.. "',..! I I.. J J \I 1 ... ... ICDOKY 3' X 12' T 75HP 6](5 U· IIÐã\S:'IEK \. .~ ... 111II8I ~ 75tP 6](5 U' GLACIER DRILLING RIG #1 ~ MUD PITS AND PUMP ROOM LAYOUT ~ 75HP (; X :5 U· I,.:,:. !l 4Ø-t' n 5V 9L 11-6IIO PT 7SJP 61e:5 11· I I - - I.::. 1 ~ ! =.~ ill =.~ --¡ 5V 9l. ~PT ,.. T "\ ~~ . ... I'LL PIT . zr-t' í ~ . nïi'l ~ -I):Ga.ah ¢:: 0 -500 LO N II E 0 0 Q) "ffi 0 en 500 1000 1500 2000 2500 - - CD CD 3000 .... - J: - C. 3500 CD C CO 4000 CJ :e CD 4500 > CD ::J l- I- 5000 . V 5500 6000 6500 7000 7500 8000 8500 '&1. BAKIR HUGHES INTEQ KOP 5.00 10.00 OLS: 2.50 deg/100ft 20.00 25.00 30.00 " 37.50 ,,'-'v EOC 133/8" Casing t> ARATHON Oil Company --- Location: Cook Inlet, Alaska(lmported) Slot: CLU·9 Field: Cannery Loop Unit Well: CLU-9 Installation: Pad #1 Wellbore: CLU·9 Ver 1 _.~ Scale 1 cm = 200 ft East (feet) -> -400 400 800 1200 1600 2000 2400 2800 3200 3600 o L-L_-1.__L..__..l__J~ I ^ I 400 I ..I: o I II -400 ~ o ;:> 800 0<1. ~ OV ~ ~ ~~~<f <> +v~~;~ ~ 5 <tj.'ò 0\ ~" ~,><$. ~0\ <:1) -0~~~' r"q) + V ~<$ ~0 ~'\.- <Q0 ,? ~ ~ò .;;)<:1)' VV --ç¡ .~o., r:;' v'I1 ~4, ,,~ ¡' WELL PROFILE DATA - Point MD In<: AzI TVD North East degllOOf1 v. Sect Tison 0.00 0.00 83.42 0.00 0.00 0.00 0.00 0.00 KOP 350.00 0.00 83.42 350.00 0.00 0.00 0.00 0.00 End of Build 2043.41 42.34 83.42 1893.47 68.48 593.74 2.50 597.87 End of Hold 4781.40 42.34 83.42 3902.66 278.13 2412.17 0.00 2428.15 Target CUJ·9· Mid Bel 6878.16 0.00 83.42 5832.00 383.70 3154.34 2.00 3175.24 7.D. & End of Hold 9068.16 0.00 83.42 8042.00 383.70 3154.34 0.00 3175.24 Sterting B-2 OLS: 2.00 deg/100ft End of Hold 38.34 32.34 \ 22.34 9 5/8" Casing ~ Ì> 18.34 Sterting C-1 Upper Beluga 14.34 10.34 6.34 2.34 83.42 Oeg Azimuth 3175' to TO ***Plane of Proposal*** CLU-9 - Mid Beluga - 8/17/04 Lower Beluga Tyonek 31/2" Liner - TO J l lanner Date plotted: 17 -Aug-2004 Plot reference is CLU·9 Ver ,. Ref wellpath is CLU-9 Ver ,. Coordinates are in feet reference CLU-9. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 42.00 ft. Plot North is aligned to TRUE North. -500 -0 500 1000 1500 2000 2500 3000 3500 4000 Scale 1 em = 250 fI Vertical Section (feet) -> Azimuth 83.42 with reference 0.00 N, 0.00 E from CLU-9 . . MARATHON Oil Company,CLU-9 Pad #1, Cannery Loop Unit, Cook Inlet, Alaska(lmported} PROPOSAL LISTING Page 1 Wellbore: CLU-9 Ver 1 Wellpath: CLU-9 Ver 1 Date Printed: 17-Aug-2004 II.. --=- lNTEQ 31 56.1546 15 48.9006 C f 2388436.208 AK-4 on NORTH AMERICAN DATUM 1927 datu ~---~.. All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3175.24 Feet on azimuth 83.42 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . MARATHON Oil Company,CLU-9 Pad #1, Cannery Loop Unit,Cook Inlet, Alaska(lmported) PROPOSAL LISTING Page 2 Well bore: CLU-9 Ver 1 Well path: CLU-9 Ver 1 Date Printed: 17-Aug-2004 .1. ...,. INTEQ ., Yi .. < '.¿. MD(ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg Vertical Easting Northing rdea/100ftl Sectionrftl 0.00 0.00 83.42 0.00 O.OON O.OOE 0.00 0.00 272424.3 2388657.9 100.00 0.00 83.42 100.00 O.OON O.OOE 0.00 0.00 272424.3 2388657.9 200.0C 0.00 83.42 200.00 O.OON O.OOE 0.00 0.00 272424.3 2388657.9 300.00 0.00 83.42 300.00 O.OON O.OOE 0.00 0.00 272424.3 2388657.9 350.00 0.00 83.42 350.00 O.OON O.OOE 0.00 0.00 272424.3 2388657.9 450.00 2.50 83.42 449.9 0.25N - 2.17E 2.50 2.18 272426.51 2388658.1 550.00 5.00 83.42 549.7<; 1.00N 8.66E 2.50 8.72 272433.0 2388658.7 650.00 7.50 83.4~ 649.14 2.25N 19.48E 2.50 19.61 272443.9 2388659.8 750.00 10.0C 83.4~ 747.9 3.99N 34.59E 2.50 34.82 272459.0 2388661.2 850.00 12.5C 83.4~ 846.04 6.22N 53.97E 2.50 54.33 272478.4 2388663.1 950.00 15.0C 83.4~ - 943.1 8.95N 77.58E 2.50 78.09 272502.1 2388665.4 1050.0( 17.5C 83.4~ 1039.1 12.15N 105.38E 2.50 106.0 272529.9! 2388668.0 1150.0( 20.0C 83.4~ 1133.8f 15.83N 137.31E 2.50 138.21 272561.9 2388671.1 1250.0( 22.50 83.4~ 1227.0' 19.98N 173.31E 2.50 174.4E 272598.0 2388674.5 1350.0( 25.00 83.4 1318.5 24.59N 213.31 E 2.50 214.7 272638.1 2388678.4 1450.0( 27.50 83.42 1408.2f 29.66N 257.25E ..~ 258.9f 272682.1! 2388682.6 1550.0C 30.00 83.42 1495.9 35.17N 305.03E 2.50 307.0f 272730.0 2388687.2 1650.0( 32.50 83.42 1581.4( 41.11N 356.56E 2.50 358.9 272781.61 2388692.2 1750.0( 35.00 83.42 1664.~ 47.48N 411.75E 2.50 414.4 272836.91 2388697.5 1850.0( 37.50 83.4 1745. H 54.25N 470.48E 2.50 473.6C 272895.8 2388703.1 1950.0( 40.0C 83.4 1823.11 61.42N 532.66E 2.50 536.1~ 272958.1 2388709.1 2043.41 42.34 83.4 1893.4 68.46N 593.74E 2.50 597.6 273019.3 2388714.9 2100.0( 42.34 83.4 1935.31 72.82N 631.60E 0.00 635.7E 273057.2 2388718.6 2200.0( 42.34 83.4 2009.2 80.54N 698.50E 0.00 703.1 273124.2 2388725.0 2300.0( 42.34 83.4 2083.1~ 88.25N 765.40E 0.00 770.4E 273191.3 2388731.4 2400.0( 42.34 83.42 2157.0 95.97N 832.31E 0.00 837.82 273258.3 2388737.9 2500.0c 42.34 83.42 2230.9E 103.68N 899.21 E 0.00 905.1 273325.3 2388744.3 2600.0( 42.34 83.42 2304.91 111.40N 966.12E 0.00 972.5~ 273392.4 2388750.7 2700.0( 42.34 83.42 2378.8~ 119.11N 1033.02E 0.00 1039.8E 273459.4 2388757.1 2800.0C 42.34 83.42 2452.7E 126.82N 1099.92E 0.00 1107.21 273526.5 2388763.6 2900.0C 42.34 83.42 2526.6E 134.54N 1166.83E 0.00 1174.5E 273593.5< 2388770.0 3000.0C 42.34 83.42 2600.6C 142.25N 1233.73E 0.00 1241.9C 273660.5 2388776.4 3100.0C 42.34 83.4~ 2674.5 149.97N 1300.63E 0.00 1309.2f 273727.6 2388782.9 3200.0C 42.34 83.4~ 2748.~ 157.68N 1367.54E 0.00 1376.6C 273794.6 2388789.3 3300.0( 42.34 83.4~ 2822.3 165.39N 1434.44E 0.00 1443.9 273861.6 2388795.7 3400.0C 42.34 83.4~ 2896.2~ 173.11N 1501.34E 0.00 1511.2~ 273928.7 2388802.1 3500.0C 42.34 83.4~ 2970.21 180.82N 1568.25E 0.00 1578.64 273995.7 2388808.6 3600.0C 42.34 83.42 3044.1 188.54N 1635.15E 0.00 1645.9E 274062.7 2388815.0 3700.0C 42.34 83.42 3118.0f 196.25N 1702.06E 0.00 1713.3 274129.8 2388821.4 3800.0C 42.34 83.42 3191.9 203.96N 1768.96E 0.00 1780.6E 274196.8 2388827.9 3900.0C 42.34 83.42 3265.9C 211.68N 1835.86E 0.00 1848.0 274263.9 2388834.3 4000.0C 42.34 83.4 3339.8 219.39N 1902.77E 0.00 1915.3 274330.9 2388840.7 4100.0C 42.34 83.42 3413.74 227.11N 1969.67E - 0.00 1982.7 274397.9 2388847.1 4200.0C 42.34 83.4 3487.6E 234.82N 2036.57E 0.00 2050.0 274465.0 2388853.6 4300.0C 42.34 83.4 3561.5~ 242.53N 2103.48E 0.00 2117.41 274532.0 2388860.0 4400.0C 42.34 83.4 3635.5C 250.25N 2170.38E 0.00 2184.7E 274599.0 2388866.4 4500.0C 42.34 83.4 3709.4 257.96N 2237.28E 0.00 2252.11 274666.1 2388872.8 4600.0c 42.34 83.42 3783.3~ 265.68N 2304.19E 0.00 2319.4f 274733.11 2388879.3 4700.0C 42.34 83.42 3857.2 273.39N 2371.09E 0.00 2386.8C 274800.1 2388885.7 4761.4C 42.34 83.42 3902.6E 278.13N 2412.17E 0.00 2428.1 274841.3 2388889.7 4861.4C 40.34 83.42 3977.7 285.69N 2477.78E 2.00 2494.1~ 274907.0 2388896.0 All data is in Feet unless otherwise stated Coordinates are from Slot MO's are from Rig and TVO's are from Rig ( Oatum #1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3175.24 Feet on azimuth 83.42 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . MARATHON Oil Company,CLU-9 Pad #1, Cannery Loop Unit,Cook Inlet, Alaska(lmported) PROPOSAL LISTING Page 3 Well bore: CLU-9 Ver 1 Wellpath: CLU-9 Ver 1 Date Printed: 17-Aug-2004 .1. .... INTEQ ;. "·/;i... MD[ft] InC[deg] Azi[dèQ] TVD[ft] North[ft] East[ft] Dogleg Vertical EasUng Northing Ideo/100ftl I ~"",tinnrftl 4961.4C 38.34 83.4 4055.0E 292.95N 2540.74E 2.00 2557.5! 274970.1 2388902.0 5061.4C 36.34 83.4 4134.5! 299.90N 2600.99E 2.00 2618.2 275030.5 2388907.8 5161.4C 34.34 83.42 4216.11 - 306.52N 2658.44E 2.00 2676.m 275088.1 2388913.3 5261.4C 32.34 83.42 4299.7( 312.82N 2713.03E 2.00 2731.0( 275142.8 2388918.6 5361.4C 30.34 83.4~ 4385.11 318.77N 2764.69E 2.00 2783.01 275194.5 2388923.5 5461.4( 28.34 83.42 4472.21 324.38N 2813.36E 2.00 2832.0C 275243.3 2388928.2 5561.4( 26.34 83.42 4561.11 329.64N 2858.97E 2.00 2877.91 275289.0 2388932.6 5661.4( 24.34 83.4~ 4651Æ 334.55N 2901.48E 2.00 2920.7C 275331.6 2388936.7 5761.4( 22.34 83.4~ 4743.31 339.08N 2940.83E 2.00 2960.3 275371.0 2388940.4 5861.4( 20.34 83.4~ 4836.4f 343.25N 2976.97E 2.00 2996.6~ 275407.2 2388943.9 5961 .4C 18.34 83.4~ 4930.8C 34 ~JM!': f-- 3009.86E 2.00 3029.8C 275440.2 2388947.1 6061.4( 16.34 83.42 5026.2E 350.45N 3039.46E 2.00 3059.5~ 275469.8 2388949.9 6161.4( 14.34 -~ 5122.6~ - 353.48N - 3065,ll!; 2.00 3086.()JI 275496.2 2388952.4 6261.4C 12.34 83.42 5219.9~ 356.13N 3088.64E 2.00 3109.1C 275519.1 2388954.6 6361.4C 10.34 83.42 5318.0 358.38N 3108.17E 2.00 3128.7E 275538.7 2388956.5 6461.4C 8.34 83.4~ 5416.7C 360.23N 3124.28E 2.00 3144.9f 275554.8 2388958.1 6561.4C 6.34 83.4~ 5515.8E 361.70N 3136.96E 2.00 3157.7~ 275567.5 2388959.3 6661.4C 4.34 83.4~ 5615.4 362.76N 3146.20E 2.00 3167.04 275576.8 2388960.2 6761.4C 2.34 83.4~ 5715.2 363.43N 3151.98E 2.00 3172.8E 275582.6 2388960.7 6861.4C 0.34 83.4~ 5815.2 363.69N 3154.29E 2.00 3175.H 275584.9 2388961.0 6878.1E 0.00 83.4~ 5832.0C 363.70N 315~.MJ; _______ 2.00 3175.24 275585.0 2388961.0 6900.0C 0.00 83.42 5853.8 363.70N 3154.34E 0.00 3175.24 275585.0 2388961.0 7000.0C 0.00 83.4~ 5953.84 363.70N 3154.34E 0.00 3175.24 275585.0 2388961.01 7100.0C 0.00 83.42 6053.8 363.70N 3154.34E 0.00 3175.24 275585.0 2388961.0 7200.0C 0.00 83.4~ 6153.8 363.70N 3154.34E 0.00 3175.24 275585.0 2388961.0 7300.0C 0.00 83.42 6253.84 363.70N 3154.34E 0.00 3175.24 275585.0 2388961.0 7400.0C 0.00 83.42 6353.8 363.70N 3154.34E 0.00 3175.24 275585.0 2388961.0 7500.0C 0.00 83.4 6453.84 363.70N 3154.34E 0.00 3175.24 275585.0 2388961.0 7600.0C 0.00 83.4 6553.84 363.70N 3154.34E 0.00 3175.24 275585.0 2388961.0 7700.0C 0.00 83.42 6653.84 363.70N 3154.34E 0.00 3175.2 275585.0 2388961.0 7800.0C 0.00 83.4 6753.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 7900.0C 0.00 83.42 6853.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8000.0C 0.00 83.42 6953.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8100.0C 0.00 83.42 7053.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8200.0C 0.00 83.42 7153.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8300.0C 0.00 83.42 7253.84 .- 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8400.0C 0.00 83.42 7353.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8500.0C 0.00 83.42 7453.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8600.0C 0.00 83.42 7553.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8700.0C 0.00 83.42 7653.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8800.0C 0.00 83.42 7753.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 8900.0C 0.00 83.42 7853.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 9000.0C 0.00 83.42 7953.84 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 9088.1E 0.00 83.42 8042.0C 363.70N 3154.34E 0.00 3175.2 275585.01 2388961.0 All data is in Feet unless otherwise stated Coordinates are from Slot MDOs are from Rig and TVDOs are from Rig ( Datum #1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3175.24 Feet on azimuth 83.42 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated . . MARATHON Oil Company,CLU-9 Pad #1 Cannery Loop Unit, Cook Inlet, Alaska(lmported) PROPOSAL LISTING Page 4 Wellbore: CLU-9 Ver 1 Wellpath: CLU-9 Ver 1 Date Printed: 17-Aug-2004 .i. ...,. INTEQ 13 3/8" Casin 9 5/8" Casin 3 1/2" Liner Latitude N60 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig ( Datum #1 42.0ft above mean sea level) Vertical Section is from O.OON O.OOE on azimuth 83.42 degrees Bottom hole distance is 3175.24 Feet on azimuth 83.42 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated J) 160 - - CI) .e - .c 1::: ~ 80 I. Created by: P,ªoner . : I , Date plotted: 17~A~~2~~~___ ..-1 rPlot referenœl$C[O~9Ver 1. .--- --- ---- ¡ , Ref wellpath isCLlJ.9 Veri. i Coordinates are in feet reference CLU..g. i True Vertical Depths are reference Rig Datum i Measured Depths are reference Rig Datum i RígOatum: Datum #1 ; Rig Datum to mean sea level: 42.00 ft. t ~?!__~~h is aI.~~~~_1:?_~RUE t-!~_~h. Scale 1 em = 20 ft -40 0 40 80 120 400 360 320 280 200 120 40 o j -40 MARA THON Oil Company LocatiQn: Cook Inlet, Alaska(lmported) Slot: ClU-9 Field: Cannery loop Unit Wen: ClU-9 Installation: Pad #1 Wellbore: ClU-9 Ver 1 160 East (feet) -> 320 360 400 440 200 240 280 '800 480 520 560 600 640 680 720 760 ~ {¡¡, {¡¡, 480 800 400 360 320 280 240 200 160 ^ . z 0 120 ;::¡. ::r ¡; CD - .......... 40 -40 800 I Created by : Planner i Date plotted: i 7 -Aug-2004 Plot reference Is CLU-9 Ver i. Ref wellpath Is CLU-9 Ver 1- I Coordinates are In feet reference CLU-9. I True Vertical Depths are reference Rig Datum. I Measured Depths are reference Rig Datum. I Rig Datum: Datum #1 Rig Datum to mean sea level: 42.00 ft. , Plot North Is aligned to TRUE North. ARATHON ny location: Cook Inlet, Alaska(lmported) Field: Cannery loop Unit Installation: Pad #1 Slot: ClU·9 Well: ClU·9 Wellbore: ClU·9 Ver 1 ~",...ç§> TRUE 290 350 o 10 340 20 330 40 310 50 300 60 70 280 80 270 90 260 100 250 110 240 120 230 220 140 210 150 200 160 190 180 170 Normal Plane Travelling Cylinder Feet All depths shown are Measured depths on Reference Well . . MARATHON Oil Company CLU-9 Ver 1, CLU-9 Ver 1 CLU-9, Pad #1 CLEARANCE LISTING Page 1 Date Printed: 17-Aug-2004 Cannery Loop Unit, Cook Inlet, Alaska(lmported) .1. -- INTEQ Ellipse separations are reported ONLY if BOTH wells have uncertainty data Only Depth and MaQnetic Reference Field error terms are correlated across tie points Proximities beyond ft with expansion rate of ft/1 OOOft are not reported Cutoff is calculated on CENTRE to CENTRE distance Summary data uses Closest Approach clearance calculation for all minima Hole size/CasinQs are NOT included Hole size/CasinQs are NOT subtracted from Centre-Centre distance Ellipses scaled to 2.00standard deviations. ClosinQ Factor Confidence limit of 99.80% Errors on Ref start at Slot Permanent Datum (0.00) Report uses Revised: (D-C)/E Factor Calculation Eastin 2388436.208 Last Revised 17 -Au -2004 Latitude N60 31 56.1546 Lon itude W151 15 48.9006 Coord tem Name 2388436.208 AK-4 on NORTH AMERICAN DATUM 1927 datu Offset WellName Offset Structure Ellipse MD[ft] Clearance Clearance Factor MD[ft] CLU-1 CLU-1 CLU-1 CLU-8 CLU-6 CLU-5 CLU-1 CLU-1 CLU-1 RdPB1 CLU-1 CLU-1Rd CLU-1 CLU-8 CLU-8 CLU-6 CLU-6 CLU-5 CLU-5 Pad #1 Pad #1 Pad #1 Pad #1 Pad #1 Pad #1 Error Model Ma Corrected well...._o- ^^'...,...........:..~. All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 42.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated · e MARATHON Oil Company CLU-9 Ver 1, CLU-9 Ver 1 CLU-9, Pad #1 CLEARANCE LISTING Page 2 Date Printed: 17-Aug-2004 Cannery Loop Unit, Cook Inlet, Alaska(lmported) .1. ~ INTEQ < ...... ... ....... ...... .... ........ ...,.(iiii;i·¿,Ù·;.,.m, ..... .. .. ..... Referenœ Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest EUipse MD[ft] TVD[ft] No'th[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach Highside Distanœ [ft] deal ftl 0.00 0.00 O.OON O.OOE CLU-1 0.00 0.00 15.67S 170.95E 95.2 171.6€ 100.0C 100.0C O.OON O.OOE CLU-1 100.0C 100.0C 15.67S 170.95E 95.2 171.6€ 200.0C 200.0C O.OON O.OOE CLU-1 200.0C 200.0C 15.67S 170.95E 95.2 171.6€ 300.0C 300.0C O.OON O.OOE CLU-1 300.0C 300.0C 15.67S 170.95E 95.2 171.6€ 350.0C 350.0C O.OON O.OOE CLU-1 350.0C 350.0C 15.67S 170.95E 95.2 171.6€ 450.0C 449.9 0.25N 2.17E CLU-1 449.9 449.9 15.67S 170.95E 12.0 169.5 550.0C 549.7E 1.00N 8.66E CLU-1 549.74 549.74 15.79S 170.94E 12.5 163.14 650.0C 649.14 2.25N 19.48E CLU-1 649.1g 649.1g 16.10S 170.90E 13.6 152.5 750.0C 747.9 3.99N 34.59E CLU-1 747.25 747.21 13.85S 171.33E 14.2 137.9C 850.0C 846.04 6.22N 53.97E CLU-1 843.14 842.81 7.29S 173.71E 13.2 120.55 950.0C 943.1 8.95N 77.58E CLU-1 938.4g 937.13 5.80N 178.55E 8.5 101.2C 1050.0C 1039.1 12.15N 105.38E CLU-1 1033.34 1030.21 22.53N 185.89E -0.8 81.67 1150.0C 1133.8' 15.83N 137.31E CLU-1 1128.81 1123.3 41.78N 193.92E -18.0 63.15 1250.0C 1227.0f 19.98N 173.31E CLU-1 1222.4 1214.2 62.88N 201.71 E -47.9 53.02 1257.4' 1233.9 20.31N 176.16E CLU-1 1229.3 1220.9 64.51N 202.29E -50.6 52.96 1350.0C 1318.5 24.59N 213.31E CLU-1 1313.7! 1302.4 85.59N 209.07E -81.3 63.24 1450.0C 1408.2f 29.66N 257.25E CLU-t -- ~4.QU! -- 1387.4 109.62N 215.72E -102.6 92.47 1550.0C 1495.9 35.17N 305.03E CLU-1 1489.1 1470.11 135.07N 221.76E -114.2 132.58 1650.0C 1581.4C 41.11N -- 356.56E CLU-1 157Q.4 1547.0( 160.96N 227.13E -12Q.4 179.70 1750.0C 1664.5 47.48N 411.75E CLU-1 1666.9~ 1637.2! 193.88N 235.88E -124.5 230.44 s All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 42.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company CLU-9 Ver 1, CLU-9 Ver 1 CLU-9, Pad #1 CLEARANCE LISTING Page 3 Date Printed: 17-Aug-2004 Cannery Loop Unit, Cook Inlet, Alaska{lmported) .1. .... INTEQ < .< ;:- < --- . Refèrence Reference Reference Reference - Offset Well Offset Offset Offset Offset Angle CloSest ¡:Bipse- MD[ft] TVD[ft] North[ftJ East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach SeparatlOO Highslde Distance Eft} deal ftl 0.00 0.00 O.OON O.OOE CLU-1 0.00 0.00 15.678 170.95E 95.2 171.6€ 100.0C 100.0C O.OON O.OOE CLU-1 --- 100.00 100.00 15.678 170.95E 95.2 171.6€ 200.0C 200.0C O.OON O.OOE CLU-1 200.00 200.00 15.678 170.95E 95.2 171.6€ 300.0C 300.0C O.OON O.OOE CLU-1 300.00 300.00 15.678 170.95E 95.2 171.6€ 350.0C 350.0C O.OON O.OOE CLU-1 350.00 350.00 15.678 170.95E 95.2 171.6€ 450.0C 449.9 0.25N 2.17E CLU-1 449.9 449.9 15.678 170.95E 12.0 169.5 550.0r 549.7F 1.00N 8.66E CLU-1 549.74 549.74 15.798 170.94E 12.5 163.14 650.0C 649.14 2.25N 19.48E CLU-1 649.H 649.19 16.108 170.90E 13.6 152.51 750.0r 747.9 3.99N 34.59E CLU-1 747.2~ 747.21 13.85S 171.33E 14.2 137.90 850.0r 846.04 6.22N 53.97E CLU-1 843.1 842.8< 7.29S 173.71E 13.2 120.55 950.0r 943.1 8.95N 77.58E CLU-1 938Æ 937.1 < 5.80N 178.55E 8.5 101.20 1050.0C 1039.1 12.15N 105.38E CLU-1 1033.3 1030.21 22.53N 185.89E -0.8 81.67 1150.0C 1133.8~ 15.83N 137.31E CLU-1 1128.8 1123.3 41.78N 193.92E -18.0 63.15 1250.0C 1227.0~ 19.98N 173.31 E CLU-1 1222.4 1214.2 62.88N 201.71 E -47.9 53.0 1257.4~ 1233.9~ 20.31N 176.16E CLU-1 1229.31 1220.9 64.51 N 202.29E -50.6 52.96 1350.0C 1318.5 24.59N 213.31E CLU-1 1313.7! 1302.4 85.59N 209.07E -81.3 63.24 1450.0C 1408.2~ 29.66N 257.25E CLU-1 1402.31 1387.4 109.62N 215.72E -102.6 92.47 1550.0C 1495.9 35.17N 305.03E CLU-1 1489.1 1470.1E 135.07N 221.76E -114.2 132.5A 1650.0C 1581.4C 41.11N 356.56E CLU-1 1570.4 1547.0E 160.96N 227.13E -120.4 179.70 1750.0C 1664.54 47.48N 411.75E CLU-1 1666.9~ 1637.2! 193.88N 235.88E -124.5 230.44 All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 42.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated · e MARATHON Oil Company CLU-9 Ver 1, CLU-9 Ver 1 CLU-9, Pad #1 CLEARANCE LISTING Page 4 Date Printed: 17-Aug-2004 Cannery Loop Unit, Cook Inlet, Alaska{lmported) .iï. ...,. INTEQ .. .. ·'f>èi.... .;( (. Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MO[ft] TVO[ft) North[ft) East[ft) MO[ft) TVO[ft) North[ft) East[ft) From Approach separation HighskIe Distance [ft) rdea 1 .ftl 0.00 0.00 O.OON O.OOE CLU-1 0.00 0.00 15.678 170.95E 95.2 171.6€ 100.0C 100.0C O.OON O.OOE CLU-1 100.0G 100.0G 15.678 170.95E 95.2 171.6€ 200.0C 200.0C O.OON O.OOE CLU-1 200.0G 200.0G 15.678 170.95E 95.2 171.6€ 300.0C 300.0C O.OON O.OOE CLU-1 300.0G 300.0G 15.678 170.95E 95.2 171.6€ 350.0C 350.0C O.OON O.OOE CLU-1 350.0G 350.0G 15.678 170.95E 95.2 171.6€ 450.0C 449.9 0.25N 2.17E CLU-1 449.9 449.9 15.678 170.95E 12.0 169.5~ 550.0C 549.75 1.00N 8.66E CLU-1 549.7 549.74 15.79S 170.94E 12.5 163.14 650.0C 649.14 2.25N 19.48E CLU-1 649.H 649.19 16.108 170.90E 13.6 152.5~ 750.0C 747.9 3.99N 34.59E CLU-1 747.2~ 747.21 13.858 171.33E 14.2 137.9C 850.0C 846.04 6.22N 53.97E CLU-1 843.1 842.8 7.295 173.71E 13.2 120.5~ 950.0C 943.1 8.95N 77.58E CLU-1 938.4~ 937.1 5.80N 178.55E 8.5 101.2C 1050.0C 1039.1 12.15N 105.38E CLU-1 1033.3 1030.21 22.53N 185.89E -0.8 81.6 1150.0C 1133.8f 15.83N 137.31E CLU-1 1128.81 1123.3 41.78N 193.92E -18.0 63.15 1250.0C 1227.0~ 19.98N 173.31E CLU-1 1222.41 1214.2 62.88N 201.71 E -47.9 53.0" 1257.4f 1233.9~ 20.31N 176.16E CLU-1 1229.31 1220.9 -- 64.51N 202.29E -50.6 52.96 1350.0C 1318.5 24.59N 213.31E CLU-1 1313.7! 1302.4 85.59N 209.07E -81.3 63.24 1450.0C 1408.2~ 29.66N 257.25E CLU-1 1402.31 1387.4 109.62N 215.72E -102.6 92.4 7 1550.0C 1495.9~ 35.17N 305.03E CLU-1 1489.1! 1470.1E 135.07N 221.76E -114.2 132.58 1650.0C 1581.4C 41.11N 356.56E CLU-1 1570.4 1547.0E 160.96N 227.13E -120.4 179.7G 1750.0C 1664.54 47.48N 411.75E CLU-1 1666.91 1637 .2~ 193.88N 235.88E -124.5 230.44 All data is in Feet unless othelWise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 42.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company CLU-9 Ver 1, CLU-9 Ver 1 CLU-9, Pad #1 CLEARANCE LISTING Page 5 Date Printed: 17-Aug-2004 Cannery Loop Unit, Cook Inlet, Alaska{lmported) B.. .... INTEQ T 'C"" ,> ..' ,,;.,>, Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MÐ[ft] TVD[ft] North[ft] East[ft] MÐ[ft] TVÐ[ft] North[ft] East[ft] From Approa<:h Separation Highside Distance (ft] Ir~l Irftl 0.00 0.00 O.OON O.OOE CLU-8 0.00 0.00 , 4.18N 60.381' 86.0 60.53 0.00 0.00 O.OON O.OOE CLU-8 0.00 0.00 4.18N 60.38'" 86.0 60.53 100.0C 100.0C O.OON O.OOE CLU-8 99.7 99.73 4.28N 60.621' 86.0 60.7 200.0C 200.0C O.OON O.OOE CLU-8 199.5! 199.5< 4.52N 61.241' 85.8 61.41 300.0C 300.0C O.OON O.OOE CLU-8 296.4 296.3f 5.64N 64.531' 85.0 64.88 350.0C 350.0C O.OON O.OOE CLU-8 345.1' 344.QA 6.51N 67.451' 84.5 67.9~ 450.0C 449.9 0.25N 2.17E CLU-8 443.2' 442.61 8.98N 75.891' -0.2 74.5£ 550.0C 549.7f 1.00N 8.66E CLU-8 541.91 540.81 12.47N 85.551' -1.9 78.24 650.0C 649.14 2.25N 19.48E CLU-8 639.31 637.3! 17.61N 97.321' -4.5 80.21 750.0C 747.9 3.99N 34.59E CLU-8 732.81 729.0' 27.21N 112.791' -9.7 83.75 850.0C 846.04 6.22N 53.97E CLU-8 829.0 822.0- 42.16N 132.301' -17.4 89.46 950.0C 943.1 8.95N 77.58E CLU-8 ._~. 922.7 911.51 58.96N 154.441' -25.1 97.01 1050.0C 1039.1 12.15N 105.38E CLU-8 1015.5 998.4~ 77.08N 181.181' -31.5 107.7~ 1150.0C 1133.85 15.83N 137.31 E CLU-8 1105.4 1080.4 95.30N 213.261' -35.7 122.2 1250.0C 1227.05 19.98N 173.31 E CLU-8 1193.1 1156.5< 114.22N 252.541' -37.6 141.8~ 1350.0C 1318.5 24.59N 213.31 E CLU-8 1290.31 1238.51 135.62N 300.141' -39.1 162.0£ 1450.0C 1408.25 29.66N 257.25E CLU-8 " 1382.8 1315.4 156.41N 346.99E -40.6 180.9C 1550.0C 1495.9 35.17N 305.031' CLU-8 1473.3 1389.11 178.42N 394.66E -42.4 199.87 1650.0C 1581.4C 41.11N 356.561' CLU-8 1559.8! 1456.91 201.38N 443.28E -43.9 220.65 1750.0C 1664.5 47.48N 411.751' CLU-8 1644.71 1520.81 226.13N 493.45E -45.4 243.4 ms All data is in Feet unless otherwise stated Coordinates are from Slot and TVO's are from Rig ( Oatum #1 42.0ft above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (10) Prepared by Baker Hughes Incorporated . e MARATHON Oil Company CLU-9 Ver 1, CLU-9 Ver 1 CLU-9, Pad #1 CLEARANCE LISTING Page 6 Date Printed: 17-Aug-2004 Cannery Loop Unit, Cook Inlet, Alaska(lmported} .1. .... INTEQ ... .~' .....: /..,;' (. ...... ...: ..... . , .. Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellip$e MO(ft) TVO[ft) North[ft) East[ft) MO[ft) TVO[ft) North[ft) East[ft) From Ap~ Sepà~ Highside Distance (ft) I rn.;"l I rft1 - 90.03~ 81.921' 121.7~ 0.00 0.00 O.OON O.OOE CLU-6 --- 0.70 0.20 137. 100.0C 100.0C O.OON O.OOE CLU-6 ---101.0! 100.5! 89.60S 81.981' 13V 121.4~ 200.0C 200.0C O.OON O.OOE CLU-6 201.51 201.0' 88.47~ 82.141' 137.1 120.7~ 300.0C 300.0C O.OON O.OOE CLU-6 301.3( 300.7! 87.14~ 82.461' 136.F 119.97 350.0C 350.0C O.OON O.OOE CLU-6 351.4t 350.81 86.43~ 82.751' 136.~ 119.6f 450.0C 449.9 0.25N 2.17E CLU-6 451.81 451.31 84.09~ 83.891' 52.5 117.4~ 550.0C 549.n 1.00N 8.66E CLU-6 550.11 549.41 80.11~ 86.87F 52.7 112.6 650.0C 649.1~ 2.25N 19.48F CLU-6 649.11 647.9( 73.87~ 94.62F 52.1 106.!If 750.0C 747.9 3.99N 34.59F CLU-6 747.41 744.6 62.7Ó~ 108.04F 49.0 99.26 850.0C 846.0~ 6.22N 53.97F CLU-6 845.11 839.8 49.4Ó~ 125.29F 44.6 90.66 950.0C 943.1 8.95N 77.58F CLU-6 941.9 933.2~ 35.27~ 146.47F 39.1 82.46 1050.0C 1039.1 12.15N 105.38E CLU-6 ---- 1039.41 1026.21 19.29~ 170.98F 31.8 73.89 1150.0f 1133.8~ 15.83N 137.31 F CLU-6 1136.0( 1116.5 0.055 199.131' 20.3 66.1 1250.0C 1227.0E 19.98N 173.31E CLU-6 1232.21 1204.7~ 22.38N 230.501' 3.9 61.4 1288.2 1262.2 21.70N 188.16E CLU-6 1269.1 1238.0 31.73N 243.19F -3.5 60.9E 1350.0C 1318.5 24.59N 213.31E CLU-6 1327.9 1290.71 47.43N 264.04F -15.8 62.H 1450.0C 1408.2E 29.66N 257.25E CLU-6 1422.3 1374.0 74.61N 299.25F -34.8 70.4C 1550.0C 1495.9~ 35.17N 305.03E CLU-6 1515.1 1453.5~ 103.73" 337.08F -49.2 86.71 1650.0C 1581.4C 41.11N 356.56E CLU-6 1605.3! 1528.0 134.51N 377.67F -58.5 109.6~ 1750.0C 1664.5~ 47.48N 411.75E CLU-6 1693.71 1597.5 167.4"" 421.15F -64.1 137.7~ 1850.0C 1745.1f 54.25N 470.48E CLU-6 1781.4 1662.21 202.33N 468.97F -66.9 169.7E 1950.0C 1823.1E 61.42N 532.66E CLU-6 1868.51 1722.71 238.42N 520.14F -68.3 203.8 2043.41 1893.4 68.46N 593.74E CLU-6 195Q.4 1777.3C 273.94N 569.84F -69.3 237.2E All data is in Feet unless otherwise stated Coordinates are from Slot and TVO's are from Rig ( Oatum #1 42.0ft above mean sea level) Reference MO's are from Rig, Offset MO's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated . . MARATHON Oil Company CLU-9 Ver 1, CLU-9 Ver 1 CLU-9, Pad #1 CLEARANCE LISTING Page 7 Date Printed: 17-Aug-2004 Cannery Loop Unit, Cook Inlet, Alaska{lmported) .i. -wa.. INTEQ ........... ......~... Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle ClO$Øst EWpse MD[ft] TVD[ft] North[ft] East[ft] MD[ft] TVD[ft] North[ft] East[ft] From Approach ~ration Higl1side Distance [ft] fdeal fftl 1150.0 1133.8 15.83N 137.31E CLU-5 1116.0 1079.64 26.81 N 370.93E 3.8 240.0Ç 1250.0C 1227.0f 19.98N 173.31E CLU-5 1207.3 1167.2~ 41.67N 391.61 E 0.9 227.3 1350.0C 1318.5 24.59N 213.31E CLU-5 1299.2 1254.6P 58.56N 414.81E -2.9 214.0Ç 1450.0C 1408.2< 29.66N 257.25E CLU-5 1389.0( 1338.8 76.69N 439.99E -7.4 201.0E 1550.0C 1495.9 35.17N 305.03E CLU-5 1478.81 1421.7 97.00N 468.21 E -13.1 189.6~ 1650.0C 1581.4C 41.11N 356.56E CLU-5 1571.41 1505.9 119.62N 499.45E -20.2 179.6 1750.0C 1664.5 47.48N 411.75E CLU-5 1659.91 1585.1 142.66N 531.34E -28.1 172.2,4 1835.21 1733.41 53.22N 461.58E CLU-5 1734.0( 1649.9 163.52N 560.45E -35.3 170.0 1850.0( 1745.11 54.25N 470.48E CLU-5 1746.11 1660.4~ 167.12N 565.52E -36.5 170.1 195Q.O( 1823.11 61.42N 532.66E CLU-5 1834.3 1735.2 194.27N 603.41E -45.4 174.31 2043.41 1893.4 68.46N 593.74E CLU-5 1917.4! 1804.H 221.42N 641.02E -53.7 183.3 2100.0( 1935.31 72.82N 631.60E CLU-5 1967.21 1844.7! 238.131'1 664.59E -58.3 191.3 2200.0( 2009.2 80.54N 698.50E CLU-5 2056.1 1915.2C 269.34N 708.95E -65.0 211.11 2300.0( 2083.1! 88.25N 765.40E CLU-5 2144.0! 1982.7! 302.10N 754.57E -70.0 236.4 ms All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig ( Datum #1 42.0ft above mean sea level) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1D) Prepared by Baker Hughes Incorporated - Marathon Oil Company Well Name: CanneryLoop Unit #9 Location: Kenai, Alaska. I' m y/ í Prepared MARAHO OIL COMPANY ell Cannery loop Unit #9 Kenai Peninsula, Alaska Prepared by: Tony Tykalsky Reviewed by: Mark Fairbanks Presented to: Win Tank August 18, . . elÆ Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATIN: Will Tank Will: Enclosed is the recommended drilling fluid program for the Cannery Loop Unit #9 Well to be drilled this year. The following is a brief synopsis of the program. Overview: CLU #9 is a development well targeting the Beluga formation at the Cannery Loop field. Flo-Pro fluid will be used for the intermediate and production intervals. After logging the production interval, the well will be completed with a 3-1/2" excape system cemented in place. Suñace Interval: The surface interval will be drilled with the standard GellGelex spud mud. No problems were noted in this interval while drilling Cannery Loop # 7 & 8. Intermediate Interval: This interval will be drilled with a Flo-Pro NT fluid. After drilling out the surface cement, the well will be displaced to a standard Flo-Pro KCl fluid. Safecarb bridging material will be maintained according to the mud program to minimize losses to the formation. Fluid loss should be maintained @ 7 - 9 cc's API. NOTE: Since this fluid will also be used in the production interval, care should be taken to maintain recommended mud properties while drilling the intermediate interval. Production Interval: This interval will be drilled with the same fluid that was used to drill the intermediate interval. The fluid will be pre-treated with Bicarb and/or citric acid prior to drilling out the cement. Any further fluid dilutions will be made in order to keep the mud properties at the recommended specifications. Fluid loss should be maintained @ 7 - 9 cc's API for this interval. NOTE: Mud weights as high as 10.0 PPG may be needed to control coal gas at the bottom of this interval. Completion: The cement will be displaced with 6% KCl brine for the completion phase of the program. Conqor 303A and Sodium Meta Bisulfate will be added to the drilling fluid that will be left between the 3-1/2" completion string and the 9-5/8" casing on the final circulation prior to cementing. ~ .FE ~~ faR . . Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Tony Tykalsky Project Engineer 1M-I SW ACO Reference Wells: CLU #7, CLU #8 NOTE: This proe:ram is provided as a e:uide only. Well conditions will always dictate fluid properties required. E ~ _FE EXECUTIVE SUMMARY Our overall goal is no spills and no incidents while providing fluids and solids control services to Marathon Oil Company. Our goal for Cannery Loop #9 is to remove drill solids from the mud system at a cost of less than $0.23 per pound. This has been the average for the last three years of centrifuge van operations With the revised fluid formulation (utilizing the Intermediate Interval fluid for the production Interval), we expect to drill this well for a product cost of less than $28.72 per foot. Use of the MI Swaco centrifuge van for the last four years has provided an estimated savings in dilution and disposal costs to Marathon Oil of over $600,000. With continued usage of our equipment, we expect to provide more savings to you during future operations. ~.IÆ ~~ . . eFE - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Interval Benchmarks and Targets Drilling Intervals Benchmark 1 Benchmark 2 Benchmark 3 Fluid cost per foot Volume Usage Solids Removal o - 2050' < $5.29 ft < 2439 bbls 2050 - < $43.89 ft < 2889 bbls 5796' 5796 - < $27.56 ft < 1274 bbls 9088' Total Avg. Max. Project < $28.72 ft <6602 bbls < $0.23 Ib No Spills from Targets for Centrifuge Van Drilling Operation Interval ~.IÆ ~~ . . _FE Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth TVD Mud Mud Sum Interval Size Size Program System Weight Days Mud Cost (in) (in) (ft) (ft) Solids Control (ppg) 13 3/8" 16" 2050' 1898' GellGelex Spud Mud 8.6 - 9.4 5 $14,228 Screens 150/180 mesh Desilter Centrifuge Van 9 5/8" 12-1/4" 5976' 4945' Plo-Pro w/SafeCarb 9.0- 10 $171,145 Screens 180 - 210 <9.5 mesh Desilter Centrifuge Van 3-1/2" 8-1/2" 9088' 8042' Plo-Pro w/SafeCarb 9.0- 7 $90,485 Screens 230 - 210 10.0 mesh Desilter Centrifuge Van 3 1/2" 8-1/2" Completion 9088' 8042' 6% KCI 8.55 2 $3,952 ~ Utilize all solids control equipment to minimize the build up of drill solids in the system (if possible, centrifuge the surface mud during trips to reduce drill solids). ~ Condition the mud prior to running casing for all intervals. ~ Cost includes the use of 3% Lubetex in the intermediate and production intervals. ~ .ø am'~ Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. - M-I Bar 0 433 1019 0 1452 3.72 M-I Gel 732 0 0 0 732 2.17 Gelex 30 0 0 0 30 0.15 Soda Ash 12 14 13 0 39 0.22 Caustic Soda 12 29 13 0 54 0.53 Conqor 404 0 7 4 0 11 4.83 Sodium Meta 24 29 13 4 70 1.70 Bisulfate Bicarb 12 14 25 0 51 0.53 Conqor 303 0 0 0 4 4 0.37 Flo Vis 0 231 102 0 333 24.98 Desco CF 12 0 0 0 12 0.21 Polypac UL 12 116 51 0 179 10.68 Bioban BP _Plus 0 29 102 0 131 1.10 KCl 0 1214 535 42 1791 8.58 Safecarb 0 1156 509 0 1665 11.10 Lubetex 0 66 29 0 95 26.55 Citric Acid 0 0 6 0 6 0.31 Defoam X 0 44 2 0 46 1.79 Engineer Service 5 10 7 2 24 . . eFE - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments CLU #7 16 123 8.7 24 28 14.2 Spud in, drill ahead 727 8.8 22 27 16.0 Drlg ahead 1684 9.0 17 24 11.6 Drill ahead 1796 9.2 23 24 10.8 Drlg to casing point, trip (clean stabilizer of clay), condition hole 12.25 2237 9.0 10 20 9.4 Drill out, displace to FloPro, Run LOT, drlg ahead 3758 9.3 8 22 7.6 Drlg ahead, run centrifuge van for solids 4806 9.1 8 21 7.4 Drlg ahead, add Lubetex for directional work 4930 9.3 9 23 7.8 POH, chenge MWO. RIH tight 1920 - 2886' 5557 9.4 13 30 8.6 Drlg ahead 6123 9.3 15 27 8.2 Drlg ahead, POH, test BOP's 7015 9.4 19 31 7.6 RIH work tight spots, drlg ahead 7780 9.5 15 29 8.8 Drlg to casing point, short trip OK 7 8406 9.5 9 24 6.2 Drlg out csign, displace to new mud, drlg ahead 8924 9.4 10 25 6.6 Calcium concentration increasing, treat mud for bacteria, drlg ahead 9270 9.4 9 25 6.0 Drlg ahead 10034 9.4 10 35 6.8 Drlg ahead, POH for mud motor 10424 9.4 9 28 6.6 Dump & dilute to reduce solids after trip, drlg ahead 10864 9,8 10 28 6.2 Increase mud weight & lubetex concentration. drlg to TO, log well, run liner, OK CLU #8 16 120 8.6 8 15 18.8 Spud in, drill ahead 1047 8.8 15 26 18.4 Drlg ahead 1821 9.2 8 23 11.8 Drlg to casing point, run surface casing 12.25 2814 9.1 6 22 10.2 Drlg out, displace to FloPro, Run LOT, drlg ahead 4818 9.2 7 20 8.4 Drlg ahead 6252 9.3 11 23 7.8 Drlg ahead, running 3% lubricant 6722 9.3 10 25 8.6 Drlg to casing point, Run 9-5/8" casing 8.5 6745 9 7 19 8.8 Drlg out, displace to FloPro, drlg ahead 7955 9.3 9 23 8.6 Drlg ahead, add lubetex to lower torque 8831 9.45 10 20 8.6 Drlg ahead 9777 9.95 12 27 8.8 Orlg to TO, weight up for gas, condition hole, log same, run tubing & cement same ~.FE ~~ . . litH Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Plans & Procedures ~ COMMUNICATION - The Field Mud Engineer will communicate daily with the In-Town Project Engineer. The Project Engineer will then communicate daily with the rig Drilling Engineer. Communications should be about, but not limited to, fluid properties, hole difficulties, possible changes to the mud program, and proposals to use products not included in the mud program. ~ Whole Mud Losses to the Sterlng C1 and Upper Beluga Sands - Refer to fluid formulas and the Optibridge charts for maintaining proper bridging material concentration in the mud system while drilling the intermediate and production intervals. ~ FLUID LOSS CONTROL - In the intermediate interval the API fluid loss will be maintained in the 7 - 9 cc's range. In the production interval the API fluid will be maintained between 6 - 8 cc's at all times. In addition to sufficient fluid loss agent additions, this may require adequate dilution of the mud system in order to keep reactive drill solids to a minimum. ~ LSRV - When drilling with a FloPro fluid, the low shear rate rheology should be maintained at approximately 30,000 cps. In addition to adequate additions of FloVis Plus, this will also require keeping reactive drill solids to a minimum in order to reduce or eliminate false and unwanted high LSRV. ~ DRILL SOLIDS - MBT - The MBT should be kept at less than 7.5 ppb in the intermediate and production intervals through aggressive use of solids equipment and dilution as needed. ~ MIXING CONDITIONS - Whenever possible all treatments to the mud system should be made as pre-mix additions. Polymers and KCI should first be mixed in fresh water in that order and then blended into the active system over one or two circulations as needed. ~ CORROSION - Conqor 404 additions should be made daily when drilling with FloPro fluid in order to maintain a Conqor 404 concentration of +/- 2000 PPM. ~ CORRISION - Sodium Meta Bisulfate additions should be made daily as needed with any fluid in the hole. Maintain a DO reading of less than 3 ppm ~ SOLIDS VAN USAGE - The Solids Van should be used whenever drill solids become un- acceptably high and reduction of drill solids in the mud can be more economically done with centrifuging and dilution then just with dumping and diluting. The weight of the drilling fluid alone should not be the determining condition for when to use the Solids Van. ~ WEIGHTING UP - All increases in mud weight should be accomplished with barite additions. In the production interval, insure chloride concentration is maintained at 30,000 to minimize the need for barite additions. r:zj 81Æ ~~ . . 8FE Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Interval Summary - 16" hole .... , (/ !/ 0·2050' /c " Drilling Fluid System Gel/Gelex Spud Mud Key Products MI Gel / Gelex / Soda Ash / Caustic Soda / MI Bar / PolyPac Supreme UL Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 150 - 180 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions ~iJ~I~ªI»tilliJ)gEIt1Îd Properties Depth Mud Funnel Yield API Drill Interval Weight Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec./qt) (I b./lOOft2) (mV30min) ( % ) 0 - 2050' 8.6 - 9.4 60 - 100 25 - 35 NC - 1 2 +/- 9.5 < 7% ~ Treat drill water with Soda Ash to reduce hardness. ~ Build spud mud with 20 - 25 PPB M-I Gel to +/- 100 seconds/quart funnel viscosity. ~ Lower funnel viscosity to +/- 75 after gravel zone has been drilled. ~ Add Gelex as needed to maintain sufficient viscosity for hole cleaning. ~ Increase funnel viscosity if fill on connections begins to occur. ~ Reduce fluid loss with additions of Polypac Supreme UL prior to running surface casing. ~ Add Sodium Meta Bisulfate to maintain a DO of < 3 PPM. ~ Condition mud prior to cementing casing to reduce yield point and gel strengths. ~ Estimated volume usage for interval - 2439 barrels. ~ Estimated haul off volume - 4179 barrels. r:zì _.FE ~~ . . faR - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Interval Summary - 12-1/4" hole ~lf50....5"79i' " i:M Drilling Fluid System Flo-Pro Fluid Key Products Flo- Vis / PolyPac Supreme UL / KCl/ SafeCarb F & M / MI Bar / Caustic Soda / Conqor 404 / Sodium Meta Bisulfate / Lubetex Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 210 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions lîi'ê~¥!iltjri1.liJ1glflmd·.·Properties .i ....< Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (ppg) (cp.) ( cps ) (mV30min) ( % ) 2050 - 5796' 9.0- < 9.5 8 - 1 2 30,000+ 7 - 9 < 7.5 +/- 5% ~ Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed fluid formula. ~ After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test ~ If running coals become a problem, treat with a 2 PPB addition of Asphasol D. ~ If torque or sliding problems occur, add 1 - 3% Lubetex. ~ NOTE: This fluid will be used in the production interval. It is inherent to maintain proper fluid properties for that purpose. ~ Estimated volume usage for interval - 2889 barrels. ~ Estimated haul off volume - 3274 barrels. ~ Condition mud prior to running 9-5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~ fiFE ~~ . . fiR Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Fluid Formula - 12-1/4" Interval 1 2-1 /4" Interval from 2050 - 59761 InDut ()escrintiø" Cannerv LOOD Unit #9 MlJdWøidht 9.1 - 9.2 Preh No WéiohtMatétialCóde MI Bar PrehvdratédGetCØnc. WéiòhtMãtêrial·SG 4.2 KGI Wfl/Q 6 Output - 1 bbl Ordèr-of PrOductS Concentration < .< AdditÎÔ/') Fièld.lb Lab am Fiéld.bbl ·J·.ìi'th_rril ill" 1 Water 298.70 298.70 0.853 298.70 2 Soda Ash 0.25 0.25 0.000 0.1 0 Reduce Hardness 3 Flovis 2.00 2.00 0.004 1 .33 Viscositv 4 Polvoac Supreme UL 2.00 2.00 0.004 1 .25 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 DH Control 6 Potassium Chloride 1 9.07 1 9.07 0.023 7.98 Inhibition 8a SafeCarb F 1 0.00 10.00 0.01 0 3.60 BridQinQ AQent 8b SafeCarb M 1 0.00 10.00 0.01 0 3.60 BridQinQ AQent 9 Sodium Meta Bisulfate 0.50 0.50 0.000 0.20 Oxvaen Scavenaer 10 Asphasol Supreme 2.00 2.00 0.006 2.08 Wellbore Stability If bit balling becomes a Droblem, add the following: 1 1 0-0 CWT 1 .00 1 .00 0.003 I 1 .00 Reduce BHA BallinQ If toraue becomes a Droblem. or sliding is difficult. add uDto 5% of the following: 12 Lubetex 14.00 14.00 0.041 14.43 Lubricity Totål 399 399 1 .000 350 Qalql.llâti;KfM...d..·W.,ight 9.05 E$til'riated>YÔlu..U". 2889 Barrels TotålChlorlde 29600 ~ fiFE œr~ - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. , Mí Max Permeability : Sand Control Device: 350 mDarcy © 1999 - 2004 M-ll.l.C. . All Rights Reserved 1.0 0.9 0.8 ¡: 0 ~ 0.7 .0 '1: ... !I'I ð 0.6 Q.I N " !II 0.5 Ü i Q.. 0.4 \I.) :» i "5 0.3 E :::I t:I 0.2 0.1 ¡x'I 0.2 'I x'l 0.1 D10 Targeti Blend: 0.1 C60 Targ~ I Blend: 18.7 D90 Targ~ I Blend: 60.6 1.4 microns 15.5 microns 127.3 microns Brand Name B"Safe-Carb 10 (F) D=Safe.carb 40 (M) E"Safe-Caro 250 (Cj Bridglna AaenWblbblì 10.1 9.3 0.0 ~ 63.38 46.62 0.00 D 46.6% 1 x'l 0° 'Ix101 1x102 Particle Size (microns) 1x103 1x104 Calcium Carbonate added: Avg Error 0 -100 % CPS Range: Max Error 0 -100 % CPS Range: 20 Iblbbl 3.50 % 11.01 % ~ Zone of interest - Sterling e-1 & Upper Beluga sands »> Pore Pressure - 4.04 - Maximum Porosity - 350 mD »> Measured Depth - +/- 5978' (4947' TVD) »> Build additional volume as needed usine. the blend listed above. . . eFE - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Interval Summary - 8-1/2" hole Drilling Fluid System Flo-Pro Fluid 5976 - 9088' Key Products Flo- Vis / Polypac Supreme UL / KCI / SafeCarb F & M / MI Bar / Caustic Soda / Conqor 404 / Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions ·ntetvEdBriUing.·..·:FluidPropemes Depth Plastic LSRV Interval Viscosity 1 min (ft) (cp.) (cps) 5976 - 9088' 10 - 14 30,000+ <7.5 API Fluid Loss (mV30min) 6-8 MBT '...._,,/ ~ Pre-treat drilling fluid with Bicarb and/or citric acid prior to drilling cement. Aggressively treat out cement contamination as soon as feasible. Build additional dilution volume to maintain proper specifications. ~ If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. ~ Estimated additional volume for interval- 1274 barrels. ~ Estimated haul off volume - 2678 barrels. ~ NOTE: Coal 2as at the bottom of this interval (+/- 8818' MD) may require mud wei2hts as hi2h as 10.0 PPG to control. ~ Condition mud prior to running 3-112" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. r:zj .IÆ rmr~ . . _FE - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Dilution Formula - 8-1/2" Interval 8-/1 2" Interval from 5976 - 90881 Input D.eS¢riDtion Cannery Loop Unit #9 MudWeiOht 9.0 - 10.0 Preh No WeiahtMatørÎaliCQde MI BaR ÞrehvdratedGølCOnc. Weidht'Mãteriaf SG 4.2 KCI. WfOk . 6 Output - 1 bbl I Ordetof Products Concentration ; AdditiOn FiØld.lb Lab, am Fiøld,bbf ....t..ab2î'rif )/ 1 Water 325.19 325.19 0.929 325.19 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 FloVis Plus 2.00 2.00 0.005 1.34 Viscosity 4 Polypac Supreme UL 2.00 2.00 0.004 1 .33 Fluid Loss Control 5a SafeCarb Fine 15.00 22.50 0.017 5.67 BridQing Agent 5b SafeCarb Medium 5.00 7.50 0.006 1 .89 BridQing Agent 6 Potassium Chloride 20.76 20.76 0.025 8.68 Inhibition 7 CONQOR 404 2.00 2.00 0.004 1 .43 Corrosion Control 8 Caustic Soda 0.50 0.50 0.001 0.23 pH Control 9 Sodium Meta Bisulfate 0.50 0.25 0.001 0.25 OXYQen ScavenQer If sliding or high torque becomes a problem add 1 - 3% of the following 10 Lubetex I 7.00 I 7.00 I 0.021 7.00 Lubricity If sloughing coals become a problem add 2 - 4ppb of the followina 1 1 Asphasol Supreme 2.00 I 2.00 0.004 1 .33 Wellbore Stability Mix fluid in the order listed above. Total 380.1 380.1 E.t.......teQVº'ûmi'U..ø;J 1274 Barrels ÇâlcÛIr.t9dMUclWe,ght 9.050 TotalCttlol'lde 29600 ~ .IÆ am'~ - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Corrosion Control in Casing x Tubing Annulus Well Cannery Loop Unit #9 Volumes: Tubing Volume 3-1/2" Tubing Annular Volume Casing x Tubing 9 3.50 )( 2.992)( 9088 ft Open Hole )( Tbg Total )( 8.681 @ 5976 ft MD +- 8.500 )( 3.50 @ 9088 ft MD Treatment Procedures. 1. After the 3-1/2" tUbing is run and the drilling fluid is circulated and an additional 366 barrels ofdl'lIIing fluid. 2. Add 4 drums of Conqor 303Aand4 sacks Sodium Meta BisUlfate to this 366 barrels. 3. After the 366 barrels of drilling>fluid with Conqor 303A and Sodium Meta Bisulfatêhave been pumped downhole. begin the cement job. 4. This rocedure will lace corrosion control in the 3-112" x 9-5/8" annulus. . . elÆ Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. - HSE Issues HANDLING OF DRilLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. I 2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. 3. PPE must be in good working order and be utilized as recommended by the PPE charts. 4. Product additions should be made with the intent to use complete unit amounts of products (sacks, drums, cans) as much as possible in order to minimize inventory of partial units. 5. Insure all MSDS sheets are up to date and readily available for workers to access for information. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all hoses and connections between the van and the rig are secure. ~ II.FE rmr~ - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Product Function M-I BAR Weighting Agent M-I GEL Viscosity control GELEX Bentonite Extender FLOVIS Viscosifier E DUAL-FLO Modified Starch E POLYPAC Fluid Loss Reducer E XCD Viscosifyer E HEC Loss Circulation Material E Safe-Carb F,M,C Bridging and weighting E agent LO WATE Weighting agent M-I Seal Mix II F,M,C DESCO CF SPERSENE CF TANNATHIN VENTROL 401 SALT (Solar) BROMIDE (NaBr) & Brine Solution POTASSIUM CHLORIDE - circulation Mat Dispersant Dispersant Dispersant Surfactant Densifier Densifier Shale Inhibitor - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Product Function CAUSTIC SODA CAUSTIC POTASH SAPP SODA ASH SODIUM BICARBONATE C ACID BIOBAN BP-PlUS Ikalinity control Ikalinity control E E pH Adjuster Biocide J J J . . faFE - Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 - Severe hazard 3 - Serious hazard 2 - Moderate hazard 1 - Slight hazard o - Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A - Safety Glasses B - Safety Glasses, Gloves C - Safety Glasses, Gloves, Synthetic Apron D - Face Shield, Gloves, Synthetic Apron E - Safety Glasses, Gloves, Dust Respirator F - Safety Glasses, Gloves, Synthetic Apron, Dust Respirator G - Safety Glasses, Gloves, Vapor Respirator H - Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator I - Safety Glasses, Gloves, Dust and Vapor Respirator J - Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator K - Air Line Hood or Mask, Gloves, Full Suit, Boots X - Consult your supervisor for special handling directions r:zj _.FE am'~ . . fiR Marathon Oil Company Well Name: Cannery Loop Unit #9 Location: Kenai, Alaska. Contacts Contact Title e-mail Work Cellular Pete Berga Drilling pkberga@marathonoil.com 907564-6319 907 231-0663 Marathon Superintendent Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398 Marathon Tony Tykalsky Project Engineer ttykalsky@miswaco.com 907 274-5011 907227-2412 MI SW ACO Gus Wik Warehouse Manager gwik@miswaco.com 907 776-8722 907 776-8680 MISWACO Michael Barry Senior Field gratefulmen@hotmail.com 907 260-4666 907 590-3636 MI SWACO Engineer (home) Locke Rooney Field Engineer rooneyl @alaska.net 907 235-0598 907 590-3636 MISWACO (home) Roland Lawson I Drilling Foremen 907 283-1312 Larry Myers I Dave Morris Marathon Responsibilities ~ MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M-I field engineers. ~ Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. ~ Field Engineers will monitor and supervise product inventory to include re-palletizing any products for shipment to other locations at the end of the well. ~ Field Engineers will communicate with office personnel (Marathon & MI SW ACO) for approval of any changes in the mud program (including introduction of new products). ~ Field Engineers will produce a recap at the end of the well based on daily activities. Recap should include any lessons learned that may be used to provide better service on future wells. Lessons learned can include changes in procedures, product additions, equipment usage, and/or utilization of any third party service. r:zj ..FE ~~ Check No Check D;¡le Bank Bank No Marathon Oil Company P. O. Box 3128 Houston, TX 77253 ~~Ó~~~S~~~ÄBLEDEPARTMENT Aeels Payable ConlaclCenler Phone: 918-925-6097 :ÐJ~¡;¡¡:¡i ......'............................. Hndlg HS 1138772 0812012004 NCBAS 7780 :iffii9iii~@@ij)iim@;~:þ(*#riiiiiÙi L 100.00 08119/2004 1900023468 TOTAL: 100.00 100.00 )ji@~M.=i~\i%¥(iij¡) . 100. 100.0 R GEt ED A G 2~ / 04 Gas Con . conmssion Anchora IIlnnn 11 :U::¡,?? ¡Jill .:0... ¡, 20 :!iSG 5.: 0 ¡'S 11..81..111 . . TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTERJP ARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME e!t-¡ ;It 9 /) ~ ~ PTD# (~C?I - Îb / ~evelopment Service Exploration Stratigraphic CHECK WßA T ADD-ONS ~'CL UE ". APPLIES (OPTIONS) MULTI Tbe permit is for a new weJlboresegment of LATERAL existing wen , Permit No, API No. . (If API num ber Production. should continue to be reported as last two (2) digits a function' of tbe original API number. stated are between 60-69) above. Pn.,OT HOLE In accordance witb 20 AAC 25.005(1), an (PH) records, data and logs acquired for tbe pilot bole must be clearly differentiated În botb name (name on permit plus PH) and API number (50 - 70/80) from records, data and logs acquired for wen (name on permit). SPACING Tbe permit is approved subject ·to fuD EXCEPTION compliance with 20 AAC 25.05S~ Approval to perforate and produce is contingent upon issuance of ~ conservation order approving a spacing exception. (Company Name) assumes tbe liability of any protest to tbe spacing .eJception tbat may occur. DRY DITCH All dry ditcb sample sets submitted to tbe SAMPLE Commission must be in no greater ·tban 30' sample intervals from below tbe permafrost or from wbere samples are first caugbt and 10' sample iIiter:vals tbrougb target zones. . . Well bore seg 0 Annular Disposal 0 Program DEV On/Off Shore On 9- Unit KENAI, C.L.U. BELUGA GAS - 448575 Well Name: CANNERY L' 0 Initial ClassfType DEVI 1-GAS GeoArea Administration ....... Y~s. - - - - -- - - - - - 2 Leas~numberappropriate. . . - - - - - - - - - - - - - - Yßs - - - - -- 3 .U.nique weltn.ame_a[ld ou.mb.er . . . . . . . . . _ _ . . . _ . . . . ... . ... . .Y~s - - - - - - - - - - - - - - - - - 4 Well JQcated in.a d.efine~pool. . - - - - - - - - - - - - - - Y~s 5 WellJQcated proper ~istance. from driJling \,mitboundjil)'. . . . .... Yßs 6 WeJUQcated pr.oper .distance from otber wells . . . .. Y~s - - - - - - - - - 7 .SJ,I{fjçient jicreage .available in. dril\iog unit. . . . . . . . .Y~s 8 Jtd~viated, is. weJlbQre platincJu.ded . . . .. Y~s - - - - - - - - - - - 9 .Operator only: affeçted party. . . . . . . . . . .Y~s - - - - - - - - - 10 .0Jerator bas.appropriateJ:~ond inJorce . . . . . _ _ . . . . . . . . _....... Yßs . - - - - - - - - - - - - - - - - 11 P~rmit c.ao be issued withQut co.nserva!ion order. ... Y~s - - -- - - - - - Appr Date 12 P~UTJit can be issued witbQut ad.ministrative.approvaJ . Yßs RPC 8/23/2004 13 Can permit be approved before 15-day wait Yes 14 WelUQC<ited within area and.strataauthorized by.lojectiolJ Ord~[ # (puUO# in.commß[lts).(For. .NA - - - - - - - - -- 15 _AJI wells.witJ1in.1l4J'uile.area.ot review id~[Itifjed (For servjCßJ>v.eU only). . . _ _ . . _ . . . . . .NA - - - - - . - - - - - - - - - -- 16 Pre-produ.ced injector; ~uratiQn.ot pre-pro~uction I~ss. than 3. montbs. (For.service well QnJy) NA - - - - - - - - 17 AÇMP.FJnding .of Con.si.stency.has bee.nissued. for. tbis project. - - - -- .NA - Engineering 18 .C.ondu.ctor string.prQvided . . . . . - - - - - Y~s 20~' @ 13.0'. . 19 .S.udaCß.casing.protec.ts alLknown USDWs . . . .Yßs 20 .CMT v.ol adeq uateJo circulate.o.n .cond.uctor. & surt c.sg . - - - - - - Yes Ade~uate ex.cess, . . . . 21 .CMT v.ol adequ.ate to tie-inJQng .string tosud csg. . . . . . - - - - - No. 22 .CMTwill coveraJl known.prQductive bQrizon.s. - - - - - Y~s - - - - - 23 C.asing designs ad.eQua!e for C,T" B& permafr.ost - - - - - - - - - - Yes - - - - - - - - - - - - - 24 A~equatetankage.or re.seIYe pit. Y~s Glacier.Rig 1.. . . . . . . . . 25 Jf.a.re-~[ilt hasa. to-403 tQr abandonment be~[I approved. . . . NA /IIewwell,. . - - - - - 26 .Mequate.weJlbore~eparaijonJro'pose~. . . . _ . . . . . . . . . . . . . . . . . . .Y~s - - - - - - - - - - - - - - - - -. 27 Jf.divertefJeq.uired, dQes iLmeet reguJations. . . . . . . . . . . . . . . . . . . . Y~s - - - - - - -- Appr Date 28 .Drilliog fluid. program schematic&. eq.uip Ji$ta~equat~. . . . - - - - - - Yes Max. MW1.o..0.ppg.. WGA 8/24/2004 29 .BOPEs,.d.othey meetreguJation . . . Y~s 30 .BOPE.press raliog appropriate; test to (pul psig in.comments). - - - - - - Y~s Test to.2500.psi. .MSF> 19.46 psi.. 31 CMkemanifold complies w/APIRP-53 (May 84). . . - - - - - - - - ~ Y~s 32 WQrk will occJ,lr without .operation .shutdown. - - - - - - - - - - - - - - Y~s 33 .Is presence. Qf H2$ gas prob.able. . - - - - - - - - - - - - - - - - - - - -- No. 34 MecbanicaLcoodJtio[l otwells within ,6.08. verified (for.sßrvice welJ only). . . NA Geology 35 P~rmitc.a!1 be issued wlo hydrogens.ulfide meas_ures. Yes 36 .D.ata.preseoted on potential overpressure .zone.s. . . . . . NA Appr Date 37 S~ism¡c.analysjs. Qf sbaJlow gas.z.ooes. .NA - - - - - RPC 8/24/2004 38 .S~abe~ .conditioo survey (if off-sh.ore) . .NA - - - -- 39 . CQnta.ctnamelpJ1oneJorweekly progressreRorts [exploratol)'onlYl - - - - NA - Geologic Date: Engineering Date Public Commissioner: Commissioner: Commissioner tJÀ:S rIJo)~