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Home My WebLink About207-064Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 2/15/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 34-6 (PTD 207-064) Perf 01/28/2022 Please include current contact information if different from above. 37' (6HW Received By: 02/15/2022 By Abby Bell at 11:41 am, Feb 15, 2022 1 Regg, James B (OGC) From:Brooks, Phoebe L (OGC) Sent:Tuesday, February 8, 2022 7:57 AM To:Herb Upton - (C) Cc:Regg, James B (OGC) Subject:RE: KGF MIT KBU 34-6 Attachments:MIT KBU 34-6 02-05-22 revised.xlsx Attached is a revised report with the following revisions: ‐ Change Type Inj to “N” – well is a gas producer ‐ Change Test psi to match sundry – 1500 psi ‐ Change Remarks to “Gas producer. Test per Sundry 322‐018. Return to production.” These revisions have been reflected on our latest MIT template (the template used was from 2012) which can be found on our website here: https://www.commerce.alaska.gov/web/aogcc/Forms.aspx Please update your copy and template. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907‐793‐1242 Fax: 907‐276‐7542 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Herb Upton ‐ (C) <hupton@hilcorp.com> Sent: Sunday, February 6, 2022 9:20 AM To: Regg, James B (OGC) <jim.regg@alaska.gov>; DOA AOGCC Prudhoe Bay <doa.aogcc.prudhoe.bay@alaska.gov>; Brooks, Phoebe L (OGC) <phoebe.brooks@alaska.gov>; Wallace, Chris D (OGC) <chris.wallace@alaska.gov> Subject: KGF MIT KBU 34‐6 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. Some people who received this message don't often get email from hupton@hilcorp.com. Learn why this is important CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. JBR; 2/8/2022 Submit to: OPERATOR: FIELD / UNIT / PAD: DATE: OPERATOR REP: AOGCC REP: Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD 2070640 Type Inj N Tubing 62 62 62 62 62 62 Type Test P Packer TVD BBL Pump IA 730 1652 1633 1630 1627 1625 Interval O Test psi 1500 BBL Return OA 15 15 15 15 15 15 Result P Well Pressures:Pretest Initial 15 Min.30 Min.45 Min.60 Min. PTD Type Inj Tubing Type Test Packer TVD BBL Pump IA Interval Test psi BBL Return OA Result TYPE INJ Codes TYPE TEST Codes INTERVAL Codes Result Codes W = Water P = Pressure Test I = Initial Test P = Pass G = Gas O = Other (describe in Notes)4 = Four Year Cycle F = Fail S = Slurry V = Required by Variance I = Inconclusive I = Industrial Wastewater O = Other (describe in notes) N = Not Injecting STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION Mechanical Integrity Test jim.regg@alaska.gov;AOGCC.Inspectors@alaska.gov;phoebe.brooks@alaska.gov chris.wallace@alaska.gov Notes: Hilcorp Alaska LLC Kenai Gas Field/Kenai/41-7 Herb Upton 02/05/22 Notes:Gas producer. Test per Sundry 322-018. Well returned to production. KBU 34-6 Form 10-426 (Revised 01/2017)2022-0205_MITP_KBU_34-6      JBR; 2/8/2022 MEMORANDUM TO: Jim Regg,, Z �Z// (7Z� P.I. Supervisor FROM: Adam Earl Petroleum Inspector NON -CONFIDENTIAL State of Alaska Alaska Oil and Gas Conservation Commission DATE: Wednesday, February 23, 2022 SUBJECT: Mechanical Integrity Tests Hilcorp Alaska, LLC 34-6 KENAI BELUGA UNIT 34-6 Sre: Inspector Reviewed By;rn� P.I. Supry Jr^^— Comm Well Name KENAI BELUGA UNIT 34-6 API Well Number 50-133-20568-00-00 Inspector Name: Adam Earl Permit Number: 207-064-0 Inspection Date: 2/2/2022 0 Insp Num: mitAGE220209111316 Rel Insp Num: Packer Depth Pretest Initial 15 Min 30 Min 45 Min 60 Min Well 34-6 ype Inj N TVD Tubing 40 PTD 2070640 4ypeTest SPT Test psi 1500 IA 1 so - BBL Pumped: 5.5 ' BBL Returned: OA 75 - Interval OTHER ]P/1F F Notes • Producer-- ,after adding perfs, MIT -IA to 1500psi as per Sundry 322-019/pumped 5.5 bbls total in three stages. Wouldn't pressure up. 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hͲϱцϱ͕ϭϰϲΖцϱ͕ϭϱϳΖϮͲϯͬϴΗ ϱdWƌŽƉŽƐĞĚ hͲϱϱ͕ϭϰϲΖϱ͕ϭϱϳΖϮͲϯͬϴΗϱKƉĞŶϬϭͬϮϭͬϭϲ hͲϱцϱ͕ϭϳϴΖцϱ͕ϭϵϮΖϮͲϯͬϴΗ ϱdWƌŽƉŽƐĞĚ hͲϱϱ͕ϭϳϴΖϱ͕ϭϵϮΖϮͲϯͬϴΗϱKƉĞŶϬϭͬϮϭͬϭϲ hͲϳϱ͕ϮϰϰΖϱ͕ϮϵϭΖϮͲϯͬϴΗϱKƉĞŶϬϴͬϮϳͬϭϵ hͲϳцϱ͕ϮϴϬΖцϱ͕ϮϴϱΖϮͲϯͬϴΗ ϱdWƌŽƉŽƐĞĚ hͲϱ hͲϱ hͲϭy͕hͲϭ hϮ )LOOWDJJHG# RQ STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Ll Plug Perforations LJ Fracture Stimulate Pull Tubing Ll Operations shutdown Li Performed: Suspend ❑ Perforate 0 Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 Exploratory ❑ 207-064 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6. API Number: AK 99503 50-133-20568-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: A028142 Kenai Beluga Unit (KBU) 34-06 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kenai Gas Filed - Beluga/Upper Tyonek Gas Pool 11. Present Well Condition Summary: Total Depth measured 7,739 feet Plugs measured 5,593 feet true vertical 7,582 feet Junk measured N/A feet Effective Depth measured 7,629 feet Packer measured N/A feet true vertical 7,472 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' Surface 1,549' 13-3/8" 1,570' 1,491' 3,450psi 1,950psi Intermediate 5,415' 9-5/8" 5,436' 5,279' 5,750psi 3,090psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160psi 10,540psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / L-80 7,717' MD 7,560' TVD Packers and SSSV (type, measured and true vertical depth) N/A; N/A N/A; N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 488 0 80 31 Subsequent to operation: 0 1175 0 85 51 14. Attachments (required per 20 AAC 25.070, 25.077, s 25.283) 15. Well Class after work: Daily Report of Well Operations ❑� Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-370 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkEamerna hilcoro com yr Q 21/[Authorized Signature: cv rJ 6. k Date: 1/� J /� Contact Phone: 777-8420 Form 10-404 Revised 412017 X0/ 4711- J0'VV¢ ' 113 M LA/M 0 7 2019 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 34-06 50-133-20568-00 1 207-064 8/27/19 8/27/19 Daily Operations: 08/27/2019 -Tuesday Sign in. Mobe to location. PTW and JSA. Spot and rig up lubricator. PT to 250 psi low and 3,000 psi high. TP - 319 psi. Shut well in and broke over around 260 psi. Hooked up high pressure hose from another well started flowing 800 psi into 34-06 from 1:30 am to 8:00 am. Shut well in and tubing pressure stared falling down to 260 psi. RIH w/GPT tool and tied into perf log date 2016. Ran correlation log and was told we needed to 10'. Added 10' and sent back to anchorage and log was good. Found fluid level at 5,202' with 219 psi on tubing. POOH. RIH w/ 2-3/8" x 5' Razor HC, 5 spf, 60 deg phase and tie into GPT log. Started flowing well at 650k at 35 psi. Ran correlation log and send to town. Get ok to perf from 5 280' to 5.2�; Fired gun with 35 psi on tubing, 5 min - 47 psi, 10 min - 66 psi and 15 min 46 psi. POOH. All shots fired gun was wet. Rig down lubricator, turn well over to field and moved to KBU 22-06. Well is flowing 725K at 37 psi. ff Hi#corp Alaska -028142 7' /01' AM KBU 34-6 Pad 41-7 132' FSL, 972' FEL Sec. 6, UN, R11 W, S.M. Contluctor SCHEMATIC Well Name & Number:EM uga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish:nsula Borough State: Alaska Country: USA Perforations (MD):' - 7,380' Perf (ND): 4,965' - 7,223' Angle Q KOP and Depth:0' 300 ft Angle/Perfs: .2° —. 0.40 0.2--0.4- Completion Completion Fluid: Dated Completed: Ground Level (MSL): 66.1' Revised by:uz Last Revison Date: 9118/2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Ll Plug Perforations LJ Fracture Stimulate Pull Tubing Ll Operations shutdown Li Performed: Suspend ❑ Perforate 0 Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development 0 Exploratory ❑ 207-064 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6. API Number: AK 99503 50-133-20568-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: A028142 Kenai Beluga Unit (KBU) 34-06 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kenai Gas Filed - Beluga/Upper Tyonek Gas Pool 11. Present Well Condition Summary: Total Depth measured 7,739 feet Plugs measured 5,593 feet true vertical 7,582 feet Junk measured N/A feet Effective Depth measured 7,629 feet Packer measured N/A feet true vertical 7,472 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' Surface 1,549' 13-3/8" 1,570' 1,491' 3,450psi 1,950psi Intermediate 5,415' 9-5/8" 5,436' 5,279' 5,750psi 3,090psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160psi 10,540psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / L-80 7,717' MD 7,560' TVD Packers and SSSV (type, measured and true vertical depth) N/A; N/A N/A; N/A 12. Stimulation or cement squeeze summary: N/A Intervals treated (measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 488 0 80 31 Subsequent to operation: 0 1175 0 85 51 14. Attachments (required per 20 AAC 25.070, 25.077, s 25.283) 15. Well Class after work: Daily Report of Well Operations ❑� Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-370 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkEamerna hilcoro com yr Q 21/[Authorized Signature: cv rJ 6. k Date: 1/� J /� Contact Phone: 777-8420 Form 10-404 Revised 412017 X0/ 4711- J0'VV¢ ' 113 M LA/M 0 7 2019 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 34-06 50-133-20568-00 1 207-064 8/27/19 8/27/19 Daily Operations: 08/27/2019 -Tuesday Sign in. Mobe to location. PTW and JSA. Spot and rig up lubricator. PT to 250 psi low and 3,000 psi high. TP - 319 psi. Shut well in and broke over around 260 psi. Hooked up high pressure hose from another well started flowing 800 psi into 34-06 from 1:30 am to 8:00 am. Shut well in and tubing pressure stared falling down to 260 psi. RIH w/GPT tool and tied into perf log date 2016. Ran correlation log and was told we needed to 10'. Added 10' and sent back to anchorage and log was good. Found fluid level at 5,202' with 219 psi on tubing. POOH. RIH w/ 2-3/8" x 5' Razor HC, 5 spf, 60 deg phase and tie into GPT log. Started flowing well at 650k at 35 psi. Ran correlation log and send to town. Get ok to perf from 5 280' to 5.2�; Fired gun with 35 psi on tubing, 5 min - 47 psi, 10 min - 66 psi and 15 min 46 psi. POOH. All shots fired gun was wet. Rig down lubricator, turn well over to field and moved to KBU 22-06. Well is flowing 725K at 37 psi. ff Hi#corp Alaska -028142 7' /01' AM KBU 34-6 Pad 41-7 132' FSL, 972' FEL Sec. 6, UN, R11 W, S.M. Contluctor SCHEMATIC Well Name & Number:EM uga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish:nsula Borough State: Alaska Country: USA Perforations (MD):' - 7,380' Perf (ND): 4,965' - 7,223' Angle Q KOP and Depth:0' 300 ft Angle/Perfs: .2° —. 0.40 0.2--0.4- Completion Completion Fluid: Dated Completed: Ground Level (MSL): 66.1' Revised by:uz Last Revison Date: 9118/2019 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KBU 34-06 Permit to Drill Number: 207-064 Sundry Number: 319-370 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 vswvv.aogcc.a laska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 49 Daniel T. Seamount, Jr. Commissioner DATED this U 7dayy of August, 2019. RBDMSI��AUG 19 P019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n AAr. 9, 7Rn 14- AUG 13 201:9 AOGCC 1. Type of Request: Abandon ❑ Plug Perforations f • Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate ❑Z Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susie Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development ❑✓ Strati ra hic ❑ g p ❑ Service r 207-064 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: � Anchorage Alaska 99503 50133-20568-00-00 7. If perforating: r 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 51 Oa Will planned perforations require a spacing exception? Yes ❑ No ❑� Kenai Beluga Unit (KBU) 34-06 9. Property Designation (Lease Number): 10. Field/Pool(s): A-028142 • Kenai Gas Field - Beluga/Upper Tyonek Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,739' 7,582' 7,629' 7,472' –2,229 psi 5,593' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' Surface 1,549 13-3/8" 1,570' 1,491' 3,450 psi 1,950 psi Intermediate 5,415' 9-5/8" 5,436' 5,279' 5,750 psi 3,090 psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3# / L-80 7,717 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development Service ❑ 14. Estimated Date for 'L7} 15. Well Status after proposed work: Commencing Operations: August]8f8, 2019 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Be York 777-8345 Contact Name: Taylor Nasse Authorized Title: Operations Manager Contact Email: tnasse� p Contact Phone: 777-8354 l"4,1 Authorized Signature Date: 1 COMMISSI USE ONLY Conditions of approve"otify Commission so that a representative may witness Sundry Number: n I C1 -10 •✓S Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS 2�AUG 191019 Post Initial Injection MIT Req'd? Yes ❑ No ❑ U Spacing Exception Required? Yes ❑ No M' Subsequent Form Required: / — / 041 APPROVED BY I 1 �}//5 Approved by' COMMISSIONER THE COMMISSION Date: OY (1 ��21�''1�- '� 4 •is /? Form 1 - Revise 4 017 A proved applicatio r i I� Ie� r f o� fk he date of approval. Submit Form and Attachments in Duplicate �+J*9$ ('�f, (fes..1014 S 1 4 /` H MI.,p Alaska, LL, Well Prognosis Well: KBU 34-06 Date:08/09/2019 Well Name: KBU 34-06 API Number: 50-133-20568-00 Current Status: Flowing Leg: N/A Estimated Start Date: August 23, 2019 Rig: N/A Reg. Approval Req'd? 403 Date Reg. Approval Rec'vd: Upper Beluga Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-064 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: 10' Upper Beluga UB 4B Maximum Expected BHP: Max. Potential Surface Pressure: Brief Well Summary — 2,229 psi @ 5,184' TVD (Assumed 0.43 psi/ft gradient) — 1,711 psi (0.10 psi/ft gas gradient) Kenai Beluga Unit #34-06 was drilled as a sidetrack EXCAPE completion in 2007 to target gas sands in the Beluga formations. The initial EXCAPE modules were placed on production in July 2007. The well loaded up in April 2014 and was unable to sustain flow. The well was plugged back and recompleted in the Upper Beluga 5A sand in July 2015, and additional perforations in the UB -5A and UB -513 were added in 2016. The purpose of this work/sundry is to add perforations in the Upper Beluga ands. Notes Regarding Wellbore Condition • Well is currently flowing 520 MSCFD at 30 psig and making 0 BWPD. • Make slickline drift and tag run prior to starting work. E -line Procedure: 1. MIRU E -line, PT lubricator to 2,000 psi Hi 250 Low. a. Tree connection is 4.5" OTIS. 2. RU perforating guns. 3. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT Upper Beluga UB 1 4846 4860 14' Upper Beluga UB 2 4897 4910 13' Upper Beluga UB 3 4963 4972 9' Upper Beluga UB 3A 4994 5019 25' Upper Beluga UB 4A 5058 5068 10' Upper Beluga UB 4B 5075 5098 23' Upper Beluga UB 7A 5244 5291 47' Upper Beluga UB 8 5317 5341 24' a. Shut in well 5 minutes before perforating. b. Use Gumma/CCL/to correlate. c. Record tubing pressures before and after each perforating run. Well Prognosis Well: KBU 34-06 101wrp Alaska, LG Date: 08/09/2019 4. POOH and RD E -line. 5. Turn well over to production. E -line Procedure (Contingency): If any zone produces sand and/or water. 6. MIRU E -line, PT lubricator to 2,000 psi Hi 250 Low. 7. RIH and set 3-1/2" CIBP (or tubing patch). Set at depth specified by Engineer. 8. RU Slickline. Swab fluid down to depth approved by Engineer. 9. RIH with bailer assembly. Dump bail cement. POOH. 10. Continue with Step 3 above. Attachments: 1. Actual Schematic 2. Proposed Schematic U Hilcorp Alaska 50-133-20568-00-00 r Des: A - 028142 athn: 87' (21' AGL) ',62,144.95 60° 27' 35.566" N 151' 14' 48.603" W 5/17/2007 18:00 hrs hod: 5/30/2007 Tree c/at = 4-314.Otis CBL TOC - 4.100' (8/13107) 1,336'above 9-518"shoe Escape System Details: - Ceramic flapper valves below each module as follows: - All reclosing flappers Flappers MD (RKB): Module 10 - 5,762' Module 9 - 6,462' Module 8 - 6,751' Module 7 - 6,792' Module 6 - 6,833' Module 5 - 6,875' Module 4 - 7,028' Module 3 - 7,140 Module 2 - 7,227 Module 1 - NA Baker Coll Jetted well clean to PBTD -7629' CTM (9-16-2011) KBU 34-6 Pad 41-7 132' FSL, 972' FEL Sec. 6, T4N, R11 W, S.M. Cement tagged @ 5,593' on 6/26/15 CIBP @ 5,701' capped w/ 108' of cement SCHEMATIC Conductor 'Perforation Y.- Lease: 20" K-65 133 ppf PE State: Top Bottom MD 0' 114' TVD 0' 114' Surface Casing 13,3/8" J-55 68 ppf BTC TOP Bottom MD 0' 1,670' TVD 0' 1,491' 16" hole, Cmt w/ 490 sks (226 bbis) 12 ppg Class G. Type 1 curt with 30 bible, 12 ppg cmt to surface. (100% returns) Imermedlate Casing 9-618" L-80 40 ppf BTC Top Bottom MD 0' 6,436' TVD 0' 5,279' 12.1/4" hole, Cmt w/ 340 sks (190 bbla) 10.6 ppg Class G cmt 100% retums, floats held. Production Tubing 3-1/2" L-80 9.3 ppf EUE TOR Bottom Ord MD 0' 7,717' TVD 0' 7,560- 8-1/2" hole, Cmt w/ 1,076 sks (647 bbls) 11.6 ppg Class G cmt. 6.26" OD control line protectors to 6,436' RK13. Escape System Details: 10 Excape modules placed - Red control line for top 6 modules control line for middle 3 modules Green control line for bottom 1 module - Ceramic flapper valves below each module except for module 1. Module 9 - 6,442' -6,452' (Beluga) Isolated Module 8 - 6,731'- 6,741' (Beluga) Isolated Module 7 - 6,772'- 6,782' (Beluga) Isolated Module 6 - 6,813'-6,823' (Beluga) Isolated Module 5 - 6,855' - 6,865' (Beluga) Isolated Module 4 - 7,008'-7,018' (Beluga) Isolated Module 3 - 7,120'- 7,130' (Beluga) Isolated Module 2 - 7,208'- 7,218' (Beluga) Isolated Module 1 - 7,369'- 7,379' (Tyonek) Isolated 4: 'Perforation Y.- Lease: Kenai Gas Field, A-028142 Detail Kenai Peninsula Borough State: Alaska I Country: USA Perforations (MD): 5,122'- 7,380' Sands Too (MD) Btm IMDI Gun Slze SPF Status Date 6°h KCL UB -6A 6,122' 6,136' 2-1/2" 6 Open 07/01/15 TD PBTD UB -6A 1IB-6B 6,146' 6,178' 6,157' 5,192' 2418" 2418" 6 6 Open Open 01/21/16 01/21/16 7,733zMD 7,b3$'lA0 7,582' TVD 7,472' TVD Well Name & Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska I Country: USA Perforations (MD): 5,122'- 7,380' Pert (TVD): 4,965' - 7,223' Angle @ KOP and Depth: -3.1" 1100' @ 300 ft Angle/Perfs: 0.20-0.40 Completion Fluid: 6°h KCL Dated Completed: 6/30/2007 Ground Level (MSL): 66.1' Revised by: Donna Ambruz Last Revison Date: 1/22/2016 U Hilcorp Alaska A- 87' 144.95 1° 27' 35.566" N ° 14' 48.603" W 7/2007 18:00 hrs I: 5/30/2007 Tree cxn'= 4-3/4" Otis. CBL TOC - 4.100'(61131071 1,336'above 9-5/8" shoe Excape System Details: - Ceramic flapper valves below each module as follows: - All reclosing flappers Flappers MD (RKB): Module 10 - 5,762' Module 9 - 6,462' Module 8 - 6,751' Module 7 - 6,792' Module 6 - 6,833' Module 5 - 6,875' Module 4 - 7,028' Module 3 - 7,140 Module 2 - 7,227 Module 1 - NA Pollard I Pollard tagged fill @ 7224' kb :W18/2012) Baker Coil jetted well clean to PBTD -7629' CTM (9-16-2011) KBU 34-6 Pad 41-7 132' FSL, 972' FEL Sec. 6, T4N, R1 1W, S.M. Cement tagged @ 5,593' on 6128115 TO PBTD 7,739' MD 7,629' MD 7,582' TVD 7,472' TVD a37 -y PROPOSED SCHEMATIC Conductor Kenai Beluga Unit 34-6Lease: - 10 Excape modules placed 20" K-55 133 ppf PE of cement Too Bottom MD 0' 114' TVD 0' 114' Surface Casino 13-3/8" J-55 68 ppf BTC Tog Bottom MD 0' 1,570' TVD 0' 1,491- 16" hole, Cmt w/490 sks (226 bbls) 12 ppg Class G, Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (100% returns) Intermediate Casino 9.518" L-80 40 ppf BTC TTS Bottom MD 0' 5,436' TVD 0' 5,279' 12-114" hole, Cant w/ 340 sks (190 bbls) 10.5 ppg Class G curt. 100% returns, floats held. 3-112" L-80 9.3 ppf EUE Tio Bottom 8rd MD 0' 7,717' TVD 0' 7,560' SALT' hole, Cmt w/ 1,076 sks (547 bbls) 11.5 ppg Class G cmt. 6.25" OD control line CIBP @ 5,701' Kenai Beluga Unit 34-6Lease: - 10 Excape modules placed capped wl 108' County or Parish: - Red control line for top 6 modules of cement Bum (MDI - control line for middle 3 modules SPF Status Date - Green control line for bottom 1 module 4,846' - Ceramic flapper valves below each module Angle/Perfs: except for module 1. Module 10 - 5,743'- 5,753' (Beluga) Isolated Module 9 - 6,442'- 6,452' (Beluga) Isolated Module 8 - 6,731'- 6,741' (Beluga) Isolated Module 7 - 6,772'-6,782' (Beluga) Isolated Module 6 - 6,813'-6,823' (Beluga) Isolated Module 5 - 6,855'- 6,865' (Beluga) Isolated Module 4 - 7,008'- 7,018' (Beluga) Isolated Module 3 - 7,120'-7,130' (Beluga) Isolated Module 2 - 7,208' - 7,218' (Beluga) Isolated Well Name & Number: Kenai Beluga Unit 34-6Lease: Perforation Detail Kenai Gas Field, A-028142 County or Parish: Sands Too (MD) Bum (MDI Gun Size SPF Status Date US -1 4,846' 4,860' Angle/Perfs: 0.2° -r 0.4- .4°Com Proposed UB -2 4,897' 4,910' Dated Completed: 6/30/2007 Proposed UB -3 4,963' 4,972' Last Revison Date: 1/22/2016 Proposed UB -3A 4,994' 5,019' Proposed UB -4A 5,058' 5,068' Proposed UB4B 5,075' 5,098' Proposed UB -5A 6,122' 5,136' 2-1/2" 6 Open 07/01/15 UBZA 5,146' 5,157' 2-3/8" 5 Open 01/21/16 UB -58 5,178' 5,192' 2-318" 5 Open 01/21/16 UB -7A 5,244' 5,291' Proposed 1.113-8 5,317' 5,341' Proposed Well Name & Number: Kenai Beluga Unit 34-6Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough Stale: Alaska I Country: USA Perforations (MD): 5,122' - 7,380' Pert (TVD): 4,965' - 7,223' Angle @ KOP and Depth: -3.1-1100' @ 300 ft Angle/Perfs: 0.2° -r 0.4- .4°Com Completion letion Fluid: 6% KCL Dated Completed: 6/30/2007 Ground Level (MSL): 66.1' Revised by: Donna Ambruz Last Revison Date: 1/22/2016 STATE OF ALASKA � AA OIL AND GAS CONSERVATION COM SSION REPORT OF SUNDRY WELL OPERATIONS ?'' 3` 1.Operations Abandon U Plug Perforations U Fracture Stimulate aPull Tubing-LI pe ations shutdown LJ Performed: Suspend ❑ Perforate ❑r Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ 207-064 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20568-00 7.Property Designation(Lease Number): 8.Well Name and Number: A-028142 Kenai Beluga Unit(KBU)34-06 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Gas Field-Beluga/Upper Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 7,739 feet Plugs measured 5,593 feet true vertical 7,582 feet Junk measured N/A feet Effective Depth measured 7,629 feet Packer measured N/A feet true vertical 7,472 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' Surface 1,549' 13-3/8" 1,570' 1,491' 3,450psi 1,950psi Intermediate 5,415' 9-5/8" 5,436' 5,279' 5,750psi 3,090psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160psi 10,540psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic5C Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3#/L-80 7,717'MD 7,560'TVD Packers and SSSV(type,measured and true vertical depth) N/A;N/A N/A;N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 794 0 80 66 Subsequent to operation: 0 1,838 0 82 91 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑� Exploratory❑ Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-011 Contact Taylor Nasse-777-8354 Email tnasse a( hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature "V7/ ` Phone 907-777-8405 Date ,311 ik 7.99 3--11—`t, , e,A4 Form 10-404 Revised 5/2015 7,4. - RBDMS I', MAR 0 2 2016 Submit Original Only • • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 34-06 E-Line 50-133-20568-00 207-064 1/21/16 1/21/16 Daily Operations: 01/21/2016-Thursday Meet at office. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT lubricator to 250 psi low and 2,000 psi high.Arm gun. RIH with 2-3/8" x 14' Connex, 5 spf, 60 deg phase and tie into Halliburton TMD 3D log dated 6- 17-15. Run correlation log and send to town.Jacob gave the ok to perf from 5,178'to 5,192' (drop theeroposed depths down 8 feet). Shut well in for 5 min and fired gun with 134 psi, went to 175 psi when fired and 391 psi after 5 min. POOH all shots fired. RIH with 2-3/8" x 11' Connex, 5 spf, 60 deg phase and tie into Halliburton TMD 3D log dated 6-17-15. Run correlation log and send to town.Jacob gave the ok to perf from 5,146'to 5,157'. Spotted gun and fired with 462.7 psi and 466.9 psi after 5 min.. POOH all shots fired. Rig down lubricator and turn well over to field.TP-480 psi • ,11KBU 34-6 HiIcor!) Alaska Pad 41-7 SCHEMATIC Permit#: 207-064 132' FSL, 972' FEL API#: 50-133-20568-00-00 Sec. 6, T4N, R11 W, S.M. conductor Property Des: A-028142 KB Elevation: 87' (21'AGL) 20 7-55 Bottom PE 0 X= 274,939.64 r MD 0' 114' Y= 2,362,144.95 , , ND 0' 114' Lat: 60° 27' 35.566" N Long: 151° 14' 48.603" W Spud: 5/17/2007 18:00 hrs TD Reached: 5/30/2007 Surface Casing 13-3I8" J-55 68 ppf BTC Top Bottom MD 0' 1,570' ND 0' 1,491' • 16" hole, Cmt w/490 sks(226 bbls)12 ppg moi. Class G,Type 1 cmt with 30 bbls,12 ppg cmt Tree cxn=4-3/4"Otis to surface. (100%returns) CBL TOC-4,100'(6/13/07) Intermediate Casing 1,336'above 9-5/8"shoeUB_5A 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,436' UB-5A ND 0' 5,279' Excape System Details: -Ceramic flapper valves below UB-5B 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 each module as follows: ppg Class G cmt. 100%returns,floats held. -All reclosing flappers Flappers MD(RKB): Production Tubing Module 10 5,762' 3.1/2" L-80 9.3 ppf EUE Module 9 - 6,462' Top Bottom 8rd Module 8 - 6,751' Cement tagged @ MD o' 7,717' Module 7 - 6,792' 5,593'on ND o' 7,560' Module 6 6,833' 6/28/15 A CIBP @ 5,701' 8-1/2"hole,Cmt w/1,076 sks(547 bbls) Module 5 - 6,875' V 1 di_..--.' capped w/108' 11.5 ppg Class G cmt.6.25"OD control line Module 4 - 7,028' of cement protectors to 5,436'RKB. Module 3 - 7,140 II Module 2 - 7,227 .?,` Module Module 1 - NA 1 ;4 Excape System Details: 1:11 010 Excape modules placed ? control line for top 6 modules to to: Tar - control line for middle 3 modules - ^_:;);control line for bottom 1 module A1 `,, -Ceramic flapper valves below each module 0r `(1 except for module 1. "." „ , �i Perfs MD(RKB)(Beluga/TYonek Zones): Pollard tagged fill @ 7,196'kb (4/4/2014) + Module 10- 5,743'-5,753' (Beluga)Isolated Module 9 - 6,442'-6,452' (Beluga)Isolated Module 8 - 6,731'-6,741' (Beluga)Isolated Module 7 - 6,772'-6,782' (Beluga)Isolated Pollard tagged fill @ 7224'kb - --'-� Module 6 - 6,813'-6,823' (Beluga)Isolated (4/18/2012) ♦♦Ili� Module 5 - 6,855-6,865' (Beluga)Isolated Module 4 - 7,008'-7,018' (Beluga)Isolated ,' Module 3 - 7,120'-7,130' (Beluga)Isolated 1 "" Module 2 7,208' 7,218' (Beluga)Isolated .'! Module 1 - 7,369'-7,379' (Tyonek)Isolated Baker Coil jetted well clean to PBTD -7629'CTM (9-16-2011) . '1 Perforation Detail Sands Top(MD) Btm(MD) Gun Size SPF Status Date UB-5A 5,122' 5,136' 2-1/2" 6 Open 07/01/15 UB-5A 5,146' 5,157' 2-3/8" 5 Open 01/21/16 TD PBTD UB-5B 5,178' 5,192' 2-3/8" 5 Open 01/21/16 7,739'MD 7,629'MD 7,582'TVD 7,472'ND Well Name&Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 5,122'-7,380' Perf(TVD): 4,965'-7,223' Angle @ KOP and Depth: -3.10/100' @ 300 ft Angle/Perfs: 0.2°-,0.4° Completion Fluid: 6%KCL Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Donna Ambruz Last Revison Date: 1/22/2016 °F T% • • �w w\� cv THE STATE Alaska Oil and Gas - of Conservation Commission 333 West Seventh Avenue 1/4 GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF *h:' Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager j Hilcorp Alaska, LLC cCANAE 2 6 ,,� 1 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KBU 34-06 Permit to Drill Number: 207-064 Sundry Number: 316-011 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, 1--; 14C&_ Cathy . Foerster Chair DATED this II,day of January, 2016. RBDMSgol) 3AN 2 2016 • • RECEIVED STATE OF ALASKA A0 6 016 ALASKA OIL AND GAS CONSERVATION COMMISSION �o / ////6 APPLICATION FOR SUNDRY APPROVALS .BOG , �/ 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate 0 • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number Exploratory ❑ Development Q 207-064 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic EIService ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20568-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 510a • Kenai Beluga Unit(KBU)34-06 • Will planned perforations require a spacing exception? Yes ❑ No Q • 9.Property Designation(Lease Number): 10.Field/Pool(s): A-028142 • Kenai Gas Field-Beluga/Upper Tyonek Gas Pool - 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 7,739' • 7,582' ' 7,629' 7,472' 1,650psi 5,593' N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' Surface 1,549' 13-3/8" 1,570' 1,491' 3,450 psi 1,950 psi Intermediate 5,415' 9-5/8" 5,436' 5,279' 5,750 psi 3,090 psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160 psi 10,530 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 7,717 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary Q Wellbore schematic El13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development❑✓ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: January 20,2016 OIL ❑ WINJ 0 WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS L • WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasseehilcorD.corn Printed Name Chad Helgeson Title Operations Manager Signature ��r /�% Phone 907-777-8405 Date , 1/tO/16P COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 3lip • 0I1 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: N 21016 Post Initial Injection MIT Req'd? Yes ❑ No ❑ RgDM1� Spacing Exception Required? Yes ❑ No LK Subsequent Form Required: Po 1.-t011 / APPROVED BY Approved by: r - COMMISSIONER THE COMMISSION Date: /_ I( _ Kr, I-1-4.20 5orRIGINAL Subs Formane Form 10-4 3 Revised 11/2015for 12 months from the date of approval. Attachments' Duplicate 772 .%C6 /..7,/r • • Well Prognosis Well: KBU 34-06 Ilikorp Alaska,LL Date: 1/5/2016 Well Name: KBU 34-06 API Number: 50-133-20568-00 Current Status: Flowing Leg: N/A Estimated Start Date: January 20`h, 2016 Rig: N/A Reg.Approval Req'd? 403 Date Reg. Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-064 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907) 229-4824 (M) AFE Number: Maximum Expected BHP: — 2,162 psi @ 5,027' TVD (Assumed 0.43 psi/ft gradient) Max. Potential Surface Pressure: — 1,650 psi (0.10 psi/ft gas gradient) Brief Well Summary Kenai Beluga Unit #34-06 was drilled as a sidetrack EXCAPE completion in 2007 to target gas sands in the Beluga formations. The initial EXCAPE modules were placed on production in July 2007. The well loaded up in April 2014 and was unable to sustain flow. The well was plugged back and recompleted in the Upper Beluga 5A sand in July 2015. The purpose of this work/sundry is to add perforations in the Upper Beluga 5 sands. Notes Regarding Wellbore Condition • Well is currently flowing 70 MSCFD at 65 psig and making 0 BWPD. • Make slickline drift and tag run prior to starting work. E-line Procedure: 1. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. a. Tree connection is 4.5" OTIS. 2. RU 2-3/8" 5 SPF perforating guns. 3. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT SPF Upper Beluga UB-5A 5,146' 5,157' 11' 5 Upper Beluga UB-5B 5,170' 5,184' 14' 5 a. Shut in well 5 minutes before perforating. b. Use Gamma/CCL/to correlate. Correlate using TMD3D Log dated 6/17/15 (TMD3D Tie-in log). c. Record tubing pressures before and after each perforating run. 4. POOH and RD E-line. 5. Turn well over to production. 6. Note: If a sand is wet,then the zone will be plugged back with a tubing patch. Attachments: 1. Actual Schematic 2. Proposed Schematic • KBU 34-6 • ACTUAL Hilcorp Alaska Pad 41-7 SCHEMATIC Permit#: 207-064 132' FSL, 972' FEL API#: 50-133-20568-00-00 Sec. 6, T4N, R11W, S.M. Conductor Property Des: A-028142 KB Elevation: 87' (21'AGL) 20" K-55 133 ppf PE X= 274,939.64 -13p Bottom Y= 2,362,144.95 MD 0' 11a' Lat: 60° 27' 35.566" N , ,.k TVD 0' 114' Long: 151° 14' 48.603" W Spud: 5/17/2007 18:00 hrs ',' N * Surface Casing TD Reached: 5/30/2007 rJoi, 13-3/8" J-55 68 ppf BTC +- = Top Bottom MD 0' 1,570' ND 0' 1,491' r, ) ` 16" hole, Cmt w/490 sks(226 bbls)12 ppg Tree cxn=4-3/4"Otis 1 '11 Class G,Type 1 cmt with 30 bbls,12 ppg cmt to surface. (100%returns) & s d r CBL TOC-4.100'(6/13/07 Intermediate Casing 1,336'above 9-5/8"shoe 9.5/8" L-80 40 ppf BTC Top Bottom r,1 MD 0' 5,436' Try �° - UB-5A ND 0' 5,279' Excape System Details: .e ; -Ceramic flapper valves below 2 ', 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 each module as follows: ,y;!"�ppg Class G cmt. 100%returns,floats held. -All reclosing flappers Flappers MD(RKB): VI. .. Production Tubing Module 10 - 5,762' 3-1/2" L-80 9.3 ppf EUE Module 9 - 6,462' k,'� Top Bottom 8rd Module 8 - 6,751' Cement tagged @ r MD 0' 7,717' Module 7 - 6,792' 5,593'on ND 0' 7,560' Module 6 - 6,833' 6/28/15 \� CIBP @ 5,701' 8-1/2"hole,Cmtwl 1,076 sks(547 bbls) Module 5 - 6,875' i ♦- capped w/108' 11.5 ppg Class G cmt.6.25"OD control line Module 4 - 7,028' of cement protectors to 5,436'RKB. Module 3 - 7,140 I1 Module 2 - 7,227 , ( ; Module 1 - NA ? '4 Excape System Details: 1l A - 10 Excape modules placed -Red control line for top 6 modules .'- I v - control line for middle 3 modules i 1 -Green control line for bottom 1 module -Ceramic flapper valves below each module ,1 except for module 1. 41 6/, Perfs MD(RKB)(Beluqa/Tyonek Zones): I ..'i Pollard fill r. 7,1 fr kb (4/4/2014) Upper Beluga UB-5A(5,122'-5,136')Isolated (1 Module 10- 5,743'-5,753' (Beluga)Isolated `` - Module 9 - 6,442'-6,452' (Beluga)Isolated II Module 8 - 6,731'-6,741' (Beluga)Isolated Pollard tagged fill @ 7224'kb -♦, Module 7 - 6,772'-6,782' (Beluga)Isolated (4/18/2012) �� Module 6 - 6,813'-6,823' (Beluga)Isolated Module 5 - 6,855'-6,865' (Beluga)Isolated Module 4 - 7,008'-7,018' (Beluga)Isolated "J Module 3 - 7,120'-7,130' (Beluga)Isolated Module 2 - 7,208'-7,218' (Beluga)Isolated Baker Coil jetted well clean to PBTD • Module 1 - 7,369'-7,379' (Tyonek)Isolated 7629'CTM (9-16-2011) "a r3 TD PBTD 7,739'MD 7,629'MD 7,582'TVD 7,472'ND Well Name&Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 5,122'-7,380' Perf(TVD): 4,965'-7,223' Angle @ KOP and Depth: -3.1°/100' @ 300 ft Angle/Perfs: 0.2°-,0.4° Completion Fluid: 6%KCL Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Taylor Nasse Last Revison Date: 1/6/2015 • KBU 34-6 0 PROPOSED IIhk 'urp Alaska Pad 41-7 SCHEMATIC Permit#: 207-064 -- 132' FSL, 972' FEL API#: 50-133-20568-00-00 Sec. 6, T4N, R11 W, S.M. Conductor Property Des: A-028142 20" K-55 133 ppf PE KB Elevation: 87' (21'AGL) Top Bottom X= 274,939.64l. MD 0' 114' Y= 2,362,144.95 * ( N D 0' 114' Lat: 60° 27' 35.566" N `!�. Long: 151° 14' 48.603" W Spud: 5/17/2007 18:00 hrs Surface Casing TD Reached: 5/30/2007 13-318" J-55 68 ppf BTC Top Bottom MD 0' 1,570' TVD 0' 1,491' 1 16" hole, Cmt w/490 sks(226 bbls)12 ppg Tree cxn=4-314"Otis * . Class G,Type 1 cmt with 30 bbls,12 ppg cmt .'r to surface. (100%returns) R� i CBL TOC-4,100'(6/13/07) Intermediate Casing 1,336'above 9-5/8"shoeUB-SA 9-5/8" L-80 40 ppf BTC Toe Bottom _ / MD 0' 5,436' 9';UB-SA TVD 0' 5,279' Excape System Details: -Ceramic flapper valves below ,. UB-SB d 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 each module as follows: ,, ' ppg Class G cmt. 100%returns,floats held. -All reclosing flappers ,'a Flappers MD(RKB): ' Production Tubing Module 10 - 5,762' 3-1/2" L-80 9.3 ppf EUE Module 9 - 6,462' Top Bottom 8rd Module 8 - 6,751' Cement tagged @ * MD 0' 7,717' Module 7 - 6,792' 5,593'onTVD 0' 7,560' Module 6 - 6,833' 6/28/15 CIBP @ 5,701' 8-1/2"hole,Cmt w/1,076 sks(547 bbls) Module 5 - 6,875' capped w/108' 11.5 ppg Class G cmt.6.25"OD control line Module 4 - 7,028' Module 3 - 7,140 t iI of cement protectors to 5,436'RKB. Module 2 - 7,227 II Module 1 - NA Excape System Details: eiiI - 10 Excape modules placed t -Red control line for top 6 modules I - control line for middle 3 modules I) -Green control line for bottom 1 module -Ceramic flapper valves below each module IIIV except for module 1. .1 lit .;:' Perfs MD(RKB)(Beluga/Tyonek Zones): Pollard tagged fill @ 7,196'kb (4/4/2014)_ Module 10- 5,743'-5,753' (Beluga)Isolated Module 9 - 6,442'-6,452' (Beluga)Isolated Module 8 - 6,731'-6,741' (Beluga)Isolated �l I :l Module 7 - 6,772'-6,782' (Beluga)Isolated Pollard tagged fill @ 7224'kb Module 6 - 6,813'-6,823' (Beluga)Isolated (4/18/2012) IIS Module 5 - 6,855'-6,865' (Beluga)Isolated Module 4 - 7,008'-7,018' (Beluga)Isolated tot Module 3 - 7,120'-7,130' (Beluga)Isolated `' Module 2 - 7,208'-7,218' (Beluga)Isolated Module 1 - 7,369'-7,379' (Tyonek)Isolated Baker Coil jetted well clean to PBTD - -7629'CTM (9-16-2011) Perforation Detail Sands Top(MD) Btm(MD) Gun Size SPF Status Date UB-5A 5,122' 5,136' 2.1/2" 6 Open 07/01/15 U13-5A 5,146' 5,157' 2-318" 5 Proposed 1:3L - TD PBTD UB-5B 5,170' 5,184' 2-3/8" 5 Proposed TBD 7,739'MD 7,629'MD 7,582'TVD 7,472'TVD Well Name&Number: Kenai Beluga Unit 34-6 _ Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 5,122'-7,380' Perf(TVD): 4,965'-7,223' Angle @ KOP and Depth: -3.1°1100' @ 300 ft Angle/Perfs: 0.2°--,0.4° Completion Fluid: 6%KCL Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Taylor Nasse Last Revison Date: 1/5/2016 • STATE OF ALASKA AL _.:A OIL AND GAS CONSERVATION COMh.....,SION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon [J Plug Perforations U Fracture Stimulate [A Pull Tubing H Operations shutdown LJ Performed: Suspend ❑ Perforate ❑✓ Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑✓ Exploratory ❑ 207-064 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20568-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 Kenai Beluga Unit(KBU)34-06 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Gas Field-Beluga/Upper Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 7,739 feet Plugs measured 5,593 feeR E C I V E D true vertical 7,582 feet Junk measured N/A feet iU! 0 8 2015 Effective Depth measured 7,679 feet Packer measured N/A feet true vertical 7,522 feet true vertical N/A feet Ao G of Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' Surface 1,549' 13-3/8" 1,570' 1,491' 3,450psi 1,950psi Intermediate 5,415' 9-5/8" 5,436' 5,279' 5,750psi 3,090psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160psi 10,540psi Liner Perforation depth Measured depth See Attached Schematic SCANNED i i I 8 2 it 1 True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV(type,measured and true vertical depth) N/A N/A N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 0 Subsequent to operation: 0 449 0 0 67 14.Attachments(required per 20 AAC 25 070,25.071,a 25 283) 15.Well Class after work: Daily Report of Well Operations E Exploratory Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-306&315-392 Contact Stan Porhola Email spOrhOla((77hiICOrp.com Printed Name Stan Porhola Title Operations Engineer Signature ,,,,j -- pat__ Phone 907-777-8412 Date "'r all15 iL 7/fiscRBDM JUL - 9 2015 Form 10-404 Revised 5/2015 /� Z/1/�� Submit riginal Only • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-06 50-133-20568-00 207-064 6/7/15 7/1/15 Daily Operations: 06/07/2015 -Sunday RU slickline. PT lubricator to 1,500 psi -test OK. RIH w/2.5" GR to 6,169' and tag fill. POOH. RD Slickline. SDFN. RU slickline. PT lubricator to 1,500 psi -test OK. RIH w/GR/CCL/press/temp tools to 6,150'. POOH. RD Slickline. Move to KBU 43-07X. 06/12/2015 - Friday RU slickline. PT lubricator to 2,000 psi -test OK. RIH w/2.75" swedge to 5,765' and tag fill. RIH w/3-1/2" AD-2 stop, packoff, and A stop and set top of plug at 5,701'. RIH w/2.5" dump bailer(8 runs) and dump 9.3 gals cement.TOC est at 5,674'. POOH. RD Slickline. Move to CLU-13. 06/14/2015 -Sunday RU slickline. PT lubricator to 1,500 psi -test OK. RIH w/2.50" DD bailer to 5,665' and tag cement. Recovered soft cement. Will allow cement more time to setup and re-tag. RD Slickline. 06/17/2015 -Wednesday PTW and JSA. Mobe to location. Rig up lubricator and pressure test to 250 psi low and 1,500 psi high. Had 2 0 ring failures on lubricator. RIH w/ HalliburtonTMD3D logging tool and log from 5,100' to 4,100' at 15' per minute. Did 200' repeat. POOH. RIH with pressure/temperature tool and logged from 5,100' to 4,100'. POOH. Rig down lubricator and turn well over to field. Mobe equipment to KBU 31-18. 06/22/2015- Monday RU slickline. PT lubricator to 2,000 psi -test OK. RIH w/2.50" DD bailer to 5,655' and tag unset cement. Recovered soft cement. RIH w/2.5" dump bailer(7 runs) and dump 8 gals cement. TOC est at 5,645'. POOH. RD Slickline. 06/25/2015-Thursday RU test pump and chart. Test 3-1/2" tubing plugback to 1,500 psi for 30 min -test OK. RD test pump. 06/26/2015- Friday RU slickline. PT lubricator to 2,500 psi -test OK. RIH w/ 1.75" bailer to 5,605' and tag unset cement. Recovered soft cement. RIH w/2.0" x 40' dump bailer(1 run) and dump 5 gals cement.TOC est at 5,595'. POOH. RD Slickline. 06/28/2015 -Sunday RU slickline. PT lubricator to 2,500 psi -test OK. RIH w/ 1.75" bailer to 5,593' and tag hard cement. POOH. RU swab cups. RIH and swab fluid down to 5,212'. POOH. RD Slickline. 07/01/2015 -Wednesday PTW ansd JSA. Mobe to location and spot equipment. Pressure test to 250 psi low and 2,500 psi high. RIH w/GPT tool and 2- 1/2" x 14' Connex HC, 3 spf, 60 degree phase and tie into Halliburton TMD log. Run correlation log and send to town. FL was 4,844' with 520 psi BHP and 349 psi surface pressure. Bled well down to 450 BHP. Spotted gun from 5,122 136' (per Jacob). Fired gun fired gun with 218 psi surface pressure and 450 psi BHP. After 5 min surface pressure was 235 psi and climbing.All guns fired and were wet. RIH w/GPT tool and 2-1/2" x 14' Connex HC, 3 spf, 60 degree phase and tie into Halliburton TMD log. Run correlation log and send to town. FL was 4,270' with 515 psi BHP. Bled well down to 450 BHP. Spotted gun from 5,122' to 5,136'. Fired gun with 450 BHP. Pull up past perf and had 1 deg warming. Waited 10 min and pulled up hole and found fluid level at 4,150'. All guns fired and were wet. Rig down lubricator, clean up work area and turn well over to field. KBU 34-6 ACTUAL Ililcor') Alaska Pad 41-7 SCHEMATIC Permit#: 207-064 132' FSL, 972' FEL API#: 50-133-20568-00-00 Sec. 6, T4N, R11 W, S.M. Conductor Property Des: A-028142 KB Elevation: 87' (21'AGL) 20 Top 5 Bott133 om PE X= 274,939.64 MD 0' 114' Y= 2,362,144.95 't TVD 0' 114' Lat: 60° 27' 35.566" N ' •'. Long: 151° 14' 48.603" W Spud: 5/17/2007 18:00 his ,W TD Reached: 5/30/2007 + Surface Casing 13-318" J-55 68 ppf BTC Tom Bottom MD 0' 1,570' • TVD 0' 1,491' • ` 16" hole, Cmtw/490 sks(226 bbls)12 ppg Tree cxn=4-3/4"Otis 4 i' 6' Class G,Type 1 cmt with 30 bbls,12 ppg cmt 1 'I to surface. (100%returns) CBL TOC-4,100'(6/13/071 - • } 4 Intermediate Casing 1,336'above 9-5/8"shoe '° ' ' 9-5/8" L-80 40 ppf BTC ' C122' Top Bottom • 4 1 9-- MD 0' 5,436' UB-SA TVD 0' 5,279' Excape System Details: . • . -Ceramic flapper valves below • 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 each module as follows: ppg Class G cmt. 100%returns,floats held. -All reclosing flappers Flappers MD(RKB): .- ;- Production Tubing Module 10 - 5,762' 3-1/2" L-80 9.3 ppf EUE Module 9 - 6,462' , • Top Bottom 8rd Module 8 - 6,751' Cement tagged @ 'r MD 0' 7,717' Module 7 - 6,792' 5,593'on • J TVD 0' 7,560' Module 6 - 6,833' 6/28/15 CIBP @ 5,701' 8-1/2"hole,Cmtw/1,076 sks(547 bbls) Module 5 - 6,875' 1 +..-- capped w/108' 11.5 ppg Class G cmt.6.25"OD control line Module 4 - 7,028' of cement protectors to 5,436'RKB. Module 3 7,140 1J Module 2 - 7,227 Module 1 - NA Dif 1, ) ' 4 ,, Excape System Details: .' DItry _ 10 Excape modules placed R. ati:: control line for top 6 modules ", 1, control line for middle 3 modules -Green control line for bottom 1 module '" -Ceramic flapper valves below each module `r except for module 1. t '` Perfs MD(RKB)(Beluga/Tyonek Zones): Pollard tagged fill @ 7,196'kb (4/412014) ) i+' Upper Beluga UB-5A(5,122'-5,136') j Module 10- 5,743'-5,753' (Beluga) Module 9 - 6,442'-6,452' (Beluga) j�l Module 8 - 6,731'-6,741' (Beluga) Pollard tagged fill @ 7224'kb � ) Module 7 - 6,772'-6,782' (Beluga) (4/18/2012) • 1 I • Module 6 - 6,813'-6,823' (Beluga) ? Module 5 - 6,855'-6,865' (Beluga) %.' Module 4 - 7,008'-7,018' (Beluga) a Module 3 - 7,120'-7,130' (Beluga) i ti Module 2 - 7,208'-7,218' (Beluga) iBaker Coil jetted well clean to PBTD Module 1 - 7,369'-7,379' (Tyonek) -7629'CTM (9-16-2011) t r,. TD PBTD 7,739'MD 7,629'MD 7,582'TVD 7,472'TVD I Well Name&Number: Kenai Beluga Unit 34-6 Lease:_ Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 5,122'-7,380' Perf(TVD): 4,965'-7,223' Angle @ KOP and Depth: -3.1°/100' @ 300 ft Angle/Perfs: 0.2° 0.4° Completion Fluid: 6%KCL - - Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Stan Porhola Last Revison Date: 7/1/2015 T411..„..\\THE STATE Alaska Oil and Gas N� � ofA LASKA Conservation Commission 2 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 OF �� Main: 907 279.1 433 ALAS Fax• 907 276 7542 SCANNED JUL 0 0 2015 www.aogcc.alaska goy Stan Porhola Operations Engineer ao7- Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KBU 34-06 Sundry Number: 315-392 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. Foerster Chair DATED this �'day of June, 2015 Encl. STATE OF ALASKA °""t t,G L Ij' ' ALASKA OIL AND GAS CONSERVATION COMMISSION Ors 4/2.1ns APPLICATION FOR SUNDRY APPROVALS ,SUN 2 2 uiL. 20 AAC 25.280 I1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑ ' �' y-siqutdown ❑ Suspend❑ Perforate ❑ • Other Stimulate LI Alter Casing ❑ Change Approved Program ❑ Plug for Rednll ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Coil N2 Q 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development ❑✓ • 207-064 • 3.Address3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service El6 API Number: Anchorage,Alaska 99503 50-133-20568-00 7.If perforating: 8 Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 510a Kenai Beluga Unit(KBU)34-06 • Will planned perforations require a spacing exception? Yes ❑ No Q 9.Property Designation(Lease Number): 10.Field/Pool(s): A-028142 • Kenai Gas Field-Beluga/Upper Tyonek Gas 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): 7,739 • 7,582 ' 7,679 7,522 5,676 N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' Surface 1,549' 13-3/8" 1,570' 1,491' 3,450 psi 1,950 psi Intermediate 5,415' 9-5/8" 5,436' 5,279' 5,750 psi 3,090 psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160 psi 10,530 psi Liner Perforation Depth MD(ft). Perforation Depth TVD(ft): Tubing Size. Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 7,717 'Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Description Summary of Proposal Q X13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development Q Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 7/6/2015 OIL ❑ WI NJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS Q • WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email sporhola@hilcorg com Printed NameStan Porhola Title Operations Engineer Signature 4t--19ov ,. ._ Phone 907-777-8412 Date (p 2.2-//5- COMMISSION USE ONLY Conditions of approval. Notify Commission so that a representative may witness Sundry Number: 315 . 3q _ Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No V Subsequent Form Required: /6) —i vz-fr APPROVED BY Approved by.(� 79)e-evj4-�_ // COMMISSIONER THE COMMISSION Date: 6p —3t lam. r1-/ Submit Form and Form 10-403 Revised 5/2015 roved application is valid for 120 frbiield t Ap val. Attachments in Duplicate RBDM��VJUL - 1 2015 Z L'3- /- 11 Well Prognosis Well: KBU 34-06 llilcorp Alaska,LL' Date: 6/22/2015 Well Name: KBU 34-06 API Number: 50-133-20568-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: July 6th, 2015 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-064 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907) 331-8228 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(M) AFE Number: Current Bottom Hole Pressure: — 1,200 psi @ 6,900' TVD (Based on PT Survey on 9/16/08) Maximum Expected BHP: — 1,200 psi @ 6,900' TVD (Based on PT Survey on 9/16/08) Max. Allowable Surface Pressure: — 510 psi (Based on actual reservoir conditions and gas gradient to surface (0.10psi/ft) Brief Well Summary Kenai Beluga Unit #34-06 was drilled as a sidetrack EXCAPE completion in 2007 to target gas sands in the Beluga formations. The initial EXCAPE modules were placed on production in July 2007. The well loaded up in April 2014 and has been unable to sustain flow.The well was plugged back in June 2015 under sundry 315-306. The purpose of this work/sundry is to add perforations in the Upper Beluga. Notes Regarding Wellbore Condition • MIRU Coil Tubing and perform BOPE Test to 250/4,500 psi to displace well over to Nitrogen. • Well will be displaced with Nitrogen before initial perforating at+/- 300 psi SITP. E-line Procedure: 1. MIRU E-line, PT lubricator to 1,500 psi Hi 250 Low. a. Tree connection is 6.5" OTIS. b. SITP will be 300 psi (Nitrogen Pressure). 2. RU 2-1/2" 6 spf Connex HC wireline guns. 3. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT SPF Upper Beluga UB-5A 5,110' 5,180' 70' 6 a. Bleed tubing pressure to 300 psi before perforating. b. Proposed perfs shown on the proposed schematic in red font. c. Correlate using TMD3D Log dated 6/17/15 (TMD3D Tie-in log). d. Use Gamma/CCL/to correlate. e. Record tubing pressures before and after each perforating run. f. Proposed intervals are in the Beluga/Upper Tyonek Gas Pool. g. Distance to nearest well open in same sands=2,773'to KBU 24-06RD. h. Spacing allowance is based CO 510a; no wells within 1,500' of property border. 4. RD E-line. 5. Turn well over to production. Well Prognosis Well: KBU 34-06 Hilcorp Alaska,Lb Date:6/22/2015 Attachments: 1. Actual Schematic 2. Proposed Schematic - inPermit#: 207-064 KB U 34-6 API#: 50-133-20568-00-00 Pad 41-7 IIilcirrp Alaska Property Des: A-028142 132' FSL, 972' FEL KB Elevation: 87' (21'AGL) Conductor X= 274,939.64 Sec. 6, T4N, R11 W, S.M. 20" K-55 133 ppf PE Y= 2,362,144.95 Tog Bottom Lat: 60° 27' 35.566" N MD 0' 114' Long: 151° 14' 48.603" W TVD a 114 Spud: 5/17/2007 18:00 hrs ; ,•* + I.,1 TD Reached: 5/30/2007 Surface Casing s 13.3/8" J-55 68 ppf BTC Bottom MD 0' 1,570' TVD 0' 1,491' 16" hole, Cmtw/490 sks(226 bbls)12 ppg l • Class G,Type 1 cmt with 30 bbls,12 ppg cmt to surface. (100%returns) Tree cxn=4-3/4"Otis ' " 1. r 'i Intermediate Casing CBL TOC-4.100'(6/13/07) , dit 9-5/8" L-80 40 ppf BTC 1,336'above 9-5/8"shoe 44 Top Bottom i MD 0' 5,436' v' TVD 0' 5,279' is Excape System Details: 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 -Ceramic flapper valves below • ppg class G cmt. 100 returns,floats held. each module as follows: , , -All reclosing flappers a, f •1' Production Tubing Flappers MD(RKB): -. 3-1/2" L-80 9.3 ppf EUE Module 10 - 5,762' Top Bottom 8rd Module 9 - 6,462' MD 0' 7,717' Module 8 - 6,751' y TVD 0' 7,560' Module 7 - 6,792' .,tt Module 6 - 6,833' -#.: 14% 8-1/2"hole,Cmtw/1,076 sks(547 bbls) Module 5 - 6,875' ', CIBP @ 5,701 11.5 ppg Class G cmt.6.25"OD control line Module 4 - 7,028' • {icapped w/25' protectors to 5,436'RKB. II '% of cement Module 3 - 7,140 - Module 2 - 7,227 Excape System Details: Module 1 - NA I; - 10 Excape modules placed II -Recti control line for top 6 modules control line for middle 3 modules Ii -Green control line for bottom 1 module t ,,, -Ceramic flapper valves below each module 1 except for module 1. .w I I 1 '. Perls MD(RKB)(Beluga/Tyonek Zones): Module 10- 5,743'-5,753' (Beluga) Pollard tagged fill @ 7,196'kb (4/4/2014) I! Module 9 - 6,442'-6,452' (Beluga) II ; Module 8 - 6,731'-6,741' (Beluga) Module 7 - 6,772'-6,782' (Beluga) Pollard taggedII r :1 Module 6 - 6,813'-6,823' (Beluga) fill @ 7224'kb Module 5 - 6,855'-6,865' (Beluga) (4/18/2012) 111 .- Module 4 - 7,008'-7,018' (Beluga) ,, Module 3 - 7,120'-7,130' (Beluga) % 0 Module 2 - 7,208'-7,218' (Beluga) Module 1 - 7,369'-7,379' (Tyonek) Baker Coil jetted well clean to PBTD I ' I-7629'CTM (9-16-2011) . 'li 1 17 Y , TD PBTD 7,739'MD 7,629'MD 7,582'TVD 7,472'TVD Well Name&Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish:. Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 5,742'-7,380' Perf(TVD): 5,585'-7,223' Angle @ KOP and Depth: -3.1°/100' @ 300 ft Angle/Perfs: 0.2°-,0.4° Completion Fluid: 6%KCL Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by:i Stan Porhola Last Revison Date: 6/12/2015 U KBU 34-6 PROPOSED FiiIcorp Alaska Pad 41-7 SCHEMATIC Permit#: 207-064 132' FSL, 972' FEL API#: 50-133-20568-00-00 Sec. 6, T4N, R11 W, S.M. Conductor Property Des: A-028142 133 KB Elevation: 87' (21'AGL) 20 Top K-55 Bottom PE X= 274,939.64 Y= 2,362,144.95 TVD 0' 114' Lat: 60° 27' 35.566" N Long: 151° 14' 48.603" W Spud: 5/17/2007 18:00 his TD Reached: 5/30/2007 surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom __ •'q MD 0' 1,570' jj... TVD 0' 1,491' I.,. 16" hole, Cmt w/490 sks(226 bbls)12 ppg .'►t Class G,Type 1 cmt with 30 bbls,12 ppg cmt Tree cxn=4-3/4"Otis to surface. (100%returns) CBL TOC-4,100'(6/13/07) ,'� Intermediate Casing 1,336'above 9-5/8"shoe i 9-5/8" L-80 40 ppf BTC Bottom { MD 0' 5,436' ' : UB-5A TVD 0' 5,279' Excape System Details: it -Ceramic flapper valves below 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 each module as follows: + ppg Class G cmt. 100%returns,floats held. -All reclosing flappers Flappers MD(RKB): Production Tubing Module 10 - 5,762' 3-1/2" L-80 9.3 ppf EUE Module 9 - 6,462' *,.0 Top Bottom 8rd Module 8 - 6,751' MD 0' 7,717' Module 7 - 6,792' TVD 0' 7,560' Module 6 6,833' CIBP @ 5,701' 8-112"hole,Cmt w/1,076 sks(547 bbls) Module 5 - 6,875' a r- capped w/25' 11.5 ppg Class G cmt.6.25"OD control line Module 4 - 7,028' - II t of cement protectors to 5,436'RKB. Module 3 - 7,140 Module 2 - 7,227 ' Module 1 - NA Ij Excape System Details: Di - 10 Excape modules placed iv'_ ' -Red control line for top 6 modules 31 - control line for middle 3 modules -Green control line for bottom 1 module D?' , -Ceramic flapper valves below each module ' �?r except for module 1. Peels MD(RKB)(Beluna/Tvonek Zones): Pollard tagged fill @ 7,196'kb (4/4/2014) �� Upper Beluga UB-5A(5,110'-5,180') . / (( Module 10- 5,743'-5,753' (Beluga) Module 9 - 6,442'-6,452' (Beluga) Di ;i Module 8 - 6,731'-6,741' (Beluga) Pollard tagged fill @ 7224'kb ) Module 7 - 6,772'-6,782' (Beluga) (4/18/2012) t 'I' Module 6 - 6,813'-6,823' (Beluga) t.* �r Module 5 - 6,855'-6,865' (Beluga) it Module 4 - 7,008'-7,018' (Beluga) Module 3 - 7,120'-7,130' (Beluga) ' Module 2 - 7,208'-7,218' (Beluga) Baker Coil jetted well clean to PBTD ; f1 4' Module 1 - 7,369'-7,379' (Tyonek) -7629'CTM (9-16-2011) , . 1y TD PBTD 7,739'MD 7,629'MD 7,582'TVD 7,472'TVD Well Name&Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 5,742'-7,380' Perf(TVD): 5,585'-7,223' Angle @ KOP and Depth: -3.1°/100' @ 300 ft Angle/Perts: 0.2°- 0.4° Completion Fluid: 6%KCL Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Stan Porhola Last Revison Date: Proposed • QF w\ I//j, s THE STATE Alaska Oil and Gas of ALASKA/ Conservation Commission OW; 333 West Seventh Avenue -* Anchorage, Alaska 99501-3572 �.�M„ GOVERNOR BILL WALKER g JUN f Main. 907 279.1433 ALAS' SCANNED •JUN Q 2015Fax: 907 276 7542 www aogcc alaska.gov Stan Porhola Operations Engineer Colt- Hilcorp Alaska, LLC fl D 0 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, (KBU) 34-06 Sundry Number: 315-306 Dear Mr. Porhola: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy . Foerster ,�/ � Chair DATED this 2/' day of May, 2015 Encl. RECEIVED STATE OF ALASKA MAY 18 2015 • ALASKA OIL AND GAS CONSERVATION COMMISSION 00731 15 APPLICATION FOR SUNDRY APPROVALS AOGCC 20 MC 25.280 1.Type of Request: Abandon❑ Plug Perforations 2 ./}}�� Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Suspend❑ <..pe�feratE }/�Y Qther Stimulate ❑ Alter Casing 0 Change Approved Program ❑ Plugfor RedrillS�t 7 r� 0 Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Olher.-6eiF112 2.Operator Name: 4.Current Wel Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development 0 207-064 ' ‘' 3.Address: 6.API Number. 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ Sr/f/5:— • Anchorage,Alaska 99503 50-133-20568-00 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510a Kenai Beluga Unit(KBU)34-06 • Will planned perforations require a spacing exception? Yes ❑ No 0 9.Property Designation(Lease Number): 10.Field/Pool(s): y 4 Z 1,,:/ , ek_6,-*-- a: 71/ A-028142 ' Kenai Gas Field/ S'-/ /.‘- 11. / /S- 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): 7,739 ' 7,582• 7,679 • 7,522 • N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' Surface 1,549' 13-3/8" 1,570' 1,491' 3,450 psi 1,950 psi Intermediate 5,415' 9-5/8" 5,436' 5,279' 5,750 psi 3,090 psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160 psi 10,530 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 7,717 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Description Summary of Proposal 0 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch 0 Exploratory ❑ Stratigraphic❑ Development 0 Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 6/2/2015 Commencing Operations: OIL 0 WINJ ❑ WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS ❑, WAG ❑ GSTOR ❑ SPLUG 0 Commission Representative: GINJ 0 Op Shutdown 0 Abandoned ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Stan Porhola Email sporhola@hilcorp.com Printed NameStan Porhola Title Operations Engineer Signature A/ ^ "tf✓C-- Phone 907-777-8412 Date 5//(cr S COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 36 -- Sock Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test D Location Clearance ❑ Other: Spacing Exception Required? Yes ❑ No L?( Subsequent Form Required: /0 ._ L/o L1 APPROVED BY Approved by: ( — COMMISSIONER THE COMMISSION Date Z1—/S '�rf�`133RilidGINA Submd Form and Form 10-403 Revis 5/2015 for 12 mon s from the date of approval. Attachments in Duplicate BDM MAY 28201 7g�� sffr Well Prognosis Well: KBU 34-06 Hilcorp Alaska,LL) Date:5/18/2015 Well Name: KBU 34-06 API Number: 50-133-20568-00 Current Status: Shut-In Gas Well Leg: N/A Estimated Start Date: June 2"d, 2015 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-064 First Call Engineer: Stan Porhola (907) 777-8412 (0) (907)331-8228(M) Second Call Engineer: Chad Helgeson (907)777-8405 (0) (907)229-4824(M) AFE Number: Current Bottom Hole Pressure: — 1,200 psi @ 6,900'TVD (Based on PT Survey on 9/16/08) Maximum Expected BHP: — 1,200 psi @ 6,900'ND (Based on PT Survey on 9/16/08) Max. Allowable Surface Pressure: —510 psi (Based on actual reservoir conditions and gas gradient to surface(0.10psi/ft) Brief Well Summary Kenai Beluga Unit #34-06 was drilled as a sidetrack EXCAPE completion in 2007 to target gas sands in the Beluga formations. The initial EXCAPE modules were placed on production in July 2007. The well loaded up in April 2014 and has been unable to sustain flow. The purpose of this work/sundry is to plugback and add perforations in the Upper Beluga. Notes Regarding Wellbore Condition • Well is SI, unable to sustain flow, built up with fluid. Current SITP is 30 psi. Slickline Procedure: 1. MIRU Slickline, PT Lubricator to 1,500 psi Hi 250 Low. 2. RU 2.5"gauge ring, RIH and tag fill at+/-7,744'. 3. RIH and set bridge plug at 5,470'. 4. Dump bail 25'of cement on top of bridge plug(9.2 gallons of cement). 5. Wait on cement for 24 hours. 6. RU 2.50" bailer and tag top of cement. a. Dump additional cement if cement top is below 5,445'. 7. Fill well with lease water. Pressure test plug to 1,500 psi for 30 min. 8. RD Slickline. C�(erc e..1ydL4 G� a 7 f-ve 1..?.7s- ,4„L t ct y • E-lin- procedure: v jr/J� ✓ 9. :U E-line, PT lubricator to 1,500 psi Hi 250 Low. a. Tree connection is 6.5"OTIS. 10. RIH w/RS .g. Log from 5,100'to 4,100'. 11. POOH. RD E-li Coiled Tubing Procedure: 12. MIRU Coiled Tubing, PT BOPE to - 00 psi Hi 250 Low. 13. RIH w/1.75" coil to 5,675' MD and t.. op of cement. 11 Well Prognosis Well: KBU 34-06 Hilcorp Alaska,LU Date: 5/18/2015 14. Displace well fluids with Nitrogen. a. Estimated volume of displaced produced water is 50 bbl. 15. Leave well with 400 psi Nitrogen SITP. 16. POOH w/coil. \ 17. RD Coiled Tubing. 18. Turn well over to p •duction. E-line Procedure: 19. MIRU E-line, PT lubricator 1,500 psi Hi 250 Low. b. Tree connection is 6. " OTIS. c. SITP will be 400 psi (Ni ogen Pressure). 20. RU 2-1/2" 6 spf Connex HC wire!''e guns. 21. RIH and perforate the following int:rvals: Zone Sands Top MD) Btm (MD) FT SPF Upper Beluga ***Pending*** N/A N/A N/A 6 a. Bleed tubing pressure to 400 psi befo e perforating. b. Proposed perfs shown on the propose. chematic in red font. c. Correlate using CBL Log dated 6/13/07 ( 'L Tie-in log). d. Use Gamma/CCL/to correlate. e. Record tubing pressures before and after ea . perforating run. f. Proposed intervals are in the Beluga/Upper T •nek Gas Pool. g. Distance to nearest well open in same sands= 73'to KBU 24-06RD. h. Spacing allowance is based CO 510a; no wells wit' 'n 1,500' of property border. 22. RD E-line. 23. Turn well over to production. ***SEPARATE 10-403 SUNDRY TO BE SUBMITTED WITH UPDAT ' PERF DEPTHS*** Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Coil BOPE Schematic 11 Permit#: . 207-064 KB U 34'6 API#: 50-133-20568-00-00 Pad 41-7 I lilcorp Alaska Property Des: A-028142 132' FSL, 972' FEL KB Elevation: 87' (21'AGL) Conductor X= 274,939.64 Sec. 6, T4N, R11 W, S.M. 20" K-55 133 ppf PE Y= 2,362,144.95 Tom Bottom Lat: 60° 27' 35.566" N MD 0' 114' Long: 151° 14' 48.603" W ' TVD 0' 114' Spud: 5/17/2007 18:00 hrs - TD Reached: 5/30/2007 Surface Casing * - 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,570' TVD 0' 1,491' 16" hole, Cmt w/490 sks(226 bbls)12 ppg • iso Class G,Type 1 cmt with 30 bbls,12 ppg cmt r to surface. (100%returns) Tree cxn=4-3/4"Otis 4* . ' , Intermediate Casing CBL TOC-4,100'(6/13/07) 9-5/8" L-80 40 ppf BTC 1,336'above 9-5/8"shoe 44; Top Bottom MD 0' 5,436' yi1fti TVD 0' 5,279' f Excape System Details: 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 -Ceramic flapper valves below ppg Class G cmt. 100%returns,floats held. each module as follows: -All reclosing flappers i 4 Production Tubing Flappers MD(RKB): r« 3-1/2" L-80 9.3 ppf EUE Module 10 - 5,762' Top Bottom 8rd Module 9 - 6,462' MD 0' 7,717' Module 8 - 6,751' rTVD 0' 7,560' Module 7 - 6,792' ' I Module 6 6,833' 8-1/2"hole,Cmtw/1,076 sks(547 bbls) 11.5 ppg Class G cmt.6.25"OD control line Module 5 - 6,875' protectors to 5,436'RKB. Module 4 - 7,028' Module 3 - 7,140 11II i Module 2 - 7,227 � Excape System Details: Module 1 - NA ll , - 10 Excape modules placed �I _:ted control line for top 6 modules �t control line for middle 3 modules It -Green control line for bottom 1 module - I Ceramic flapper valves below each module except for module 1. 11 Perfs MD(RKB)(Beluga/Tyonek Zones): II Module 10- 5,743'-5,753' (Beluga) Pollard tagged fill @ 7,196'kb (4/4/2014) 21 ' y . MModule 9 - 6,442'-6,452' (Beluga) Module 8 - 6,731'-6,741' (Beluga) Module 7 - 6,772'-6,782' (Beluga) Pollard taggedDI Module 6 - 6,813'-6,823' (Beluga) fill @ 7224'kb -- � ' Module 5 - 6,855'-6,865' (Beluga) (4/18/2012) UI I Module 4 - 7,008'-7,018' (Beluga) Module 3 - 7,120'-7,130' (Beluga) M Module 2 - 7,208'-7,218' (Beluga) Module 1 - 7,369' 7,379' (Tyonek) Baker Coil jetted well clean to PBTD ,i -7629'CTM (9-16-2011) 'iA TD PBTD 7,739'MD 7,629'MD 7,582'ND 7,472'ND Well Name&Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State:_ Alaska Country: USA Perforations(MD): 5,742'-7,380' _ Perf(ND): 5,585'-7,223' Angle @ KOP and Depth: -3.1°/100' @ 300 ft Angle/Perfs: 0.2°-.0.4° • Completion Fluid: 6%KCL - _ Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Stan Porhola Last Revison Date: 5/12/2015 UI KBU 34-6 PROPOSED IIilcm-p Alaska Pad 41-7 SCHEMATIC Permit#: 207 064 - 132' FSL, 972' FEL API#: 50-133-20568-00-00 Sec. 6, T4N, R11 W, S.M. Conductor Property Des: A-028142 20" K-55 133 ppf PE KB Elevation: 87' (21'AGL) Top MDBottom X= 274,939.64 :„.' 0' 114' Y= 2,362,144.951 jj] TVD 0' 114' Lat: 60° 27' 35.566" N Long: 151° 14' 48.603" W Spud: 5/17/2007 18:00 hrs TD Reached: 5/30/2007 f Surface Casing 13-3/8" J-55 68 ppf BTC • Top Bottom MD 0' 1,570' TVD 0' 1,491' • UB(pending) 16" hole, Cmt w/490 sks(226 bbls)12 ppg Tree cxn=4-3/4"Otis k;+ Class G,Type 1 cmt with 30 bbls,12 ppg cmt to surface. (100%returns) CBL TOC-4,100'(6/13/07) Intermediate Casing 1,336'above 9-5/8"shoe 9-5/8" L-80 40 ppf BTC 1;. Top Bottom ' MD 0' 5,436' TVD 0' 5,279' Excape System Details: -Ceramic flapper valves below 12-1/4" hole, Cmt wl 340 sks(190 bbls)10.5 each module as follows: ppg Class G cmt. 100%returns,floats held. -All reclosing flappers Flappers MD(RKB): S'' b q Production Tubing Module 10 - 5,762' 3-1/2" L-80 9.3 ppf EUE Module 9 - 6,462' Top Bottom 8rd Module 8 - 6,751' , 1 MD 0' 7,717' Module 7 - 6,792' , , TVD 0' 7,560' Module 6 - 6,833' < CIBP @ 5,700' 8-1/2"hole,Cmt w/1,076 sks(547 bbls) Module 5 - 6,875' 1 .4-� capped w/25' 11.5 ppg Class G cmt.6.25"OD control line Module 4 - 7,028' . of cement protectors to 5,436'RKB. Module 3 - 7,140 II Module 2 - 7,227i ) I Module 1 - NA )t ° Excape System Details: Di i i, - 10 Excape modules placed control line for top 6 modules D� - control line for middle 3 modules t -Green control line for bottom 1 module Dl -Ceramic flapper valves below each module 11 r • except for module 1. 7 I Perfs MD(RKB)IBeluna/Tyonek Zones): Pollard tagged fill @ 7,196'kb (4/4/2014) �?` Upper Beluga(Depths pending RST to r Module 10- 5,743'-5,753' (Beluga) C Module 9 - 6,442'-6,452' (Beluga) Pollard taggedDI Module 8 - 6,731'-6,741' (Beluga) fill @ 7224'kb �_ Module 7 - 6,772'-6,782' (Beluga) (4/18/2012) Di • Module 6 - 6,813'-6,823' (Beluga) ' • , •*a Module 5 - 6,855'-6,865' (Beluga) I I; ' Module 4 - 7,008'-7,018' (Beluga) Module 3 - 7,120'-7,130' (Beluga) Module 2 - 7,208'-7,218' (Beluga) Baker Coil jetted well clean to PBTD , i Module 1 - 7,369'-7,379' (Tyonek) - -7629'CTM (9-16-2011) - Aa2 TD PBTD 7,739'MD 7,629'MD 7,582'TVD 7,472'TVD Well Name&Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska Country:I USA Perforations(MD): 5,742'-7,380' Perf(TVD): 5,585'-7,223' Angle @ KOP and Depth: -3.1°/100' @ 300 ft Angle/Perfs: 0.2°-,0.4° Completion Fluid: 6%KCL Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Stan Porhola Last Revison Date: Proposed II Kenai Gas Field KBU 34-06 5/18/2015 ailrnrj. u:..k...I.I.(. Kenai Beluga Unit34-06 20X133/8X95/8x31/2 Coil Tubing BOP Lubricator to injection head fir 1.75"Tandem Stripper t 1---1 •11111 Blind/Shea:= 1/161. •_Blind/Shear l,l,'• •'.I.Blind/Shear - _ Blind/Shear.l,'•= Q= VAN =i WW1 PTI MCI 111.14 lih a mom It,Iiii NS= ii lir ' ' j_81_IIuI.i .. • Mud Cross 4 10M 1/16 10M NI CO 1 1I( fd ( 111' 1�II�� outlet w/2-2 1/16 10M full opening FMC valves Manual Manual Manual Manual 2 1/16 10M 2 1/16 10M 1 2 1/16 10M 2 1/16 10M Crossover spool 4 1/16 10M X 3 1/8 5M 00 �<, of I ` 4 .gyp, 'y\ 4' 0 Valve,Swab,VG-300, C.A. r• ��F`i'r �+ ' °� 3 1/16 10M FE,HWO, • . ,X10-``F �cP9 Jct02'4`.\F DD trim `CS �r� Ja ti0 QO y\ e•-k-'s i;•uTi 'bOSP J \P 71 %1 I t��^0 „ O Valve,Upper Master, \, VG 300,3 1/16 1OM FE, t 0 HWO,DD trim J' • r i.•Fil iii A viiir - AValve,Master,VG-300, IlilY�3 1/16 10M FE,HWO, :O,''• '4 DD trim Will Davies, Stephen F (DOA) From: Stan Porhola <sporhola@hilcorp.com> Sent: Tuesday, May 19, 2015 2:14 PM To: Davies, Stephen F (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: KBU 34-06 (PTD#207-064): Perforation Depths Steve, Here is the planned schedule. Set plug—6/02 Wait on cement—6/03 Test plug—6/04 ‘4 I- 3e) Run RST lo: —6/05 v dy • «e cj....,1 Rig up Coil—6/08 C / E-line perf-6/12 �4/r;tc� .5 'Ldv-y i1�f'- moi Stan From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Tuesday, May 19, 2015 11:06 AM To: Stan Porhola Cc: Schwartz, Guy L (DOA) Subject: RE: KBU 34-06 (PTD #207-064): Perforation Depths Stan, Let me re-phrase that question: Hilcorp plans to run the RST tool on what date? Hilcorp plans to rig up the coiled-tubing unit on what date? Thanks, Steve Davies AOGCC CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it,and, so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. From: Stan Porhola [mailto:sporhola@hilcorp.com] Sent: Tuesday, May 19, 2015 10:58 AM To: Davies, Stephen F (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: KBU 34-06 (PTD #207-064): Perforation Depths The RST log is step#10 in the procedure. It will happen after the well is plugged back in steps#1-#8. 1 • Stan From: Davies, Stephen F (DOA) [mailto:steve.davies@alaska.gov] Sent: Tuesday, May 19, 2015 10:21 AM To: Stan Porhola Cc: Schwartz, Guy L (DOA) Subject: KBU 34-06 (PTD #207-064): Perforation Depths Stan, The proposed program for this well indicates that the perforation depths will be determined after an RST log is run in KBU 34-06. When will the RST log be run? Thanks, Steve Davies Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission (AOGCC) Phone: 907-793-1224 AOGCC: 907-279-1433 Fax: 907-276-7542 333 West 7th Avenue,Suite 100 Anchorage,AK 99501 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments,contains information from the Alaska Oil and Gas Conservation Commission(AOGCC),State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information.The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it,without first saving or forwarding it, and,so that the AOGCC is aware of the mistake in sending it to you, contact Steve Davies at 907-793-1224 or steve.davies@alaska.gov. 2 • • ~' ~ ~ ~ ~~~~ ~~~ ~~~~ ~~~~ , ~~~~' ~ ~~~IZC ~~is page ide~tifies those iterns that we~e no~ scanned du~ir~g the ~nitial g~roductio~ scan~irag phase. They are available in the original file, rnay be scanned during a speciaf rescan activity or are viewable ~y direct inspection of the file. ~ ~ - ~ ~(j ~- f - ~1/e8i hlistory ~ile 9clentofier O-"ga/1%Z/119f (done) ^ Two-sided III IIIIIIIIII) IIIII ^ Rescan Needed II) II'I~IIIII IIIIII RE CAId DIGITAL DATA OVERSIZED (Scannable) Color Items: ^ Diskettes, No. ^ Maps: ~Greyscale Items: ^ Other, No/Type: ^ Other Items Scannable by a Large Scanner ^ Poor Quality Originals: OVERSIZED (Non-Scannable) ^ Other: ~ Logs of various kinds: NOTES, ^ Other:: BY: Maria Date: ~ 3 D ~S~ ~ Project Proofing , , (II II'I II II III I(~II ~ BY~ Maria Date: ~~ 31 D 9 ~S~ ~ ~ r ~ Scanning Preparation ~_ x 30 =~+~= TOTAL PAGES__~,~ R~~ / O~ (Count does n~t inclu~e c~ver sheet) ,/~ /~ BY: Maria Date: ~S~ ~ 1 ` Production Scanning Stage 1 Page Count from Scanned File: (count aoes inciude cover sheet) Page Count Matches Number in Scanning Preparation: ~,~, YES NO BY: Maria Date: ~ 3 ~ /s/ ~, ~ ~ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: ~SUi u~iuiun i~~i Scanning is complete at this point unless rescanning is required. ~esca~ned Illlllllllllll lllll BY: Maria Date: ~S~ Comments about this file: Quality Checked ~I) II'lll III IIII III 1b$ 10/6/2005 Well History File Cover Page.doc STATE OF ALASKA AL,---.dok OIL AND GAS CONSERVATION COMM„,SION • REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon ❑ Repair Well U Plug Perforations U Perforate U Other U CT FCO Performed: Alter Casing 0 Pull Tubing El Stimulate-Frac ❑ Waiver fl Time Extension❑ Change Approved Program 0 Operat.Shutdown ID Stimulate-Other ❑ Re-enter Suspended Well Li 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory 0 • 207-064 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic Li Service ❑ 6.API Number: Anchorage,Alaska 99503 • 50-133-20568-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 1 • Kenai Beluga Unit 34-6 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A * Kenai Field/Up Tyonek Beluga Gas Pool 11.Present Well Condition Summary: RECEIVED Total Depth measured • 7,739 feet Plugs measured N/A feet true vertical 7,582 feet Junk measured 7,196(FILL) feet MAY 0 7 2014 Effective Depth measured 7,196 feet Packer measured N/A feet {�p�GC true vertical 7,039 feet true vertical N/A feet lam{'',' Casing Length Size MD TVD Burst Collapse Structural Conductor 114' 20" 114' 114' 3,060psi 1,500psi Surface 1,570' 13-3/8" 1,570' 1,491' 3,450psi 1,950psi Intermediate 5,436' 9-5/8" 5,436' 5,279' 5,750psi 3,090psi Production 7,717' 3-1/2" 7,717' 7,560' 10,160psi 10,540psi Liner Perforation depth Measured depth 5,742'to 7,379' True Vertical depth 5,585'to 7,222' WED MAY 2 9 2014 Tubing(size,grade,measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV(type,measured and true vertical depth) N/A N/A N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A RBDMS MAY 1 7 2014 Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 664 0 50 252 Subsequent to operation: 0 1131 5 50 240 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory 0 Development Q • Service 0 Stratigraphic 0 Daily Report of Well Operations X 16.Well Status after work: - Oil ❑ 6 Gas 0 WDSPL El GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: N/A Contact Paul Chan / 1 Email pchan hiIcorp.com Printed Name Paul Chan Title Operations Engineer Signature Phone 907-777-8333 Date 4/29/2014 Form 10-404 Revised 10/2012 95- 6 . i ti Submit Original Only . UPermit#: 207-064 KBU 34-6 API#: 50-133-20568-00-00 Pad 41-7 1lilcorla Alaska Property Des: A-028142 132' FSL, 972' FEL KB Elevation: 87' (21'AGL) conductor X= 274,939.64 Sec. 6, T4N, R11 W, S.M. 20" K-55 133 ppf PE Y= 2,362,144.95 Tom Bottom Lat: 60° 27' 35.566" N MD 0' 114' Long: 151° 14' 48.603" W TVD 0 114 Spud: 5/17/2007 18:00 hrs r TD Reached: 5/30/2007 Surface Casing y 13-3/8" J-55 68 ppf BTC Th3p Bottom +1 MD 0' 1,570' TVD 0' 1,491' -a 16" hole, Cmt w/490 sks(226 bbls)12 ppg Al Class G,Type 1 cmt with 30 bbls,12 ppg cmt E ' -.. to surface. (100%returns) Tree cxn=4-3/4"Otis ,T Intermediate Casing Top of Cement(est.) 9-5/8" L-80 40 ppf BTC ???'above 9-5/8"shoe Tom Bottom MD 0' 5,436' ''' 1' TVD 0' 5,279' Excape System Details: o, 4;y 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 -Ceramic flapper valves below # _} ppg Class G cmt. 100%returns,floats held. each module as follows: All reclosing flappers , ,, Production Tubing Flappers MD(RKB): � 3-1/2" L-80 9.3 ppf EUE Module 10 - 5,762' IlitTop Bottom 8rd Module 9 6,462' MD 0' 7,717' Module 8 - 6,751' '1 `v ND 0' 7,560' Module 7 - 6,792' Module 6 6,833' .; 8-1/2"hole,Cmt w/1,076 sks(547 bbls) 11.5 ppg Class G cmt.6.25"OD control line Module 5 - 6,875' 1* %' protectors to 5,436'RKB. Module 4 - 7,028' ,7 'y; Module 3 - 7,140 , ' Module 2 - 7,227 � Module 1 - NA A I t ` Excape System Details: # ,� - 10 Excape modules placed 111 :' -Red control line for top 6 modules T control line for middle 3 modules I1, $* -Green control line for bottom 1 module - 1 or -Ceramic flapper valves below each module except for module 1. 0 - •i:4, Perfs MD(RKB)(Beluga/Tyonek Zones): 4; Module 10- 5,743'-5,753' (Beluga) Pollard tagged fill @ 7,196'kb (414/201.1 '' I- t1 Module 9 - 6,442'-6,452' (Beluga) 11 Module 8 - 6,731'-6,741' (Beluga) '' Module 7 - 6,772'-6,782' (Beluga) I +� Module 6 - 6,813'-6,823' (Beluga) Pollard tagged fill @ 7224'kb Module 5 - 6,855'-6,865' (Beluga) (4/18/2012) I d° Module 4 - 7,008'-7,018' (Beluga) Module 3 - 7,120'-7,130' (Beluga) lot I I Module 2 - 7,208'-7,218' (Beluga) Module 1 - 7,369'-7,379' (Tyonek) • o Baker Coil jetted well clean to PBTD . T -7629'CTM (9-16-2011) F;a, TD PBTD 7,739'MD 7,629'MD 7,582'TVD 7,472'ND Well Name&Number: Kenai Beluga Unit 34-6 Lease. Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State. Alaska Country. USA Perforations(MD): 5,742'-7,380' Perf(TVD): 5,585'-7,223' Angle @ KOP and Depth: -3.1°/100' @ 300 ft Angle/Perfs: 0.2°--,0.4° Completion Fluid: 6%KCL • Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Tom Fouts Last Revison Date: 4/8/2014 i I Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-6 50-133-20568-00-00 207-064 3/6/14 4/8/14 Daily Operations: 3/5/2014-Wednesday No operations to report. 3/6/2014-Thursday Start equipment. Start crane.Lay 3" suction hoses and instrument lines. Function tes visually BOP's close blind rams and choke. Test blinds and choke to 250psi low/4,500psi high. Test good. Insert 1-3/4" test bar. Close pipe rams. Test pipes, inside reel valve, and N2 check valve.Test 250psi low/4,500psi high. Test good. Test accumulator. BOP test complete. Change out stripper rubber in packoff. PU injector assembly. Carry to WH. NU injector on WH. Open swab. SIWP 0 psi. RIH Pumping KCL at min rate. Tag fill at 6,460'. Continue with CT clean out to 6,750'. Begin to POOH. Fluid returns to surface. Blow coil dry w/ N2. POOH. Allow coil to blow down. Displace 5 bbls MEOH down tree to freeze protect over night. ND injector. Install night cap. Secure well and location for the night. 3/7/2014- Friday Extend crane boom to accomodate 65' lubicator. Spot Wireline unit. NU 7" Bowen XO on Baker BOP's. PU 65' of 3" lubricatorMU tool string-RS, 1-3/4" x 10' stem, KJ, OJ, LSSJ,NU lubricator on BOP's. PT lubricator 250psi low/2,500psi high. Test good. RIH(1) w/2-1/2" LIB. Set down at 6,456' kb. Tap down once. POOH. OOH. Lib indicated large imprints in face as if stuck large rocks/RIH(2)w/2-1/4" DD bailer to 6,456'. Tap down twice. Break thru bridge. Fall to 6,724'kb. WT lightly. Sticky, but spang free easily. POOH. OOH. Recover cup of fine sand and large angular flapper ceramic. RIH(3) w/same WT. POOH. OOH. Recover 2 cups Beluga sand 1 large shard of flapperRlH(4) w/2-1/4" pump bailer to 6,725', WT 6,729'. POOH. OOH. Recover 1/4 cup Beluga clay flapper chips. RIH(5) w/2-1/2" LIB to 6,725'kb. Tap down once. POOH. OOH. Imprint of RS in middle of LIB. RIH(6) w/2-1/2" RB pinned w/brass( shear up). Latch fish on third attempt. Work tools increasing tension. No movement seem in lower tools(spanges). Work tools up to 3,000' before pin sheared. RIH(7) w/2-1/2" SB pinned w/brass. Latch fish. Hit one 2,300#jar lick. Slipped free. POOH to check tool. RIH(8) w/2-1/2"JD. • 3/8/2014-Saturday Start equipment and crane. PU 2-1/4" DD bailer with muleshoe bottom-flapper. Carry to WH. PT lubricator 250psi low /2,500psi high. RIH(1) w/2-1/4" drive down bailer. Sets down in top module,then falls thru to 6,725'WT. POOH. OOH. Recover 1/2 cup fine Beluga clay and coal. RIH(2) w/2-1/4" pump bailer t o 6,725. Work pump. OOH Recover 2 cups mud and a 1/2" chunk of cement. RIH(3) w/same to 6,725' Work pump. POOH. OOH. Recover 1/2 cup fine Beluga mud. RIH(4) w/2-1/2" RB ( shear up-brass pinned)to 6,725'. WT Latch fish. Bump it a couple times. Slips off. Relatch. Bump a couple more times. Slips off. Latch again. Good latch. Bump and work tools. Hit one good jar lick and come free. POOH. OOH. Tool sheared. RIH(5) w/2-1/2" split skirt SB. Latch fish. Hit one spang lick, pulls free. Latch again. Hit a couple spang licks, pulls free. Beat down a little harder. Bump w/spang lick. Pull 1,600#. Hit jar lick. Pull free. Beat down more aggressively. Pull 1,850#. Hit 200# lick. Pull 1,950#. Hit jar lick, pull free. POOH to check tool. OOH. Tools sheared. Two dogs rolled. Replace dogs. RIH(6) w/2-1/2" split skirt JD. Latch fish. Hit spang licks. Pull 1,800#. Tool pulls free. Relatch fish. Hit two spang licks. Tool pulls free. POOH to check tool. Tools sheared. RIH(7) w/same. Latch fish. Pull 1,200#to hit soft jar lick to check latch. Tool jars free. WT Relatch fish. Spang twice Tools pulls free Re-latch fish. Spang a couple times. Jar once and jar free. POOH to check tool. Tool damaged, missing quarter size piece of piece of the outer skirt at the split. Unable to get a good hook-up on fish. Call Operations Engineer to discuss options going forward. Make two runs with magnets to retrieve missing part of overshot skirt. Recover metal but not missing chuck of skirt. RD Pollard 3/9/2014-Sunday No operations to report. 3/10/2014-Monday No operations to report. 3/11/2014-Tuesday No operations to report. • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-6 50-133-20568-00 207-064 3/6/14 4/8/14 Daily Operations: 3/12/2014-Wednesday No operations to report. 3/13/2014-Thursday No operations to report. 3/14/2014- Friday No operations to report. 3/15/2014-Saturday Rig up lubricator. PT lubricator to 250psi low/3,000psi high. RIH w/2.5" LIB and spud down twice on obstruction at 6,726' KB. POOH. No rope socket imprint on LIB. RIH with 2.25"x5' pump bailer to 6,726' KB. Work bailer. POOH. Bailer 1/2 full gummy clay. RIH with 2.25"x5' pump bailer to 6,727' KB. Work bailer. POOH. Bailer 1/2 full gummy clay. RIH with 2.25"x5' pump bailer to 6,728' KB. Work bailer. POOH. Bailer full of coarse sand. RIH with 2.25"x5' pump bailer to 6,732' KB. Work bailer. POOH. Bailer full coarse sand. RIH with 2.25"x5' pump bailer to 6,732' KB. Work bailer. POOH. Bailer had 2 cups coarse sand. RIH with 2.25"x5' pump bailer to 6,733' KB. Work bailer. POOH. Bailer 1/4 full coarse sand. Rig for standby. 3/16/2014-Sunday Mobe to location. PT lubricator to 250psi low/3,000psi high. Make 3 runs with 2.25"x5' bailer and bailed sand from 6,731' to 6,732' KB. Last run saw rope socket marks inside of bailer bottom. Ran in hole w/2-1/2"JB (pin w/brass) and latch fish at 6,732' KB. Made several spang licks and 2 jar licks at 1,600Ibs and sheared pin. Ran back in hole pinned with steel and latch fish. Made several jar licks at 1,600lbs and slipped off fish. POOH and found 1 dog broke. Ran back in hole and latch fish. Made several jar licks at 1,600lbs and 1 at 2,200lbs and slipped off fish. Could not latch on back on fish. POOH. Ran in hole with 2.75" GU with overshot to 5,743' KB (first mod) and could not work tools past. POOH. Ran 2-1/4" bailer to 6,732' KB to check for fill while checking to get 2-1/2" baited sub out to location. POOH with bailer and it was empty. Did not have 2-1/2" sub in stock. Check with operations engineer and Pollard will have one made. Rig for stand-by. 3/17/2014- Monday Mobe to location. RIH with 2-1/4"x5' pump bailer and work tools at 6,732' KB. POOH. Bailer empty. RIH with 2-1/2" GU baited w/internal fishing neck and bowen overshot and latch fish at 6,732' KB. Jar on fish 2,600lbs over, numerous times. Jar on fish at 3,600lbs over,4 times and come off fish. POOH. Found big pin and broke in the GU adaptor sub. Wait on tools to come from Pollard shop. RIH with 2-1/2"JDC baited w/1-3/4" rope socket and bowen overshot and latch fish at 6,732' KB. Shear off and leave 1-3/4" external fish neck looking up for coil. Rig down slickline. 3/18/2014-Tuesday No operations to report. • Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-6 50-133-20568-00 207-064 3/6/14 4/8/14 Daily Operations: 3/19/2014-Wednesday Obtian SWP and HWP for Steam on Wheels to heat frac tank. Start equipment. Lay drip liners. Spot equipment. and OPS cab. NU BOP's. MU 2" hard lines. MU 5" lubricator. Connect hydraulic lines to reel and BOP's. Load coil w/25 bbls of 50/50 MEOH. Establish circulation across flowcross to FB tank. Visually function test BOP's. Close Blinds and choke. PTest blinds 250psi low/5,000psi high, test good. Insert 1-3/4" test bar. Close pipe rams. Test pipes, inside reel valve, and N2 check valve. Test 250 psi,test good. Test 5000 psi,test good. Test accumulator. BOP test complete. Cut coil. Prep cut. Install coil connector-grapple. MU w/36's, pull test to 16.7K. Good no movement. Tighten 1/2 additional turns, dimple. Install lock screws. Close valves on tree and BOP's. Secure WH. Secure equipment and location for the night. 3/20/2014-Thursday No operations to report. 3/21/2014- Friday Start equpment and crane. PU injector. MU 25' of 5" lubricator. MU BHA 1-3/4" extermal coil grapple, 2-1/2" DFCV, 2-1/8" accelerator,XO, 2-1/2" wt bar,XO, 2-1/8"jars, FAU disconnect. Install test plate. PTest. Coil has ice plug. ND BHA. NU lubricator. Pressure coil. Establish circulation thru coil. Install test plate. PT coil and BHA-250psi low/3,500psi high, test good. Install 1-3/4" hydraulic release JDC on BHA. NU lubricator. Displace MEOH out of coil w/ KCL. PT shell to 1,000psi. Open WH. RIH. Can't get below 11'. Not even getting into tree. Close lower master. ND lubricator. RIH Tag about 4' below top of BOP's. Appears to be a ledge at the adapter flange on flowcross. Hand guide coil into tree. NU lubricator. Open master valve. RIH to 6,600'. PUH, weight check 17.4K Continue RIH pumping 1/2 bpm. Tag fish at 6,742'. Latch up. PUH 27K(10K over.) Slow pump to 1/4 bpm. Plan to pull 40K. Fish starts moving at 37.6K. Pull fish up hole. Fish breaks free at 6,732'. Pulling 18K, PUH to 5,700'. RIH to 6,729'. Taking weight. Bring pump on line 1-1/4 bpm. Setting weight down. Sink to 6,739' before JDC released. POOH. Stand down Baker for the night. MIRU Pollard slickline w/68' of lubricator to recover fish. PU lubricator. MU tool string 1-3/4" RS, stem, KJ, OJ, LSSJ, 2-1/2"JDC. RIH(1)w/2-1/2"JDC to 6,741'. Weight check. Latch fish. Hit one jar lick. Fish pulls free. PUH 200# heavy. POOH. OOH Recover-RS, KJ, 5' stem, KJ, 10' stem. Bottom stem has 3/4" rod thread broken. Left in hole: oil jars, short stroke spangs and 8' x 1-3/4" bailer. RD secure well for the night. 3/22/2014-Saturday RU .125 wire and PT lubricator. RIH with 2.5" LIB to 6,719' and POOH. NO impression. RIH with 2.25" pump bailer to 6,721'. POOH. Bailer had clay and a set screw in it. RIH with 2.25" PB to 6,722'. Bailer came back full of watter. RIH with magnet to 6,726'. No metal on magnet. RIH with 2" DD bailer to 6,727'. Work bailer through to 6,737'. Bailer full of fine grey sand. RIH with 2.25" PB to 6,723'. Full of water. RIH with 2.5" RB to 6,758'. Tapped 1 time and fell through to fish and latched it. Worked jars 10 times and sheared off. POOH and re pin with steel. RIH with 2.5 RB to 6,741' and latched up. Worked jars for 1 hr. Sheared off and pulled out of hole. Layed down for the night and secured location. 3/23/2014-Sunday Start equipment and crane. RU 160" wire. Rehead/repack stuffing box. PU 60' of lubricator. MU tool string-RS,Stem, stem, KJ, LSOJ, SSSJ. Carry lubricator to WH. PT lubricator 250psi low/2,500psi high. Test good. Open swab. RIH(1)w/2-1/2" SB to 6748. WT. On latch. POOH. Dogs on SB packed with sand. No sheared. RIH(2) w/2" bailer to 6,748'. WT. POOH bailer empty. Metal marks on mule shoe bottom. RIH(3) w/2-1/2" SB to 6,748'. WT hitting down. No latch, but drive fish down hole 14'. POOH. RIH(4) w/2-1/2" RB to 6,762'. Latch fish. Can see both sets of spangs and lower jars. Hit 2,000lb jar licks with lower jars on fish. No movement. Shear tools with upper jar lick. POOH. RIH(5) w/2-1/2" SB to 6,762'. Latch fish. Hit on jar lick. Pulled free. WT no more hook up's. POOH. Schucked dogs on overshot. RIH(6) w/2.1" spiral grapple on "bait" sub and 2-1/2 GR. Latch fish on first try. POOH. RIH(7) w/2-1/2" GS. Latch fish. Hit nine 3,4001b jar licks w/20" stroke jars. Fish pulls free. POOH. Recover entire fish-oil jars, LSSJ, KJ, 3" stem, 8' x 1-3/4" bailer. RIH(8) w/2-1/2" wirefinder and wire grab to 6,802' kb. WT. OOH. Recover no wire. RIH(9) w/2" magnet to 6,802. WT. Recover no wire gibblets. RD 160" wire unit. Secure WH and location for the night. 3/24/2014- Monday Start equipment and crane. PU injector. Cut coil grapple. Prep coil end. Install dimple-on connector. MU BHA-DFCV, 3' straight bar, 2"forward jetting nozzle. NU injector. PT shell to 1,500psi. Test good. Open swab vavle. RIH pumping min rates. At 3,000' increase rates. Tag fill at 6,780'. Pushing minus 3K weight. Break thru at 6,789'. continue down hole to PBTD of 7,629'. POOH. Turn well over to production. Total KCL pumped 227bb1s, total N2 pumped 272,300 scf,total fluid recovered 370 bbls. Secure well and equipment for the night. 3/25/2014-Tuesday No operations to report. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-6 50-133-20568-00 207-064 3/6/14 4/8/14 Daily Operations: 4/2/2014-Wednesday No operations to report. 4/3/2014-Thursday Arrive KGF-JSA,TGSM, Permit. Pressure test lubricator 250 LP 1500 HP. R/U .125RIH 2.25" DD Bailer. Tag 5,778'KB. POOH. OOH. Bailer Empty. RDFN. 4/4/2014- Friday Arrive KGF-TGSM,JSA, Permit. Pressure test lubricator 250 LP 1500 HP. R/U .125RIH w/2.62 LIB to 5,770' KB, 400#0/P after slight set down(no beat down.) POOH. LIB slight impression of flapper. RIH w/2.31 swedge to5,778' KB set down no spangs, 300#0/P cycled several passes. POOH. Reconfigure w/knuckle jar between stem. RIH w/2.25x4' DD bailer to 7,172' KB. W/T POOH. OOH w/2 cups sand. Lay down to lube 0-rings. RIH w/same to 7,171' KB. W/T to 7,191' KB. POOH. Empty,flapper stuck. RIH w/same to 7,193' KB. W/T to 7,196' KB. POOH. Bailer 1/2 full w/ loose sand. RIH w/same to 7,193' KB. W/T to 7,196' KB. POOH. Bailer full of hard sand. RIH w/2.25 bailer 8' to 5,770' KB. W/T down. No Pass. POOH. Empty Bailer. RIH w/same to 7,196' KB. W/T to 7,196'. POOH. Bailer 1/2 full w/ loose sand. RIH w/same to 7,196' KB. W/T to 7,196'. POOH. Bailer 1/2 full w/ loose sand. L/D- Clean up Head to Shop- PWL. 4/5/2014-Saturday No operations to report. 4/6/2014-Sunday No operations to report. 4/7/2014- Monday No operations to report. 4/8/2014-Tuesday RU and PT lubricator 250 LP 1500 HP. RIH with 2.25 DD bailer to 7,144'. Full bailer. RIH with same to 7,145'. Full bailer. RIH with same to 7,130'. Full bailer. Well bore filling up with sand or side wall falling down. RIH with same to 7,132'. Full bailer. RIH with same to 7,122'. Full bailer. RIH with 2.5" DD bailer to 5,777'. Beat through bridge and fell down to 7,150'. Full bailer. RIH with 2.5" DD bailer to 5,777'. Worked through bridges. Fell through to 7,101'. Operator made the call to stop and open well to production. RD for the night STATE OF ALASKA ALA ,OIL AND GAS CONSERVATION COMM ON =-`"`- I f ?014 REPORT OF SUNDRY WELL OPERATIONS AOLICC 1.Operations Abandon Li Repair Well [J Plug Perforations L] Perforate U Other [] CT FCO Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ 207-064 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 4 50-133-20568-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 • Kenai Beluga Unit 34-6 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): • N/A Kenai Field/Up Tyonek Beluga Gas Pool 11.Present Well Condition Summary: Total Depth measured • 7,739 feet Plugs measured N/A feet true vertical 7,582 feet Junk measured 7,196(FILL) feet Effective Depth measured • 7,196 feet Packer measured N/A feet true vertical 7,039 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 114' 20" 114' 114' 3,060psi 1,500psi Surface 1,570' 13-3/8" 1,570' 1,491' 3,450psi 1,950psi Intermediate 5,436' 9-5/8" 5,436' 5,279' 5,750psi 3,090psi Production 7,717' 3-1/2" 7,717' 7,560' 10,160psi 10,540psi Liner Perforation depth Measured depth 5,742'to 7,379' True Vertical depth 5,585'to 7,222' SCANNED MAY 2 7 2014 Tubing(size,grade,measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV(type,measured and true vertical depth) N/A N/A N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A RBDMS� MAY 1 5 2014 Treatment descriptions including volumes used and final pressure: N/A I 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 664 0 50 252 Subsequent to operation: 0 1131 5 50 240 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory Development❑✓ , Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: N/A Contact Paul Chan Email pchan(a�hilcorp.com Printed Name P. I Chan Title Operations Engineer Signature Phone 907-777-8333 Date 4/14/2014 Form 10-404 Revised 10/2012 �, yv „Alit 6-,Za-/I Submit Original Only / fj j`i" r. - Permit#: 207-064 KBU 34-6 API#: 50-133-20568-00-00 Pad 41-7 Hilcorrp Alaska Property Des: A-028142 132' FSL, 972' FEL KB Elevation: 87' (21'AGL) X= 274,939.64 Sec. 6, >T4N R11 W> S.M. Conductor 20" K-55 133 ppf PE Y= 2,362,144.95 Two Bottom Lat: 60° 27' 35.566" N MD 0' 114' Long: 151° 14' 48.603" W 1.i.a d ND 0' 114' Spud: 5/17/2007 18:00 hrs - ` TD Reached: 5/30/2007 - t Surface Casing ,-t 13-3/8" J-55 68 ppf BTC m4 7p Bottom ta'' s MD 0' 1,570' TVD 0' 1,491' ;- « 16" hole, Cmt w/490 sks(226 bbls)12 ppg ti, 41 Class G,Type 1 cmt with 30 bbls,12 ppg cmt t ' t" to surface. (100%returns) Tree cxn=4-3/4"Otis ' 11111, v, , 0 Intermediate Casing Top of Cement(est.) 9-5/8" L-80 40 ppf BTC ???'above 9-5/8"shoe ` Top Bottom A MD 0' 5,436' 1.ti• ND 0' 5,279' Excape System Details: 19 ) 12-1/4" hole, Cmt w/340 sks(190 bbls)10.5 Ceramic flapper valves below >/ ppg Class G cmt. 100%returns,floats held. each module as follows: All reclosing flappers '111 Production Tubing Flappers MD(RKB): 3-1/2" L-80 9.3 Top Bottomf 8Ed E Module 10 - 5,762' Module 9 - 6,462' L., MD 0' 7,717' Module 8 - 6,751' y'� 4 ND 0' 7,560' Module 7 - 6,792' 1"44 8-1/2"hole,Cmt w/1,076 sks(547 bbls) Module 6 - 6,833' 11.5 ppg Class G cmt.6.25"OD control line Module 5 - 6,875' if protectors to 5,436'RKB. Module 4 - 7,028' Module 3 - 7,14011 t4 Module 2 7,227 l Iti Excape System Details: Module 1 - NA ;;P4i - 10 Excape modules placed IE _Red control line for top 6 modules k control line for middle 3 modules -Green control line for bottom 1 module } -Ceramic flapper valves below each module a except for module 1. Perfs MD(RKB)(Beluga/Tyonek Zones): -,0Br; Module 10 5,743' 5,753' (Beluga) Pollard tagged fill @ 7,196'kb (4/4/2014) - Module 9 - 6,442'-6,452' (Beluga) [ t Module 8 - 6,731'-6,741' (Beluga) Module 7 - 6,772'-6,782' (Beluga) � ` r Module 6 - 6,813'-6,823' (Beluga) Pollard tagged fill @ 7224'kb --Iv- ? °! Module 5 - 6,855'-6,865' (Beluga) (4/18/2012) .. -111f .4` Module 4 - 7,008'-7,018' (Beluga) Module 3 - 7,120'-7,130' (Beluga) ` '�' Module 2 - 7,208'-7,218' (Beluga) Module 1 - 7,369'-7,379' (Tyonek) Baker Coil jetted well clean to PBTD t -7629'CTM (9-16-2011) TD PBTD 7,739'MD 7,629'MD 7,582'TVD 7,472'TVD Well Name&Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 5,742'-7,380' Perf(TVD): 5,585'-7,223' Angle @ KOP and Depth: -3.1°/100' @ 300 ft Angle/Perfs: 0.2° '0.4° Completion Fluid: 6%KCL • Dated Completed: 6/30/2007 Ground Level(MSL): 66.1' Revised by: Tom Fouts Last Revison Date: 4/8/2014 Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-6 50-133-20568-00-00 207-064 3/6/14 4/8/14 Daily Operations: 3/5/2014-Wednesday No operations to report. 3/6/2014-Thursday Start equipment. Start crane.Lay 3" suction hoses and instrument lines. Function testvisually BOP's close blind rams and choke. Test blinds and choke to 250psi low/4,500psi high. Test good. Insert 1-3/4" test bar. Close pipe rams. Test pipes, inside reel valve, and N2 check valve. Test 250psi low/4,500psi high. Test good. Test accumulator. BOP test complete. Change out stripper rubber in packoff. PU injector assembly. Carry to WH. NU injector on WH. Open swab. SIWP 0 psi. RIH Pumping KCL at min rate. Tag fill at 6,460'. Continue with CT clean out to 6,750'. Begin to POOH. Fluid returns to surface. Blow coil dry w/ N2. POOH. Allow coil to blow down. Displace 5 bbls MEOH down tree to freeze protect over night. ND injector. Install night cap. Secure well and location for the night. 3/7/2014- Friday Extend crane boom to accomodate 65' lubicator. Spot Wireline unit. NU 7" Bowen XO on Baker BOP's. PU 65' of 3" lubricatorMU tool string-RS, 1-3/4" x 10' stem, KJ, OJ, LSSJ,NU lubricator on BOP's. PT lubricator 250psi low/2,500psi high. Test good. RIH(1) w/2-1/2" LIB. Set down at 6,456' kb. Tap down once. POOH. OOH. Lib indicated large imprints in face as if stuck large rocks/RIH(2) w/ 2-1/4" DD bailer to 6,456'. Tap down twice. Break thru bridge. Fall to 6,724'kb. WT lightly. Sticky, but spang free easily. POOH. OOH. Recover cup of fine sand and large angular flapper ceramic. RIH(3) w/same WT. POOH. OOH. Recover 2 cups Beluga sand 1 large shard of flapperRlH(4) w/2-1/4" pump bailer to 6,725', WT 6,729'. POOH. OOH. Recover 1/4 cup Beluga clay flapper chips. RIH(5) w/2-1/2" LIB to 6,725'kb. Tap down once. POOH. OOH. Imprint of RS in middle of LIB. RIH(6) w/ 2-1/2" RB pinned w/ brass( shear up). Latch fish on third attempt. Work tools increasing tension. No movement seem in lower tools(spanges). Work tools up to 3,000' before pin sheared. RIH(7) w/2-1/2" SB pinned w/ brass. Latch fish. Hit one 2,300#jar lick. Slipped free. POOH to check tool. RIH(8) w/ 2-1/2"JD. 3/8/2014-Saturday Start equipment and crane. PU 2-1/4" DD bailer with muleshoe bottom-flapper. Carry/to WH. PT lubricator 250psi low /2,500psi high. RIH(1) w/2-1/4" drive down bailer. Sets down in top module, then fals thru to 6,725' WT. POOH. OOH. Recover 1/2 cup fine Beluga clay and coal. RIH(2) w/2-1/4" pump bailer t o 6,725. W�' rk pump. OOH Recover 2 cups mud and a 1/2" chunk of cement. RIH(3) w/same to 6,725' Work pump. POOH. OOH. Re'Icover 1/2 cup fine Beluga mud. RIH(4) w/2-1/2" RB ( shear up-brass pinned) to 6,725'. WT Latch fish. Bump it a couple times. Slips off. Relatch. Bump a couple more times. Slips off. Latch again. Good latch. Bump and work tools. Hit one good jar lick and come free. POOH. OOH. Tool sheared. RIH(5) w/2-1/2" split skirt SB. Latch fish. Hit one spang lick, pulls free. Latch again. Hit a couple spang licks, pulls free. Beat down a little harder. Bump w/spang lick. Pull 1,600#. Hit jar lick. Pull free. Beat down more aggressively. Pull 1,850#. Hit 200# lick. Pull 1,950#. Hit jar lick, pull free. POOH to check tool. OOH. Tools sheared. Two dogs rolled. Replace dogs. RIH(6) w/2-1/2" split skirt JD. Latch fish. Hit spang licks. Pull 1,800#. Tool pulls free. Relatch fish. Hit two spang licks. Tool pulls free. POOH to check tool. Tools sheared. RIH(7) w/same. Latch fish. Pull 1,200#to hit soft jar lick to check latch. Tool jars free. WT Relatch fish. Spang twice Tools pulls free Re-latch fish. Spang a couple times. Jar once and jar free. POOH to check tool. Tool damaged, missing quarter size piece of piece of the outer skirt at the split. Unable to get a good hook-up on fish. Call Operations Engineer to discuss options going forward. Make two runs with magnets to retrieve missing part of overshot skirt. Recover metal but not missing chuck of skirt. RD Pollard 3/9/2014-Sunday No operations to report. 3/10/2014- Monday No operations to report. 3/11/2014-Tuesday No operations to report. - , Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-6 50-133-20568-00 207-064 3/6/14 4/8/14 Daily Operations: 3/12/2014-Wednesday No operations to report. 3/13/2014-Thursday No operations to report. 3/14/2014- Friday No operations to report. 3/15/2014-Saturday Rig up lubricator. PT lubricator to 250psi low/3,000psi high. RIH w/2.5" LIB and spud down twice on obstruction at 6,726' KB. POOH. No rope socket imprint on LIB. RIH with 2.25"x5' pump bailer to 6,726' KB. Work bailer. POOH. Bailer 1/2 full gummy clay. RIH with 2.25"x5' pump bailer to 6,727' KB. Work bailer. POOH. Bailer 1/2 full gummy clay. RIH with 2.25"x5' pump bailer to 6,728' KB. Work bailer. POOH. Bailer full of coarse sand. RIH with 2.25"x5' pump bailer to 6,732' KB. Work bailer. POOH. Bailer full coarse sand. RIH with 2.25"x5' pump bailer to 6,732' KB. Work bailer. POOH. Bailer had 2 cups coarse sand. RIH with 2.25"x5' pump bailer to 6,733' KB. Work bailer. POOH. Bailer 1/4 full coarse sand. Rig for standby. 3/16/2014-Sunday Mobe to location. PT lubricator to 250psi low/3,000psi high. Make 3 runs with 2.25"x5' bailer and bailed sand from 6,731' to 6,732' KB. Last run saw rope socket marks inside of bailer bottom. Ran in hole w/2-1/2"JB (pin w/brass) and latch fish at 6,732' KB. Made several spang licks and 2 jar licks at 1,600lbs and sheared pin. Ran back in hole pinned with steel and latch fish. Made several jar licks at 1,600lbs and slipped off fish. POOH and found 1 dog broke. Ran back in hole and latch fish. Made several jar licks at 1,600lbs and 1 at 2,200Ibs and slipped off fish. Could not latch on back on fish. POOH. Ran in hole with 2.75" GU with overshot to 5,743' KB (first mod) and could not work tools past. POOH. Ran 2-1/4" bailer to 6,732' KB to check for fill while checking to get 2-1/2" baited sub out to location. POOH with bailer and it was empty. Did not have 2-1/2" sub in stock. Check with operations engineer and Pollard will have one made. Rig for stand-by. 3/17/2014- Monday Mobe to location. RIH with 2-1/4"x5' pump bailer and work tools at 6,732' KB. POOH. Bailer empty. RIH with 2-1/2" GU baited w/internal fishing neck and bowen overshot and latch fish at 6,732' KB. Jar on fish 2,600lbs over, numerous times. Jar on fish at 3,600lbs over, 4 times and come off fish. POOH. Found big pin and broke in the GU adaptor sub. Wait on tools to come from Pollard shop. RIH with 2-1/2"JDC baited w/1-3/4" rope socket and bowen overshot and latch fish at 6,732' KB. Shear off and leave 1-3/4" external fish neck looking up for coil. Rig down slickline. 3/18/2014-Tuesday No operations to report. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-6 50-133-20568-00 207-064 3/6/14 4/8/14 Daily Operations: 3/19/2014-Wednesday Obtian SWP and HWP for Steam on Wheels to heat frac tank. Start equipment. Lay drip liners. Spot equipment. and OPS cab. NU BOP's. MU 2" hard lines. MU 5" lubricator. Connect hydraulic lines to reel and BOP's. Load coil w/25 bbls of 50/50 MEOH. Establish circulation across flowcross to FB tank. Visually function test BOP's. Close Blinds and choke. PTest blinds 250psi low/5,000psi high, test good. Insert 1-3/4" test bar. Close pipe rams. Test pipes, inside reel valve, and N2 check valve. Test 250 psi, test good. Test 5000 psi, test good. Test accumulator. BOP test complete. Cut coil. Prep cut. Install coil connector-grapple. MU w/ 36's, pull test to 16.7K. Good no movement. Tighten 1/2 additional turns, dimple. Install lock screws. Close valves on tree and BOP's. Secure WH. Secure equipment and location for the night. 3/20/2014-Thursday No operations to report. 3/21/2014- Friday Start equpment and crane. PU injector. MU 25' of 5" lubricator. MU BHA 1-3/4" extermal coil grapple, 2-1/2" DFCV, 2-1/8" accelerator, XO, 2-1/2" wt bar, XO, 2-1/8"jars, FAU disconnect. Install test plate. PTest. Coil has ice plug. ND BHA. NU lubricator. Pressure coil. Establish circulation thru coil. Install test plate. PT coil and BHA- 250psi low/3,500psi high, test good. Install 1-3/4" hydraulic release JDC on BHA. NU lubricator. Displace MEOH out of coil w/ KCL. PT shell to 1,000psi. Open WH. RIH. Can't get below 11'. Not even getting into tree. Close lower master. ND lubricator. RIH Tag about 4' below top of BOP's. Appears to be a ledge at the adapter flange on flowcross. Hand guide coil into tree. NU lubricator. Open master valve. RIH to 6,600'. PUH, weight check 17.4K Continue RIH pumping 1/2 bpm. Tag fish at 6,742'. Latch up. PUH 27K(10K over.) Slow pump to 1/4 bpm. Plan to pull 40K. Fish starts moving at 37.6K. Pull fish up hole. Fish breaks free at 6,732'. Pulling 18K, PUH to 5,700'. RIH to 6,729'. Taking weight. Bring pump on line 1-1/4 bpm. Setting weight down. Sink to 6,739' before JDC released. POOH. Stand down Baker for the night. MIRU Pollard slickline w/68' of lubricator to recover fish. PU lubricator. MU tool string 1-3/4" RS, stem, KJ, OJ, LSSJ, 2-1/2" JDC. RIH(1) w/2-1/2"JDC to 6,741'. Weight check. Latch fish. Hit one jar lick. Fish pulls free. PUH 200# heavy. POOH. OOH Recover-RS, KJ, 5' stem, KJ, 10' stem. Bottom stem has 3/4" rod thread broken. Left in hole: oil jars, short stroke spangs and 8' x 1-3/4" bailer. RD secure well for the night. l. 3/22/2014-Saturday RU .125 wire and PT lubricator. RIH with 2.5" LIB to 6,719' and POOH. NO impression. RIH with 2.25" pump bailer to 6,721'. POOH. Bailer had clay and a set screw in it. RIH with 2.25" PB to 6,722'. Bailer came back full of watter. RIH with magnet to 6,726'. No metal on magnet. RIH with 2" DD bailer to 6,727'. Work bailer through to 6,737'. Bailer full of fine grey sand. RIH with 2.25" PB to 6,723'. Full of water. RIH with 2.5" RB to 6,758'. Tapped 1 time and fell through to fish and latched it. Worked jars 10 times and sheared off. POOH and re pin with steel. RIH with 2.5 RB to 6,741' and latched up. Worked jars for 1 hr. Sheared off and pulled out of hole. Layed down for the night and secured location. 3/23/2014-Sunday Start equipment and crane. RU 160" wire. Rehead/repack stuffing box. PU 60' of lubricator. MU tool string-RS, Stem, stem, KJ, LSOJ, SSSJ. Carry lubricator to WH. PT lubricator 250psi low/2,500psi high. Test good. Open swab. RIH(1) w/2-1/2" SB to 6748. WT. On latch. POOH. Dogs on SB packed with sand. No sheared. RIH(2) w/ 2" bailer to 6,748'. WT. POOH bailer empty. Metal marks on mule shoe bottom. RIH(3) w/2-1/2" SB to 6,748'. WT hitting down. No latch, but drive fish down hole 14'. POOH. RIH(4) w/2-1/2" RB to 6,762'. Latch fish. Can see both sets of spangs and lower jars. Hit 2,000lb jar licks with lower jars on fish. No movement. Shear tools with upper jar lick. POOH. RIH(5) w/2-1/2" SB to 6,762'. Latch fish. Hit on jar lick. Pulled free. WT no more hook up's. POOH. Schucked dogs on overshot. RIH(6) w/2.1" spiral grapple on "bait" sub and 2-1/2 GR. Latch fish on first try. POOH. RIH(7) w/2-1/2" GS. Latch fish. Hit nine 3,4001b jar licks w/20" stroke jars. Fish pulls free. POOH. Recover entire fish-oil jars, LSSJ, KJ, 3" stem, 8' x 1-3/4" bailer. RIH(8) w/2-1/2" wirefinder and wire grab to 6,802' kb. WT. OOH. Recover no wire. RIH(9) w/2" magnet to 6,802. WT. Recover no wire gibblets. RD 160" wire unit. Secure WH and location for the night. 3/24/2014- Monday Start equipment and crane. PU injector. Cut coil grapple. Prep coil end. Install dimple-on connector. MU BHA-DFCV, 3' straight bar, 2" forward jetting nozzle. NU injector. PT shell to 1,500psi. Test good. Open swab vavle. RIH pumping min rates. At 3,000' increase rates. Tag fill at 6,780'. Pushing minus 3K weight. Break thru at 6,789'. continue down hole to PBTD of 7,629'. POOH. Turn well over to production. Total KCL pumped 227bbls, total N2 pumped 272,300 scf, total fluid recovered 370 bbls. Secure well and equipment for the night. 3/25/2014 Tuesday No operations to report. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 34-6 50-133-20568-00 207-064 3/6/14 4/8/14 Daily Operations: 4/2/2014-Wednesday No operations to report. 4/3/2014-Thursday Arrive KGF -JSA,TGSM, Permit. Pressure test lubricator 250 LP 1500 HP. R/U .125RIH 2.25" DD Bailer. Tag 5,778'KB. POOH. OOH. Bailer Empty. RDFN. 4/4/2014- Friday Arrive KGF-TGSM,JSA, Permit. Pressure test lubricator 250 LP 1500 HP. R/U .125RIH w/2.62 LIB to 5,770' KB, 400#0/P after slight set down(no beat down.) POOH. LIB slight impression of flapper. RIH w/2.31 swedge to5,778' KB set down no spangs, 300#0/P cycled several passes. POOH. Reconfigure w/knuckle jar between stem. RIH w/2.25x4' DD bailer to 7,172' KB. W/T POOH. OOH w/2 cups sand. Lay down to lube 0-rings. RIH w/same to 7,171' KB. W/T to 7,191' KB. POOH. Empty, flapper stuck. RIH w/same to 7,193' KB. W/T to 7,196' KB. POOH. Bailer 1/2 full w/ loose sand. RIH w/same to 7,193' KB. W/T to 7,196' KB. POOH. Bailer full of hard sand. RIH w/2.25 bailer 8' to 5,770' KB. W/T down. No Pass. POOH. Empty Bailer. RIH w/same to 7,196' KB. W/T to 7,196'. POOH. Bailer 1/2 full w/ loose sand. RIH w/same to 7,196' KB. WIT to 7,196'. POOH. Bailer 1/2 full w/ loose sand. L/D- Clean up Head to Shop- PWL. 4/5/2014-Saturday No operations to report. 4/6/2014-Sunday No operations to report. 4/7/2014- Monday No operations to report. 4/8/2014-Tuesday RU and PT lubricator 250 LP 1500 HP. RIH with 2.25 DD bailer to 7,144'. Full bailer. RIH with same to 7,145'. Full bailer. RIH with same to 7,130'. Full bailer. Well bore filling up with sand or side wall falling down. RIH with same to 7,132'. Full bailer. RIH with same to 7,122'. Full bailer. RIH with 2.5" DD bailer to 5,777'. Beat through bridge and fell down to 7,150'. Full bailer. RIH with 2.5" DD bailer to 5,777'. Worked through bridges. Fell through to 7,101'. Operator made the call to stop and open well to production. RD for the night tAj •perations Summary Report by J. Marathon Oil Well Name: KENAI BELUGA UNIT 34 -6 207 `(xii Qtr /Qtr, Block, Sec, Town, Range Field Name License # State/Province Country 1 KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.001 20.12 26.52 6.40 5/17/2007 6/3/2007 Daily Operations Report Date: 6/13/2007 Job Category: COMPLETION 24 Hr Summary MIRU Vetco pull 3 -1/2 "" Back pressure check valve, install 5K SSV, install inner /outer annulus gauges MIRU EXpro to run CBL. Ops Trouble Start Time End Time Our (hr) Ops Code Activity Code Status Code Com 09:00 09:30 0.50 SAFETY MTG AF Hold PJSM and obtain Permit for Vetco Gray . Discuss scope of job. 09:30 10:00 0.50 RURD OTHR AF MIRU Vetco to pull Back pressure check valve. 10:00 10:30 0.50 RUNPUL VLVE AF Pull 3 -1/2 "" BPCV. 10:30 12:00 1.50 TEST WLHD AF Install inner/ outer annuli pressure manifold on tree. Run instrument tubing to respective valves on tree. Test to 5k. Test good. 12:00 14:00 2.00 TEST WLHD AF Install 5K SSV on wing valve. Ptest to 5K. Test good. 14:00 14:20 0.33 RURD OTHR AF Rig down Vetco. 14:20 14:40 0.33 SAFETY MTG AF Hold PJSM and obtain Permit for Expro. Discuss scope of job. 14:40 15:30 0.83 RURD ELEC AF MIRU E -line for CBL.PU lubricator and tool string. 15:30 16:00 0.50 PULD LOG AF RIH with CBL. 16:00 16:55 0.92 RUNPUL ELEC AF Run free pipe pass from 3300'- 3500'. RIH. 16:55 17:30 0.58 LOG CSG TA MDLG Run repeat pass., Tool radials quit working. 17:30 18:00 0.50 RUNPUL ELEC TA MDLG POOH. 18:00 18:55 0.92 RUNPUL ELEC TA ' MDLG @ 3800' Tool working. RIH to log. 18:55 19:35 0.67 LOG CSG AF Run repeat section. 19:35 20:40 1.08 LOG CSG TA MDLG Run main pass. Tool problems. POOH. 20:40 21:25 0.75 RUNPUL ELEC TA MDLG OOH. Change out tool. 21:25 22:00 0.58 RUNPUL ELEC TA MDLG RIH with second CBL tool. 22:00 23:00 1.00 RUNPUL ELEC AF Run free pipe pass @ 3500'. RIH. 23:00 23:10 0.17 LOG CSG AF Run repeat section PBTD. 7613'. 23:10 01:00 1.83 LOG CSG AF Start main pass. Cement top @ 4100'. 01:00 01:30 0.50 LOG CSG AF End main pass @ 3900'. POOH. 01:30 02:00 0.50 RUNPUL ' ELEC AF OOH. RD. 02:00 02:30 0.50 RURD ELEC AF Leave location. Tum in Permits. Report Date: 6/30/2007 Job Category: COMPLETION 24 Hr Summary MIRU Expro Escape Crew, RU to Perforate Module 1 (7370'- 7380') Pert Module 1 on Green line. Good shot, verified acoustically and by vibration on wellhead. ' ., . -. - ., -- .• - _, - Ops - °' Trouble - - -. _. - - - - °- .. - _ _ Start Time End Time (hr) . Ops Code Activity Code Status Code , Com 08:00 08:30 0.50 SAFETY MTG . AF Hold PJSM and obtain safe work permit. 08:30 09:30 ' 1.00 RURD EQIP AF Rig up Expro Americas Escape Crew and hydraulic lines to perforate Module 1 on Green line. Module 1 is @ 7370' - 7380' MD 09:30 10:00 0.50 TEST TBG AF Pressure test hydraulic lines, Test good 10:00 11:00 1.00 PERF CSG AF Perforate Module 1 on Green line. Verified acoustically and by vibration on wellhead 11:00 12:00 1.00 RURD EQIP AF Stand Back for Frac, Sign out leave location Report Date: 7/1/2007 Job Category: COMPLETION 24 Hr Summary Safety meeting. Fraced mods 1 & 2 - screened out on mod 3. The three mods were pumped nearly as designed. . . _ Aps Trouble ' StartTime r, End Time , Dur {trr) _ Cps Code, Activity Code . .Status - Code Com. 06:00 07:30 1.50 SAFETY MTG AF Held pre frac safety meeting. Discussed slips trips and falls, high pressure frac ops, flowback, muster location, evac route, etc. 07:30 08:35 1.08 PERF CSG AF Pressure test frac lines to 9250psi. Good test. Test Nz lines. Gel up for Frac. 08:35 09:40 1.08 PERF CSG AF Open well SITP = 96 psig. Loaded hole with 1 bbl linear gel. Attempting to pump into mod 1. (7368' - 7378') Pumped 2 - 8 ppg. Fraced mod 1 with 4148 flex 12/20 and 30,845 white 20/40 = 34,944 TOTAL. Extended on 4 ppg stage to allow monitoring of the 4ppg on the perfs. 09:40 10:08 0.47 PERF ) Q G AF Mod 2 -( 7208' - 7218') pressured up to 4500psi and not sure when gun fired St N , UN 2 due to N2 in flush, but pinning was such that it was way above max firing pressure of 3300 on yellow line. Stage pad. 15.5 BPM. Frac'd perfs with 3683 flex 12/20 and 25,798 white 20/40 = 29,481 TOTAL. Pumped 2 - 10 ppg. NO commnication on the orange line - faced zone 1. 2975 isip. www.peloton.com Page 1/4 Report Printed: 8/3/2011 • •perations Summary Report by J. • Marathon Oil Well Name: KENAI BELUGA UNIT 34 -6 Qtr /Qtr, Block, Sec, Town, Range Field Name I License # State /Province Country KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB -Ground Distance (m) Spud Date Rig Release Date 0.00 20.121 26.52 6.40 5/17/2007 6/3/2007 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 10:08 13:25 3.28 PERF CSG AF Orange line is intact and holding pressure (250 - 750 psi). Mod 3 (7120' - 7130') - Fired at 4900 psi. Pumped 2 - 10ppg. Spike in pressure to 10,000, screened out when to 10ppg hit the perfs. Re -flush to attempt to clear the screen out. Flow back 13 bbl. Ran re -flush and pressure shot up again. Expro to flow back 100 bbls. Calling for coil. Frac'd perfs with 5446 flex 12/20 and 38150 white 20/40 = 43,596 TOTAL. Flow back of 60 bbl trying re flush at 2bpm and pressure went to 8400. Bleed off lines and rig up coil. Note, orange line spiked at screen out to 3,000 psi and was immediately vented. Appears to barely have missed minimum firing window. 13:25 16:30 3.08 RUNPUL COIL Rig up coil. Pressure test, Pull test, RIH circulating at 1 BPM. Tag sand at 2,750 feet. 16:30 17:30 1.00 AF Increase rate to 2 BPM and wash in hole at 60 feet per minute with full returns. Varying amounts of sand in retums entire time. Circulate for 5 minutes at 7,100 feet. Tag #3 flapper at 7,143' and broke with 6K down. Immediately lost fluid retums and slowly regained. RIH and did not see flapper #2. Partial fluid loss after washing sand across module 1 perfs. Continue in hole an tagged PBTD at 7,629 feet. 17:30 19:15 1.75 AF Circulate 1.5 hole volumes from TD at 2 BPM and POH with coil while circulating. Rig down injector head and secure well. SDFN. Report Date: 7/2/2007 Job Category: COMPLETION 24 Hr Summary Safety mtg. Fraced Excape modules 4 - 10 w/ 10 to 12 lb/gal sand placed Maintained integrity of Excape chem. inj. line . Rig up coil clean out. Jet in. Well to sales at 6.2 MM, 1300 psi, 340 BWPD and improving. Tum to Production Final Rpt. Ops Trouble Start Tithe .. Ere/ Time Dur (hr) Ops Code Activity Code ' Status Code Com 06:00 07:20 1.33 SAFETY MTG AF Held pre frac safety meeting. Discussed slips trips and falls, high pressure frac ops, flowback, muster location, evac route, etc. 07:20 07:35 0.25 PERF CSG AF Pressure test frac lines to 9250psi. Good test. Test Nz lines. Gel up for Frac. 07:35 08:53 1.30 PERF CSG AF Open well SITP = 300 psig. Loaded hole with 1 bbl linear gel. Mod 4 fired at 8820psi on yellow line, which then vented. (7007' - 7015') Pumped 2 - 4 ppg. Saw a rise in psi when 2bbl hit the perfs, cut the sand to allow 4bbl to hit the perfs and monitor. Shut down due to rising pressure. 4050 isip. Fraced mod 4 with 1034 flex 12/20 and 7145 white 20/40 = 8179 TOTAL. 08:53 09:05 0.20 PERF CSG AF Mod 5 - (6855' - 6865') fired at 2350 psi on green line. Pumped 2 - 10 ppg. Fraced mod 5 with 1923 flex and 13,388 white. Total slurry 184bb1. 09:05 09:27 0.37 PERF CSG AF Mod 6 - (6813' - 6823') fired at 4370psi. Pumped 2 - 10 ppg. Fraced mod 6 with 4344 flex 12/20 and 30,430 white 20/40. Total slurry 277bbl. 09:27 09:50 0.38 PERF CSG AF Mod 7 - (6772' - 6783') fired at 5294psi. Pumped 2 - 10ppg. Fraced mod 7 with 1976 12/20 flex and 13823 20/40 white. Total slurry 172bb1. Orange line is still intact. 2500 isip. 09:50 10:20 0.50 PERF CSG AF Mod 8 - (6731' - 6741') fired at 6430psi. Pumped 2 - 10 ppg. Fraced mod 8 with 4269 12/20 flex and 29,895 white 20/40. Total slurry 279bbl. 2300 isip. 10:20 10:58 0.63 PERF CSG AF Mod 9 - (6442' - 6452') fired at 7355psi at 10:35. Pumped 2 - 10 ppg. Fraced mod 9 with 5816 flex and 40735 white. Total slurry 331 bbl. 2200 isip. 10:58 11:35 0.62 PERF CSG AF Mod 10 - (5742' - 5753') fired at 8375psi at 11:14. Pumped 2 - 12 ppg. Fraced mod 10 with 6249 flex and 43,760 white. 2400 Total slurry bbl. 11:35 13:25 1.83 RUNPUL COIL AF Rig up coil for clean up and rigged down other equipment. NOTE: Orange line (downhole chemical injection line) intact and was not perforated or frac'd in two. 13:25 13:38 0.22 RUNPUL COIL AF Open well head. and start in hole 13:38 17:20 3.70 RUNPUL COIL AF Broke flappers at 6760' and 6802' (# 7 & #8) no other flappers detected. Ran to bottom at 7,644 CTM. Circulation rate during clean out was initially 2 BPM . Note: Lost returns below module #8 and had to start nitrogen injection to gain full returns. POH to above perfs 17:20 17:30 0.17 RUNPUL COIL AF CT Setting © 5700' Pump rate .5bpm N2= 47OCFM CTU = 2500 PSIG WH 238 PSIG. 17:30 18:05 0.58 RUNPUL COIL AF Start in hole - shut down water pumping and continued N2 at 470 CFM. 18:05 18:06 0.02 RUNPUL COIL AF CIH to 7639' increase N2 to 750 CFM. www.peloton.com Page 2/4 Report Printed: 8/3/2011 ftV J •Operations Summary Report by J• Marathon Oil Well Name: KENAI BELUGA UNIT 34 -6 Qtr /Qtr, Block, Sec, Town, Range Field Name License # State /Province Country KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.12 26.52 6.40 5/17/2007 6/3/2007 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 18:06 18:36 0.50 RUNPUL COIL AF Start back up hole to 5700' with WH pressure rapidly increasing - WH = 1050 PSIG. 18:36 18:45 0.15 RUNPUL COIL AF Stop coil & continue to circ N2 @ reduced rate of 450 CFM. Circ for 10 minutes and shut down N2. Wellhead pressure holding © 850 psig. 18:45 19:30 0.75 RUNPUL COIL AF TOH w /coil @ avg speed of 100 FPM. At surface w/1300 psig on wh & strong flowback. 19:30 20:25 0.92 RUNPUL COIL AF Shut well in due to washout problems. Repaired flowback iron and opened well to testers w/350 psig on choce. Well produced large amounts of sand - washing. 20:25 20:30 0.08 RUNPUL COIL AF work on cut out iron & packing off sand buster. 20:30 20:50 0.33 RUNPUL COIL AF Shut well in due packed off sand buster Expro making repairs. 20:50 21:30 0.67 RUNPUL COIL AF RB BJ Coil - secured location Current SITP = 1600. 21:30 06:00 8.50 RUNPUL COIL AF Turned well over to testers for night. Well was stabilized and brought on line to sales. Sand production significantly decreased, and cut out flow tees diminished (13 total to 6 AM). Well producing at 6.1 MM SCFD, 1300 PSI, and 340 BWPD at 06:00. Well turned to Production to manage with well testers at 0:600. Final DIMS completion report. Report Date: 8/15/2007 Job Category: COMPLETION 24 Hr Summary MIRU Expro to RIH with 1"" swage, 2.25 - fluted centralizer, with spang jars to break flappers. - ` 'Ops Trouble Start Time End Time Our (ttr) ; Ops Code Activity Code Status Code - Com 17:15 ' 17:45 0.50 RURD ELEC AF Move over from KBU 12 -5. RU 1"" swage, 2.25 - fluted centralizer on spang jars to RIH to break flappers. 17:45 18:00 0.25 TEST BOPE AF PTest Lubricator to 1500 psi. Test good. 18:00 18:31 0.52 TRIP TOOL AF RIH with 1 "" swage to break flappers. 18:31 18:44 0.22 RUNPUL ELEC AF Sat down in Module #3(7130- 7140') 18:44 19:15 0.52 RUNPUL ELEC AF Work thru flapper, but very sticky. 7140' TD. POOH. 19:15 19:45 0.50 TRIP TOOL AF OOH. Lay down lubricator and tools. RD. 19:45 20:00 0.25 SECURE WELL AF Secure well for the night. Tum in Permit. Leave loc. Report Date: 8/16/2007 Job Category: COMPLETION 24 Hr Summary MIRU Expro to RIH with Down hole video and WIT tool. / Ops ' ' Trouble .. . S t a r t Time - End Time Dui (te Ops Code Activity Code Status - C o d e , Com 07:30 08:30 1.00 SAFETY MTG AF Hold PJSM. Obtain Safe Work Permit. Go over JSA. Point out escape route and muster area. Discuss hazards such as overhead loads, pinch points, sorking at heights. 08:30 09:00 0.50 RURD ELEC AF PU 2.812 "" GR and junk basket run run thru swab valve and WH to Gear out grease. 09:00 09:15 0.25 TEST BOPE AF PTest Lubricator to 1500 psi. Test good. 09:15 09:30 0.25 RUNPUL ELEC AF RIH with tool string to clean grease out of tree. 09:30 09:45 0.25 RURD ELEC AF OOH. RU side view camera/ View Max. 09:45 10:45 1.00 RUNPUL ELEC AF RIH with DHV tool string. Well flowing © 1000 psi, 4.46 MMcf, 20 BWPD. Visibility not great. Able to see flowing mist, large beads, and slugs of water. 10:45 12:00 1.25 LOG OTHR AF Start viewing modules. In down view, able to see shiney machined tops of mandrels, nipple profiles, and couplings. Able to identify mandrels bu length using log depths. Can see pert nodes erupting from the casing wall. View often obscured by fluid froth or large slugs. Side view camera has a very close up view. Often obscured by flowing water slugs and froth. Threads appear very large in this view, but see them clearly. Difficult to know exact location in well. No CCL so you need an optical reference point to reference everything else from. 12:00 12:55 0.92 RUNPUL ELEC AF Sat down at 7000'(Module #4) tool stuck. PU to module #4. Viewing difficult because of water slugs flowing at camera. 12:55 13:30 0.58 RUNPUL ELEC AF Shut in well. View modules. Difficult to see in well fluid. WHP 1000 psi. 13:30 14:00 0.50 RUNPUL ' ELEC AF Open well to flow. Max shut in pressure 1150 psi. 14:00 14:30 0.50 TRIP TOOL AF OOH. RU WHIT tool. 14:30 15:25 0.92 TRIP ' TOOL AF Start in hole. 15:25 16:15 0.83 LOG OTHR ' AF Start 30 fpm down pass. w/ video(5600'). Spinner quit working @ 6300'. www.peloton.com Page 3/4 Report Printed: 8/3/2011 • - ANY" SperationS Summary Report by J• Marathon oil Well Name: KENAI BELUGA UNIT 34 -6 Qtr /Qtr, Block, Sec, Town, Range Field Name License # State/Province Country KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.12 26.52 6.40 5/17/2007 6/3/2007 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 16:15 17:00 0.75 LOG OTHR AF End sown pass © 6850'. Start up pass. Inspecting modules. Visiblity is better with this camera. More distict images. Able to see nipple profiles more clearly. 17:00 17:45 0.75 SECURE WELL AF OOH. RD.Secure well for night. 17:45 18:30 0.75 SECURE WELL AF Leave location. Turn in Permit. Report Date: 8/17/2007 Job Category: COMPLETION 24 Hr Summary MIRU Expro to RIH PLT Survey log and DH video in upper module. Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 07:30 . 08:30 1.00 SAFETY MTG AF Hold PJSM. Obtain Safe Work Permit. Go over JSA. Point out escape route and muster area. Discuss hazards such as slick surfaces due to rain, pinch points, working at heights. Well flowing 1003 psi @ 3.92 MMscf. Last test 22.7 BWPD. 08:30 08:55 0.42 RURD ELEC AF Check capacitance tool in air and in water durring pressure test. PU PLT tool string with 1- 11/16 "" caged spinner. 08:55 09:05 0.17 RURD ELEC AF PTest Lubricator to 1500 psi. Test good. 09:05 10:12 1.12 RUNPUL ELEC AF RIH with PLT tools © 90 fpm. Spinner is running. 10:12 10:20 0.13 RUNPUL ELEC AF Below Module # 10 spinner drops from 70 to 50 rpm. 10:20 10:24 0.07 RUNPUL ELEC AF Module #9 -no spinner or temperature change 10:24 10:26 0.03 RUNPUL ELEC AF Below Module #8- spinner drops 50 % 10:26 10:28 0.03 RUNPUL ELEC AF Module #7 - spinner continues to drop. 10:28 10:30 0.03 RUNPUL ELEC AF Module #5 no spinner or temp response. 10:30 10:43 0.22 RUNPUL ELEC AF 6970' End 90 fpm down pass.(Just above Module #4) No spinner, but temp shows cooling from below. Start 90 fpm up pass. Hung up © 7008' yesterday. (1278 psi & 117 F) 10:43 10:44 0.02 RUNPUL ELEC AF End 90 fpm Up pass © 5500'. Spinner count 50 rpm above Module #10 on up pass. 10:44 11:06 0.37 RUNPUL ELEC AF Start 60 fpm Down pass. 11:06 11:07 0.02 RUNPUL ELEC AF End 60 fpm Down pass © 6970'.(1298 psi & 117 F) 11:07 11:33 0.43 RUNPUL ELEC AF Start 60 fpm Up pass. 11:33 11:34 0.02 RUNPUL ELEC AF End 60 fpm Up pass © 5500' 11:34 12:18 0.73 RUNPUL ELEC AF Start 30 fpm Down pass Modules #8 and 10 seem to be the big contributers. 12:18 12:19 0.02 RUNPUL ELEC AF End 30 fpm Down Pass @ 6970'.( 1303 psi & 117 F) 12:19 ' 13:07 0.80 RUNPUL ELEC AF Start 30 fpm Up pass. 13:07 13:30 0.38 RUNPUL ELEC AF End 30 fpm Up pass @ 5500'. POOH. 13:30 13:50 0.33 RURD ELEC AF OOH. PU Down hole video tool. 13:50 14:03 0.22 RUNPUL ELEC AF PTest QTS. Test good. 14:03 14:30 0.45 RUNPUL ELEC AF RIH with DHV. Camera working. 14:30 14:50 0.33 RUNPUL ELEC AF @ module #10. Pad was ESD'd at 14:30. Fluid falling into wellbore. Cann't see anything but water falling. 14:50 15:55 1.08 RUNPUL ELEC AF Drop down into Module #9. Able to see X nipple profle and mandral. 15:55 16:35 0.67 RUNPUL ELEC AF POOH. Well retumed to production after ESD. 1250 psi. WHP. 16:35 17:30 0.92 RURD ELEC AF OOH. RD. Report Date: 8/18/2007 Job Category: COMPLETION 24 Hr Summary RUN Expro SRO P/T log. Surface P = 620 psi. Tagged at 7116' ELMD with 886 psi FBHP and 108 DegF BHT. Ops Trouble . Start Tine _, End Time , ; Our (hr) Ops Code Activity Code Status : ' Code , Com. . 08:00 09:00 1.00 SAFETY MTG AF Hold PJSM. Obtain Safe Work Permit. Go over JSA. Point out escape route and muster area. 09:00 10:00 1.00 RURD ELEC AF RU Expro eline unit and PU P/T logging tools. St6ab on well. 10:00 10:30 0.50 TEST EQIP AF Pressure test lubricator to 2000 psi with McOH. 10:30 ' 13:30 3.00 LOG CSG AF Log P/T from surface (620 psi) to tag at 7116 at 886 psi, 108 DegF. POH. 13:30 15:00 1.50 RURD ELEC AF RD eline unit. Secure well. Close permit and leave location. www.peloton.com Page 4/4 Report Printed: 8/3/2011 ~° `. ,; r '`' ,~~ ~.. - .~~, r ~;' a_ F ,~ iaw'- ~~. ~ ~ t ~. ` `~ _s , ~ _ ~ . MLCROFILMED 6/30/2010 D O NOT P LAC E ANY NEW MATERIAL UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc u ~ Marathon IIh0.RAiHON ~Alaska Productian LLC • `r~re'~C1w /C't'1 Marathon Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-9371 Fax 907/283-1350 ~G~+E~ V ~~ October 15, 2009 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 OCT 1 6 200~ ~1laska Oil & Gas Cans. Co~nission Anchorage ~ o~~ ~~ ~ Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 34-6 ~ Dear Mr. Aubert: Attached for your records is the10-404 Report of Sundry Well Operations for KBU 34-6 well. The AOGCC provided approval for the addition of 23' of perforations under Sundry # 308-380. Marathon n~c longer intends to perform this activity and is closing out this sundry as a Non~Work activity. Other wells in this program experienced reduced production when perForated, which was caused by additional water infiltrating the wellbore. This decision is intended to minimize the risk of loosing crucial production while entering the high demand season. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~Q~~''~ ` ~ Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Kenai Well File KJS STATE OF ALASKA ALAS~IL AND GAS CONSERVATION COMMI~N REPORT OF SUNDRY WELL OPERATIONS ~Cr~ IoltoC2oo9 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Non-Work of Performed: Alter Casing ~ Pull Tubin~ Perforate New Pool ~ Waiver^ Time E~ension ^ Perforations Change Approved Program ~ Operat. Shutdowr0 Perforate ^ Re-enter Suspended Well ~ 2. Operator Marathon Oil Company N 4. Well Class Before Work: 5. Permit to Drill Number: ame: Development ^~ Exploratory^ 207-064 3. Address: p0 Box 1949 Stratigraphic ~ Service ^ 6. API Number. ~~°~ Kenai Alaska, 99611-1949 50-133-~A6a6~00-00 7. KB Elevation (ft): 9. Well Name and Number: ~ ' 87 21' AGL Kenai Belu a Unit 34-6 8. Property Designation: 10. Field/Pool(s): ~ A- 028142 ~ Kenai Gas Field / Beluga & Tyonek Pools 11. Present Well Condition Summary: ~~ Total Depth measured 7,73g~ feet Plugs (measured) NA true vertical 7,gg2~ feet Junk (measured) NA Effective Depth measured 7,g7g' feet true vertical 7,522~ feet Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' SurFace 1,549' 13-3/8" 1,570' 1,491' ~'~~~~~~ Intermediate 5,415' 9-5/8" 5,436' 5,279' Production 7,696' 3-1/2" 7,717' 7,560' QC~ ~(D ZQQ~ Liner Alaska Oil & Gas Cons. Cotnmis~ion Perforation depth: Measured depth: 5,742' - 7,370~ Anchorage True Vertical depth: 5,585' - 7,213' Excape Tubing 3-1/2" L-80 7,717' Tubing: (size, grade, and MD) Capillary String Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): The approved perforation additions were not added because of the additional water infiltration issues experience with some of the other Treatment descriptions including volumes used and final pressure: wells, in this program, after they were perforated. 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: NA - - - - Subsequent to operation: NA - - - - 14. Attachments: 5. Well Class afterwork: Copies of Logs and Surveys Run Exploratory ^ Development Q Service ~ Daily Report of Well Operations 6. 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: 308-380 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory ComplianCe Technician ~ Signature ~~, ~ Phone (907) 283-1371 Date October 15, 2009 Form 10-404 Revised 04/2006 V ~~ S +~ 1~~~ ~ Submit Original Only 30~~,~ DATA SUBMITTAL COMPLIANCE REPORT 6/22/2009 Permit to Drill 2070640 Well Name/No. KENAI BELUGA UNIT 34-6 Operator MARATHON OIL CO API No. 50-133-20568-00-00 MD 7739 TVD 7582 Completion Date 6/30/2007 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log Yes Samples No Directional Survey Yes DATA INFORMATIDN Types Electric or Other Logs Run: CBL, Quad Combo, Gama Ray, CCL (data taken from Logs Portion of Master Well Data Maint Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / T Med/Frmt Number ~ame scale Meaia No Start Stop CH Received Gomments D C 15336' Report: Final Well R Open 8/23/2007 Final Well Report, with ~ Mudlogs and LAS files with other Graphics PDF, TIF and LAS Well CoreslSamples Information: Sample Interval Set Name Start Stop Sent Received Number Comments Cores and/or Sampies are required to be submitted. This record automatically created from Permit to Drill Module on: 5/11/2007. ADDITIONAL INFORM/~TION ~ Well Cored? Y~ Daily History Received? Chips Received? Y/ N Formation Tops ~ N Analysis 47N~ Received? Comments: Compliance Reviewed By: Date: ~ ~ ~_~ L~iIL1a7~L'f ~~ ~`L ~7 COI~TSERQATIOI~T COMDIISSIOI~T Kyle Miranda Production Engineer Marathon Oil Company PO Box 1949 Kenai, AK 99611 ~ SARAH PALIN, GOVERNOR 333 W. 7thAVENUE, SUITE 100 ANCHORAGE, ALASKA 995013539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kenai Gas Field, Upper Tyonek/Beluga Gas Pool, 34-6 Sundry Number: 308-380 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, Daniel T. Seamount, Jr. d Chair I/~ DATED this ZZ"day of October, 2008 Encl. , ~ ~ M Marathon MARATHON Oil Company October 20, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: 10-403 Application of Sundry Approvals Field: Kenai Gas Field Well: Kenai Beluga Unit 34-6 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~~~~ ~ ~ T 2 Z 2008 Alaska Oil ~ Gas ~ons. Comr~r~sio~ Anchorage Attached for your records is the10-403 Application of Sundry Approvals for KBU 34-6 well. Marathon proposes to enhance gas production by adding 23' of perForations to the Beluga formation. The proposed operation will be performed during three perForating gun runs at: MD TVD ft 5,516'-5,522' S,359' - 5,365' 7 6,608'-6,618' 6,451'-6,461' 10 6,972'-6,979' 6,815'-6,822' 6 Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~~Z~~-' , ~ Kevin J. Skiba Engineering Technician Enclosures: 10-403 Application of Sundry Approvals cc: Houston Well File Wetl Schematic Kenai Well File Perforation Procedure KJS KM . ~ ~ ~ STATE OF ALASKA ~~ ~" ~' " ~ /oV~B' ~ ~ ~ ' .'1~~ ALASKA OIL AND GAS CONSERVATION COMMISSION ~ ~ ~ APPLICATION FOR SUNDRY APPROVA~S ~T 2~ 2008~~`}~ ~n nnr ~~ ~Rn ~Sk~ Ott ,~ r.,.. ~ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown^ Perforate ~- W~i'~~ ' °~S~lO~ ~ Alter casing ^ Repair well ~ Plug Perforations ^ Stimulate ^ Time Extension ~ Change approved program ~ Pull Tubing ~ Perforate New Pool ~ Re-enter Suspended Well ~ 2. operator -vame: Marath011 OII CO111 an p y 4. Current Well Class: 5. Permit to Drill Number: Development ~ ~ Exploratory ~ 207-064 - 3. Address: p0 Box 1949 Stratigraphic ~ Service ~ 6. API Number: 6~~ Kenai Alaska, 99611-1949 50-133-205~00-00 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: i E ti R S ^ ~ Kenai Beluga Unit 34-6 ' ng xcep on equired? Yes pac No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): A- 028142 87' (21' KB) Kenai Gas Field / Beluga & Tyonek Pools 12• PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): 7otal Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7,739' - 7,582' - 7,679' 7,522' NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 93' 20" 114' 114' 3,060 1,500 Surface 1,549' 13-3/8" 1,570' 1,491' 3,450 1,950 Intermediate 5,415' 9-5/8" 5,436' S,279' 5,750 3,090 Production 7,696' 3-1/2" 7,717' 7,560' 10,160 10,530 Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5,742' - 7,370' gross 5,585' - 7,213' gross 3-1/2" L-80 7,717' 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 0 BOP Sketch ~ Exploratory ~ Development ~' Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: November 3, 2008 ~~I ~ Gas ^~ ~ Plugged ^ Abandoned ^ 17.VerbalApproval: 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 Titie Production Engineer Signature r , Phone Date ~' ,~~ ~ (907) 283-1370 October 20, 2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3D~, 3~v Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: 'W~L~~ ~'f~~\ ~~ \ ~'C`~L.~~ \`~ O-e.C~W ~ ~S a ~S l Subsequent Form Required: ~~~ APPROVED BY O ~Z ~ ~ ~ I Approved by: COMMISSIONER THE COMMISSION Date: `" ~ i-~ i~ I I~~I /~ L . . ~ ~i~~ ~,c-, ~ :~ ~o~s Form 10-403 Revised 06/2006 Submit in Duplicate M~ IstARATHON ~ ~ September 18, 2008 ~ Marathon Oil Corporation Field: Kenai Beluga Unit WBS: Not requested yet Pad: 41-7 KBU 34-6 Well Status: 2.649 MMcf/d @ 326 psi (TOW 9-21-08) and 2 bwpd (TOW 9-9-08). Obiective: Perforate three Beluga sands. Depths and surface pressure to fire guns: 6972' - 6979' (7' net, 6' gun, single run) -1240 psi 6608' - 6618' (10' net, 10' gun, single run) - 1260 psi 5516' - 5522' (6' net, 6' gun, single run) - 900 psi Guns to be used: 2-3/8" RTG (Retrievable Tubing Gun) guns loaded 4 SPF 60 degree-phased - with TAG-2375-402NTX charges and PX-1 firing head. API target performance: 0.27" entrance hole and 19.21" penetration. Max ~un swell in air: 2.575" OD. Note: the latest PT survey (9-17-08) tagged fill at 7212' (OH). Procedure: a) Remove well house. b) MI diesel man-lift. c) MIRU Expro E-line service with full lubricator, pump-in sub, flow tubes, and pressure control equipment. d) Hold PJSM. e) PT lubricator to 2000 psi (MPSP+) with KCL H20 or methanol, weather dependent. ~ RIH with dummy guns to minimum depth needed for CCL correlation. POOH GR. 2. a) RIH w/ 6' of guns (type shown above, 6' guns, single run). b) Correlate Expro CBL/GR/CCL log depth to open-hole logs. c) SI well long enough to obtain 1240 psi WHP (underbalanced at 40% DD). d) Pull up into position and shoot 6972' - 6979' (OH). Leave well shut in for 15 minutes while POOH. Observe and note pressure build rate over 15 minutes. Open well to flow while continuing to POOH. a) RIH w/ 10' of guns (type shown above, 10' guns, single run). b) Correlate Expro CBL/GR/CCL log depth to open-hole logs. c) SI well long enough to obtain 1260 psi WHP (underbalanced at 40% DD). d) Pull up into position and shoot 6608' - 6618' (OH). Leave well shut in for 15 minutes while POOH. Observe and note pressure build rate over 15 minutes. Open well to flow while continuing to POOH. ~ • , 1 ~ ~ 4. a) RIH w/ 6' of guns (type shown above, 6' guns, single run). b) Correlate Expro CBL/GR/CCL log depth to open-hole logs. c) SI well long enough to obtain 900 psi WHP (underbalanced at 40% DD). d) Pull up into position and shoot 5516' - 5522' (OH). Leave well shut in for 15 minutes while POOH. Observe and note pressure build rate over 15 minutes. Open well to flow while continuing to POOH. e) LD spent perf gun and lubricator. RD Expro. Return well to production. Flow test. 5. Produce well to sales. CONTACTS Ken Walsh: 907-283-1311 (w) Jennifer Enos: 713-296-3319 (w) 907-394-3060 (c) 713- 408-3583 (c) Lyndon Ibele: 907-565-3042 (w) Clyde Scott: 713-296-2336 (w) 907-748-2819 (c) KGF Operators: 907-283-1305 Perf MD Perf TVD Formation 40% dd Formation Surface Pressure to fire guns Bottom bottom Pressure* Pressure WAM calc temp Fill Fill _ ._~ _ 6979 6822 2425 1455 1241 125 6618 6461 2450 1470 1263 121 5522 5365 1700 1020 902 109 *MFT pressure KBU 34-6 Add perfs - MD Dammeyer 10/17/2008 12:05:24 PM - , i I~}r. GV/'VVY 50-133-20568-00-00 :rty Des: A - 028142 evation: 87' (21' AGL) 274,939.64 2,362,144.95 60° 27' 35.566" N : 151 ° 14' 48.603" W : 5/17/2007 18:00 hrs :ached: 5/30/2007 Tree cxn = 4-3/4" Otis Top of Cement (est.l ???' above 9-5/8" shoe - Ceramic flapper vaives below each module as follows: Flappers MD (RKB): Module 10 - 5,766' Module 9 - 6,466' Module 8 - 6,753' Module 7 - 6,795' Module 6 - 6,836' Module 5 - 6,878' Module 4 - 7,032' Module 3 - 7,145' Module 1 - NA - KBU 34-6 Pad 41-7 132' FSL, 972' FEL Sec. 6, T4N, R11W, S.M. .~ ~, ~a • ~r~ Expro ran P/T log on 1/20/08 tagged @ 7,116' ELM TD PBTD 7,739' MD 7,629' MD 7,582' ND 7,472' ND ~ Conductor 20" K-55 133 ppf PE To~ Bottom MD 0' 114' ND 0' 114' Surface Casinq 13-3/8" J-55 68 ppf BTC To~ Bottom MD 0' 1,570' ND 0' 1,491' 16" hole, Cmt w/ 490 sks (226 bbls) 12 ppg Class G, Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (100% returns) Intermediate Casing 9-5/8" L-80 40 ppf BTC T~o Bottom MD 0' S,436' ND 0' S,279' 12-1/4" hole, Cmt w/ 340 sks (190 bbls) 10.5 ppg Class G cmt. 100% returns, floats held. Production Tubing 3-1/2" L-80 9.3 ppf E U E T~o Bottom MD 0' 7,717' ND 0' 7,560' 8rd with 6.25" OD control line protectors to 5,436' RKB. 8-1/2" hole, Cmt w/ 1,076 sks (547 bbls) 11.5 ppg Class G cmt. - 10 Excape modules placed - Red control line for top 6 modules - control line for middle 3 modules - Green control line for bottom 1 module - Ceramic flapper valves below each module except for module 1 Module 10 - 5,742' - 5,752' (Beluga) Module 9 - 6,442' - 6,452' (Beluga) Module 8 - 6,728' - 6,738' (Beluga) Module 7 - 6,770' - 6,780' (Beluga) Module 6 - 6,812' - 6,822' (Beluga) Module 5 - 6,854' - 6,864' (Beluga) Module 4 - 7,008' - 7,018' (Beluga) Module 3 - 7,120' - 7,130' (Beluga) Module 2 - 7,210' - 7,220' (Beluga) Module 1 - 7,370' - 7,380' (Tyonek) Well Name & Number: Kenai Beluga Unit 34-6 Lease: Kenai Gas Field, A-028142 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 5,742' - 7,380' Perf (TVD): 5,585' - 7,223' Angle @ KOP and Depth: Angle/Perfs: Completion Fluid: 6% KCL Dated Completed: Ground Level (MSL): 66.1' Prepared By: Kevin Skiba Last Revison Date: 10/17/2008 )/20/2008 6:52 AM * ' ~ ~ Marathon Oif Company Alaska Asset Team Marathon ~.~. ~~x ~g~ . Kenai, AK 95611 MABATHQN O~I Company Telephone 9Q7/283-1871 Fax 907/283-1350 November 28, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7~' Ave ~~~~~~~~ Anchorage, Alaska 99501 NOV 2 9 2J0~ Reference: 10-421 Open Flow Potential Test Report A~~sk~ ~+! &~~s ~~~~~ ~~~miss6~r Anchorage Field: Kenai Gas Field Weli: Kenai Beluga Unit 34-6 ` c~,b~ Qear Mr. Maunder: Enclosed is the Qpen Flow Potential Test Report 10-421 for well KBU 34-6. This is a 10 module Excape well drifled in the Kenai Gas Field during May and June of 2007. All 10 modules were utilized to perforate and fracture stimulate the Tyonek and Beluga formations. If you have any questions or require additional information, please call me at (907) 283- 1371. Sincerely, • ~Q,~CJ~ ` `~-~ Kevin J. Skiba Production Technician Enclosures: 10-421 Open Flow Report cc: Houston Well File Kenai Well File KJS DMD ~~t.r CTV C V ~~~~s ~ ~ NOV 2 9 2007 STATE ~F ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION AlBSka Oil & Gas Cons. Commission GAS WELL ~PEN FLOW PUTENTIAL TEST REPOR°`~horag~ 'ia. Test: ~ Initial Annual Special 1b. Type 7est: Stabilized Non Stabilized Mlultipoint ^ Constant Time ~ Isochronal Q 4the~ Initial Well Test Data 2. Operator Name: 5. Date Completed: 11. Petmit t~ Drill Number: Marathon Oil Company 6/30/20~7 207-064 3. pddress: 6. Date Td Reached: 12. API Numker; PO BOX 1949 Kenai, Alaska 99611-1949 5/30/2007 50-133-20568-00-00 4a. tocation oE Well (Governmental Section); 7. KB E-evation (ft)s 13. Well Name a~d Number: Surface: 132' FSL, 972' FEL, Sec. 6, T4N, R11 W, S.M, 87' Kenai Beluga Unit 34-6 Top of Productive Horizon: $: Piug Back De~fh{MD+ND): 14. Field/Pool(s); 119.87" FSL. 1,886.85' FEL, Sec. 6, T4N, R11W, S.M. 7644' MD / 7487' TW Kenai Gas Field / Beluga & Upper Total Depth,i 9. Total Depth (MD + ND): 7yonek Pools 117.42' FSL, 1,896.86' FEL, Sec. 6, T4N, R11 W, S.M. 7739' MD / 7582' ND 4b. Lacation of Weil (State BasePlane Coardinates): 14, ~and Use Partnit; 15. Pr4perry Designation: Surface: x- 274939.64 y- 2362144.95 2one- +~ N/A A-028142 TPI` x- 274p24.73 y- 2362150.14 Zone- 4 16. Type of Gomplefion (Describej: Total Depth: x- 274014~66 y- 2362147.88 Zone- 4 Excape Compietion, Multi Zone-Frac 5timulated 17_ Casing Size Weight per foot, Ib. l:D. in inches Set at ft. 19. Perforatlons: From To 3-1/2" 9.3 2:992" 7739' MD 5742'-5752', 6442'-6452', 6731'-6741', 6772'-6782', 6813'- ' ' ' 18. Tubing Size' Weight per foot, Ib. I.D. in inches Set at ft. 6823', 6855 -6865', 7007 -7417 , 7120'-7130', 720$'-7218', 7368'-7378' (AII 10' Zones in MD) N/A N/A N!A N/A 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): N/A N/A N/A 0.564 24a. Produeing through; 24b. Reservoir Temp: 24c_ Reservoir Pressure: at t424psi Estd SiWHP 24d. Barometric Pressure;(Pa}> [] Tubing Q Casing EsYd 133 p° ~pgTV Est'd 1692 psia @.Datum 748T PBTUD 14.73 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg; % C02: % N2: % H2S: ' Prover; Meter F2un: Taps: 7378` 7221' 0,564 0 0 U Facility Test 26. FLOW DATA TUBING DATA GASWG DATA No. Provar Choke Line ~ Oriiice pressure biff. Temp. Pressure Temp. Pressure Temp. Duratian of Flow Size (in.) Size (in.) psig Hw F° pstg F° psig F° Hr. ~• 3.826 X 1.000 1000 A6.5 5Q - - - - 11:83 2• 3.826 X 1.Q00 899 5$ 53' - - - - 5.00 3• 3.826 X 1.000 800 64 60 - - - - 11.17 4• 3.826 X 1.Q40 701 72 64 - . - 7.83 5. X N Basic Coefficient 4 ~ Pressure Flow Temp. GravityFactor Super Comp. Rate of Flow o. Hour} (2 h Pm Factor F 9 Factor (~1 Mcfd Fb or Fp Ft Fpv 1. 81.9 48.2182538 1014.73 1:00 1.332 1.0$AO 3949 2. 85.3 55.4436651 913.73 1,00 1.332 1.4709 4729 $. 85.9 61.96773354 814.73 1.OU 1.332 1.0642 5321 4. '87.3 67.88225099 715.73 1.00 1.332 1.0574 5924 5. for Separator far Flowing Temperature No: Pr Tr z Gas Fluid T Gg G '! . 7.51 510 1.49 0.851 0.564 N/A 2, 1.36 513 1.49 0.872 3.' 1.21 520 1.52 U.883 Critical Pressure 673.1 4. 1.Q6 524 9.53 0.895 C~+f+cal Temperature 343.2 5. Farm 10-421 Revised 1/2 t ~ q~~~ ~}~~, ~C~N~J,R~JED ON REVERSE SIDE U f"~' ~~'v ~ L Submitin Duplicate ~r 9 UU~ ~ ~~3 • ~ Pc 1439 p~a 2d7172g,4 Pf py~ No. Pt Pt~ Pc2-Pt~ ~ Pw2 Pc2-PwZ PS P z Pf~-Ps2 1. 1015 1029254 1042474.705 2. 914 835350 1236378.862 3. 815 663715 1408013.243 4. 716 512789 1558938.924 5. "L5. AOF (Mcfd} 7,868 n ~•~ Remarks: Excape well. SIWHP estimated at 1424.7 psig. I hereby ce ify that th foregoing is true and cor~ect to the best of my knowledge. Signe Dennis M Donovan Jr. Title Praduction Engineer Qate ~v2at2oo7 DEFINITIONS OF SYMBOLS AOF Absolute Open Flow Potential. Rate of Flow that would be obtained if the bottom hole pressure opposite the producing face were reduced to zero psia Fb Basic orifice factor Mcfd/ hwPm Fp Basic critical flow prover or positive choke factor Mcfdlpsia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= Z dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensioniess GOR Gas-oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential p~essure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back-p~essure equation, dimensionless Pa Field baromet~ic pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute tempe~ature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manua/ of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 ~ ` ~1'1~~'101'~ MARATHOPI ~II ~oV~~a~~ August 23, 2007 Alaska Oil & Gas Conservation Commission Attn: Howard Okland 333 W. 7`~' Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon KBU #34-6 - API 50-133-20568-00 CONFIDENTIAL Dear Mr. Okland: A(as"ka Asset Team United States Production Operations P.O. Box 3128 Houston, TX 77253 Telephone 713-296-3597 Fax 713-235-6322 Hand Delivefy Enclosed is one CD containing confidential digital well data for the above referenced well, as described on the attached CD Contents document. Please indicate your receipt of this data by signing below and returning one copy to my attention at the letterhead address or fax to 713-23~-6322. Thank you, ~~~j~,~~~ ~~~?t~-'r,~~ ~~~ ,~ ° Courtney McElmoyl r.~~'-O(o~~ # ~ 533~ ~ Received by: ~~~~~~., ~ s ~ ~ ~,. ~ :~ ~ ~~ ~ ~ ~~ .~ ;~ Date: ~ ~ ~~5~ ._, :~ 7_'~0 3 Enclosures ~ ~ff;~ ~~ '; t~ ~ ~'i(i~ ~"ruC~.iilt~~lGt~ ,~,.~;1t^~m~~ ~ ~ M Marathon MARATHON Oil Company August 17, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-407 Sundry Notice Field: Kenai Gas Field Well: KBU 34-6 Dear Mr. Maunder: Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~EC~IVEQ AUG 2 0 2007 Alaska Oil & Gas Cons. Cemmission Anchorage Attached and submitted for your records is the Form 10-407 for the completion work perFormed in the Kenai Beluga Unit 34-6. This well is an active Tyonek gas producer. Also attached for your records are the operational history, final directional survey, and well schematic. If you have any technical questions or need further information please call me at (907) 283-1311. Please send any return correspondence to Kevin Skiba at the letterhead address above. Non-technical questions should be directed to Kevin at (907) 283-1371. Sincerely, C~,/~/~.~ , ~ I Ken D. Walsh Senior Production Engineer Enclosures: 10-407 Sundry cc: AOGCC Well Schematic Houston Well File Operations Summary Kenai Well File Directional Survey KDW " STATE OF ALASKA ~~ , ALAS~ OIL AND GAS CONSERVATION COM~SION ~GliGl V LV AUG 2 0 2007 WELL COMPLETION OR RECOMPLETION REPORT~~R~~~ ~~ons. Cornmission 1a. Well Status: Oil ~ Gas~ Plugged ~ Abandoned ~ Suspended ~ 1b. Well Class: zonnczs.~os zonaczs.~~o Development ^~ Exploratory^ GINJ^ WINJ^ WDSPL~ WAG^ Other^ No. ofCompletions: Service ^ StratigraphicTest^ 2. Operator Name: 5. Date Comp., Susp., or 12. Permit to Drill Number: Marathon Oil Company Aband.: 6/30/2007 207-064 3. Address: 6. Date Spudded: ' 13. API Number: PO Box 1949, Kenai Alaska, 99611-1949 5/181'2007 50-133-20568-00-00 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: 5/3~/2007 Kenai Beluga Unit 34-6 SurFace: 132' FSL, 972' FEL, Sec. 6, T4N, R11W, S.M. Top of Productive Horizon: 8. KB (ft above MSL): g7' 15. Field/Pool(s): 119.87' FSL, 1,886.85' FEL, Sec. 6, T4N, R11W, S.M. Ground (ft MSL): 66' i G Fi ld / K Total Depth: 9. Plug Back Depth(MD+TVD): ena e as geluga & Upper Tyonek Pools 117.42' FSL, 1,896.86' FEL, Sec. 6, T4N, R11W, S.M. 7,644' MD 7,487' ND 4b. Location of Well (State Base Plane Coordinates, NAD 27): 10. Total Depth (MD + TVD): 16. Property Designation: SurFace: x- 274,939.64 y- 2,362,144.95 Zone- 4 7,739' MD 7,582' ND A- 028142 TPI: x- 274,024.73 y- 2,362,150.14 Zone- 4 11. SSSV Depth (MD + TVD): 17. Land Use Permit: Total Depth: x- 274,014.66 y- 2,362,147.88 Zone- 4 NA 18. Directional Survey: Yes ~ No 19. Water Depth, if Offshore: 20. Thickness of Permafrost (TVD): (Submit electronic and printed information per 20 AAC 25.050) NA (ft MSL) NA 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): CBL, Quad Combo, Gamma Ray, CCL 22. CASING, L INER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM pULLED 0 2p^ 133 K-55 0' 114' 0' 114' Driven NA NA 13•3/8" 68 J-55 0' 1,570' 0' 1,491' 16" 490 sks, 12 ppg 65 sks 9-5/8" 40 L-80 0' S,436' 0' S,279' 12-1/4" 340 sks, 10.5 ppg, Class G NA 3-1/2" 9.3 L-80 0' 7,739' 0' 7,582' 8-1/2" 1,076 sks, 11.5 ppg, Class G NA 0 23. Open to production or injection? Yes ~ No ~ If Yes, list each 24. TUBING RECORD interval open (MD+TVD of Top & Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD) Ten Excape Intervals 3-1/2" 7,717' NA MD: 5,742'-5,752', 6,442'-6,452', 6,731'-6,741', 6,772'-6,782', 6,813'- ' ' -7,130 , 7,208'-7,218', 6,823', 6,855'-6,865', 7,007'-7,015', 7,120 7 3 ' ' 25 ACID, FRACTURE, CEMENT SQUEEZE, ETC. , -7,378 68 DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED ND: 5 285'-6 295' 6 574'-6 584' 6 615'-6 625' 6 656'- 585'-5 595' 6 , , , , , , , , , , , , , 6,666', 6,698'-6,708', 6,850'-6,860', 6,963'-6,973', 7,051'-7,061', 5,742' - 7,378' (Gross) 273,969 Ib 20/40 white sand 7,211'-7,221' 38,8881b 12-20 flex Module #1: 2.375" 6 spf Module #2 - #10: 2.625" 10 spf 26. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 7/1/2007 Flowing Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 7/28/2007 24 Test Period 0 4,700 22.7 0.5" NA Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bbl: Oil Gravity - API (corr): Press. 975 0 24-Hour Rate ~ 0 4,700 22.7 NA 27. CORE DATA Conventional Core(s) Acquired? Yes ^ No ^~ Sidewall Cores Acquired? Yes ^ No ^~ If Yes to either question, list formations and intervals cored (MD+TVD of top and bottom of each), and summarize lithology and presence of oil, gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions, core chips, photographs and laboratory analytical results per 20 AAC 25.071. C~it~P~zT!ClN~` ~~~~~ ~~~ ~~ ~ ~ ~ 2oor ~, 3a - o ~ ~ Form 10-407 Revised 2/2007 ~ ~ ~ ~ ~ ~i ~~NTINUED ON REVERSE ~' ~, .~~ ~'/ '"'"~~ ~ 1 Y ~. 28. GEO~~OGIC MARKERS (List all formations and ma ncountered): 29. FORMATION TESTS NAME MD ND Well tested? Yes Q No yes, list intervals and formations tested, briefly ~ summarizing test results. Attach separate sheets to this form, if needed, and submit Permafrost - Top detailed test information per 20 AAC 25.071. Permafrost - Base Zone Top MD Top ND psia M Beluga 5,742' S,585' 2,066 Middle Beluga 5,436' S,279' L Beluga 6,442' 6,285' 2,639 L Beluga 6,728' 6,571' 2,366 L Beluga 6,770' 6,613' 2,182 Tyonek 7,340' 7,183' L Beluga 6,812' 6,655' 2,196 L Beluga 6,854' 6,697' 3,348 L Beluga 7,008' 6,851' 2,466 L Beluga 7,120' 6,963' 3,627 L Beluga 7,210' 7,053' 2,821 Tyonek 72-8 7,370' 7,213' 2,597' Formation at total depth: 30. List of Attachments 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Kevin Skiba (907) 283-1371 Printed Name: Ken D. Walsh Title: Senior Production Engineer Signature: ~J~~ Phone: (907) 283-1311 Date: 8/17/2007 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 I njection, 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 and Ground Level elevations in feet above mean sea level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20. Provide MD and ND for the top and base of permafrost in Box 28. 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 peRinent 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: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 29: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 2/2007 ~: 50-133-20568-00-00 ~erty Des: A - 028142 21' AGL (87' KB Elevation) 274,939.64 2,362,144.95 60° 27' 35.566" N ~ 151 ° 14' 48.603" W d: 18:00 hrs 5/17/2007 teached: 5/30/2007 Released: 24:00 hrs 6/6/07 Tree cxn = 4-3/4" Otis Top of Cement (MD) 1,336' above 9-5/8" shoe - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 1 - NA Module 2 - 7,234' Module 3 - 7,145' Module 4 - 7,032' Module 5 - 6,878' Module 6 - 6,836' Module 7 - 6,795' Module 8 - 6,753' Module 9 - 6,466' Module 10 - 5,766' ~ KBU 34-6 Pad 41-7 132' FSL, 972' FEL Sec. 6, T4N, R11W, S.M. Conductor 20" K-55 133 ppf PE Top Bottom MD 0' 114' ND 0' 114' Surface Casinq 13-3/8" J-55 68 ppf BTC To~ Bottom MD 0' 1,570' ND 0' 1,491' 16" hole, Cmt w/ 490 sks (226 bbls) 12 ppg Class G, Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (100% returns) Intermediate Casinq 9-518" L-80 40 ppf BTC To~ Bottom MD 0' S,436' TVD 0' 5,279' 12-1/4" hole, Cmt w/ 340 sks (190 bbls) 10.5 ppg Class G cmt. 100% returns, floats held. Production Tubinq 3-112" L-80 9.3 ppf EUE To~ Bottom MD 0' 7,717' ND 0' 7,560' 8rd with 6.25" OD controlline protectors to 5,436' RKB. 8-112" hole, Cmt w/ 1,076 sks (40 bbls) 11.5 ppg Class G cmt. - 10 Excape modules placed - Green control line for bottom 1 module - Yellow control line for middle 3 modules - Red control line for top 6 modules - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB) (Beluaa/Tvonek Zones): Module 1 - 7,368' - 7,378' (Tyonek) Module 2 - 7,208' - 7,218' (Beluga) Module 3 - 7,120' - 7,130' (Beluga) Module 4 - 7,007' - 7,017' (Beluga) Module 5 - 6,855' - 6,865' (Beluga) Module 6 - 6,813' - 6,823' (Beluga) Module 7 - 6,772' - 6,782' (Beluga) Module 8 - 6,731' - 6,741' (Beluga) Module 9 - 6,442' - 6,452' (Beluga) Module 10 - 5,742' - 5,752' (Beluga) Well Name & Number: KBU 34-6 Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Perforations (MD): 5,742' - 7,380' Perf (TVD): 5,585' - 7,223' Angle/Perfs: Angle @ KOP and Depth: BHP: BHT: Completion Fluid: 6% KCL Dated Completed: Ground Level (MSL): 66.1' Prepared By: Kevin Skiba Last Revison Date: 7/26/2007 8/16/2007 4:26 PM TD - 7,739' (MD) PBTD - 7,679' (MD) ., ~ ~ Marathon Oil Company Page ~ of 6 I Operations Summary Repork Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL DRILLING Start: 5/14/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date J From - To Mours Code Code Phase 5/14/2007 00:00 - 06:00 6.00 MOB RIG MIRU 5l15/2007 06:00 - 06:00 24.00 RURD RIG MIRU 5l16/2007 I 06:00 - 03:00 ~ 21.00 ~ RURD_~ RIG_ I MIRU 03:00 - 06:00 5/17/2007 I 06:00 - 13:00 13:00 - 21:30 21:30 - 06:00 5/18/2007 I 06:00 - 12:00 12:00 - 13:00 13:00 - 15:30 15:30 - 17:30 17:30 - 18:00 18:00 - 21:45 21:45 - 22:00 22:00 - 22:30 22:30 - 06:00 5/19/2007 06:00 - 09:00 09:00 - 11:30 11:30 - 12:00 12:00 - 13:30 1330 - 14:30 14:30 - 16:00 3.001 NUND I BOPE I SURDRL 7.00 I NUND I BOPE I SURDRL 8.50 PULD_ DP_ SURDRL 8.50 WAITON EQIP SURDRL 6.00 I WAITONI EQIP I SURDRL 1.001 SAFETYI DRIL I SURDRL 2.50 RURD_ OTHR SURDRL 2.00 PULD_ DP_ SURDRL 0.50 PULD_ BHA_ SURDRL 3.75I DRILL_ ~ ROT_ ~ SURDRL 0.25 CIRC_ MUD_ SURDRL 0.50 TRIP_ BHA_ SURDRL 7.50 WAITON EQIP SURDRL 3.00 WAITON EQIP SURDRL 2.50 PULD BHA SURDRL 0.50 CIRC CFLD SURORL 1.50 TRIP_ TOOL SURDRL 1.00 TRIP_ TOOL SURDRL 1.50 ~ TRIP_ ~ TOOL ~ SURDRL Description of Operations Finish cleaning rig. Prep to move. Move and set pits boiler and water tank. Spot sub. Set mud boat set carrier and level up. Set pits and pumps. PJSM. crane fuel tank, stairways ,gray iron ,choke and dog houses. Crane up wind walls. Set Catwalk. Move Generator house and install generator. Set Generator Unit. Run electrical and control lines. Raise mast to floor level. Set rear windwalls on rig floor. Scope up mast. R/U pit & pumps. Re install oil coolers. Set MI van Rig up GD-1. Set beaver slide. R/U torque tube. Set Mats and # 3 Mud pump. Set shop and parts houses. P/U top drive install serviceloop, Inspect turnbuckles clean and paint . Set-in rebuilt generator #1. Dress top of 20 " conductor and install Starting head , test seals to 500psi / 10 min. complete R/U of torque tube. Install 3" outlets on 20". Set pipe racks. Re-build mud pump pop-off. Re-dress 5" swab.Complete R/U GD-1 0300hrs 5-16-07 PJSM. NU the 20" diverter stack, install Koomey hyd. lines. Build battery cables for #1 generator. Cont. N/U diverter system R/U flow nipple & trip tank lines. Install flow nipple, Kinfe valve and diverter line. P/U Drift stand back in mast and tally 220jts 5" drillpipe. Complete Instalation of # 1 generator and put on line. R/U Epoch rig watch. Pre charge compensator on top drive. fill pits and function test all mud system components . Fill Pits and mix spud mud. Fire boiler and work on steam lines. service rig. Function test diverter system. AOGCC and BLM notified but witnessing wavied. System tests as it should. Make repairs to piYs aggitator electrical system. General clean-up and painting. Hold weekly safety meeting with both crews. Review recent incidents and past FORC cards. Set pipe racks load 5" HWDP and strap P/U drift and stand back 21jts HWDP and jars M/U BHA # 1, 16" bit, Bit sub and cross over sub. For clean out of 20" conductor Drill /clean out conductor. Tag up at 35' Clean out to 114' conductor shoe Drill new hole F-114'-165' ( drill enough hole to allow Pick up of remaining directional bha. Circ 438gpm 280psi 2-3wob 40rpm tq 2-3k ART = 3hr. Spud well at 1800hrs 5-17-2007 Circ B/U 220spm 434gpm 280psi Clean up hole POOH For Bha change. UD clean out bha Rig maintenance and repair. Wait on directional personal. Drift and tally 13 3/8 Csg. Inspect brakes adjust linkage work on # 2 Charge pump Cont. rig maintenance. Wait on Baker personal PJSM: P/U BHA#2 16" bit motor, mwd, flex drill collars stab Attempt to circulate. Drill string pressured up without flow. check surface lines. TOH found bit plugged with gravel. Due to influx of fine gravel TIH attempt to break circulation with same results. Bit appears to be plugged. TOH L/D MWD. /I Printed: 8/16/2007 4:48:23 PM . ~ ~ Marathon Oil Company Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Event Name: ORIGINAL DRILLING Start: 5/14/2007 Contractor Name: Rig Release: Rig Name: Rig Number: Date From - To Hours Code Code Phase 5/19/2007 16:00 - 17:15 17:15 - 17:30 17:30 - 18:00 18:00 - 19:00 19:00 - 00:00 00:00 - 06:00 5/20/2007 06:00 - 10:00 10:00 - 10:45 ' 10:45 - 18:00 18:00 - 19:00 19:00 - 21:00 I 5/21 /2007 21:00 - 21:30 21:30 - 22:30 22:30 - 00:30 00:30 - 02:15 02:15 - 04:40 04:40 - 06:00 06:00 - 07:00 07:00 - 11:00 11:00 - 12:30 12:30 - 14:30 14:30 - 14:45 14:45 - 15:30 15:30 - 16:58 16:58 - 18:00 18:00 - 19:00 19:00 - 20:50 20:50 - 00:00 00:00 - 00:20 00:20 - 04:00 04:00 - 06:00 5/22/2007 06:00 - 07:30 07:30 - 17:30 Page 2 ~af 6 Spud Date: End: Group: Description of Opsrations ~ 1.25 TRIP TOOL SURDRL TIH cleanout to 165'. 0.25 DRILL ROT SURDRL Drill from 165' to 199'. 0.50 TRIP TOOL SURDRL TOH 1.00 PULD BHA_ SURDRL PU MWD align toolfaces. RIH 5.00 DRILL_ ROT_ SURORL Directionally drill f/ 199' to 470' W06= 5-15k 490gpm 700-850psi TF= 270 deg (ART= 0.8hrs) (AST= 3.8hrs) 6.00 DRILL_ ROT_ SURDRL Directionally drill ahead f/ 470' to 873'. Increasing pump rates to 638gpm 1360psi. (ART= 1.Ohrs) ( AST= 3.7hrs) 4.00 DRILL_ SLID SURDRL Directionally drill f/ 873'-1085' 620gpm 1250psi WOB 5-15k Tq 3-3.5 Up wt =65 Dn wt. 65 Rt wt. 62 Ast= 1.3hrs Art = 0.2hrs 0.75 CLEAN LOC_ SURDRL Clean up mud from cellar, berm and pad. Trip tank overFlowed 2-4bbls mud spilled outside of containment. 7.25 DRILL_ SLID SURDRL Drill rotate f/ 1085' -1578' 600gpm 1400 psi WOB 5-15 Tq 2-6 Up wt. 74k. Dn.wt. 64k Rtwt. 70k. Ast= 0 Art= 5.4 1.00 CIRC_ MUD_ SURDRL CBU 2X 2.00 TRIP_ DP_ SURDRL PJSM review tripping hazards. Wiper trip to conductor shoe. No overpulls. 0.50 SERVIC RIG SURDRL Service rig. 1.00 TRIP DP SURDRL TIH 2.00 CIRC MUD SURDRL Circulate condition hole. 1.75 TRIP DP SURDRL Drop rabbit. TOH SLM no correction. 2.42 PULD BHA SURDRL L/D SS MWD, SDC and motor. 1.33 RURD CSG SURCSG PJSM. Changeout to long bales. 1.00 RURD CSG SURCSG Continue RU long bales. Casing elevators and tongs. 4.00 RUN CSG_ SURCSG Run 13 3/8 csg. M/U shoe track and bakerlok, Ck floats Run 36jts 13 3/8 J-55 68# BTC Csg.to 1570' ( Shoe at 1569' ) 1.50 RURD CSG_ SURCSG R/D csg. tools. R/U floor. C/O bails and elevators. Set false rotary 2.00 TRIP DP SURCSG PJSM; M/U stab in tool and DP centralizer on 5" DP pup. RIH W/ 5" DP innerstring. Stab into float collar and space out . 0.25 RURD OTHR SURCSG R/U Flow nipple, head pin and cement lines 0.75 CIRC MUD_ SURCSG Break circulation, stab-in tool holding. 100% returns at 5.5bb1 per min. Dump 180 bbls mud to hanson tank. Hold PJSM with BJ vac drivers and crew. ( Cementing procedures and Hazards) 1.47 PUMP CMT_ SURCSG Pump 40bbls Mud clean 2 preflush with rig pump. switch to BJ and pump 2bbls H20 test lines to 3000. Mix and pump 226bb1s 490sx 12ppg. Displace with 2bbls H2o and 24 bbls mud. 100% returns cement in place at 16:58 hrs. 30 bbls returned to surface. floats held. 1.03 CIRC MUD SURCSG Load and pump sponge ball thru DP. CBU 1.00 CLEAN_ TANK SURCSG Cleanout stack, cellar, trip tank. 1.83 TRIP_ DP_ SURCSG TOH 3.17 NUND BOPE SURCSG RD 16" blooie line. Strip down 20" diverter and 16" knife valve make ready to rough cut 13-3/8" csg. Transfer mud from pits to Hansen holding tank. Clean cuttings tanks. Haul spud mud to G&I. 0.33 SAFETY DRIL SURCSG New crews back f/ days-off. PJSM review days events and Plan Forward. Check cement sample - hard. 3.67 NUND BOPE SURCSG Test f/ LEL H2S 02. Make rough cut on 13-3/8" csg and UD same. LD mousehole. ND drilling nipple. Finish ND 20" diverter/blooie line spool. Hoist and remove from cellar. 2.00 NUND WLHD SURCSG Make final cut on 13-3/8" csg. Remove 20" starting head. Install Vetco Multi-bowl, FC29-MB-236 5m wellhead. 1.50 NUND WLHD SURCSG Finish installing wellhead. Test to 1500psi / 10min. Good test. : Note RKB is 21.80' 10.00 NUND BOPE SURCSG PJSM; N/U 13-5/8" 5K BOPE, flow lines trip tank, Choke and Kill lines. Printed: 8/16/2007 4:4823 PM ~ ~ Marathon Oil Company Page3 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL DRILLING Start: 5/14/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Phase Description of Operatians Date From - To Hours Code Code 5/22/2007 07:30 - 17:30 10.00 NUND BOPE SURCSG Install Koomey hydraulic control ines. Install drip pan Mix 500 bbls flow pro mud. 17:30 - 00:00 6.50 TEST BOPE SURCSG Held PJSM for High Pressure testing reviewed hazards and procedures. M/U test joint, set test plug. Test BOP and all components 250/3000 f-10min Found leak on Kill line'grey-lock' fitting and replaced. Check pre-charge pressure on N2 bottles. Perform accumulator drawdown test. ( Witnessing waved by Jeff Jones w/ AOGCC and Tim Lawlor w/ BLM) 00:00 - 00:15 0.25 SAFETY DRIL SURCSG PJSM review "Plan Forward" and PU BHA hazards. 00:15 - 01:00 0.75 RUNPU WBSH SURCSG Set wearbushing RILDS. 01:00 - 03:30 2.50 PULD BHA_ SURCSG PU directional BHA. Align toolfaces on motor and MWD. 03:30 - 04:00 0.50 REPAIR RIG_ SURCSG Driller checked the "Crown-O-Matic" operation and was unable to release the brake. 04:00 - 05:00 1.00 PULD BHA SURCSG Finish PU BHA. 05:00 - 06:00 1.00 TRIP DP SURCSG TIH. 5/23/2007 06:00 - 06:30 0.50 TRIP DP SURCSG TIH with BHA 06:30 - 07:00 0.50 SERVIC RIG SURCSG Wire in RPM Sensor for EPOCH 07:00 - 09:00 2.00 DRILL CMT SURCSG Drill out Cement and Float Equip. From 1523'-1603' 09:00 - 10:00 1.00 CIRC MUD_ SURCSG Displace Surface fluid with Flowpro 9.2# Lots of sand in returns. 10:00 - 11:00 1.00 TEST LOT_ SURCSG Perform FIT test. Press. to 460 psi EMW of 15 ppg. W/9.15 ppg mw Press. to 460 psi W/ 11 stks.,Shut in log press. loss. Went from 460 psi to 265/ 5 min.-From 265 psi to 230 psi 10 mins.-From 230 psi to 200 psi/15 mins.From 200 psi to 150 psi/30 min.Stablized for 10 min.-Bled off Test Casing to 1500psi test good , 11:00 - 18:00 7.00 DRILL_ ROT_ IN1 DRL Drill F/ 1603'- 2020'. W06= 4-6 Pump= 425gpm PP= 800psi ART= 3.7 AST= .2 18:00 - 00:00 6.00 DRILL_ ROT_ IN1 DRL Directionally drill f/ 2020' to 2373'. WOB= 2-10k Pump= 575 to 625gpm (graduallly increasing rate as mud shears and shakers can handle additional flow) PP= 1350psi ART= 3.1 AST= .5 00:00 - 06:00 6.00 DRILL_ ROT_ IN1 DRL Directionally drill f/ 2373' to 2817'. WOB= 2-10k Pump 625gpm PP 1450psi. (#1 shaker 200 mesh, #2 shaker 230 mesh screens) ART= 3.0 AST= 1.0 5/24/2007 06:00 - 12:00 6.00 DRILL_ ROT_ IN1 DRL Continue directionally drill ahead f/ 2817'-3090' WOB = 5K-20K Pump 640gpm 1450psi 330spm. ( pump hi-vis sweep at 2950' sweep returned 100inc cuttings.) Up Wt. = 110k Dn. Wt. = 82k Rt. Wt.= 98k Tq = 4.6-5.6 Ast =1.7 Art=1.4 No gain / loss 12:00 - 12:30 0.50 DRILL_ SLID IN1 DRL Continue directionally drill ahead f/ 3090' -3132' 12:30 - 13:15 0.75 SECUR WELL IN1 DRL Gas alarms in main production building. Secure well and shut down Boiler,camp generator and main rig power. Muster all personal to rig floor. Production operator confirmed gas leak. Wait for authorization . All clear at 1300hrs. Bring rig back on line. at 1315hrs. All personal reported to muster area 4 min. Rig secured In 7min. 13:15 - 16:15 3.00 DRILL_ SLID IN1 DRL Drill Ahead f 3132'- 3284' Up Wt. 110 Dn. Wt. 83k Rt Wt. 101 Tq. 4.6-5.8k Art= 1.0 Ast = .8 16:15 - 18:00 1.75 TRIP_ WIPR IN1DRL Monitorwell POH wiper trip, F-3284' - 1550' Hole slick no over pulls. No Gain/ Loss. ( Note planed wiper trip at 3300' Wash out in goose neck Printed: 8/16/2007 4:48:23 PM a ~ Marathon Oil Company Page 4 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Event Name: ORIGINAL DRILLING Contractor Name: Rig Name: Date From - To Hours Code Code Phase 5/24/2007 16:15 - 18:00 1.75 TRIP WIPR IN1DRL 18:00 - 19:00 1.00 SERVIC RIG IN1 DRL 19:00 - 20:30 1.50 REPAIR RIG IN1 DRL 20:30 - 21:30 1.00 TRIP DP IN1 DRL 21:30 - 06:00 8.50 DRILL ROT IN1 DRL 5/25/2007 06:00 - 12:00 6.00 DRILL_ ROT_ IN1DRL 12:00 - 00:00 12.00 DRILL_ ROT_ IN1DRL 00:00 - 06:00 6.00 DRILL ROT IN1DRL 5/26/2007 06:00 - 08:00 2.00 DRILL_ ROT_ IN1 DRL 08:00 - 09:00 1.00 CIRC_ CFLD IN1 DRL 09:00 - 10:00 1.00 TRIP_ WIPR IN1 DRL 10:00 - 10:30 0.50 DRILL_ ROT_ IN1 DRL 10:30 - 12:00 1.50 CIRC_ CFLD IN1DRL 12:00 - 16:30 4.50 TRIP_ WIPR IN1DRL 16:30 - 17:30 1.00 CIRC_ CFLD IN1DRL 17:30 - 22:00 4.50 TRIP_ DP_ IN1DRL 22:00 - 02:00 4.00 PULD_ BHA_ IN1DRL 02:00 - 03:30 1.50 PULD_ EQIP IN1CSG 03:30 - 06:00 2.50 TEST_ BOPE IN1CSG 5/27/2007 06:00 - 11:00 5.00 RURD_ CSG_ IN1CSG 11:00 - 21:30 10.50 RUN_ CSG_ IN1CSG 21:30 - 23:00 1.50 CIRC MUD_ IN1CSG 23:00 - 23:30 0.50 SAFETY MTG_ I N 1 CSG 23:30 - 03:30 4.00 PUMP CMT_ IN1CSG 03:30 - 06:00 2.50 TEST_ WLHD IN1CSG 5/28/2007 06:00 - 10:00 4.00 RURD_ RIG_ IN1CSG Spud Date: Start: 5/14/2007 End: Rig Release: Group: Rig Number: Description of Operations on swivel.) Service rig . Carrier, crown blocks, top drive and drive lines on carrier. PJSM; Repair Gooseneck on Top Drive,Washed out,Weld up and test to 1500psi PJSM; Run in Hole from 1555' to 3284' No Fill Hole Slick Drill from 3284' -3702' ART= 2.4 AST= 1.6 Up Wt.= 120K Dn. Wt.=80K Rt. Wt.=105K No Gains No Losses Drill ahead f/ 3702'- 4205' Up Wt.125k Dn Wt.95k Rt. Wt. 110k WOB 4-8.Tq 6-9k Art = 3.6hrs WOB = 4-8k Max gas 270u. Dynamic losses 10-12bph static loss 1-2bph Pump rate 330stks 640gpm 1750psi Drill ahead 4205'- 4832' Up Wt.=145K Dn. Wt.=110K Rt.Wt.=135K Tq.=6-10K ART=8.3 AST=O Add 1% lube tex due to torque Drill Ahead F/ 4832'-5209' AST= 0 ART=4.6 Up Wt.=145K Dn.Wt.=118K Rt. Wt.=135K Max. Gas 503 Units Dynamic losses 2-5 BPH/ Static 1-2 BPH Increase Lube tex to 2% Start up centrifuge van at 0300hrs Drill ahead 5209'- 5399' Up Wt 150 k Dn.Wt.125k Rt.Wt.135k TQ 8-9k Art Ast 0 Dynamic losses 1-2bph /static1bph Max gas 132u Circ at 5399' for MOC Geo samples. Circ at 645gpm 330stks 1750psi Pull 5 stands ( short trip ) wating for orders to confirm TD from MOC Geo Dept. f/ 5399'-5000' Rih to 5399' No fill hole slick, normal drag. Drill ahead f/ 5399'-5448' T/D Intermediate Hole section. Up Wt. 150k Dn Wt.150k Rt. Wt. 136k Tq 6-9k Art= 2hr Circ B/U At 5448' 330spm 645gpm 1750psi. B/U gas 80u Monitor well POH wiper trip 5448'- 3284' Hole slick 1-2bph fluid loss RIH 3284'-5448' Circ. B/U at 5448' 275 spm 550 gpm 1450psi. Clean hole. Circ until shakers clean up. PJSM;Monitor well, pull 5 stands, pump dry job POH to run 9 5/8 Csg SLM No correction PJSM; POOH stand back HWDP and lay down dir. assy. Pull Wear ring and Make dummy run with 9 5/8 csg hanger Change rams to 9 5/8 and shell test to 3000 psi PJSM; Remove short bails. R/U fill up tool. Move torque tube Back. Install long bails. R/U 9 5/8 csg. elevators,spider and tongs. R/U and Function test Stabbing board. Hold PJSM; Review Procedures running 9 5/8 csg. M/U shoe track and bakerlok. Check floats. Run 134jts 9 5/8 L-80 40# BTC csg. To 5331' Wash and C/O f- 5331' to 5436. 20' of fill Circ. Hole clean for Cement job.Batch Mix 340 sks.190bb1 Class G cement. Hold Safety Meeting and Prejob for Cement Job Test Cmt lines to 3500 psi.,Launch plug W/ 30 bbls. MCS40 spacer Followed by 190bb1s/340 sks.Class G cement at 10.5# ppg Displace W/ 5bbbl H2o and 401 bbls mud. Bumped plug at 450psi Press up to 1050psi hold for 5min . Bleed Off /Floats held. Cement in place at 01:35hrs. 100°/a returns. Pick up test joint. Run 9 5/8 pack off.Test to 5000 psi bled off. Having trouble getting pack off to hold. Reset and test to 5000 F 30 min. Test good. C/O csg rams to 2 7/8 X 5", Re-set torque tube C/O bails R/D Printed: 8/16/2007 4:48:23 PM ' ~ ~ Marathon Oil Company Page 5 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL DRILLING Start: 5/14/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From - To Hours Code Code Phase Description of Operations 5/28/2007 06:00 - 10:00 4.00 RURD RIG IN1CSG Fill up tool. R/U floor. 10:00 - 14:00 4.00 TEST BOPE IN1CSG M/U testjoint set test plug. Test bop and all components 250/3000 5min. Preform accumulator drawdown test. Test all gas alarms pvt and flow alarms. all test passed. Witness waved by Bob Noble AOGCC 14:00 - 15:00 1.00 RUNPU WBSH IN1CSG Set bushing L/D testjoint. Service rig. 15:00 - 17:30 2.50 TRIP BHA IN1CSG PJSM; M/U 8 1/2 BHA Scribe mwd/ motor RIH and pulse test 17:30 - 20:30 3.00 TRIP DP IN1CSG RIH to 4900' 20:30 - 22:00 1.50 CUT WIRE IN1CSG PJSM; Slip and cut drilling line 22:00 - 01:30 3.50 WAITON CMT_ IN1CSG Wait on cement Inspected Angel lift line, Dress pop offs,Clean out goose neck,Service shakers and caustic barrel,Service pit area grease gun lines, Change alternator on camp generator ' 01:30 - 02:30 1.00 TEST CSG_ IN1CSG Test csg. to 1500 psi for 30 min. no pressure loss 02:30 - 05:30 3.00 DRILL_ CMT_ IN1CSG RIH tagged at 5349' Drill out shoe track To 5436' Clean out to 5448'. firm cement, Returns over shaker consistent hard chips. 05:30 - 06:00 0.50 DRILL ROT IN1CSG Drill new hole f 5448'-5468' Art. .2 5/29/2007 06:00 - 07:00 1.00 CIRC MUD IN3CSG Circulate and condition mud for Fit/leak off test At 5468'. 07:00 - 07:30 0.50 TEST LOT_ IN3CSG Preform FIT 9.5mw ,980psi.at 5290TVD =13.1 EMW. After 10 min pressure down to 900psi 5290TVD= 12.8EMW 07:30 - 12:00 4.50 DRILL_ ROT_ PR1 DRL Drill ahead f/5468'- 5780' Up. Wt. 142 Dn.Wt.118 Rt. Wt. 131 Tq. 6-11 k Art 2.4 Ast.O No Gain Loss Max Gas 270u 12:00 - 18:00 6.00 DRILL_ ROT_ PR1 DRL Drill ahead f/ 5780'-6171' ART=3.9 Up Wt.=160K Dn. Wt.=130K Rt. Wt.= 146K Tq.= 8-9K Max. Gas=270u 18:00 - 00:00 6.00 DRILL ROT PR1 DRL Drill ahead f/6171'-6404' ART=3.2 Up Wt.=165K Dn. Wt.=130K Rt. Wt.=145K Tq.=8-10K No Gain No Losses Max Gas=495u 00:00 - 06:00 6.00 DRILL_ ROT_ PR1 DRL Drill ahead f/6404'- 6783' ART= 3.5 Up Wt.=168k Dn. Wt.=130K Rt. Wt.=150K Tq.=6-12K Max Gas=495u 5/30/2007 06:00 - 07:15 1.25 DRILL ROT PR1 DRL Drill Ahead 6783' - 6840' 07:15 - 09:00 1.75 REPAIR EQIP PR1 DRL Repair / replace gripper dies on top drive 09:00 - 11:30 2.50 DRILL_ ROT_ PR1 DRL Drill Ahead 6840'-7035' Up Wt. 155k Dn. Wt. 145k Rt. Wt. Tq 8.5-9.5k Art=2.2hrs Ast=O No Gain Loss max Gas 420u 11:30 - 12:30 1.00 CIRC MUD_ PR1DRL Circ B/U at 7035' 248spm 1580psi 485gpm Condition hole for Wiper trip. Up Wt 175k Dn Wt 145k Rt. Wt. 155k 12:30 - 18:30 6.00 TRIP_ WIPR PR1 DRL Monitor well. Poh Wiper trip F- 7035'- 5436' Work various tight spots ( Clays ) F- 6850' to 5436' 18:30 - 19:30 1.00 SERVIC EQIP PR1 DRL Service rig , top drive, carrier, blocks, crown. pumps 19:30 - 20:30 1.00 TRIP WIPR PR1DRL RIH wiper trip f- 5436' -6969' No Tight spots 20:30 - 21:00 0.50 TRIP WIPR PR1DRL Ream f/6969'-7035' No fill 21:00 - 00:00 3.00 DRILL_ ROT_ PR1 DRL Drill ahead f/7035'-7161' Up wt.=185K Dn. wt.=140K Rt wt.=160K Tq.=8-10K Art=2.0 Ast=O No Gain No Loss Max. gas =629units 00:00 - 06:00 6.00 DRILL_ ROT_ PR1 DRL Drill ahead F/7161'-7476' Up wt.=185K Dn.wt.=145K Rt wt.=160 Tq.=8K-10K Art=3.1 Ast=O No Gain No losses Max. gas=625u 5/31/2007 06:00 - 12:00 6.00 DRILL ROT PR1 DRL Dir drill and survey F/7476' to 7739'(ART=3.7hrs). 12:00 - 13:30 1.50 CIRC MUD_ PR1 DRL Circ. samples. (693 units conn gas). Lay down one single and circulate @ 7700'(conn gas 1552 units). 13:30 - 14:30 1.00 CIRC MUD PR1DRL Circ. and raise MW 10.OOppg to 10.2ppg. 14:30 - 15:30 1.00 CIRC MUD_ PR1 DRL Flow check and simulate conn.(10min) well static. CBU (conn gas 851 units). 15:30 - 16:30 1.00 CIRC MUD PR1 DRL Circ. and increase MW to 10.4ppg. 16:30 - 18:00 1.50 CIRC MUD_ PR1 DRL Flow check and simulate conn.(10min) well static. CBU(conn gas 65 units). 18:00 - 00:00 6.00 TRIP_ WIPR PR1DRL PJSM; Wiper Trip F/7739' to shoe at 5436' Back ream F/7739' up to 5614' Printed: 8/16/2007 4:48:23 PM ~ ~ Marathon Oil Company Page 6 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL DRILLING Start: 5/14/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From - To Hours Code Code Phase Description of Operaticans 5/31/2007 18:00 - 00:00 6.00 TRIP WIPR PR1 DRL Cont. POOH to shoe at 5436'. POOH on different service break on drill pipe. 00:00 - 01:30 1.50 SERVIC RIG PR1 DRL PJSM; Service top drive and carrier.lnstall fall arrest on crown. 01:30 - 03:00 1.50 TRIP_ WIPR PR1 DRL PJSM;RIH With 5" drill pipe from 5436' to 7739' Hole slick no fifl. Up Wt.=200K Dn. wt.=160K Rt wt.=175K On bottom. 03:00 - 06:00 3.00 CIRC MUD_ PR1 DRL Circ. bottoms up ,put well on choke and gas buster at 3000 units of gas. Increase MW to 10.6# mud around. 6/1/2007 06:00 - 07:00 1.00 CIRC MUD_ PR1 DRL Cont. to circ. through open choke until gas units dropped to 100units. Open BOP and cont. to circ. out @ 500GPM 1700psi until shakers clean(CBUX1) cont. to increase MW to 10.6ppg. 07:00 - 08:00 1.00 TRIP DP PR1 DRL Flow check well(well static). POOH to 7006'(tight @ 7006'). 08:00 - 09:00 1.00 TRIP DP PR1DRL PJSM;RIH to 7739'(no fill, hole in good condition). 09:00 - 10:00 1.00 CIRC MUD_ PR1DRL Circ. shakers clean. CBU X 1(450GPM 1450psi 60RPM, trip gas 20units). 10:00 - 17:00 7.00 TRIP_ DP_ PR1DRL Flow check(well static, pump dryjob, drop 2 7/8" rabbit). POOH(SLM, hole in good condition) No correction on pipe tally. PJSM; 17:00 - 18:30 1.50 TRIP BHA PR1 DRL UD BHA. 18:30 - 19:00 0.50 SAFETY MTG_ PR1 DRL PJSM; Hold safety meeting with Weatherford Wireline personel and rig personal 19:00 - 02:30 7.50 RUNPU ANCH PR1 EVL Rig up wireline logs and Log with S-Quad combo logging tools(logger TD 7739'). 02:30 - 03:30 1.00 RURD ELEC PR1 EVL Lay down logging tools and rig down wireline. 03:30 - 04:30 1.00 PULD DP PR1 EVL PJSM;Lay down 6 joints HWDP (damaged tool faces) and Jars. 04:30 - 06:00 1.50 TRIP DP PR1 EVL RIH with 5" Mule shoe on drill pipe. 6/2/2007 06:00 - 09:00 3.00 TRIP DP PR1 EVL RIH w/5 1/2" muleshoe. 09:00 - 10:00 1.00 CIRC MUD_ PR1EVL Circ. shakers clean. (CBUX2,445GPM, 900psi, trip gas 61units). 10:00 - 11:00 1.00 TRIP DP PR1EVL Flow check and POOH to 7076'. 11:00 - 13:00 2.00 LOG OH PR1 EVL PJSM. R/U to run Weatherford RFT tool. 13:00 - 13:30 0.50 LOG OH_ PR1 EVL M/U Formation test tool.and run inside drill pipe. Test tool (No Good) 13:30 - 14:00 0.50 LOG OH PR1 EVL POOH Check tool on surface. 14:00 - 19:00 5.00 LOG OH PR1 EVL RIH Thru 5" drill pipe @ 7073' and Log from 7500' to 7122' 19:00 - 21:00 2.00 LOG OH PR1 EVL POOH with logging tools and hang back in derrick. 21:00 - 21:30 0.50 TRIP_ DP_ PR1 EVL PJSM; POOH with 5" Drill pipe from 7073' to 6570' Park drill pipe for Iogs.Pulled 15K over to free pipe ~ 21:30 - 06:00 8.50 LOG_ OH_ PR1 EVL Rig up logging tools and RIH with Formation test tool thru drill pipe. Set at 6570' Log from 7013' to 6614'. 6/3/2007 06:00 - 15:00 9.00 LOG OH PR1 EVL Run RFT log. POOH. 15:00 - 16:00 1.00 TRIP DP PR1 EVL POOH w/DP to 5432'. 16:00 - 02:30 10.50 LOG OTHR PR1 EVL RIH w/RFT. Run RFT log(total 55 RFT points). 02:30 - 03:30 1.00 RURD ELEC PR1 EVL PJSM;Lay down wireline tools, rig down Weatherford. 03:30 - 06:00 2.50 TRIP_ DP_ PR1 EVL PJSM; POOH w/ 5" Drill pipe and L/D 5" mule shoe. Move to completion operations @ 06:OOhrs 06/03/2007. Printed: 8/16/2007 4:48:23 PM 1 ~ ~ Marathon Oil Company Page 1 of 2 Qperattons Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL COMPLETION Start: 6/9/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From - To Hours Cade Code Phase 6/4/2007 06:00 - 07:00 1.00 TRIP_ BHA_ PR1CSG 07:00 - 12:00 5.00 TRIP DP PR1CSG 12:00 - 13:30 1.50 CIRC MUD PR1CSG 13:30 - 18:00 4.50 PULD DP PR1CSG 18:00 - 19:30 1.50 REPAIR EQIP PR1CSG 19:30 - 23:00 3.50 PULD_ DP PR1CSG 23:00 - 23:30 0.50 RUNPU WBSH PR1CSG 23:30 - 03:00 3.50 RURD_ CSG_ PR1CSG 03:00 - 03:30 0.50 SAFETY MTG_ PR1 CSG 03:30 - 06:00 2.50 RUN CSG_ PR1CSG 6/5/2007 06:00 - 10:00 4.00 RUN CSG PR1CSG 10:00 - 10:30 0.50 CIRC MUD PR1CSG 10:30 - 15:00 4.50 RUN CSG PRICSG 15:00 - 15:45 0.75 CIRC MUD PR1CSG 15:45 - 16:30 0.75 SAFETY MTG PR1CSG 16:30 - 20:30 4.00 RUN_ CSG_ PR1CSG 20:30 - 22:30 2.00 CIRC MUD PR1CSG 22:30 - 01:30 3.00 LOG CSG PR1 CSG 01:30 - 03:30 2.00 RURD CMT PR1CSG 03:30 - 05:30 2.00 PUMP CMT PR1CSG 05:30 - 06:00 0.50 RURD CMT PR1 CSG 6/6/2007 06:00 - 09:30 3.50 WAITON CMT PR1 CSG 09:30 - 12:00 ~ 2.50 ~ WAITON~ CMT_ ~ PR1 CSG 12:00 - 14:00 ~ 2.00 ~ WAITON~ CMT_ ~ PR1 CSG 14:00 - 16:30 I 2.50I NUND I BOPE I PR1CSG 16:30 - 17:30 1.00 TEST_ BOPE PR1CSG 17:30 - 20:00 2.50 TEST_ TREE PR1CSG 20:00 - 06:00 10.00 RURD_ RIG_ PR1CSG Description ~f Operations M/U 8.5" bit RIH w/5" HWDP and jars. Cont. RIH w/5" DP. Circ. shakers clean(CBUX2, 450GPM, 1150psi, Trip gas 53units). PJSM.Pump dryjob monitorwell. POOH UD DP. Model 966 -D Loader broke down .Wait on 966-C loader. Continue to lay down 5" drill pipe. Pull wear bushing and lay down same. Clean off floor and rig up to run 3 1/2" csg. and modules. Hold safety Meeting and JSA Pick-up shoe track, ck. floats and start in hole. with 3 1/2 Excape. Cont. running 3 1/2" 9.3ppf L-80 EUE-Mod Excape Completion(total 10 modules). Circ. 3 1/2" CSG. Cont. Running 3 1/2" Excape comp 4 control lines and one protective i line to CSG shoe @ 5436'(PJSM/JHA with crew coming on @ 12:OOhrs). Circ.@ shoe(215GPM, 675psi). While running firstjoint after circulation floor hand smashed the tip of his middle finger on his left hand between the CSG and the tongs. Hold safety meeting and investigate incident. Cont. run 3 1/2" Excape comp(shoe at 7715'). Circ. bottoms up. Max. gas=35 units Up wt.=92K Dn. wt.=75K PJSM; Rig up and run logs to set modules. PJSM;Rig up cement head and circ. inhibited mud. PJSM; Pump 5 bbls. water ahead,test cmt. lines to 3600 psi, Mix and pump 40bbls. MCS-4 sweep @ 11.5 Ib.Mix 1076 sx.Class G cement,+1.2%BA-56 +.5% EC-1 +3% CD-32 +2% A-2 +.05% Static Free +1 GHS FB-6L 15.8 ppg.,YieId1.160 cuft/sk, 4.917 gal/sk.,3:42 Thickening time. / 222.3 bbls. slurry , 125.9 bbis.water to mix. Bump plug with 68.5 bbls. Pres. up 1000 psi over circ. press to 2800 psi cmt in place at 0520 Rig down cmt. lines and clear floor. Flush pumps, choke line, topdrive w/fresh H20 and blow down lines. Remove mousehole, drip pan, riser, bleeder line, fill up and trip tank lines. Empty pits. PJSM. N/D choke and kill lines form BOP. N/D check valve and outside kill line valves. N/D outside choke line valve. R/D turnbuckles on BOP stack. R/D trip tank actuator. Hook up bridge cranes. Install exciter on # 2 rig generator. Empty pits. PJSM. Cont. N/D BOP stack. Remove choke and kill line from manifold side. Remove bleeder line. Prep stack to be lifted. Prep boiler for hydrostatic test. Empty pits. PJSM. N/D last 4 bolts on stack. Lift stack. Cut control lines and set slips with 70K. Cut and dress 3 1/2" CSG. Clean pits. Install packoff and test to 5000psi. Clean pits. Install Tree, test void to 5000 psi for 10 min. ( Good) Test tree to 10,000 psi (Good) Remove two way check,install BPV PJSM; R/D Pump #3 ,R/D Elavators ,Remove bales , Disconnect Top Drive service lines ,and kelly hose ,C/O Swabs #1 pump ,Finish cleaning pits ,R/D shock hose for pumps 1,2,and 3,Panic line ,Rig down koomey lines Printed: 8/16/2007 4:41:18 PM ' ~ ~ ~ Marathon Oil Company Page 2 of 2 Operations Summary R~port Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL COMPLETION Start: 6/9/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From - To Hours Code Code Phase Description of Operations 6/6/2007 20:00 - 06:00 10.00 RURD_ RIG_ PR1CSG and hang R/D M-I van and cuttings tank ,Lay down top drive and load out ,Lay down top drive rail and load out ,Prep derrick to scope down ,Rig down gas buster Rig down stairs on beaver slide , 6/7/2007 06:00 - 12:00 6.00 RURD RIG_ RDMO Remove carrier roof tarps and frame. PJSM. Prep derrick and scope down. Prep derrick to lay over. R/D drillers console, brake linkage. pull wires from choke and dog house, carrier and pits. Remove exit light on choke and dog house. R/D dresser sleeves and service lines. Load out pump#3 house. 12:00 - 12:15 0.25 SAFETY DRIL RDMO Crew change. PJSM with crews and crane operator. 12:15 - 20:15 8.00 RURD RIG RDMO Crane out tool,dog and choke houses, grey iron and fuel tank. 20:15 - 00:00 3.75 RURD RIG_ RDMO Move carrier away from sub base. Move off well with sub structure and scope down. Rig released from KBU 34-6 at 2400 hrs 6-6-2007. Moving to SU 43-9X Printed: 8/16/2007 4:41:18 PM • ~ Marathon Oil Company Operations Summary Report Pa~e 1 of 4 I Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL COMPLETION Start: 6/13/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From - To Hours Code Code Phase Description of Operations 6/13/2007 09:00 - 09:30 0.50 SAFETY MTG_ PR1 CSG Hold PJSM and obtain Permit for Vetco Gray . Discuss scope of job. 09:30 - 10:00 0.50 RURD OTHR PR1CSG MIRU Vetco to pull Back pressure check valve. 10:00 - 10:30 0.50 RUNPU VLVE PR1CSG Pull 3-1/2" BPCV. 10:30 - 12:00 1.50 TEST WLHD PR1CSG Install inner/ outer annuli pressure manifold on tree. Run instrument tubing to respective valves on tree. Test to 5k. Test good. 12:00 - 14:00 2.00 TEST WLHD PR1CSG Install 5K SSV on wing valve. Ptest to 5K. Test good. 14:00 - 14:20 0.33 RURD OTHR PR1CSG Rig down Vetco. 14:20 - 14:40 0.33 SAFETY MTG_ PR1CSG Hold PJSM and obtain Permit for Expro. Discuss scope ofjob. 14:40 - 1530 0.83 RURD ELEC PR1CSG MIRU E-line for CBL.PU lubricator and tool string. 15:30 - 16:00 0.50 PULD LOG PR1CSG RIH with CBL. 16:00 - 16:55 0.92 RUNPU ELEC PR1CSG Run free pipe pass from 3300'-3500'. RIH. 16:55 - 17:30 0.58 LOG CSG PR1 CSG Run repeat pass., Tool radials quit working. 17:30 - 18:00 0.50 RUNPU ELEC PR1CSG POOH. 18:00 - 18:55 0.92 RUNPU ELEC PR1CSG @ 3800' Tool working. RIH to log. 18:55 - 19:35 0.67 LOG CSG PR1 CSG Run repeat section. 19:35 - 20:40 1.08 LOG CSG PR1 CSG Run main pass. Tool problems. POOH. 20:40 - 21:25 0.75 RUNPU ELEC PR1 CSG OOH. Change out tool. 21:25 - 22:00 0.58 RUNPU ELEC PR1CSG RIH with second CBL tool. 22:00 - 23:00 1.00 RUNPU ELEC PRICSG Run free pipe pass @ 3500'. RIH. 23:00 - 23:10 0.17 LOG CSG PR1 CSG Run repeat section PBTD. 7613'. 23:10 - 01:00 1.83 LOG CSG PR1CSG Start main pass. Cement top @ 4100'.- 01:00 - 01:30 0.50 LOG CSG PR1 CSG End main pass @ 3900'. POOH. 01:30 - 02:00 0.50 RUNPU ELEC PR1CSG OOH. RD. 02:00 - 02:30 0.50 RURD ELEC PR1CSG Leave location. Turn in Permits. 7/1/2007 06:00 - 07:30 1.50 SAFETY MTG_ CMPSTM Held pre frac safety meeting. Discussed slips trips and falls, high pressure frac ops, flowback, muster location, evac route, etc. 07:30 - 08:35 1.08 PERF CSG_ CMPSTM Pressure test frac lines to 9250psi. Good test. Test Nz (ines. Gef up for Frac. 08:35 - 09:40 1.08 PERF CSG_ CMPSTM Open well SITP = 96 psig. Loaded hole with 1 bbl linear gel. Attempting to pump into mod 1. (7368' - 7378') Pumped 2- 8 ppg. Fraced mod 1 with 4148 flex 12/20 and 30,845 white 20/40 = 34,944 TOTAL. Extended on 4 ppg stage to allow monitoring of the 4ppg on the perfs. 09:40 - 10:08 0.47 PERF CSG_ CMPSTM Mod 2-( 7208' - 7218') pressured up to 4500psi and not sure when gun fired due to N2 in flush, but pinning was such that it was way above max firing pressure of 3300 on yellow line. Stage pad. 15.5 BPM. Frac'd perfs with 3683 flex 12/20 and 25,798 white 20/40 = 29,481 TOTAL. Pumped 2- 10 ppg. NO commnication on the orange line - fraced zone 1. 2975 isip. ' 10:08 - 13:25 3.28 PERF CSG_ CMPSTM Orange line is intact and holding pressure (250 - 750 psi). Mod 3 (7120' - 7130') - Fired at 4900 psi. Pumped 2- 10ppg. Spike in pressure to 10,000, screened out when to 10ppg hit the perfs. Re-flush to attempt to clear the screen out. Flow back 13 bbl. Ran re-flush and pressure shot up again. Expro to flow back 100 bbls. Calling for coil. Frac'd perfs with 5446 flex 12/20 and 38150 white 20/40 = 43,596 TOTAL. Flow back of 60 bbl trying re flush at 2bpm and pressure went I to 8400. Bleed off lines and rig up coil. Note, orange line spiked at screen out to 3,000 psi and was immediately vented. Appears to barely have missed minimum firing window. 13:25 - 16:30 3.08 RUNPU COIL CMPSTM Rig up coil. Pressure test, Pull test, RIH circulating at 1 BPM. Tag sand at 2,750 feet. 16:30 - 17:30 1.00 CMPSTM Increase rate to 2 BPM and wash in hole at 60 feet per minute with full returns. Varying amounts of sand in returns entire time. Circulate for 5 Printed: 8/17/2007 6:57:08 AM • ~ Marathon Oil Company Paye 2 of 4 Operations Summa~-y RepQr~ Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL COMPLETION Start: 6/13/2007 End: ' Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From - To Mours Code Cod Phase Descript~c~~t ~f Qperations e 7/1/2007 16:30 - 17:30 1.00 CMPSTM minutes at 7,100 feet. Tag #3 flapper at 7,143' and broke with 6K down. Immediately lost fluid returns and slowly regained. RIH and did not see flapper #2. Partial fluid loss after washing sand across module 1 perfs. Continue in hole an tagged PBTD at 7,629 feet. 17:30 - 19:15 1.75 CMPSTM Circulate 1.5 hole volumes from TD at 2 BPM and POH with coil while circulating. Rig down injector head and secure well. SDFN. 7/2/2007 06:00 - 07:20 1.33 SAFETY MTG_ CMPSTM field pre frac safety meeting. Discussed slips trips and falls, high pressure frac ops, flowback, muster location, evac route, etc. 07:20 - 07:35 0.25 PERF CSG_ CMPSTM Pressure test frac lines to 9250psi. Good test. Test Nz lines. Gel up for Frac. 07:35 - 08:53 1.30 PERF CSG_ CMPSTM Open well SITP = 300 psig. Loaded hole with 1 bbl linear gel. Mod 4 fired at 8820psi on yellow line, which then vented. (7007' - 7015') Pumped 2- 4 ppg. Saw a rise in psi when 2bbl hit the perfs, cut the sand to allow 4bbl to hit the perFs and monitor. Shut down due to rising pressure. 4050 isip. Fraced mod 4 with 1034 flex 12/20 and 7145 white 20/40 = 8179 TOTAL. 08:53 - 09:05 0.20 PERF CSG_ CMPSTM Mod 5-(6855' - 6865') fired at 2350 psi on green line. Pumped 2- 10 ppg. Fraced mod 5 with 1923 flex and 13,388 white. Total slurry 184bb1. 09:05 - 09:27 0.37 PERF CSG_ CMPSTM Mod 6-(6813' - 6823') fired at 4370psi. Pumped 2- 10 ppg. Fraced mod 6 with 4344 flex 12/20 and 30,430 white 20/40. Total slurry 277bb1. 09:27 - 09:50 0.38 PERF CSG_ CMPSTM Mod 7-(6772' - 6783') fired at 5294psi. Pumped 2- 10ppg. Fraced mod 7 with 1976 12/20 flex and 13823 20/40 white. Total slurry 172bb1. Orange line is still intact. 2500 isip. 09:50 - 10:20 0.50 PERF CSG_ CMPSTM Mod 8-(6731' - 6741') fired at 6430psi. Pumped 2- 10 ppg. Fraced mod 8 with 4269 12/20 flex and 29,895 white 20/40. Total slurry 279bb1. 2300 isip. 10:20 - 10:58 0.63 PERF CSG_ CMPSTM Mod 9-(6442' - 6452') fired at 7355psi at 10:35. Pumped 2- 10 ppg. Fraced mod 9 with 5816 flex and 40735 white. Total slurry 331 bbl. 2200 isip. 10:58 - 11:35 0.62 PERF CSG_ CMPSTM Mod 10 -(5742' - 5753') fired at 8375psi at 11:14. Pumped 2- 12 ppg. Fraced mod 10 with 6249 flex and 43,760 white. 2400 Total slurry bbl. 11:35 - 13:25 1.83 RUNPU COIL CMPSTM Rig up coil for clean up and rigged down other equipment. NOTE: Orange line (downhole chemical injection line) intact and was not perforated or frac'd in two. 13:25 - 13:38 0.22 RUNPU COIL CMPSTM Open well head. and start in hole 13:38 - 17:20 3.70 RUNPU COIL CMPSTM Broke flappers at 6760' and 6802' (# 7&#8) no other flappers detected. Ran to bottom at 7,644 CTM. Circulation rate during clean ~ out was initially 2 BPM . Note: Lost returns below module #8 and had to start nitrogen injection to gain full returns. POH to above perfs 17:20 - 17:30 0.17 RUNPU COIL CMPSTM CT Setting @ 5700' Pump rate .5bpm N2=470CFM CTU = 2500 PSIG WH 238 PSIG. 17:30 - 18:05 0.58 RUNPU COIL CMPSTM Start in hole - shut down water pumping and continued N2 at 470 CFM. 18:05 - 18:06 0.02 RUNPU COIL CMPSTM CIH to 7639' increase N2 to 750 CFM. 18:06 - 18:36 0.50 RUNPU COIL CMPSTM Start back up hole to 5700' with WH pressure rapidly increasing - WH = 1050 PSIG. 18:36 - 18:45 0.15 RUNPU COIL CMPSTM Stop coil & continue to circ N2 @ reduced rate of 450 CFM. Circ for 10 minutes and shut down N2. Wellhead pressure holding @ 850 psig. 18:45 - 19:30 0.75 RUNPU COIL CMPSTM TOH w/coil @ avg speed of 100 FPM. At surface w/1300 psig on wh & sYrong flowback. Printed: 8/17/2007 6:57:08 AM • ~ Marathon Oil Company Page 3 of 4 Op~rations Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL COMPLETION Start: 6/13/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From - To Hours Code ~ade Phase Description of Operations 7/2/2007 19:30 - 20:25 0.92 RUNPU COIL CMPSTM Shut well in due to washout problems. Repaired flowback iron and opened well to testers w/350 psig on choce. Well produced large amounts of sand - washing. 20:25 - 20:30 0.08 RUNPU COIL CMPSTM work on cut out iron & packing off sand buster. 20:30 - 20:50 0.33 RUNPU COIL CMPSTM Shut well in due packed off sand buster Expro making repairs. 20:50 - 21:30 0.67 RUNPU COIL CMPSTM RB BJ Coil - secured location Current SITP = 1600. 21:30 - 06:00 8.50 RUNPU COIL CMPSTM Turned well over to testers for night. Well was stabilized and brought on line to sales. Sand production significantly decreased, and cut out flow tees diminished ( 13 total to 6 AM). Well producing at 6.1 MM SCFD, 1300 PSI, and 340 BWPD at 06:00. Well turned to Production to manage with well testers at 0:600. Final DIMS completion report. 8/15/2007 17:15 - 17:45 0.50 RURD ELEC WRLN Move over from KBU 12-5. RU 1" swage, 2.25" fluted centralizer on spang jars to RIH to break flappers. 17:45 - 18:00 0.25 RURD ELEC WRLN PTest Lubricator to 1500 psi. Test good. 18:00 - 18:31 0.52 RURD ELEC WRLN RIH with 1" swage to break flappers. 18:31 - 18:44 0.22 RUNPU ELEC WRLN Sat down in Module #3(7130-7140') 18:44 - 19:15 0.52 RUNPU ELEC WRLN Work thru flapper, but very sticky. 7140' TD. POOH. 19:15 - 19:45 0.50 RURD ELEC WRLN OOH. Lay down lubricator and tools. RD. 19:45 - 20:00 0.25 RURD ELEC WRLN Secure well for the night. Turn in Permit. Leave loc. 8/16/2007 07:30 - 08:30 1.00 SAFETY MTG WRLN Hold PJSM. Obtain Safe Work Permit. Go over JSA. Point out 08:30 - 09:00 I 0.501 RURD I ELEC 09:00 - 09:15 0.25 RURD_ ELEC 09:15 - 09:30 0.25 RUNPU ELEC 09:30 - 09:45 0.25 RURD ELEC 09:45 - 10:45 1.00 RUNPU ELEC 10:45 - 12:00 I 1.251 RUNPULI ELEC 12:00 - 12:55 0.92 RUNPU ELEC 12:55 - 13:30 0.58 RUNPU ELEC 13:30 - 14:00 0.50 RUNPU ELEC 14:00 - 14:30 0.50 RURD_ ELEC 14:30 - 15:25 0.92 RUNPU ELEC 15:25 - 16:15 0.83 RUNPU ELEC 16:15 - 17:00 I 0.751 RUNPULJ ELEC 17:00 - 17:45 0.75 RURD_ ELEC 17:45 - 18:30 0.75 RURD ELEC 8/17/2007 07:30 - 08:30 1.00 SAFETY MTG escape route and muster area. Discuss hazards such as overhead loads, pinch points, sorking at heights. WRLN PU 2.812" GR and junk basket run run thru swab valve and WH to clear out grease. WRLN PTest Lubricator to 1500 psi. Test good. WRLN RIH with tool string to clean grease out of tree. WRLN OOH. RU side view camera/ View Max. WRLN RIH with DHV tool string. Well flowing @ 1000 psi, 4.46 MMcf, 20 BWPD. Visibiliry not great. Able to see flowing mist, large beads, and slugs of water. WRLN Start viewing modules. In down view, able to see shiney machined tops of mandrels, nipple profiles, and couplings. Able to identify mandrels bu length using log depths. Can see perf nodes erupting from the casing wall. View often obscured by fluid froth or large slugs. Side view camera has a very close up view. Often obscured by flowing water slugs and froth. Threads appear very large in this view, but see them clearly. Difficult to know exact location in well. No CCL so you need an optical reference point to reference everything else from. WRLN Sat down at 7000'(Module #4) tool stuck. PU to module #4. Viewing difficult because of water slugs flowing at camera. WRLN Shut in well. View modules. Difficult to see in well fluid. WHP 1000 psi. WRLN Open well to flow. Max shut in pressure 1150 psi. WRLN OOH. RU WHIT tool. WRLN Start in hole. WRLN Start 30 fpm down pass, w/ video(5600'). Spinner quit working @ 6300'. WRLN End sown pass @ 6850'. Start up pass. Inspecting modules. Visiblity is better with this camera. More distict images. Able to see nipple profiles more clearly. WRLN OOH. RD.Secure well for night. WRLN Leave location. Turn in Permit. WRLN Hold PJSM. Obtain Safe Work Permit. Go over JSA. Point out Printed: 8/17/2007 6:57:08 AM ~ . ~ Marathon Oil Company Pa~e 4 af 4 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: ORIGINAL COMPLETION Start: 6/13/2007 End: Contractor Name: Rig Release: Group: Rig Name: Rig Number: Date From - To Hours Code Code Phase 8/17/2007 07:30 - 08:30 1.00 SAFETY MTG_ WRLN 08:30 - 08:55 I 0.421 RURD I ELEC I WRLN 08:55 - 09:05 0.17 RURD ELEC WRLN 09:05 - 10:12 1.12 RUNPU ELEC WRLN 10:12 - 10:20 0.13 RUNPU ELEC WRLN 10:20 - 10:24 0.07 RUNPU ELEC WRLN 10:24 - 10:26 0.03 RUNPU ELEC WRLN 10:26 - 10:28 0.03 RUNPU ELEC WRLN 10:28 - 10:30 0.03 RUNPU ELEC WRLN 10:30 - 10:43 0.22 RUNPU ELEC WRLN 10:43 - 10:44 I 0.021 RUNPUl1 ELEC I WRLN 10:44 - 11:06 0.37 RUNPU ELEC WRLN 11:06 - 11:07 0.02 RUNPU ELEC WRLN 11:07 - 11:33 0.43 RUNPU ELEC WRLN 11:33 - 11:34 0.02 RUNPU ELEC WRLN 11:34 - 12:18 0.73 RUNPU ELEC WRLN 12:18 - 12:19 0.02 RUNPU ELEC WRLN 12:19 - 13:07 0.80 RUNPU ELEC WRLN 13:07 - 13:30 0.38 RUNPU ELEC WRLN 13:30 - 13:50 0.33 RURD ELEC WRLN 13:50 - 14:03 0.22 RUNPU ELEC WRLN 14:03 - 14:30 0.45 RUNPU ELEC WRLN 14:30 - 14:50 0.33 RUNPU ELEC WRLN 14:50 - 15:55 1.08 RUNPU~ ELEC WRLN 15:55 - 16:35 0.67 RUNPU ELEC WRLN 16:35 - 17:30 0.92 RURD ELEC WRLN Description of Operatians escape route and muster area. Discuss hazards such as slick surfaces due to rain, pinch points, working at heights. Well flowing 1003 psi @ 3.92 MMscf. Last test 22.7 BWPD. Check capacitance tool in air and in water durring pressure test. PU PLT tool string with 1-11/16" caged spinner. PTest Lubricator to 1500 psi. Test good. RIH with PLT tools @ 90 fpm. Spinner is running. Below Module # 10 spinner drops from 70 to 50 rpm. Module #9-no spinner or temperature change Below Module #8- spinner drops 50 % Module #7 - spinner continues to drop. Module #5 no spinner or temp response. 6970' End 90 fpm down pass.(Just above Module #4) No spinner, but temp shows cooling from below. Start 90 fpm up pass. Hung up @ 7008' yesterday. (1278 psi & 117 F) End 90 fpm Up pass @ 5500'. Spinner count 50 rpm above Module #10 on up pass. Start 60 fpm Down pass. End 60 fpm Down pass @ 6970'.(1298 psi & 117 F) Start 60 fpm Up pass. End 60 fpm Up pass @ 5500' Start 30 fpm Down pass Modules #8 and 10 seem to be the big contributers. End 30 fpm Down Pass @ 6970'.( 1303 psi & 117 F) Start 30 fpm Up pass. End 30 fpm Up pass @ 5500'. POOH. OOH. PU Down hole video tool. PTest QTS. Test good. RIH with DHV. Camera working. @ module #10. Pad was ESD'd at 14:30. Fluid falling into wellbore. Cann't see anything but water falling. Drop down into Module #9. Able to see X nipple profle and mandral. POOH. Well returned to production after ESD. 1250 psi. WHP. OOH. RD. Printed: 8/17/2007 6:57:08 AM MARATH~N Actual Wellpath Report NaviTrak <165-1509'><1623 - 5343'><5463 - 7739'> Page 2 of 6 r~~~ BAKER M1~61~IES INTEQ . . Operator .. ~ ~ MARATHON Oil Company Slot slot# KBU34-6 Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU34-6 Field Kenai Gas Field Wellbore KBU34-6 Facility Pad 41-7 i • ELLPAT H DATA (91 sta tions) MU Course Length Inclination Azimuth TVD Vert Sect North East Grid East Grid North DLS Build Rate 7'urn Rate (feet] [feet] [°] ~°] [feet] ~feet] [fect] [feet] [us survey feet] ~us surve feeY] [°/100tt] [°/100ft] ~°/100ft 0.00 0.00 0.000 0.000 0.00 0.00 0.00 0.00 274939.64 2362144.95 0.00 0.00 0.00 151.00 151.00 0.490 249.130 151.00 0.61 -0.23 -0.60 274939.03 2362144.73 0.32 0.32 0.00 211.00 60.00 0.610 253.340 211.00 1.16 -0.41 -1.15 274938.48 23G2144.56 0.21 0.20 7.02 272.00 61.00 0.730 251.570 271.99 1.84 -0.63 -1.83 274937.80 2362144.36 0.20 0.20 -290 ° 332 00 ~ 60 00 1 400 2G1 020 331 98 2 93 0 86 2 92 274936 1 2362 44 ' 1 . . . . . . - . . - .7 1 .~y .15 1.12 15.75 392.00 60.00 2.760 272.680 391.94 5.10 -0.91 -5.08 274934.54 2362144.14 2.36 2.27 19.43 453.00 61.00 4.740 275.740 452.81 9.07 -0.59 -9.06 274930.57 2362144.53 326 3.25 5.02 513.00 60.00 6.760 ~ 274.490 512.50 15.04 -0.07 -15.05 274924.60 2362145.17 3.37 3.37 -2.08 574.00 _ 61.00 ___ ._ _ 9.620 __ ~ 272.510 .- _ _~ _ 572.87 ..--- 23.71 -__ ___ 0.44 -23.72 274915.94 _._ 2362145.84 4.71 4 69 -3.25 G35 00 ~ ~ 61 00 ~ , 13,~60 ( _ ~ 273 070 , _ °~ 32 58 -- 36 09 1 05 _ '' `~ l : -~ 2362146 6 95 ' ` 6 ~5 '~ . : .. . . i . . . ~; _ , ~x . .,, : -; . : ~ 695.00 (0.00 17.940 ~ 272.620 690.28 52.49 1.86 -52.53 274887.16 2362147.80 6.80 6.80 -0.75 755.00 60.00 20.400 271.490 746.94 72.16 2.56 -72.21 274867.49 2362148.87 4.15 4.10 -1.88 815.00 60.00 21.290 271170 803.02 93.50 3.05 -93.56 274846.16 23G2149.77 1.50 1.48 -0.53 879.00 - - .---- _ _ 64.00 ---- _ 21.640 270.410 862.58 116.91 3.37 -11698 _- 274822.75 2362150.54 0.70 0.55 -1.19 943 00 64 00 268 340 1 83 141 09 3 10 141 16 4 9 = 2 . ,,, , . ~~~~~~ ( 92 . . ~ . . - 27 ~,~7 7 236215Q ~ , 2.15 1.77 -3. 3; 1006.00 63.00 25.210 268.240 979.38 166.70 2.33 -166.76 274772.96 2362150.44 3.87 3.87 -0.16 ]069.00 63.00 26.070 268.190 1036.18 193.96 1.48 -194.01 274745.71 2362150.10 1.37 1.37 -0.08 1131.00 62.00 25.700 268.730 109196 221.02 0.75 -221.0G 274718.64 2362149.89 0.7] -0.60 0.87 1194.00 63.00 25.550 267.910 1148.76 ` 248.27 -0.04 -248.30 274691.40 2362149.61 0.61 -0.24 -1.30 1257 00 63 00 25 150 2G7 530 1205 70 23 275 1 12 27 25 2746G4 4 2362149 04 - ----- 0 69 - 63 bO . . . . . . - . - 5. . 3 . . -0. -O. 1320.00 63.00 24.890 266.270 1262.79 301.86 -2.56 ~ -301.85 274637.81 2362148.11 094 -0.41 -2.00 1384.00 64.00 24.650 266.190 132090 328.64 -4.32 ~-328.61 274611.02 2362146.85 0.38 -0.37 -012 1446.00 62.00 24.570 266.250 1377.27 ~ 354.42 -6.02 -35437 274585.23 2362145.64 O.14 -0.13 010 1509.00 -- - ----- --_- 63.00 - -- _ -_ _ _ 24.1301 .__ _ 265 420 _ _-- 1434 66 ~ 380.36 .,_. _ _ 7.91 -_ _ 380 28 ~_._ --- _ .. 274559.30 ~ 2362144 24 _ _~ _ ~ 0.88 - - 0.70' ~- -].32 1623.00 114.00 ~ 23.210 264 'i00 1539 07 i 426.00 ~ ~ - ] 2.00 _ 425 86 ~..~~.,._.w. ~ 274513.65 „~__._ __..__ _ _ 2362141 02 , ~.._,. --- 0.90 _ __ . 0.81 ~ - ---.~ -0.98 ~ • ELLPAT H DATA (91 sta tions ) MD Course Length Inclination Azimuth TVD Vert Sect North East Grid East Grid North DLS Build Rate Turn Rate ~feet] [feet] [°] ~°] [feet] ~feet] [feet] [feet] us survey feet] (us survey feet] ~°/100ft] (°/100ft] ~°/IOOft] 1686.00 63.00 22.710 265.630 1597.08 450.51 -14.16 -450.34 274489.13 2362139.32 1.14 -0.79 2.11 1749.00 63.00 22.480 266.470 1655.24 474.68 -15.83 -474.49 274464.96 236213811 0.63 -0.37 1.33 1812.00 63.00 22.080 266.600 1713.54 498.54 -17.27 -49833 274441.10 2362137.12 0.64 -0.63 0.21 1875.00 63.00 21.740~ 266.270 1771.99 522.02 -18.73 -521.79 274417.61 2362136.10 0.57 _ -0.54 -0.52 ~ 4 06 20 06 544 82 94 274 57 2362135 21 98 0 0 84 40 1 - 1938.00 63.00 21.210 267.150 1830.G2 5 5. - . . - . 3 . . - . . 200 ].00 63.00 20.680 266920 1889.45 567.57 -21.22 -56731 274372.06 2362134.47 0.85 -0.84 -0.37 2064.00 63.00 20.400 266.6]0 1948.45 589.66 -22.47 -58938 274349.97 2362133.64 0.48 -0.44 -0.49 2126.00 62.00 20.030 266.820 2006.G3 611.06 -23.70 -610.76 274328.56 2362132.82 _. ~._ ._. . _ 0.61 -0.60 v 034 _ - - 2189.00 _--- 63.00 19.370 2G7.600 2065.94 632.29 - -24.73 ~. -63197 .- 274307.34 -------.- . 2362132. ] 9 1.l 3 ~ ~ -1.05 _ __ -- l.24 -- - '~ ---- ` ----- ; 4` 1 ~~ "' ~ -._ 25 87 44 -b`~2 27428b 86 2362131:4~'' ' 1 48 ~ 1 22 -2 54 . :; .252.00 , 63.00 "' ; - '. ,, C1 266 000 ~~25 5 .76 . _ . . . . - . 2315.00 63.00 17.690 266.890 2185.38 67236 -27.09 -672.02 274267.26 2362130.59 1.51 i -1.44 1.41 2379.00 64.00 17340 267.840 2246.41 691.61 -27.98 -691.26 274248.O1 2362130.07 0.71 -0.55 1.48 2441.00 62.00 17.000 267.130 2305.65 709.91 -28.78 -709.54 274229.71 2362129.61 0.64 -0.55 -I.15 25 ~ ,. 16.900 _-- 1 ;~ 2368.83 728.56 29 29 72_ 746 ___---274192 53 ---- 2362129.31 ' - 0 4~~ 19 O _ _ _. 4 80~ 69.00 ~ G4.00 ; ro s , ~ ., ~ 27 .960 . , .. ; _... v. - . . - _--____- . ~ , ._ ____ . ._._._ . - -- . - ~_. ~_.~___ 2632.00 _ 63.00 15.950 270.880 2488.58 764.83 -28.85 -764.47 274174.80 2362130.58 1.40 -132 -1.71 2694.00 62.00 15.490 269.710 2548.26 781.62 -28.76 -781.26 274158.01 2362130.99 0.90 -0.74 -1.89 2758.00 64.00 14.850 272.060 2610.03 79835 -28.51 -798.00 274141.27 2362131.56 1.39 -1.00 3.67 2822.00 64.00 13.590 273.390 2672A6 814.04 r -27.77 - -813.71 - 274125.59 -- --- 2362132.59 - - - 2.03 -197 2.08 -- - --- --- ` _ 4 ~ 26 74 - 827 71 274i11 61 - 2362133 89 ~ 2 34 2 25 ~i ~ ~< 2885.00 G3.00 12,170~ 275.140 2733. 8 8~~~3'4 . - - . . _ . . . - , . 2948.00 63.00 10.760~ 276.100 ~ 2795.22 840.47 __ -25.52 -840.17 274099.17 ~ 2362135.35 2.26 -224 1.52 3011.00 63.00 9.800 276.140 2857.2] 851.63 -24.32 -851.35 274088.02 2362136.76 1.52 -1.52 0.06 3074.00 63.00 9.140 276.240 2919.35 86192 -23.20 -861.66 274077.74 2362138.07 1.05 -1.05 0.16 3137.00 63.00 8.180 276.750 1~ 2981.63 87132 -22.13 -871.08 274068.33 2362139.32 1.53 -1.52 0.81 3200.00 63.00 ~ 7.400~ 277.460 ; ~ 3044.051 879.78 ~-21.08 C, -879.56 274059.88 ~ 2362140.53 1.25 -1.24 113 Actual Well ath Re ort sA ~~R ~ p p KE NaviTrak <165-1509'><1623 - 5343'><5463 - 7739'> H1~6NES MARATHON Page 3 of 6 INTEQ MARATHON Actual Wellpath Report NaviTrak <165-1509'><1623 - 5343'><5463 - 7739'> Page 4 of 6 r~~^ BAKER M1~61~IES INTEQ e , Operator ,. ~ ~ MARATHON Oil Company Slot slot# KBU34-6 Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU34-6 Field Kenai Gas Field Wellbore KBU34-6 Facility Pad 41-7 w s ELLPAT H DATA (91 sta tions ) MD Course Length Inclination Azimuth TVD Vert Sect North East Grid East Grid North DLS Build Rate Turn Rate [feet ~fcet] [°] [°] [feet] [feet] [feet] [feet] [us survey feet] [us survcy feet] [°/100ft] ~°/100ft] °/100ft 3264.00 64.00 6.450 276.780 3107.58 887.42 -20.12 -887.2] 274052.25 2362141.63 1.49 -1.48 -1.06 3326.00 62.00 5.450 274.100 3169.25 893.80 -19.49 -893.61 274045.86 236214238 1.67 -1.61 -4.32 3390.00 64.00 4.550 275.620 3233.00 899.35 -19.03 -899.16 274040.32 2362142.95 1.42 -1.41 2.37 3453.00 63.00 3.180 274.100 - 3295.86 - -- 903.58 - - -- -18.G6 -90339 274036.09 2362143.40 8 -2.17 -2.41 - ~ 4 0 2 050 284 80 -- 33 9 45 906 24 18 2 906 274033 22 2362143 8 1 91 1 7 '1b 3 3517.00 ~G 6 .0 . .5 59.7 . - . - . 7 . . 7 . - . 7 ; 7 3580.00 63.00 0.980 308.680 3422.77 907.95 -17.62 -907.78 274031.72 2362144.52 1.94 -1.70 38.25 3643.00 63.00 0.780 334.570 3485.76 908.54 -16.90 -908.39 274031.13 2362145.25 0.70 -0.32 41.10 3768.00 125.00 0.660 3i1.560 3610.75 909.23 -15.50 -909.10 274030.45 2362146.67 0.10 -O.10 -2.41 3899.00 131.00 0.590 ~35.230 3741.74 909.85 -14.22 -909.74 274029.83 2362]47.95 - OA6 r -0.05 2.80 _ _ 1 b0 - - ---- 118 O ~ 370~ ~ 312 580 - 38 ~~' `~ -- ~ ~ 37 13 41 - -- 274029 32 - - 2 ~ 7 6 - 24 0 19 0 -~ „ ~ 9 40 7. . Q ; ~~: . 5~, : . 10. - . ~~~t~~~7 . 8:7 2~ 3 . - . ~, ~; 9~:1 4144.00 127.00 0.370 318.470 3986.74 910.94 -12.83 -910.85 274028.75 2362149.37 0.03 0.00 4.64 4269.00 125.00 0.250 312.410 4111.73 911.40 -12.34 -911.32 274028.29 2362149.86 O.10 -0.10 -4.85 4394.00 125.00 0.230 296.180 4236.73 911.82 -12.05 -911.74 274027.87 2362150.17 0.06 -0.02 -12.98 4523.00 ]29.00 % 0.190 274.740 - 4365.73 912.26 ; - -11.92 . ~ -912.19 _ 274027.43 2362150.31 -__ _ 0.07 ~.__ -0.03 -16.62 ~--- 4649.00 126.00 ` ~ 0.220 271.1201 4491.73 912>71 i -11.89 -912,~ ~ ~_~27402G.98 2362150.3~ . 0.03 0.0~ ~ _2.87 4776.00 127.00 0.130 286.050 ~ 4618.73 913.09 -11.85 -913.02 274026.60 2362150.39 0.08 -0.07 11.76 4901.00 125.00 O.170 304.430 4743.73 913.38 -11.71 -913.31 274026.31 2362150.54 0.05 0.03 14.70 5026.00 125.00 0.030 256.930 4868.73 913.56 -11.61 -913.50 274026.13 2362150.64 0.12 -0.11 -38.00 5153.00 127.00 0.070 300 180 4995.73 913.66 -1 1.58 -913.59 274026.03 2362150 67 • 0.04 0.03 34.06 ~ 8 00 12 120~ 0 244 600 51 913 85 ` ~11 59 913 8 --274025 85 2362150 66 i _ 0 08 -- -- _ 0 04 - --- - 44 46 527 . 5.00 . . i 20 ,~~ . ~ . ~ - .7 . . . ~ . . - 5343.00 65.00 0.250 ~258.580 i 5185.73 914.05 -l 1.65 -913.98 ~ 274025.64 2362150.60 ~ 021 020 21.51 5463.00 120.00 0.220 225.610 5305.73 914.47 -11.86 -9I4.40 274025.22 2362150.40 0.11 -0.02 -27.47 5588.00 125.00 0.280 250.i80 5430.73 914.94 -12.13 -914.86 274024.75 2362150.14 0.10 0.05 19.82 _____~ ~ 5715.00 ~ ]27.00 I ~ 0.220;~ 205.770 5557.73 ~- 91534 ~ ~ ~ 12.46 --- -915 26 ~ -~ 27402435 - ~ ~______. _ 2362149.82 0.16 ____.._ -0.05 _. _ _ -35 13 _ T~5842 00 ! .~,~_, rr 127 00 --.._ . m.~.._ O.130 _ 239 990 ~ 5684 72 ~ _ , 915.58 12.75 ~9] 5 49> ---- 274024.11 ~ ~~ 2362149.53 0.11 _ _ OA'7 ~ _ 26.94 MARATHON Actual Wellpath Report NaviTrak <165-1509'><1623 - 5343'><5463 - 7739'> Page 5 of 6 r~.~ BAKER M1~6MES INTEQ . . Operator ~. ~ ~ MARATHON Oil Company Slot slot# KBU34-6 Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU34-6 Field Kenai Gas Field Wellbore KBU34-6 Facility Pad 41-7 • ~ ELLPAT H DATA (91 sta tions) MD [feetj Course Length [feet] Inclination [°] Azimuth ~°j 1'VD [feat] Vert Sect [feet North [feet] East ~feet] Grid East [us survey feet Grid North [us survey feet] DLS (°/100ft] Build Rate (°/100ft] Turn Rate (°/100ft] 5968.00 126.00 0.200 228.560 5810.72 915.87 -12.97 -915.78 274023.82 2362149.32 0.06 0.06 -9.07 6095.00 127.00 0350 243.810 5937.72 91639 -13.29 -916.29 274023.30 2362149.01 0.13 0.12 12.01 6221.00 126.00 0.620 279.400 6063.72 917.41 -13.34 -917.31 274022.28 2362148.98 0.31 0.21 28.25 6348.00 127.00 0.560 269.530 6190.7] 918.70 -13.24 -918.61 274020.99 2362149.11 0.09 -0.05 -7.77 6474.00 126.00 0.350 271.930 6316.71 919.70 -13.23 -919.61 274019.99 2362149.13 0.17 -0.17 1.90 6600.00 ]26.00 0.540 357.530 6442.70 920.10 -12.G2 -920.02 274019.59 2362149.75 0.49 0.15 6794 6727.00 127.00 0.590 27G.850 6569.70 920.77 -11.95 -920.69 274018.93 2362150.44 0.58 0.04 -63.53 6853.00 126.00 0.340 256.130 6695.70 921.78 -11.96 -921.70 274017.92 2362150.44 0.24 -0.20 -16.44 6979.00 126.00 0.440 ~ 268_700 ~ 6821.G9 922.62 ~ 12.06 -922.55 274017.07 2362150.36 0.10 0.08 998 7105.00 126.00 0.250 ~ 291.030 G947.G9 923.36 -11.97 -923.29 274016.33 2362150.46 0.18 -0.15 17.72 7231.00 126.00 0.170 130.220 7073.69 923.48 -11.99 -923.40 274016.22 2362150.44 0.33 -0.06 -127.63 7356.00 125.00 0.440 194.240 7198.69 923.46 -12.58 -92338 274016.23 2362149.85 032 0.22 51.22 7482.00 126.00 0.350 220.250 7324.69 923.84 -13.34 -923.75 274015.85 2362149.10 0.16 -0.07 20.64 7608.00 126.00 0.510 217.840 7450.68 924.45 -14_08 -924.34 274015.24 2362148.37 --- - O.13 - 0.13 -1.91 7672.00 64.00 ___ 0.260 ~ 231.500 7514.G8 924.74 -14.39 -- __--- -924.63 ~ -- 274014.95 2362148.06 0.41 -0.39 21.34 7739.00 67.00 0.260 231.500 7581.68 92498 -14.58 ~-924.86 274014.71 2362147.88 0.00 0.00 0.00 ELLPATH CO MPOSITION Ref Wellbore: KBU34-6 Ref Wellpath: NaviTrak <165-1509'><1623 - 5343'><5463 - 7739'> Start MD [feet] End MD [feet] Positional Uncertainty Model Log Name/Comment Wellbore 0.00 1509.00 NaviTrak (Magcorrl) NaviTrak <165-1578'> KBU34-6 1509.00 5343.00 NaviTrak (Magcorrl) NaviTrak (1623 - 5448'> KBU34-6 5343.00 7739.00 NaviTrak (Magcorrl) NaviTrak<5463 - 7739'> KBU34-6 • • Page 1 of 2 Maunder, Thomas E (DOA) From: Skiba, Kevin J. [kskiba@marathonoil.com] Sent: Friday, September 21, 2007 11:04 AM To: Maunder, Thomas E (DOA) Cc: Donovan Jr, Dennis M.; Walsh, Ken; Rang, Craig L. Subject: RE: KBU 34-6 (207-064) and KBU 12-5 (207-042) Attachments: KBU 34-6 Operations Summary 063007.doc Tom, Attached is the Operations Summary for the work that was performed on well KBU 34-6 between June 13, 2007 and July 1, 2007. The only work performed between these dates was on June 30th (2007). Let me know if you have any other questions, Kevin Skiba Production Technician Marathan Oil Cornpany Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 From: Maunder, Thomas E {DOA) [mailto:tom.maunder@alaska.gov] Sent: Wednesday, September 19, 2007 11:35 AM To: Skiba, Kevin J. Cc: Walsh, Ken; Donovan Jr, Dennis M.; Rang, Craig L. Subj~ct: RE: KBU 34-b (207-064) and KBU 12-5 (207-042) Kevin, et al, I am just getting uncovered after a little vacation. Thanks for the info on KBU 12-5. With regard to KBU 34-6, are there reports for the operations conducted befinreen June 13 and July 1? If so please send them via email. Call or message with any questions. Tam Maunder, PE AOGCC From: Skiba, Kevin J. [mailto:kskiba@marathonoil.com] Sent: Monday, August 27, 2007 3:33 PM To: Maunder, Thomas E (DOA) Cc: Walsh, Ken; Danovan Jr, Dennis M.; Rang, Craig L. Subject: RE: KBU 34-6 (207-464) and KBU 12-5 (207-042) Tom, 1.) Attached are the Operations Summaries that were intended to accompany the KBU 12-5 Sundry Report 10- 407. 9/24/2007 ~ • Page 2 of 2 2.) I presume that your 2nd inquiry relates to well KBU 34-6. Module # 1, on this well, was shot on 6/29/2007. The June 26th date is a typo. The actual completion date is 007. Sorry for the confusion. Please contact me if you have any additional inquiries. ~~~J~1 ~ 5~~ ja~~~~ Thanks, ~,„, ~, . ~- I Kevin Skiba Production Technician Marathon Oil Company Offioe (907) 283-X371 Cell (907) 394-1332 Fax (907) 283-1350 From: Maunder, Thomas E (DOA} [mailto:tom.maunder@alaska.gov~ Sent: Friday, August 24, 2QQ7 9:41 AM To: Waish, Ken; Skiba, Kevin J. Subject: KBU 34-6 (207-064) and KBU 12-5 (207-042) Ken and Kevin, We just received the 407 completion repo~ts for these welis. A couple of items. 1. The opera#ions summary attached to both 407s is for KSU 3-4-6, Wouid you please submit the reports fo~ KBU 12-5? Email is fine. 1t does appear that the information on the 12-5 407 is correct, at least it is different frarn what is reported for 34-6. 2. CBL{s) are run on June 13, then there is a break in the summary until July 1. It appears tha# module 1 has aiready been fired by July 1, however the summary does not provide that infom3ation. ! presume tha# module 1 was fired on June 26 which is the date you have listed as the comple6on date on #he 407. Thanks in advance. Cali or message with any questions. Tnm Maunder, PE AOGCC 9/24/2007 ~ ~ Marathon Oil Company Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 34-6 Common Well: Name: KENAI BELUGA UNIT 34-6 Spud Date: Event Name: Contractor. ORIGINAL COMPLETION Start: 6/13/2007 End: Name: Rig Name: Rig Release: Group: Rig Number: Date From - To Hours Code C~ Phase Description of Operations e 6/30/2007 08:00 - 08:30 0.50 SAFE7Y MTG CMPPRF Hold PJSM and obtain safe work permit. 08:30 - 09:30 1.00 RURD_ EQIP CMPPRF Rig up Expro Americas Escape Crew and hydraulic lines to pertorate AAodule 1 on Green line. Module 1 is ~ 7370' - 7380' MD 09:30 -10:00 0.50 TEST TBG_ CMPPRF Pressure test hydraulic lines, Test good 10:00 - 11:00 1.00 PERF_ CSG_ CMPPRF Perforate Module 1 on Gre2n line. Verified acousticalfy and by vibration on wellhead 11:00 -12:00 1.00 RURD_ EQIP CMPPRF Stand Back for Frac, Sign out leave iocation • • ~ ~ ~ /~~ ~ SARAH PALIN, GOVERNOR _ ( , l ~T ~-7~~ Qaay ~s~1 ~ ;! 333 W. 7thAVENUE, SUITE 100 CDisSERQ~~~~ CQ~QIIsSIQx ~ ANCHORAGE,ALASKA 99501-3539 ~' PHONE (907) 279-1433 FAX (907) 276-7542 Craig Rang Senior Completions Engineer Marathon Oil Company PO Box 1949 Kenai, AK 99611-1949 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pools, Kenai Beluga Unit 34-6 Sundry Number: 307-200 Dear Mr. Rang: Enclosed is the approved Application for Sund?y 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 unl~ss rehearing has been requested. DATED this ~8 day of June, 2007 Encl. ~D~-o ~ `/ Sincerely, 4~ • ~ Marathon Oil Company Alaska Asset Team M Mar~hdn P.O. Box 1949 . Kenai, AK 99611 MARATHON O~I Company Telephone 907/283-1326 Fax 907/283-1350 June 6, 2007 ~~~~~~~~ Mr. Tom Maunder ~~N ~ ~~ lC!L?7 Alaska Oil & Gas Conservation Commission 333 W 7th Ave ~laska~ Gi! ~~as ~~e~s, t~;;r~;~~;$rfl~ Anchorage, Alaska 99501 Anc~ara~~ Reference: 10-403 Sundry Notice Field: Kenai Gas Field Well: KBU 34-6 Dear Mr. Maunder, Enclosed please find an Application for Sundry Approvals form 10-403 for Kenai Beluga Unit well 34-6 and associated attachments. This well has been completed cased hole with a 3.5" Excape monobore production string to surFace. Request for approval is being made to perforate, fracture stimulate the 10 Excape madules placed in the weil, and vent gas during the initial post fracture treatment flowback period. ~ Should you require further information, I can be contacted at (907) 398-1372 /(907) 394- 1824, or by email at crang@marathonoil.com. Sincerely, ~ > Craig Rang Completions Engineer Enclosures: 10-403 Sundry Notice cc: AOGCC Well Schematic Houston Well File Description summary of proposal Kenai Well File Request for approval to vent gas KJS CLR ST ~ E OF AL~KA ~/U ~~ ~'~ ALA~ OIL AND GAS CONSERVATION COM~SION ~ APPLICATION FOR SUNDRY APPROVALS ~' 20 AAC 25280 ~C~~~~~~ JfJN .~ 4 ~~~~ ~~ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown ^ Perforate ^~ aiver 7S COt)g, ~~ Alter casing ~ Repair well ~ Plug PerForations ^ Stimulate ~ Time Extension ^Ancyo~,~~e Change approved program ~ Pull Tubing ~ Perforate New Pool ^ Re-enter Suspended Weil ~ 2. Operator Name: Marathon Oil Company 4. Current Well Class: 5. Permit to Driil Number: Develo ment EX iorato P ~ p rY ~ 207-064 3. Address: Stratigraphic ~ Service ~ 6. API Number; PO Box 1949, Kenai Alaska, 99611-1949 50-133-20568-00-00 7. If perforating, closest approach in pooi(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ No ~ Kenai Belu a Unit 34-6 ~ 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): A- 028142 ; 87' (21' AGL) ' Kenai Gas Field / Beluga & Upper Tyonek Pools 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): 7,739' ~ 7,582' i 7,679' 7>522' NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor g3~ 20" 114' 114' 3,060 psi 1,500 psi Surface 1,549' 13/3/8" 1,570' 1,491' 3,450 psi 1,950 psi Intermediate 5,415' 9-5/8" 5,436' 5,279' S,750 psi 3,090 psi Production 7,696' 3-1/2" 7,717' 7,560' 10,160 psi 10,540 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 7,370' - 5,742' (Gross) 7,213' - 5,585' (Gross) 3-1/2" L- 80 7,717' Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal 0 14. Well Class after proposed work: Detailed Operations Program ~ BOP Sketch ~ Exploratory ~ Development ~ Service ~ 16. Estimated Date for 16. Well Status after proposed work: Commencing Operations: 8/1/2007 Oil ~ Gas Q 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 Craig Rang Title Senior Completions Engineer Signature J ~ Phone Date ~ (907) 283-1372 ~ ~ ~ _ ~ ~ ~ ~ COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ~ BOP Test ~ Mechanical Integrity Test ^ Location Clearance ~ Other. 3SUa ` ~ ~ ~. ~ ~ ~ ~w~ ~a`~ r~.~ r~ S ~~ JUN ~ 9 2007 Subsequent Form Required: ~~y~ U APPROVED BY Approved by: CO ISSIONER THE COMMISSION Date: ~~i' ~an Form 10-403 Revised 06/2006 ~~' ~~~ Submit in Duplicate • • KBU 34-6 Fracture Stimulation Desription Summary of Proposal Kenai Beluga Unit 34-6 was drilled and cased as a 3.5" Monobore Excape completion containing ten Excape perforating modules. Each module will complete a different production interval with ten feet of perforations followed by individual fracture stimulations in each interval. Fracture stimulation operations will commence with the perforating and treatment of Module 1 followed by modules 2 through 10. All fracture stimulation operations are typically concluded in one day, unless screenouts occur. After all treatments have been performed, coiled tubing will be utilized to cleanout the wellbore of module isolation flappers and frac proppant to PBTD. The well will then be jetted in with nitrogen via the coil tubing. Once the well is flowing on its own, coil tubing will be pulled from the well and rigged down. Well testing operations will then commence and continue until an acceptable gas rate is acheived and produced frac water load volumes are at manageable levels. Once well is adequately cleaned up, well testing equipment will be rigged down and the well witl be turned over to production. Request for Approval to Vent Gas Due to the nature of such fracture stimulations, large amounts of water are injected, along with the fracture proppant, that will have to be unloaded and cleaned up during the post fracture flowback/testing period. This unloading, or cleaning up period, requires the well to be vented to atmosphere until enough gas volume is achieved to flow the well into the high pressure sales gas system. The duration of this venting operation can last as little as a few hours up to a number of days based upon reservoir pressures, permeability, well perFormance, tubing size, and fracture placement success. For Marathon's gas well operations in the Kenai Gas Field, typical vent times are less than 48 hours. However, due to the uncertainty of exactly how long KBU 34-6 will be required to vent to atmosphere, this request is for a maximum vent period of 72 hours with a maximum vent volume during that period of 6 MMCF of inethane gas. This volume is minimized due to the utilization of the Excape completion process which enables all intervals of interest to be fracture treated on the same day and unloaded together at one time, instead of multiple frac days with multiple flowback periods each requiring the venting of gas. If you have any questions regarding this gas venting request, please get in touch with the contact person indicated on the Form 10-403. ~ I #: 50-133-20568-00-00 >aertv Des: A - 028142 _ 21' AGL (87' KB Elevation) 274,939.64 2,362,144.95 60° 27' 35.566" N ~g 151 ° 14' 48.603" W ~d: 18:00 hrs 5/17/2007 Reached: 5/30L2007 Tree cxn = 4-3/4" Otis Top of Cement (est.) ???' above 9-5/8" shoe Excape Svstem Details - Ceramic flapper valves below each module as follows: Fiappers MD (RKB): Module 1 - NA Module 2 - 7,234' Module 3 - 7,145' Module 4 - 7,032' Module 5 - 6,878' Module 6 - 6,836' Module 7 - 6,795' Module 8 - 6,753' Module 9 - 6,466' Module 10 - 5,766' KBU 34-6 Pad 41-7 132' FSL, 972' FEL Sec. 6, T4N, R11W, S.M. Conductor 20" K-55 133 ppf PE To~ Bottom MD 0' 114' ND 0' 114' Surface Casina 13-3/8" J-55 68 ppf BTC To~ Bottom MD 0' 1,570' ND 0' 1,491' 16" hole, Cmt wl 490 sks (226 bbls) 12 ppg C~ass G, Type 1 cmt with 30 bbls, 12 ppg cmt to surface. (100°/, returns) Intermediate Casinq 9-5/8" L-80 40 ppf BTC To~ Bottom MD 0' S,436' ND 0' S,279' 12-1/4" hole, Cmt wl 340 sks (190 bbls) 10.5 ppg Class G cmt. 100°/ returns, floats held. Production Tubina 3-1/2" L-80 9.3 ppf EUE T~ Bottom MD 0' 7,717' ND 0' 7,560' 8rd with 6.25" OD control ~ine protectors to 5,436' RKB. 8-1/2" hole, Cmt w/ 1,076 sks (40 bbls) 11.5 ppg Class G cmt. - 10 Excape modules placed - Green control line for bottom 1 module - Yellow control line for middle 3 modules - Red control line for top 6 modules - Ceramic flapper valves below each module except for module t Perfs MD (RKB) (Beluaa/Tvonek Zones): Module 1 - 7,370' - 7,380' (Tyonek) Module 2 - 7,210' - 7,220' (Beluga) Module 3 - 7,120' - 7,130' (Beluga) Module 4 - 7,008' - 7,018' (Beluga) Module 5 - 6,854' - 6,864' (Beluga) Module 6 - 6,812' - 6,822' (Beluga) Module 7 - 6,770' - 6,780' (Beluga) Module 8 - 6,728' - 6,738' (Beluga) Module 9 - 6,442' - 6,452' (Beluga) Module 10 - 5,742' - 5,752' (Beluga) Well Name & Number: KBU 34-6 Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State/Prov: Alaska Country: USA Perforations (MD): 5,742' - 7,380' Perf (TVD): 5,585' - 7,223' Angle/Perfs: Angle @ KOP and Depth: BHP: BHT: Completion Fluid: 6% KCL Dated Completed: Ground Level (MSL): 66.1' Prepared By: Kevin Skiba Last Revison Date: 6/12/2007 6/12/2007 11:06 AM TD - 7,739' (MD) PBTD - 7,679' (MD) • ~ • ~ ~~I '13~-7 C011T~1ER~~~`I011T CONffi~IISSIO1dT Willard Tank Advanced Senior Drilling Engineer Marathon Oil Company 3201 C. Street Suite 800 Anchorage, AK 99503 ~ S.4RAH P.9LIAl, GOVERMOR 333 W. 7thAVENUE, SUITE 1Q0 ANCHORAGE,ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kenai Gas Field, Beluga/Upper Tyonek, KBU 34-6 Marathon Oil Company Permit No: 207-064 Surface Location: 132' FSL, 972' FEL, SEC. 6, T4N, R 11 W, S.M. Bottomhole Location: 123' FSL, 1862' FEL, SEC. 6, T4N, R11W, 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 an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the 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. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (9~659-3607 (pager). J DATED this ~l day of May, 2007 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. ..~~ ~ECE~ ~ STATE OF ALASKA ~ S-~D~~ ALP. OIL AND GAS CONSERVATION COM ~ ION ,. MAY 0 9 2007 PERMIT TO DRILL ~~~`~ Commission 20 AAC 25.005 Alaska Oii & Gas Cons. ia. Type of Work: Drill Q Redrill ~ Re-entry ~ ib. Current Well Class: Exploratory ~ Stratigraphic Test ~ Service ~ Multiple Zone Q Development Oil ~ Development Gas ~ Single Zone ~ ic. Specify if well is proposed for: Coalbed Methane ~ Gas Hydrates ~ Shale Gas ^ 2. Operator Name: Marathon Oil Company 5. Bond: Blanket Q Single Well ~ Bond No. 5194234 11. Well Name and Number: KBU 34-6 3. Address: 3201 C. Street, Suite 800, Anchorage, AK 99503 6. Proposed Depth: MD: 7,739 TVD: 7,582 12. Field/Pool(s): Kenai Gas Field 4a. Location of Well (Governmental Section): Surface: 132' FSL, 972' FEL, Sec. 6, T4N, R11W, S.M. 7. Property Designation: A-028142 Beluga / Upper Tyonek Pool Top of Productive Horizon: 123' FSL, 1,862' FEL, Sec. 6, T4N, R11W, S.M. 8. Land Use Permit: 13. Approximate Spud Date: Ma 18, 2007 Total Depth: 123' FSL, 1,862' FEL, Sec. 6, T4N, R11W, S.M. 9. Acres in Property: 2,560 14. Distance to Nearest Property: 3,185 ft 4b. Location of Well (State Base Plane Coordinates): Surface: x- 274,939.64 y- 2,362,144.95 Zone - 4 10. KB Elevation (Height above GL): (21' AGL) 87 feet 15. Distance to Nearest Well Within Pool: 1,279 ft KBU 31-7RD 16. Deviated wells: Kickoff depth: 200 feet Maximum Hole Angle: 25 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 4,179 Surface: 2,394 18. Casing Program: Specifications To p - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 133 K-55 PE 79' 0' 0' 100' 100' 16" 13 3/8" 68 L-80 BTC 1,556' 0' 0' 1,577' 1,500' 484 sacks 12 1/4" 9 5/8" 40 L-80 BTC 5,413' 0' 0' 5,434' S,277' 339 sacks 8 1/2" 3 1/2" 9.3 L-80 EUE 7,718' 0' 0' 7,739' 7,582' 1,068 sacks 19. PRESENT WEI.L CONDITION SUMMARY (To be completed for Redrill and Re-Entry O perations) 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 ND Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee Q BOP Sketch Q Drilling Program ~ Time v. Depth Plot ~ Shallow Hazard Analysis ~ Property Plat ^~ Diverter Sketch ^~ Seabed Report ^ Drilling Fluid Program ^~ 20 AAC 25,050 requirements ^ 21. Verbal Approval: Commission Representative: 22. I hereby certify that the foregoing is true and correct. Printed Name Willard J. Tank Signature ~~ ~r(, , s ..t, WTy' Date Contact Title Advanced Senior Drilling Engineer Phone 713-296-3273 Date May 9, 2007 Commission Use Only Permit to Drill Number: aQ~7~~0 API Number: so-/.~3ao~dtoooo Permit Approval Date: 5 1/ 07 See cover letter for other requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: Samples req'd: Yes~ No[] Mud log req'd: Yes~ No[./~ ~L~'~ ~~ ~~~.~ ~~ti~ ~?~~ ~~5~ HZS measures: Yes^ No Directional svy req'd: Yes~ IVo^ APPROVED Y THE COMMISSION DATE: ~~,/~^ D~ , COMMISSIONER `~ ' / Form 10-401 Revised 12/2005 /^~ ^ 1 ~ ~ ~ ~ ~ ~./ ~„% K 1 Submit in Duplicate # ~ M Marathon MARATHON Oil Company May 9, 2007 John Norman Commissioner ~E~E~V~~ State of Alaska Alaska Oil & Gas Conservation Commission ~1,4Y a07 333 West 7t" Ave, Suite 100 0~~ Worldwide Drilling North America P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 Anchorage, AK 99501 Alaska Oi18~ Gas Cons. CornmissiQ~ Anchorage Reference: Drilling Permit Application Field: Kenai Gas Field Well: KBU 34-6 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 well in the Beluga / Upper Tyonek Pool in the Kenai Gas Field. No completion is desired in the Sterling pool. If you require further information, I can be reached at 713-296-3273 or by e-mail at wjtankC~ marathonoil.com. Sincerely, 0~~~~ ~--d. S"~ ~.~ ~.~-r Willard J. Tank Advanced Senior Drilling Engineer Enclosures • ~ KBU 34-6 Drilling Program Marathon Oil Company Alaska ~ ~ ~VIARATH~lV MARATHON OIL COMPANY DRILLING PROGRAM Kenai Gas Field KBU 34-6 Originator: Will Tank Mav 9, 2007 Date Reviewed by: Pete Berqa Date Brian Rov Date 5/9/2007 CONFIQENTIAL MATERIAL Page 1 of 18 KBU 34-6 • • Marathon Oil Company Drilling Program Alaska TABLE OF CONTENTS 1. Emergency Response Information ................................................................................................................ .. 4 1.1 Directions to Location .................................................................................................................................... .. 4 . 1.2 Rig Contact Numbers .................................................................................................................................... .. 4 1.3 Marathon Emergency Response Contacts ................................................................................................... .. 4 1.4 Outside Emergency Response ..................................................................................................................... .. 4 1.5 Marathon Contact List ................................................................................................................................... .. 5 2. Regulatory Agency Contacts ........................................................................................................................ .. 5 2.1.1. Internai Regulatory Contact .......................................................................................................................... .. 5 2.1.2. External Regulatory Contact ......................................................................................................................... .. 5 3. Regulatory Compliance ................................................................:................................................................ .. 5 4. Drilling Program Summary ............................................................................................................................ .. 6 4.1 General Well Data ......................................................................................................................................... .. 6 4.2 Working Interest Owners Information ........................................................................................................... .. 6 4.3 Geologic Program Summary ......................................................................................................................... .. 6 4.4 Summary of Potential Drilling Hazards ......................................................................................................... .. 7 4.5 Formation Evaluation Summary .................................................................................................................... .. 7 4.6 Drilling Program Summary ............................................................................................................................ .. 8 4.7 Casing Program Summary ............................................................................................................................ 10 4.8 Casing Design ............................................................................................................................................... 10 4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP) ........................................................... 10 4.10 Casing Test Pressure Calculations ............................................................................................................... 12 4.11 Blowout Prevention Equipment, Testing and General Procedures ............................................................... 12 4.11.1. Function Testing ............................................................................................................................................ 12 4.11.2. Pressure Testing ........................................................................................................................................... 13 4.12 Wellhead Equipment Summary ................................................................................................................... 13 4.13 Directional Program Summary ...................................................................................................................... 13 4.14 Directional Surveying Summary .................................................................................................................... 14 4.15 Drilling Fluid Program Summary ................................................................................................................... 15 4.16 Drilling Fluid Specifications ........................................................................................................................... 15 4.17 Solids Control Equipment .............................................................................................................................. 16 4.18 Cement Program Summary .......................................................................................................................... 17 4.19 Bit Summary .................................................................................................................................................. 17 4.20 Hydraulics Summary ..................................................................................................................................... 18 4.21 Formation Integrity Test Procedure .............................................................................................................. 18 5/9/2007 CONFIDENTIAL MATERIAL Page 2 of 18 KBU 34-6 • Drilling Program ~ Marathon Oil Company Alaska Attachments Group Attachment Attached Commercial Information AFE Da s/Cost vs. De th Curves X Pro'ect Ob'ectives and Scorecard RSO Codin Information X Re uisitions Vendor List Bonus Pro ram Drillin Contract Re ulato / HES Information Emer enc Evacuation Plan X H2S Contin enc Plan n/a Re ulato Permits X Re ulato Rules and Re ulations Risk Anal sis Miscellaneous Pro rams Vendors Bit Pro osal X Cement Pro osal X Directional Plan X Fluids Pro ram X Wellhead E ui ment - Descri tion/Drawin s Drill Strin and BHA Summa Ri Mobilization/Moorin Procedure n/a Geolo ical Information Location Ma w/ offsets X Offset Data Pro osed Formation Pore Pressure, Mud Wt & Fracture Gradient X Tem erature Curves Geolo ic Structure Ma s Geolo ic Cross Section Bath met Ma n/a Anal sis Riser Anal sis n/a Station Kee in Anal sis - Moorin /DP n/a Stress Check Casin Desi n File X Maximum Allowable Over ull Miscellaneous Information Wellbore Dia ram n/a Ri Elevations X Well Location Dia ram X BOP Schematic X BOP Well Control Brid in Document Detailed Casin S ecifications X Detailed Drill Pipe Specifications 5/s/2007 CONFIDENTIAL MATERIAL Page 3 of 18 KBU 34-6 • Drilling Program 1. Emerqencv Response Information 1.1 Directions to Location i Marathon Oil Company Alaska Method Directions Air Latitude - 60°27'35.566"N Longitude - 151 °14'48.603"W From the Kenai airport, go 0.5 mile South on Willow Street. Turn East on Main Street Loop, go 0.3 miles. Continue East on Ground Bridge Access Road 3.2 miles. Turn West on Kalifornsky Beach Road. Go West and then South, go approximately 5 miles, just past the Kenai Gas Field office at Pad 34-31. Turn East onto the next lease road South of the Kenai Gas Field office. Travel Southeast 1 mile to pad 14-6. Go through pad and continue East 0.5 mile to pad 41-7. 1.2 Riq Contact Numbers Contact Office Cell Glacier Drilling Rig 1 Inlet Drilling Tool Pusher 907-283-1314 907-394-1321 Marathon Supervisor 907-283-1312 907-394-1317 1.3 Marathon Emerqencv Response Contacts Individual Postion Main Phone Alternative Kenai Gas Field Emergency Number 907-283-6465 CERT 24 hrs Notification 1-800-MOGCERT CERT Crisis Center Houston 713-296-4230 713-296-4237 1.4 Outside Emerqencv Response Location Contact Phone Fire Kenai / Soldotna, Alaska 907-262-4792 Ambulance Hospital Kenai / Soldotna, Alaska Central Peninsula Hospital 907-262-4404 Police Kenai / Soldotna, Alaska Kenai Police Soldotna Police State Police 907-283-7879 907-262-4455 907-262-4453 Coast Guard 800-478-5555 Spill and Contamination Alaska Alaska State Spill Reporting National Response Center Oil / Toxic Chemical Spills 800-424-8802 Best Practices: 1 Policy: Post emergency notification information on rig floor, company man's and tool pushers' office Comments: 5/9/2007 CONFIDENTIAL MATERIAL Page 4 of 18 ~ i KBU 34-6 Drilling Program Marathon Oil Company Alaska 1.5 Marathon Contact List Contact Title Office Mobile Facsimile Home Will Tank Drilling Engineer 713-296-3273 713-203-8398 713-499-6737 832-934-2617 Pete Berga Drilling Superintendent 907-565-3032 907-529-0551 907-565-3076 907-346-3763 Bryan Roy Drilling Manager 713-296-3256 832-444-4772 713-499-6707 281-246-4686 Jennifer Enos Geologist 713-296-3319 713-408-3583 Moksh Dani Reservoir Engineer 713-296-3140 832-692-4700 Craig Meese Completion Engineer 713-296-2214 713-725-7114 Ken Walsh Production Engineer 907-283-1311 907-394-3060 907-283-3050 John Nicholson Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Dan Byrd Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Mike Feketi Drilling Supervisor 907-283-1312 907-394-2641 907-283-1313 Rowland Lawson Drilling Supervisor 907-283-1312 907-394-0953 907-283-1313 2. Requlatorv Aqencv Contacts 2.1.1. Internal Requlatorv Contact Contact Title Office Phone Cell Phone Home Phone Facsimile Chick Underwood Re ulato Com liance 713-296-3254 979-830-7927 979-836-9390 713-499-6748 2.1.2. External Requlatorv Contact Contact ~ Title Office Phone Facsimile 24 hr Emer enc Pa er AOGCC 907-793-1236 BLM 907-267-1442 3. Requlatorv Compliance Regulation Requirement 20 AAC 25.035 e 10 A BOP testing interval requirement is now 14 days. 20 AAC 25.035 e 10 F Requirement for a 24 hour notice to AOGCC prior to BOP test. Comments 5/9/2007 CONFIDENTIAL MATERIAL Page 5 of 18 KBU 34-6 ~ Drilling Program ~ Marathon Oil Company Alaska 4. Drillinq Proqram Summarv 4.1 General Well Data Well Name KBU 34-6 Lease / License Surface Location 132' FSL, 972' FEL, Sec. 6, T4N, Ri i W, S.M. WBS Code SIoUPad KGF Pad 41-7 Field Kenai Gas Field Spud Date 05/18/07 (est.) KB (above MSL) 88' County/Province Kenai Peninsula API No. GL (above MSL) 67' State / Country Alaska Permit No. Perm. Datum KB Total MD 7,739' Well Class Development Water Depth N/A Total TVD 7,582' Rig Contractor Glacier Drilling Water Protection Depth Rig Name Glacier Rig 1 Best Practices: Comments: 4.2 Workinq Interest Owners Information Com an Workin Interest Address Phone Facsimile Marathon 100% P•O. Box 196168 907-561-5311 907-565-3076 Anchora e, AK 99519-6168 4.3 Geoloqic Proqram Summarv Surface Location Coordinates From Lease/Block Lines 132' FSL, 972' FE~, Sec. 6, T4N, Ri i W, S.M. Latitude 60° 27' 35.566" N Longitude 151 ° 14' 48.603" W UTM North (Y) 2,362,144.95' UTM East (x) 274,939.64' Tolerance Formation MD - RKB (ft) TVD - RKB (ft) Pore Pressure (psi) Pore Pressure (ppg) Lithology Possible Fluid Content Sterling A-8 (Not a Prod Target) 3,734 3,577 0.8 - 6.5 Sandstone Gas/Water Beluga (Not a Prod Target) 4,819 4,662 1.5 - 7.3 ' Sandstone Gas Middle Beluga (Primary Target) 5,454 5,297 5.8 - 8.6 Sandstone Gas Lower Beluga (Primary Target) 6,199 6,042 5.8 - 10.6 Sandstone Gas Tyonek (Secondary Target) 7,739 7,182 5.8 - 10.6 Sandstone Gas 5/9/2007 CONFIDENTIAL MATERIAL Page 6 of 18 ~ KBU 34-6 Drilling Program • Marathon Oil Company Alaska Depth (KB) Horizontal Displacement (ft) Target MD (ft) TVD (ft) Location +N/-S (Y) +E/-W (X) Tolerance (ft) Middle Beluga 5,454 5,297 123' FSL, 1,862' FEL, Sec. 6, T4N, R11W, S.M. -9 -890 Circle 200' radius Lower Beluga 6,199 6,042 123' FSL, 1,862' FEL, Sec. 6, T4N, R11W, S.M. -9 -890 Circle 200' radius Tyonek 7,339 7,182 123' FSL, 1,862' FEL, Sec. 6, T4N, R11 W, S.M. -9 -890 Circle 200' radius TD 7,739 7,582 123' FSL, 1,862' FEL, Sec. 6, T4N, R11 W, S.M. -9 -890 Circle 200' radius 4.4 Summarv of Potential Drillina Hazards Depth KB Hazard Event Discussion Precautions (TVD) Lost Circulation in Low Pressure ' Intermediate Control losses by using sufficiently sized LCM, Take care not to surge the hole during Sterling and Beluga sands Hole including fibrous and calcium carbonate types. tripping operations. Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the driller's dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands will be encountered from +/- 3,734' MD (3,577' 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. Best Practices: 1 Comments: 4.5 Formation Evaluation Summarv Interval LWD Electric Logs Mud Logs Surface 0' - 1,577' MD None None None Intermediate 1,577' - 5,434' MD None None Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Production 5,434' - 7,739' MD None Reeves Quad Combo, MFT. Pull GR- Neutron to surface. Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Completion N/A GR, CCL, CBL N/A Comments: 5/9/2007 CONFIDENTIAL MATERIAL Page 7 of 18 KBU 34-6 • ~ Marathon Oil Company Drilling Program Alaska 4.6 Drillinq Proqram Summarv Drive Pipe: N/A Conductor: 20" set to approximately 100', prior to drilling rig move. MIRU drilling rig. NU diverter. 1. RU crane and hammer. Drive 20" conductor to +/-100 ft. RKB. RD crane and hammer. 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. Best Practices: 1 Comments: Surface: Drill 16" hole to +/- 1,577' set 13-3/8" casing. 1. Drill a 16" hole to 1,577' MD (1,500' 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 13 3/8" casing. Sting out, shear out drill pipe wiper plug, and circulate drill pipe clean. TOOH with inner string. 3. Cut off 13 3/8" casing. ND diverter. 4. Install 13 3/8" slip lock connection X 13 5/8" 5M flanged multibowl wellhead. 5. NU 13 5/8" 5M BOP'S. Test BOP'S and choke manifold to 250/2,500 psi. 6. Set wear bushing. 7. Test surface casing to 1,500 psi. Best Practices: 1 During cementing operations, take returns in the cellar, instead of into the pits. Eliminates the clean up of pits from cement that circulated to surface. Vac trucks will pull from cellar. Comments: Intermediate: Drill 12-1/4" hole to +/- 5,434' set 9 5/8" casing. 1. PU 12 1/4" PDC bit and directional BHA. Drill out float equipment and 20' of new formation. CBU. 2. Test shoe to leak off. Estimated EMW is 15 ppg. 3. Drill 12 1/4" directional hole to 5,434' MD (5,277' TVD) as per directional program, short tripping as required. 4. At TD circulate hole clean. Make wiper trip. TOOH and lay down BHA. Pull wear bushing. 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 9 5/8" casing rams with variable pipe rams. Run test plug and test rams to 250/2,500 psi. 8. Set wear bushing. Test casing to 1,500 psi. Best Practices: 1 Pre-heat mud mix water to help in early shaker screen blinding issues with the mud. Comments: Due to anticipated losses in the Sterling and Upper Beluga, both calcium carbonate and fibrous material may be needed. Care must be taken on trips to minimize the possibility of surging the hole. 5/s/2oo7 CONFIDENTIAL MATERIAL Page 8 of t8 ~ ~ KBU 34-6 Marathon Oil Company Drilling Program Alaska Production: Drill 8 1/2" hole to +/- 7,739' set 3-1/2" EXCAPE string. 1. PU 8 1/2" bit and directional BHA. Drill float equipment and 20' of new formation. CBU. 2. Test shoe to leak off. Estimated EMW 13 ppg. . 3. Drill 8 1/2" hole to an anticipated TD of 7,739' MD (7,582' TVD) as per the directional program, short tripping as required. 4. At TD circulate hole clean. Make wiper trip. TOOH. 5. RU Precision. 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 lay down BHA and drill pipe. Pull wear bushing. 7. RU and run 3 1/2" 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. Make control line and electric line connections to tubing bonnet assembly. Set slips. Cut 3 1/2" casing. 10. LD BOP. Set 3 1/2" packoff. NU 13 5/8" 5M X 3 1/16" 10M tubing head adapter and 3 1/16" 10M tree. Test tree to 5,000 psi. 11. Rig down and move out drilling rig. Note: Drill all hole sections with 5" drillpipe. 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. Best Practices: 1 Drill all hole sections with 5" drillpipe to maximize hole cleaning hydraulics. 2 Do not circulate on bottom longer than 1 hour prior to moving pipe on a short trip to minimize hole washout. This is important when waiting on log analysis to give EXCAPE module placement points. 3 Put lubricant in prior to drill out of intermediate shoe. 5% Lubetex is normally required, possibly more depending on solids in the mud. Comments: Completion: Completion will be done without a rig. Best Practices: 1 Comments: 5>s/2oo7 CONFIDENTIAL MATERIAL Page 9 of i8 KBU 34-6 • • Drilling Program Marathon Oil Company Alaska 4.7 Casinp Proqram Summarv MD (ft) ~ Connection A PI Ratings Casing Size (in) op ottom Weight (Ibs/ft) ID (in) Drift (in) rade ype O. D. (in) Makeup Torque (ft-Ibs) Hole Size (in) y~ m~- a~ Q= o~- v o~, ~~ ~ 13 3/8 0 1,577 68 12.415 12.259 L-80 BTC 14.375 N/A' 16 5,020 2,260 1,545 9 5/8 0 5,434 40 8.835 8.679 L-80 BTC 10.625 N/A * 12 1/4 5,750 3,090 979 31%2 0 7,739 9.3 2.992 2.867 L-80 8rd 4.5 3,200 81/2 10,160 10,530 207 Best Practices: 1 Have ftoat equipment made up at Tubescope's yard prior to bringing casing to location. Buck on all equipment to the pin end and not make up to box below, due to rig height restrictions. 2'` - Make up buttress connection to proper mark, not to a torque value. Comments: 4.8 Casinq Desiqn Casing Shoe Safety Factors Setting Maximum Casing Depth Mud Wt Frac. Form Surface a~ Q ~ o Size Weight TVD When Set Grad Press Pressure ~ o ~ (in) (Ib/ft) Grade (ft) (Ib/gal) (Ib/gal) (Ib/gal) (psi) m U ~ 13 3/8 68 L-80 1,500 9.4 15.0 8.4 0 3.12 3.09 3.88 9 5/8 40 L-80 5,277 9.5 13.0 1.5 2,394 1.90 1.19 2.65 31/2 9.3 L-80 7,582 10.6 15.0 10.6 2,394 1.17 2.53 1.30 4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP1 Setting Casing Depth Size TVD MAWP * MASP " Mud/Gas (in) (ft) (psi) (psi) Percentage 13 3/8 1,500 3,428 0 30/70 9 5/8 5,277 3,998 2,394 30/70 3 1/2 7,582 6,678 2,394 30/70 " MAWP = Maximum allowable working pressure "" MASP = Maximum anticipated surface pressure The calculation method for MASPBHP has been modified from the standard AOGCC use of a Bottom Hole Pressure - 0.1 psi/ft gas gradient to what Marathon considers a more accurate Bottom Hole Pressure - 30% Mud Column - 70% Gas Column. This method follows the MMS standard for any well with a TVD of 12,000' or less. Marathon believes that constant gas monitoring and proper rig supervisor well control training will prevent the possibility of a weilbore being completely evacuated with only a gas gradient remaining. 5/9/200~ CONFIDENTIAL MATERIAL Page ~o of 18 ~ ~ KBU 34-6 Drilling Program Surface casinq: 13 3/8" (1,577' MD, 1,500' TVD) MASPf,a~ _((Fracture gradient at shoe) x.052 x TVDsn~) - Hydrostatic pressure of gas column at the shoe. MASPfrac =(15.0 ppg x.052 x 1,500') -(0.1 pSl/ft X 1,500') MASPfrac = 1,170 pSi - 150 psl MASPtrac = 1,020 pSi. MASPbnP = BHPoPe~ noietd - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbnP =(1.50 ppg x.052 x 5,277') -(0.3 x 9.5 ppg x.052 x 5,277') -(0.7 x 0.1 psi/ft x 5,277') MASPbnP = 412 psi - 782 psi - 369 psi MASPbnp = 0 psi MASP = MASPbhP = 0 psi MAWP =(0.7 x Casing Burst) -(Mud Wt. - Backup Fluid Wt.) x.052 x TVD MAW P=(0.7 x 5,020) -(9.4 - 8.3) x.052 x 1,500' MAW P= 3,514 psi - 86 psi = 3,428 psi Intermediate casinq: 9 5/8" (5,434' MD, 5,277' ND1 MASPf,a~ _((Fracture gradient at shoe) x.052 x TVDsnoe) - Hydrostatic pressure of gas column at the shoe. MASPt~ac =(13.0 ppg x.052 x 5,277') -(0.1 psl/ft x 5,277') MASPfrac = 3,567 pSl - 528 pSl MASPfrac = 3,039 psi. MASPbnP = BHPoPe„ naietd - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbnp =(10.6 ppg x.052 x 7,582') -(0.3 x 10.6 ppg x.052 x 7,582') -(0.7 x 0.1 psi/ft x 7,582') MASPbhp = 4,179 psi - 1,254 psi - 531 psi MASPbhp = Z,394 psi MASP = MASPbhP = 2,394 psi MAWP =(0.7 x Casing Burst) -(Mud Wt. - Backup Fluid Wt.) x.052 x TVD MAW P=(0.7 x 5,750) -(9.5 - 9.4) x.052 x 5,277' MAW P= 4,025 psi - 27 psi = 3,998 psi Production casinq: 3 1/2" (7,739' MD, 7,582' TVD) MASPf~a~ _((Fracture gradient at shoe) x.052 x TVDsnoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac =(15.0 ppg x.052 x 7,582') -(0.1 psl/ft x 7,582') MASPfrac = 6,113 pSi - 784 psi MASPtrac = 5,329 pSi. MASPbnP = BHPopen no~eta - Hydrostatic pressure of mud portion - Hydrostatic pressure of gas portion MASPbhP =(10.6 ppg x.052 x 7,582') -(0.3 x 10.6 ppg x.052 x 7,582') -(0.7 x 0.1 psi/ft x 7,582') MASPbhP = 4,179 psi -1,254 psi - 531 psi MASPbhp = 2,394 ps+ MASP = MASPbhP = 2,394 psi MAWP =(0.7 x Casing Burst) -(Mud Wt. - Backup Fluid Wt.) x.052 x TVD MAW P=(0.7 x 10,160) -(10.6 - 9.5) x.052 x 7,582' MAW P= 7,112 psi - 434 psi = 6,678 psi Marathon Oil Company Alaska 5/9/200~ CONFIDENTIAL MATERIAL Page 11 of 18 KBU 34-6 • Drilling Program Best Practices: 1 Comments: 4.10 Casinp Test Pressure Calculations • Marathon Oil Company Alaska Casing test pressure calculations 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. AOGCC regulations state that casing pressures must be 50% of the BOP working pressure documented on the approved permit to drill. Best Practices: 1 Comments: 4.11 Blowout Prevention Equipment. Testinq and General Procedures BOP PROGR AM Casing Test Test Casing Test Fluid Pressure Size MAWP MASP press Density BOPS Low/High Casing (in) (psi) (psi) (psi) (Ib/gal) Size & Rating (psi) (1) 13-5/8" 5M annular ~1) 13-5/8" 5M pipe ram Surtace 13 3/8 3,428 0 1,500 9 4 250/2,500 (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Intermediate 9 5/8 3,998 2,394 1,500 9.5 250/2,500 (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Production 31/2 6,678 2,394 1,500 10.6 250/2,500 (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets 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 3-1/8" 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. 4.11.1. Function Testinq Function Regularly. 5/9/2007 CONFIDENTIAL MATERIAL Page 12 of 18 ~ i KBU 34-6 Drilling Program 4.11.2. Pressure Testinq Marathon Oil Company Alaska The Marathon Drilling Supervisor will verify all pressure tests of BOP's, surface lines, seals, casings and FIT or LOT tests. All tests are to be recorded on the IADC and daily drilling reports. . Best Practices: 1 Comments: 4.12 Wellhead Equipment Summarv Component Description Casing Hanger Type Casing Head 13-5/8" 3M X 13-3/8" Slip Loc W/ 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL1, PRt ~ 3 5/8" x 9 5/8" Fluted Mandrel Tubing Head 13-5/8" 3M Studded Bottom X 13-5/8" 5M Flg Top, W/ 2, 2-1/16" 5M Studded Outlets, 13 5/8" x 3 1/2" Manual U,AA,PSLI,PR1 Slip Adapter Flange 13-5/8" 5M X 3-1/16" 10M W/ Seal Pocket and 3" H BPV Threads Best Practices: 1 Comments: Control lines and electric cable for the EXCAPE system will be routed through the adapter flange ports. 4.13 Directional Proqram Summarv Build Turn Coordinates Sec. No. Description MD (ft) TVD (ft) Rate (°/100') Rate (°/100') Dogleg (°/100') Inclination (deg) Azimuth (deg) +N/-S (ft) +E/-W (ft) VS (ft) 1 Tie On 0 0 0 0 0 0 269.430 0 0 0 2 KOP 200.00 200.00 0 0 0 0 269.430 0 0 0 3 Build up Section 3.00 0 3.00 269.430 4 End of Build 1,033.33 1,007.14 3.00 0 3.00 25.00 269.430 -1.78 -178.93 178.94 5 Hotd Section 0 0 0 25.00 269.430 6 End of Hold 1,870.00 1,765.42 0 0 0 25.00 269.430 -5.30 -532.50 532.53 7 Drop Section -1.50 0 1.50 269.430 8 End of Drop 3,536.67 3,379.70 -1.50 0 1.50 0 269.430 -8.86 -890.36 890.41 9 TD 7,738.96 7,582.00 0 0 0 0 269.430 -8.86 -890.36 890.41 5/9/2007 CONFIDENTIAL MATERIAL Page 13 of 18 KBU 34-6 ~ • Drilling Program Marathon Oil Company Alaska 0 iooo 2000 c g 3000 ~ ~ ~ ~ a4ooo ~ p + ~o ~ 5000 Z 'C ^ ~ ~ L 6000 ~ ~ 0 F~ ~ 7000 8000 -30 00 -2000 -1000 0 10 00 2 0 00 3000 40 00 -1000 0 Vertical Secti o n at 269 .43° ( 2 500 ~n) West(-)/East(+) (500 ft/in) Comments: Vertical section calculated from a reference azimuth of 269.43° taken from surface location to bottom hole location. Potential Well Interference: Well Distance (ft1 Depth (MD) KBU 12-5 59.20 779 KBU 41-6 62.07 677 KBU 33-6X 130.57 208 KBU 33-6 160.40 Surface KBU 42-7 174.40 226 KBU 42-6 174.94 223 No serious interference exists. See attached directional plan and anticollision analysis for more details Best Practices: 1 ~. i. ~ i ~ - ~ ~~ ~ - _ __ _ - ~ _ i ~ _ - _. _ ~ - , t ~ - - _ , _ . _ , _ ; _ I ~ , _ _~ - - _ I ~ _ 13 3/8" - -- - ~_ -__ . II ____ i . . r _ _ i --~ J T - - - _. ~ .. .- _-.. . I 1 __ _... _ ~ - I t _ .. ._- -- - - ---- - I ._ J... -- - -- - ~ ` I I ~ ~- , Y ~ I-- ._~- I _ I _ -i i I _ ~ - _ _ _~ _ ~, T ~ ~ ~ ~ ~ ~ ~ . _~ _ i i ~- ' ~ i - I =- -~ r '- - i ,i 34-6 Middle Bel KBU ' - - 9 5/8 " I ;. ~, , I i ~ i- _ I _ ~ , I ~ , .I - - _ KBU 34-6 Lower Bel T _ __ ~ - - I 1 I -- i -. ' i _ - I_ ~ - ~- ~ -F r -- - _ _ KBU 34-6 Tyon ~ KBU 34-6TD _ I - _ r _ - _ _ - ~ -t .3 1/2 i " __ _--- ~~ , , . .~~.. . .-_ ';- . i .. J . I _-. ..._ .' : I . --. .. ._.. - . Comments: 4.14 Directional Survevinq Summarv Interval MD (ft) MWD Survey Magnetic Multishot Gyro Multishot Other Survey Tool Remarks Surface 0 - 1,57T X Intermediate 1,577' - 5,434' X Production 5,434' - 7,739' X Best Practices: 1 _ I I ~ ~ II _ _-}_ _-- -~----~-- _ I I i KBU 34-6 Lo wer Beluga KBU 34-6 Middle Beluga i ~ ? ~ ~ I I ~ ~" ~ i ~ , i ~ I ~ ~ i _ ~ _.> . __1 _ i _ _ _ KBU 34-6 KBU 34-6 TD I Tyonek ~ I ---_. --- - _ ---- - - 5/s/2oo~ CONFIDENTIAL MATERIAL Page 14 of 18 KBU 34-6 ~ ~ Drilling Program Comments: 4.15 Drillinq Fluid Proqram Summarv Marathon Oil Company Alaska Interva l - TVD Minimum Inventory From To Density Ge! (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite Gel, Gelex, Soda Ash, Caustic, Barite, Polypac 0 1,500 8.6 - 9.4 Gel / Gelex Spud Mud Supreme UL, Sodium Meta Bisulfate Flo-Vis, PolyPac Supreme UL, KCI, SafeCarb 1,500 5,277 9.0 - 9.5 6% Flo-Pro NT w/ Safecarb 10,40,250, Mix II, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate, Lubetex Flo-Vis, PolyPac Supreme UL, KCI, SafeCarb, 5,277 7,582 9.4 - 10.6 6% Flo-Pro NT w/ Safecarb Barite, Caustic, Conqor 404, Sodium Meta Bisulfate, SteelLube, Lubetex Best Practices: 1 Because the production zone will be fracture stimulated, the mud system from the intermediate section will be re-used for the production hole after cleanup through the on-site centrifuge. Comments: 4.16 Drillinq Fluid Specifications Interval - TVD LSRV Drill From (ft) To (ft) Density (Ib/gal) Vis (sec/qt) 1 min (Ib./100ft ) PV (cP) YP (Ib/100 ftz) Fluid Loss (cc) pH Solids (%) 0 1,500 8.6 - 9.4 60 - 100 N/A 25 - 35 NC - 12 +/- 9.5 < 7.5 1,500 5,277 9.0 - 9.5 40,000 + 8- 12 7- 9 +/- 9.5 +/- 5 5,277 7,582 9.4 - 10.6 30,000 + 10 - 16 5- 8 +/- 9.5 +/- 5 Best Practices: 1 As a standard practice for long string completions, the drilling mud that will remain above the top of cement on the 3~/z" production casing will be treated with corrosion inhibitor (Conqor 303A) at a concentration of 1 drum per 100 barrels of drilling fluid. Comments: See mud prognosis for details. Sized CaC03 (SafeCarb) will be used to control leakoff. 5/s/2oo7 CONFIDENTIAL MATERIAL Page 15 of 1s KBU 34-6 Drilling Program 4.17 Solids Control Equipment ~ . Marathon Oil Company Alaska ~ o ~. N N ~` U ~ ~ N ~ fd N ~ ~ ~ fq C Ul U ~ Y c~a ~ U - ~' ~' - 0 ~ ~ aNi ~ aNi ~ ~ ~ a~i U ~ U ~ U o ~ N Iflt61'Val Comments 0- 7,739' MD X X X X Closed Loop System, Full Containment, Run shakers with finest screens possible Item Equipment Specifications (quantity, design type, brand, model, flow capacity, etc) Shaker 2- Swaco Mongoose PT Desander 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 Best Practices: 1 Have vacuum trucks pull fluids from trough above slop pit to more efficiently pull fluids for disposal. This minimizes water added to the solids to suspend for pickup by the trucks, thus minimizing total volume to be disposed of. Comments: 5/9/2007 CONFIDENTIAL MATERIAL Page 16 of 18 ~ KBU 34-6 Drilling Program ~ Marathon Oil Company Alaska 4.18 Cement Proqram Summarv De pth Gauge Top of Cement Gauge Ann Vol Slurry Casing Size (in) MD (ft) TVD (ft) Hole Size (in) MD (ft) TVD (ft) Ann Vol To TOC (ft3) With OH Excess (ft3) Density Lead/Tail (ppg) Open Hole Excess (%) Thickening Time (hrs) 20 100 100 Driven N/A 133/8 1,577 1,500 16 0 0 715 1,215 12.0 75 8 95/8 5,434 5,277 121/4 3,200 3,043 700 1,014 10.5 40 8 31/2 7,739 7,582 81/2 4,900 4,743 946 1,249 15.8 40 N/A Mix Water Compressive Casing Size Density Qty Yield Slurry Vol TOC MD Qty WL FW Strength (psi) (in) Slurry Cement Description (Ib/gal) (sx) (ft3/sx) (ft3) (ft) (gal/sx) Type (cc) (%) 8 hr 24 hr 13 3/8 Tail Type I Cement 12.0 484 2.51 1,215 0 11.28 Fresh 812 0 196 818 95/8 Tail Class"G" 10.5 339 2.99 1,014 3,200 12.39 Fresh 24 0 145 1,441 3 1/2 Tail Class "G" 15.8 1,068 1.17 1,249 4,900 4.97 Fresh 24 0 226 2,632 Best Practices: 1 Pump several fluid calipers at TD to help with the hole volume determination from the open hole caliper log. Comments: See cement prognosis for details and spacer specifications. 4.19 Bit Summarv Interval - MD Type Recommended Estimated From (ft) To (ft) Size (in) Manufacturer Model No. IADC WOB (kips) RPM Rotating Hours Expected Minimum ROP (fUhr) 0 1,577 16 Christensen MX-1 115 1- 4 80 - 350 1,577 5,434 12 1/4 Christensen HCM 506Z M323 Up to 52 Motor 5,434 7,739 8 1/2 Christensen HCM605 M323 Up to 25 Motor Best Practices: 1 Comments: See bit prognosis for additional information. If a second bit is necessary for the 12'/a" hole a MX-C3 (IADC 137) should be used to finish this section. Back up bits for the 8'/z" hole section wifl consist of mill tooth and TCI tricone bits. 5/9/2007 CONFIDENTIAL MATERIAL Page 17 af 18 KBU 34-6 Drilling Program ~ ~ Marathon Oil Company Alaska 4.20 Hvdraulics Summarv Qty Make Model Liner ID (in) Stroke (in) Max Press (~3 g0% WP (psi) Displacement Q 95% Vol. eff (gal/stroke) Max Rate @ 95°fo Vol. eff (spm/gpm) Hole Sections Used 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 Est. Hole Pump Standpipe Openhole Nozzle Depth-MD Size Rate Pressure Min AV MW ECD Size ~P at bit (ft) (in) (gpm) (psi) (fpm) (ppg) (ppg) (32"s) ( si) Remarks (Drill string configuration) 0- 1,950 16 650+ 1,400 69 9•3 2- 1$ S Actual Data KBU 24-7X (@ 1,636' MD) 1-16 1,950 - 6,561 12 1/4 663 2,050 130 9•5 6- 13's Actual Data KBU 24-7X (@ 6,077' MD) 6,561 - 8,990 8 1/2 477 1,850 249 9•7 5- 15's Actual Data KBU 24-7X (@ 8,176' MD) Best Practices: 1 Drill all hole sections with 5" drillpipe to maximize hole cleaning hydraulics. Comments: See separate hydraulics calculations. Annular velocities in the 16", 12'/a", and 8'/z" holes were calculated using 5" drilipipe. 4.21 Formation Inteqritv 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: Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and 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. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Best Practices: 1 Comments: 5/9/2007 CONFIDENTIAL MATERIAL Page 18 of 18 ~ ~ Marathon Oil Well KBU 34-6 Diverter Flow line 21 1/4" 2M Diverter ~ 16" Automatic Knife Valve I I~ Diverter Spool _~ ~ uu U 16" Diverter Line ~ Flow Nipple 13 5/8" 5M Annular Preventer -~ 13 5/8" 5M Double ~ Ram Preventer ~ 2 1/16" 5M Check Valve 2 1/16" 5M Manually Operated Valves ~ ~~ ~~~ ~X~ ~{~{{~ {x~ ~~~ Kifl La~--k-J-~LJL1~-~~-UJ 13 5/8" 5M Cross ~~ 13 5/8" 5M x 13 5/8" 5M ~ Drilling Spool Marathon Oii Well KBU 34-6 BOP Stack Pipe Ram Blind Ram Flow Line Choke ~ 3 1/8" 5M Manually Operated Valve ~ ~/ll II II I~I II I 1 3 1/8" 5M Hydraulically Operated Valve Bottom of mud cross must be 24-45"from groundlevelfor Glacier 1 rig placement. ~13 5/8" 5M Tubing Head Flange ~ ~ ~ Marathon Oil Well KBU 34-6 Choke Manifold To Gas Buster To Blooey Line Bleed off Line to Shakers ~ ~ Surface Use Plan for Kenai Beluga Unit, well KBU 34-6 Surface Location: Anticipated at 132' FSL, 972' FEL, Sec. 6, T4N, R11 W, S.M. 1) Existing Roads Existing roads which wi~l be used for access to KBU 34-6 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 KBU 34-6. 3) Location of existing wells Well KBU 34-6 will be drilled on Kenai Gas Field (KGF) pad 41-7. A pad drawing is enclosed that shows existing wells and the proposed location of KBU 34-6. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the KGF pad 41-7 are shown on the enclosed pad drawing. A flowline will be installed from the KBU 34-6 wellhead to an existing line heater and separator. 5) Location of Water Supply A water supply well exists on the pad that KBU 34-6 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 Sewage will be hauled to the Kenai sanitation facility. 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. S& R will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surface KBU 34-6 will be drilied from an existing pad. Reclamation of the pad will occur after the abandonment of KBU 34-6 and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from Salamatof Native Association prior to any reclamation work beginning. 10) Surface ownership The surface owner of the land in the Kenai Beluga Unit is the Salamatof Native Association. 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: S- l~ ~ 0 7 Name and Title: ~C ~ ~-^ • ~ ' GJJT. Willard J. Tank, Adv nced enior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, TX 77253 (713) 296-3273 ~ ~ NORTH SCALE o so ~zo FEET WELL K.B.U. 34-6 AS-STAKED WELL LOCATION ASP ZONE 4 NAD27 N: 2362144.95 E: 274939.64 LAT: 60°27'35.566" N LONG: 151°14'48.603' W FEL = 972' FSL = 132' ELEV = 66.1' (MSL) SECTION 6, TOWNSHIP 4N RANGE 11 W. SM AK EDGE OF PAD KENAi GAS FIELD PAD41-7 972' FEL SECTION 6 K.B.U. 11-8Y ~ I 8' WELL CELLAR N: 2362098.81 E: 275205.83 ~O~ ~ K.B.U.43-7X ~ 8' DIA. WELL CELLAR K.B.U. 33-6X K.B.U. 42-6 K.B.U. 41-6 LL N: 2362053.16 8' DIA. WELL CELLAR 8' DIA. WELL CELLAR ~ 8' DIA. WELL CELLAR M E: 274996.71 N: 2362053.94 N: 2362054.15 K.B.U. 11-8X I K.B.U. 12-5 N: 2362054.63 ~ E: 275050.91 E: 275105.24 8' DIA. WELL CELLAR DIA. WELL CELLAR E: 274916.45 CONCRETE p N: 2362053.64 N:2362041.14 ~ VAULT i~ ~ ~ ~ E:275155.57 I E: 274850.05 \°/ L~J 180 L~ ~ CONCRETE VAULT v/PIPEGUARD ` 6 I C _ _ - 6.13 _ . - - - - SECTION L INE . ` K.B.U.24-6H - - - - - ~ METHONAL ~6' DIA. WELL SI LO ~ K.B.U.44-B 16' DIA WELL SILO ~ ~ SKID N: 2361975.18 E:275073.31 . N:236196724 I ~ ~ --~ ~~ L'~ ~ ~~ ~ \ ~ E:275191.17 ~ \ ~~ ~ W WELL K.B.U. NORTH o K B U 42-7 ~_-= I Z AS-STAKED WELL LOCATION ~.g.U. 33-6 16' DIA. WELL SILO N: 236~964.51 ~6' DIA~. WELL SILO N: 2361975.39 E: 2749905.82 N: 2361974J5 E 275022.43 E:274973.34 SECTION 7 NOTES 1. BASIS OF COORDINATES IS U.S.C. 8 G.S. TRI STATION AUDRY IN A.S.P. ZONE 4. (NAD 27) AVERAGE CONVERGENCE OF POINTS SHOWN: 01 °5'58'. 2. AUDRY LOCATION: ~ LAT: 60°30'S0.559"N LONG: 151 °16'37.445'W NORTHING = 2,382,045.42 EASTING = 269,866.75 K.B.U. 32-7 16' DIA. WELL SILO N: 2361972.17 E: 275138.30 CONTROL POINT 3 2" ALCAP N = 2361855.33 E = 275081.95 ELEV. = 6621 ~i~ ~ K.U.43-6X K.U.43-6 WELL HOUSE ~0' DIA. WELL SILO N: 2361775.96 17' x 17' PIPE GUARD E:275063.53 N:2361787.02 E:275134.92 r~ ``~'` ~ ~ ~ ~ ~- --~ ~__ ~ Z \ I ~ ~G' I w K.T.U.32-7H ~ ~ 16' DIA. WELL SILO I N: 2361929.50 E:275232.7b I I K.B.U. 41-7 I N: 2361808.64 E:275201.30 C) I K.B.U.41-7X I~ N:2361770.89 I E:27525124 ~ON ~aECf REVISION: - 1-JL ~ M ~[ 3 KENAI GAS FIELD PAD 41-7 DATE: M13/07 DII.. w-rxo ~~~Y WELL K.B.U.34-6 °w'"'"aY: .~"" • ~'~'~ ~ AS-STAKED SURFACE LOCATION DIAGRAM ~`E ~ ~ . PRQIECT NO. 073032 ENGINEERING / MAPPING / SURVEVING / TESTING BOOK NO. OB-21 GI~ IIC P.O. 80X 488 SOLDOTWI, AK. 98889 LOCATION SHEET ~°~~E: ~~"~'2,8 F,~: `s°"~~.~ EMAII: SAMCI.ANE~MCLANECG.COM S6 T4N R11 W SEWARD MERIDIAN, ALASKA '~ ~ 1 • • J KU KU ~ 34-31 N 1432 ~~ ~DU ~ 1 34 2 ~ ~-6 U KU KBU 41-6 \ ~ K r K U , U S 21-BX 6 ~ DU KBU 22-6 ~. ~ h 5 , U 42-6 MI ~~~ r~ IM ~ KTU 43-BXR KBU 23X-~ , 6 r~ KBU 4 K 33-6 N KU F KB U 6X 43-6A KTU o t3-5 KTU 6R KBU 34-6 " 24 _ _5 ' ~ICBU 24 _. - ' q S KU ' 24-SRO KDU ~ ~ 8 KBU _ 24- KBU I -BX U 1-7 KDU 1 ~ „ 2 ~ KU J~ ~ ' _ ~ K t 7 K8U ~-~X ._ KU q •• 1-]RD ~1-B ~3 KTU r J " BU 2-~ 32-7H ~ 5 S S ~, 6 + S ~ KT 32 7 6 ~ ~ KBU y KDU ~ KBU 13-B 4RD ' 33-7 BU 3-12 ? -7 f. -7 ~ 7, U 6 3-7X Maralhon Oil Company KBU 2~7- X KUH KU ~ 41-1b 24-7 . ~ . ~ ; '11-17 ~ A Beluga/Tyonek PA , Kenai Gas Field, Alaska 0.25 mi • • . . . _ _ .. . _ _ ,.«, _ _ - o°so ? ,_. _ '~ ' -, s . !4C}RTH ~ . P~pe1'u~e ~ .._ ~" ~.~~ '~ . , . .- - ~ ~ - ~ - - ' ^'~ GrovBt ~ , , . _._ _ ~ k f ~ 4 __.__ _ ~r T ~1 ~ •~~ ~~ ~~ ~~ ae~u r..r ,r' ~ 3 ' ~, i t ~ i~ ' ' , r. ~ •. A Pad 33-30 ,~ _' ~ ~ ~ i ( . f~ . ~~" ~ l ,~'o'~PY ~Lan~ ~~i~R~+ t~~1 s~ , { ` ;.-~r: Privat~l~iosd ~ •`~ ~%~ ,, ;; 23~0000 ~ i s. ~ '. ° ~ _' s , . ~. ., '' ~~ ; v c~rr ~ ~ ~ ~ ~ io ~ , ~ ~- ,."._,:__- P a d 4 3- 3 2 ~'i~ ~ ~ ~ , Lauadi~ ~i " i~ ~~ . , ~ P a d 3 4- 3 1 q~~%~Gas wens_ _ • ~. .. str~s ,.. . . _ z . , ,, .. :. ^~ ~ ~ , ~~ t r`~'`~ K~ENA1 (iAS FIELD ~ ~ ' ~ ~ . , ~ ~I t Grovel ~~,V- ~ ~ ~~ 6 5 4 ~ ~ i~ ,,a ~ Pft~V ;. r ~ _. ._ ~ `~Pac~ _14-6 = --- -~-~- ~~~; ~ :l o'" r ~ . ~ , ~ Pad~ 33-t f ~ _~ . •(~ ~~ ~' ~ ~ - c,a5 we~~s ~ , ,i:~ ~ -~ Pea 4,-~ a. , ~ P a d 14 - 4 ~,,,d, ~ 1, ~. ~ i~' suip . ~ • i: ProjecC Location ~ L ~- ~ ~ s 9 ~ ,`' ~ ' . ' o ~ Privst~4 Road ~ f~ Y ,. ~ I?~ r c _ ~ ~i ~ . _ . ~ ~ " `~ ~ Pad 41-18 1 `f~~ t ' s ~ , Ecleo `~ ~ i ~ l.ake . _ _ . ~ ~ F ~. ~ . COOK INLET P~44-18 +~ T~ ~~. . 1'~ ~ Abandonad ~~'1 - ~ " ~ ~,~_;~.-~a=?-- „c`' ~~ ..7 ~~ , is~a~~ : ~~ f ~ ' ~ ``~ :,` ~ ':- . . f c..~ ~' . ! ~~ - :, _- • scnP •~* ~~ . r ~.J f ' ` ~. - - ~. % ~ ~R2( ~ , ~~~ ;, -. : ; . ,, K~nei Unit Boundery 4 - 'd + . ~ Knfitm~eky ~ ~ ~ ~ :~~ .'i • r • , ~ • ~' . ; ~. _„~,~ '125' ' . ~ff „" i ~..,,, ,~ i . ' ~ • ~ i. . 2i3 ~ .. ~ ~ ' . tL4 . • ~i ~ ~ ~ ~ '~ . ' i G ~ .. ,'S ~ 3O 29 2~"'' ~_.'~ ! - ; • ' . . - z.io ~ i-, ' ` ~ - f , ~~ ~~• ~ .~° ~ • ~~ : ~ ~ ~ r~ .~~: ~ ~ • • j ~' AeJicdicm ~ ; ,a , f sp Lake . - ~ a t . _ .~ .~ Kasllof Rivar . : • _ .. . , ~: ~ ~ ~~ 4 . ~~~ 1 + ~• ~ . ., . . i .. . ~ ' ~ , 1~• ' _f.. __~~~~~~~~ .r._~ ~_._" f.§ .i -~rT --~_._~ ._.. _..-._._. .. ... _. . _'______~ ~. . ~--~`-r ~ , r . :; ~~_ _T ~ , .,~~. :~ ~ ~ ~ _ - . ~ ' ~~ ~" - I ~ i ~ ~ ~ ~Nr ~~t ~.. 2 i ~ - .~..nn . ~ t . y i Rl . ~. ~ ~ . . ZP... ~~5hP~' _ J ~. ,~~ ,~ ~ ,~ ~ _ ~ Source Map: USGS, 1951 K~nai, Aleske B-4. 7:63,360 - __ SCAIE !63360 1 ' f. S : M~ie r...i..t~. I...f_~f_3~.. I 1:.1_k .___.._.._ ~.. :._'_-.' ""_2 ` .... " __ _'. _ ..... _ . . .. " "' _. . ....' ' .____'_ _ "F' .___ .~ ...~.__-~---~.._..-." ' _-__.. ] ~ 3?;O llYYl RfcKl 9000 !i000 150fU i ' ?IOIXI iFEt {=T-_i3`_'-'~-~F:= .? _. _F-~.=i____~--i _-L--.'.i . _x:__-=3_ .::.^__..^3. '_ F'=~-t_ ._~.-1 _'.. .~_;t ' .`s'..:~ ' :'i.__...,,. ;. ,> ~ ~ ; -0 S Kll(WEIER'S :f~l-I-'T" . . : '~. ". ' . ___~._ . 1 ~. ____ -_ ' _ ._ ._ .-L- _.___'~ Marathon Oil Corr~any Kenai Gas Field Area Map ~. ntapsli~lF?~rnnlaplPrs GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT . ~ MARATHON s~a~e , ~~« = zoo n •1200 -1t00 -to0o MARATHON Oil Company Location: Cook Inlet, Alaska (Kenai Pennin sula) Slot slot# KBU34-6 Field: Kenai Gas Field Well: KBU34-6 Easting (ft) 100 ;-1500 s °u -7.5~ ~ L a N Q l0 U ~ N 1 ~ ~ ~ 6750 7500 8250 900~500 13.375in Casing, i BAKER ~ Nu6NEs INTEQ 3.Sin Casing 9.625in Casing ~ KBU39-o~ KU34-6 TD T U34-6 Tyonek Lower Beluga , Middle Beluga KOP 3.00°/100ft End of Build ~ ~ 13.375in Casing Begin Drop slot# KBU34-6 Z O 0 ~ 7 ~ .Y` -100 N nwe -200 V1` I; BGS Gleba~ GeamegnaM1C MoCel ~1965.0.200].U~ Olp: 1J.J5' FKM: 553i6.5 nT Megrie4c Nor[~ is 19.)1 Eegrees East af True NoM (al OBHSI05) To cortecl ezlmulM1 hwn Mepnellc lo True atltl 19.]1 tlepreea rot (Ril a (SOOa~, ~9 Mi qr~ w+~Rn~omea~,..i. e~ e .,= tF. .~r. o Location Information Faoliry Name GrM Eesl (U9fl) Gntl NoriM1 (115M) LaN1uEe Le iWtle Padat-J 210916010 2162063.9"/0 80'2~'3a0~2'N t51'18'OB.)%1N SIM _~_ ai N~fi) L JI E(fl) ~ Grq Eacl (U511) GrM Norlh (US%) LaGNOe LongMEa &aM KBU34-6 ' i58.$i 4Q21 G9 2]69~9.600 2J611J4950 BO• 3]' ]5.588"N 151' 16' 68.803NJ Gi+c~ardi (ai~ ~o Mutl Ilne (Fetlllty- PeU 9t-]) 81M r utl Ilne (Faclllly - Pe0 <t-]) ~ Ofl i ~ar~~o B]R Targets ~m~ .wim 1.50°/100ft ~»~ ~... ~.~,,. End Drop Sterling A8 Beluga 4 ~ 9.625in Casing ~<11't9 ~, t•~icf~+~r- g,±~~»~ 1`~J;31-6 LG;:er 6clu~~=, - KU54-6 T~o~~_E-. ~ 3.Si~ Casing KU34-r, rG ~; TD Vertical Section (ft) s~'°„^°^°,s~~^ Azimuth 269.43° with reference 0.00 N, 0.00 E from welihead Wellpath Comments MD (fl) x~n~ v~n~ rvo 1rt1 mcu~aeo~ ~•~ azimuu ~•~ vs te~ commem ]80398 -890.38 A.86 ]66]OU 0.000 269030 890.41 Sieningne 491].96 -890.38 d.86 015100 0.000 289<~0 89041 Belu a Hole and Casing Secfions MO Inl EnE ~(nl rvn Inl ^I EnE ~E Irtl o ~ EM EM e Inl 000 o ~ 0.00 Well Profile Data Dnqn Gommenl MD (11) Inc (') Az ~"~ ND ~ttJ aral N(N) L acal E(11) L OLS ('I10011) VS (R) TeOn 000 0000 2fi96]0 0.00 0.00 ~40 0.00 000 Koa zoo.oo ooao 2fi9J]0 zaa.oa a.oa a.oo aaa a.aa EneolBUila 103].]] 250o0 2fi94a0 7007.10 -178 -71B9] 3.00 17894 Boqinprop 187000 25.440 2694]0 1]fi542 -5.30 -5]]50 Op0 5]2.5] Enaprop 3596.8] 0.000 2690]0 ]]]9.]0 -BBfi -89038 1.50 09041 Tp tl]9.% 0000 269<JO i5B200 -BBfi -99036 00p 09041 ~ ~ lMIARA'~HQN Planned Wellpath Report KBU34-6 Version 1 Page 1 of 4 ~~~~ 8~~-~CER ~ut~NE~i INT~Q MARATHQM ;LLPATH DATA MD Inclination ~teetJ _..- ~~~ --- 0.00 0.000 _ _ _----- 100.00 j- 0.000 200.00 0.000' 300.OOt 3.000' A~w~.00~- ;~~~ 500.00 fi 9.000 600.OOt _ _12A00' 700.00-~ 15.000' 800.OOt' 18.000! 1000.00 1033.33 1100.00 1200.00 t~~ao.oo 1400.00 1500.00 1600.00 1700.00 1800.00 1870.00 1900.00 2000.00 2100.00 3100.00-~ 3300.00~', _. 3400.00~ 3500.00 j- . 3536.67 ~ • ~~ 24. 23 21 17 IS 11 3 Planned Wellpath Report KBU34-6 Version 1 Page 2 of 4 ~~~~ BA-KER Hu~N~s INTEQ _ _.. _ ._, _ 32 stations) ~ = interpolated/extrapolated station __ _ _ ~zimuth TVD Vert Sect i North East Grid East ; Grid North DLS Build Rate Turn Rate ~°] ' ~feet] [feet] !, [feetJ , ~feetJ ~us survey feet] ;; [us survey feetJ ; [°/100ft] ; [°/100ft] ; [°/100ft] - -- __ _ - - - - _ _- -- _ -- - - --- - - 269.430; 0.00 ' 0.00 = 0.00 0.00 274939.64 2362144.95 0.00 ; 0.00 OA~ _ _ - --- -- ___---- - __._.. _ 0.000; 100.00 ; 0.00 : 0.00 0.00 274939.64 ; 2362144.95 0.00 0.00', OAi _ - _, _ _ - --_ _ _. ___ _ , 269.430 200.00 ; 0.00 ~ 0.00 0.00 274939.64 ; 2362144.95 ~; 0.00 ! O.OOj OAi _ . ~ _. ~_. 269 430, 299 95 , 2 62 q 0 03 ^~ 2.62 274937 02' 2362144 97 3 00' 3 00` 0 Oi ~~~ 43~k " 3'~9 &3; := i~~~~ ~~~°, -10.4~ I .. ~~~~ ~-~~~i~~w~~~°~,~~"~~~~~ ~ ~ ~ ~ h~~ ', '~i~ 269.430 498 77 , 23 51 7 0 23 ! -23.51 274916.13 ; 2362145 16 ; 3 00 ;~ ~ 3.00~ OAi 269.430' S97.08 ; 41.74 ;-0.42 -41.73 ¢ 274897.91 ' 2362145.32 ` 3.00 ' 3.00~ OAi , --~. _. _. ._._ ~_ .~~_ ___., ~ ., ~-~. --~~ . _ 269.430, 69431 ~ 65.08 ~ 0.65 ; -65.07 ~ 274874.57 2362145.53 ~ 3 00 ; 3.00~~ OAi __ _ _ _ --- _ ~ _ ~ __. _.. 269.430' 790.18 93.48 ~-0.93 ; -93.47 ; 274846.17 ~ 23621A5.79 ` 3.00 ? 3.00~ OAi 269.4~C? ~ ~ , 884 4~ ~~ ~~,~. ~. 7~~~~ "; ~~~~` ~~ ` ~~~ ~~ .W,~~~~~~ ~~ ~~.,~ _. _.. _._ . ~ ~ _ _ - . -. 269.430 976.81 ~~~ 165.12' -1.64 ;-165.11 i 274774.54 ~ 2362146.43 ; 3.00 ; 3.OOj OA~ ~_ __ •, ~~ ._~_ . _ _. . _ 269.430 1007.14 ; 178 94 ?-1.78 ' 178.93 274760.72 2362146.56 ; 3 00 ;~ 3.OOj OAi __ . , __ _ . ---- - _ _ - _ _._~-._~. .. _ _ _.. .__ ~ -- 269.430' 1067.56 ? 207 11 ' 2.06 -20710 274732.54 2362146.81 : 0.00 : 0.00~ OA~ - ' - --- _ _ _..~. _ . __ 269.430 1158.19 24938 !-2.48 ;-24936 , 274690.29 : 2362147.19 0.00 , O.OOj OAi ~.~~.a~a i~as~sz ~~~.~~~~~a~, z~~`'+~~~~sw - ~~~_ :~~~~~'~_~~~~~,~QC~ ___-_ ~~ . ~`~± - _ -_ 269.430 1339.45 333.90 i-3.32 ;-333.88 274605.77' 2362147.95' 0.00',, O.OOj 0.01 ~ _ 269.430 1430.09 376 16 ? ~ ~~~~ ~ ~ ~~~ 3 74 ;-37614 , 274563.51 2362148 33 ; 0 00' O.OOz 0.01 . _._ ._ .. _. __. _. 269.430~ 1520.72 ; 418 42 ~ 4 16 ~-418.40 a 274521 25 - 2362148.71 :~ 0 00 0.00~ 0.01 ~...._ ..__ _... _ _..,_ ~.__.~ ..__ . ~.. 269 430~ 1611 35 460 68 ~ 4 58 , 460.66 ' 274478 99 ~ 2362149 09 0 00 ; 0 OOj 0.01 f .~. , ,, ~._ ~, w ~~ }~~ Z~9.~~`'' 1701 9R .,_~~S :_ ~~': S(12.~!~ _~~~~ _~~62149 47 ~ „s~~~„ t ~~ '~=_a .~. ~ .._ _ 269.430 1765.42 532.53 :-5.30 '-532.50 ' 274407.16 2362149.73 0.00 ` 0.00? 0.01 - - __•. _; _ _ __ -- _ _ 269.430, 1792.66 545.10 ;-5.42 -545.07 274394.58 2362149.85 ; 1.50 , -1.50, OA~ _ _ . _ ~__- _ - 269.430 1884.15 585.45 ;-5.82 :-585.43 , 274354.24 ' 2362150.21 ` 1.50 1.50, 0.01 _.: . _ 269.430 1976.67 623 40 -6.20 ;-623.37 274316.29 2362150.55 1.50 -1.SOj OA~ ~ . ~::_ ~.a3a ~ofia ~,~~ =~~~~r~ ~._ ~~ =~s8:8s ~~a~~~sr~.~9 __23~~isa.s~ ~ ~~~~ F . : o:o~ 269.430; 2164.53 ; 691.96 3-6.88 ;-691.93 '~ 274247.74 ~ 2362151.17 ~ 1.50 i -1.50~ OA~ _. . : _ _ ~. 269.430 2259.74 722.53 y-7.19 i-722.49 274217.17 2362151.44 , 1.50 ; -1.50~ 0.01 .. ~ ~ _ 269.430~ 2355.71 ~ 750.59 ~ -7.47 ~' -750.56 { 274189.11 ~ ~ 2362151.69 °~ 1.50' -1.SOa ~ OA~ 269.430' 2452.39 "" 776.14 ;-7.72 '-776.10 274163.57 2362151.92 ° 1.50 ` -1.50; OA~ 26~.430 2549,71 799 ~~:~=7.9~5 ! -799.1~ ~~~~~!b.a7 2362152.r~~ ~ ~~3 ` ~~~v_ . . ~~:~M'''I ,- . . ~.__.____, ,., , - _._ m _ _ 269.430 2647.59 819.59 ?-8.15 -819.55 27412012 2362152.31 ` 1.50' -1.50" OAi . _ _ _. 269.430 2745.98 837.47 -8.33 -837.43 274102.24. 2362152.47 1.50 -1.50 OAi -_. _ _ 269.430' 2844.80 852.77 -8.48 -852.73 274086.94 2362152.61 1.50 ~-1.50 OAi . _ . __ _ 269.430 2943.99 865.47 -8.61 -865.43 274074.24 2362152.73 1.50 -1.50 O.Oi 269:430 3043.47 875.5~' -8.7t -875.54 ~~7~~~~3 2362152.82 t.50 ' _1,~' :O.a 269.430 3143.19 883.08 -8.79 -883.03 274056.64 2362152.88 1.50 -1.50 OAi 269.430 3243.06 ' 887.96 -8.83 -887.92 274051.75 2362152.93 1.50 -1.50 OAi 269.430 3343.04 890.23 '-8.86 -890.19 274049.48 2362152.95 1.50 -1.50 OAi _ . __ 269.430 3379.70 890.41 -8.86 '-890.36 274049.31 2362152.95 1.50 -1.50 OAi MARATH0~1 ~ • Planned Wellpath Report KBU34-6 Version 1 Page 3 of 4 ~~~~ B~~CER ~u~NEs INTEt~ ___ _ _ _ _ _ _ _ _ VELLPATH DATA (82 stations) -~ = interpolated/extrapolated station MD Inclination Azimuth TVD Vert Sect : North ' East Grid East Grid North DLS ; Build Rate Turn Rate ~feet] ~°] ; [°] ~feetJ ' [feetJ ; [feet] ~feet] ~us survey feet] ', [us survey feetj ;; [°/100ft] "; [°/100ft] ~°/100ft) _ _ _ - __ . __ _ . _ ---- ,_ _ . -- -- .__._ 3700.00-~; 0.000; 0.000 3543.04 ; 890.41 ;-8.86 -890.36 274049.31 ; 2362152.95 ; 0.00 ; 0.00' 0.00 _ _ _ _ _ _ _ _ ----- - _. _ _ _ _ - 3800.00~- O.OOOi 0.000 3643.04 890.41 =8.86 !-890.36 ; 274049.31 ' 2362152.95 "i 0.00 ; 0.00 0.00 __ _ _; ---- 3900.00~ 0.000; 0.000; 3743.04 890.41 ;-8.86 ;-890.36 ; 27404931 2362152.95 ~ 0 00 j N. 0.00; 0.00 4000.00~- 0 000~ 0 000 3843.04 890 41 8 86 890 36 j 274049 31 E 2362152 95 ~ 0 00 ~ 0 00 0 00 4roo.oo~ ' ~~~j.. ~~'~~ ~9a~3.o4 $~~~ta_ -~~~f_ s~t~:~~I~ :~~~~~~~a-~~+~~~~~'~~~~N:~:~~ :...~~~~ _~.~«!~;! ~ .. , _ .,,_..._ .. ., ., . _ _ _.... _. .... 6 274049.31 2362152.95 0 00 0.00 0 00 4200 00~ 0 000, 0.000, 4043.04 890 41 a 8 86 : 890 36 , 274049 31 ~ 2362152.95 ~~ 0 00 ! 0.00~ 0 00 1 8 86 ~ ' I 0 4400.00~- 0 000,~ 0.000 424~3.04 890.41 ~ 8.86 ~ 890 3 - -- ! __ , 890.36 l 274049 31 2362152 95 1 0 00 ~ 0.00 0 0 4500.OOt 0 000~ 0 000 4343 04 890 41 8 86 890.36 274049 31 2362152 95 0 00 0 00 0 00 ~6oo.oa~ ~~~ ~~+~ ~3 ~~a ~~~~~~ ~~ ~~4,3~~~~_. ~~~~ ~~ i~~~~~x~~ j`.:. ~_.~~ ~ ~ ~~~~-''.~'~ ~ .~ , ,_ ~ ~ _~_ . .~ _ _w____._ ~ _ .... -. _: _ ._ . t . _~._ _ _ ~_ ~ __ .._. 4800.00 ; 0.000 0.000 4643.04 890.41 Y 8.86 ~-89036 ; 274049.31 ' 2362152 95 ' 0 00 ~ 0.00, 0.00 _~' 2 95 : 0 00 # 0.00 0.00 _ _ -__t_ _ . _~.._ r... _ _. 4900.OOt~ 0.000~ 0.000 4743.04 ~890.41 ', 8.86 ! 890.3 ~ ~ ~ 6~ 274049.31 ` 2362152.95 0 00 ; 0.00. 0.00 __ _ , ,.. u -- _ _ ._. 5000.00~-~ 0 000; 0.000 4843.04 890.41 ;-8.86 '; -89036 ~ 274049.31 2362152.95 0.00 ; 0.00; 0.00 ~~~~ ~~ _ . ~:v~v ~w 4~a~~.~a4 - ~~~~~ : ~~~ ~ ~ ~+~~d~~~ ~ _ , ~~~a ~µ ~.~~~is~ s~~ ~_~ ~~~ .. =+~.4~) ~. ~ ~; a.oo 5200.00 j~' 0.000; 0.000 5043.04 890.41 ;-8.86 :' -890.36 ; 27404931 : 2362152.95 ' 0.00 ; 0.00! 0.00 0 0~; 0 000 0.000 5143.04 890 41 ' 8 86 890.36 ~ 274049 31 2362152 95 ' 0 00 „ m 0~ 00 0.00 5400. 00 0 000 0.000 5243.04 890 41 ~ 8 86 890.36 ~ 274049 31 2362152 95 ; 0 00 , 00; 0.00 ~. ... ..~ _ . _... 5500.00 j~ 0 000 0 000 5343.04 890 41 8 86 89036 27404931 2362152 95 3 0 00 ( 0 OOs 0 00 $6i~.00j' . ~~,'_; ~~~!~} ~` ~'~~.0'~~~ S~0 4I;, ~~ ~F ~#8~0.3"fi ~~l4~3~~ ' ~~~`~"`~r~"s' :~ fi~~-~'~~~~y ~ ~ ~~i ~"7~~?~171 - - - - _ _~ _ , _ _- - ~ _ ._~_~_ ._ .~ __- . __.: 5700.OOt 0.000 0.000 5543.04 ` 890.41 -8.86 [-890.36 274049.31 2362152.95 0 00 ;V 0.00, 0.00 _. _ ~ . _ . --- . ._ ~ _ .._ _ - - 5800.00~- 0.000' 0.000' S643.04 890.41 8 86 ;-890.36 , 274049.31 2362152.95 ' 0.00 ;~ 0.00 0.00 _. ___ _ _ _ - ._. 5900.OOt, 0.000- 0.000, 5743.04 890.41 _ 8.86 ;-890.36 27404931 2362152.95 0 00 { 0.00; 0.00 _ __.~. . 6000.OOt 0.000 0.000' S843.04 890.41 ; 8.86 ;-890.36 274049.31 2362152.95 0.00 0.00; 0.00 61~OO.~iO~'~ ; ~~'. ~~ 594304 ~~~,~ ~~h: -890.3b ,`~~~~'`-~~s~15295 i .~ . Q t~~t ~ F . ~ ~_~ ; U.~~ ~ _ : _~ _..__~~.._ 6200.00 j~; 0.000 O.OOQ 6043.04 890.41 -8.86 '-89036 274049.31 . 2362152.95 0.00 0.00' 0.00 _. _ _. _ _ 6300.00~, 0.000 0.000 6143.04 890.41 ;-8.86 -890.36 ~ 274049.31 2362152.95 0.00 . 0.00 0.00 . . ., _ . ~ _ ».. ,~ _. , . .. 6400.00 ~ 0.000~ OA ~ - ~ ~ ~~~ ~~ ~ t 00 6243.04 890.41 ~ 8.86 ~~~ 890.36 ~ 2'74049.31 2362152.95 0.00 ' 0.00. 0.00 _. _. . _ __ - 6500.00~-' 0.000 0.000' 6343.04 890.41 ', -8.86 -890.36 274049.31 2362152.95 0.00 ~ 0.00 0.00 6600.04~- 4.0~ 1}.OOU 6443.04 ~9~.~1 ` -8.86 ` -89U.3~r' , ~'~~~~~~' ~362152.95 ~~ ~3.''~~~._ O.OC1 . _ __._ 6700.00~- 0.000 0.000 6543.04 890.41 -8.86 -890.36 274049.31 2362152.95 ' 0.00 : 0.00 0.00 6800.00 j- 0.000 0.000 6643.04 890.41 `-8.86 -890.36 274049.31 2362152.95 0.00 ` 0.00. 0.00 _ _ _ _ __ 6900.00 f 0.000 0.000 6743.04 890.41 '-8.86 -890.36 ~ 274044.31 2362152.95 0.00 0.00" 0.00 _ _ _ _ _ _ _ --- _ _ _ 7000.00 f 0.000 0.000 6843.04 890.41 -8.86 -890.36 ' 274049.31 2362152.95 0.00 ' 0.00` 0.00 7100.00~ ~ 0.000 6943.04 89U.41 -8.8~i -$90.36 - _ ~f ~ 27~~~= ;2362152.95 _t~~ °- ~ -= 0.00 _ __ _ _ -_ 7200.00 fi 0.000 0.000 7043.04 890.41 -8.86 -890.36 274049.31 ' 2362152.95 0.00 0.00 0.00 _._ _ . 7300.00 f 0.000; 0.000 7143.04 890.41 '-8.86 -890.36 274049.31 2362152.95 0.00 ' 0.00 0.00 7400.00 j~ 0.000. 0.000 7243.04 890.41 -8.86 '-890.36 274049.31 2362152.95 ` 0.00 0.00 0.00 m _ _. . 7500.OOt 0.000' 0.000 7343.04 890.41 -8.86 -890.36 274049.31 2362152.95 0.00 0.00 O.Oa ~ i ,M~iRAT'Hiyl~ Planned Wellpath Report KBU34-6 Version 1 Page 4 of 4 ~~~t~ B/~KER ~Vt~NE~ IN'TEt~ ~OLE & CASING SECTIONS Ref Wellbore: KBU34-6 Ref Wellpath: KBU34-6 Version 1 _.m ~ _ .M..~_~ _a_.~ue tring/Diameter M.. w_~ ~ Start MD ~ _ . r . __ .~ _ ~, ..,e _ End MD ~ Interval ~ Start TVD ~ _,.~._ _.~~~~. ..~,~ . End TVD ~ Start N/S ~~Start E/W ~ End N/S ~ End E/W ~ [feet] [feet] ~ [feet] ~ [feet] ; [feet] [feet) + [feet] ~ [feet] ~ [feet] 3 375m Casing Surface 0 00 1577 14 j 1577 14 ~ 0 00 ~ 1500 00 ~ 0 00 ~ 0 00 ~ 4 07 ~ 408 74 .625m Casmg Intermed~ate 0 00 ~ 543 3 96; 5433 96 ~ 0 00 ~ 5277 00 ~ 0 00 ~ 0 00 ~ 8 86 ~ 890 36 x,v.. aa._ ~.w~,.~..eer Sin Casing Production 0 OOi~ 7738.96~~ 7738.96~ 0.00~ 7582.00~ 0.00~ 0.00~ -8.86~ -890.36 ARGETS ame . ~~ , ~~...:w.a ......_~ ....._.~ ww..:~:w ~ MD TVD North ~ East Grid East ~ Gr~d North ;~ Latitude ; ,: _~._. Long~tude ~ Shape .~,.~. ~_~,~~~ ,. ,, H ~ [feet] ' [feet] [feet] ~ [feet] ~ [us survey feet] j [ us survey feet] , [°] [°] ~ . . .... _. ,.~~ .... ~ + 5297.00 _ 8 791 889 67 ~ _ 274050 00 ~ .. 2362153.00 ~ 60 27 35 479N' ~. 151 15 06 344W ~ circle~ :U34-6 Middle Beluga _ . . . i . ~. ~ ~ ..~ . _ ~. , .. , ~ ... ....~r . . ,. ..~. . .~. _ . . .. ~.. ~ ,.. . ., ._.. .. . _. P ~. ~, u, ~ _ ~._~_~e s....~ . ~.. ~__~ .U34-6 Lower Beluga _ _ _~ ., ~ ~ 6042.00 ~ ~ ~- - ~ _ 8 79 ~ 889 67 ~ . - -~~ ~ ~--~ ~- ~ ~ ~ n 274050 00 ~ -- -~ - ~ ~-~~ - - = - . _ . . :. 2362153 00 ~ 60 27 35 479N ~ ~ -a- ~~ a~ . 151 15 06.344W ~ circle ,. , _~_ ~ ~ .~,~ ~, _~u . _ «_ ~~ ~ ; 7182 00 ' 8 79 ~ 889 67 ~ ,~v 274050 00 ° ~ 2362153 00 F 60 27 35 479N r ~ 151 15 06 344W ~ oircle .U34-6 Tyonek ~.~.. ~ . _.. ~i .. .,~v._.~ _ ~~. _. . .._.r , ...,_.. ~. ....,,~ _..~~.. ..~...,._. ~. .._e., ~ . _._ ..~.. . __w. ..._~. .~._N. ~ w.._ a.~~_. .. .~ ..~ . . . ,~ . .~ . . ~ a ~~ 7582.00 .~_~ ...~. .. 8.79 ~ 889.67 ~ _ ~_~ _... _. 274050.00 ` ~. 2362153.00 ` 60 27 35 479N~ .. 151 15 06344W ~ circle U34-6 TD [tVEY PROGRAM Ref Wellborec KBU34-6 Ref Wellpath: KBU34-6 Version 1 ~~.~ , . . ,.. ~_ . ~ .~ ~ .. ..~,..~: ~, _ , ~,~.~..._; Start MD : End MD ~ Positional Uncertainty Model ; Log Name/Comment ; ~Wellbore [feet] [feet] _ ; . ... .. ... m.~ ... . _,._. ~ , _ . :. .. . ....... ~ ~ :.,.. 0.00':' 1520.OO~NaviTrak (Standard) ~ ~ ~KBU34-6 . . . _ : _ w._.. _ .. ~ . _~ ~ _.__.~._ _ _ _ ~_-- 1520.00; 7738.96NaviTrak (Standard) < ~KBU34-6 _. _ .. , _ ~ ._. .. ~ _~ . _ _ . .~._.~ . .~ ~__ _ _ __~ - WELLPATH DATA (82 stations) ~ interpolated/extrapolated stahon ~ m,. . ,.,__ ~. .._.. „_~v~.. . x_..... ~ _ . MD ~ Inclmat-on , Azimuth TVD ; Vert Sect j North East Grid East ~ Grid North ; DLS Build Rate , Turn Rate ~ ~4 [feet],, ,y [°] 4 ~2~ [°] [feet] k [feet] ~ [feet]4 y F [feet] _rt, [us survey feet]v ~ [us survey feet] ~ [°/100ft] ,y [°/100tt] ~ [°/100ft] ; 7700.OOt 0 OOOg 0 000~ 7543.04 j 890.41 j 8 86 ; 89036 ' 274049.31 ~ 2362152.95 j 0 00 0.00 Y 0.00~ _ ___ __ _ ._ ~ _ _ __: $ 7738.46 ; O.OOQ~ 269.430t 7582.00 ; 890.41 ~-8.86 ;-890.36 .- 27404931 ; 2362152.95 ~ 0.00 € 0.009 0.00; ~ , LPATH DATA (6 stations) MD ~ feet] IncLnat~on ~ r [°] Azimuth ~ [~] ~ -- ~ TVD [feet] ~ ~.__ ,.~ Vert Sect J [feet] ~ ~~~ North ~ [feet] East (feetl g w.z.~ .,_~~a~_ _~ DLS ~Design I°/IOOft] ~Comments 0 00 3 0 000; 269 430. u 0.00 ~ ~_. _, 0.00 ; ~ 0.00 ; ~. ,.n_ . 0.00 : . _.~we~, ,. ~ ~ ~-_ ___~ _._.K ~.....__~ W_ 0.00 ~Tie On 200 00 ; ~ . 0 000 269 430; 200 OO i 0 00 ` 0 00 ` 0 00 ° 0 00'KOP 1033 33 ~ .. . . _ 25 000 ... 269 430 _ m.. _~. 1007 14 ' ..... _,. 178 94 _M,.,.. _.. . 1 78 F ~ _.,~.w r~ 178.93 ; ~. _ ~... ~ _.w.~. ~..m,. ~ 3 00 sEnd of Build _... _ -- . w _-o~ __ ~dn__. 1870 00 ` 25 000 269 430 1765 42 j 532 53 5 30 532 50 0 00 9Begin Drop ~~ = ~~ ~~~ ~ '~ ~~~~~~ ~~ x~ ~- ,~~~~~~ ~ ~ LL ~~ ~ ~~~~ ~ ~~~~~'~~ ~ 7738.96 i 0.000'_ 269.430? 7582 00~~; 890.41 ~ -8.86 ~~ ~ 890.36 . ~ ~ 0.00 <TD ~ ~~ . ~ ~~ ~~~ _ . ~a . e.. _ . . w . . _ _ . _~ ~r. ~_ . _ _. .. . _ ~_. . . , .__ m._ >AOLE & CASING SECTIONS Ref Wellbore: KBU34-6 Ref Wellpath: KBU34-6 Version 1 >String/Diameter -- - ---__~_~ . ~v, u _ .. ~ _~._ .._.. ~ Start MD ~ End MD ~ Interval . Start TVD , End TVD ~ Start N/S ~ Start E/W ~ End N/S . ..___ _~ ~___. End E/W ; ~__ _ .__. [feet] ~ [feet] ° [feet] ~ [feet] ~ [feet] [feet] ~ [feet] [feet] € [feet] ;13.375in Casing Surface ~. . ~. _ ~ 0.00' _. 1577.14. ._.._ ... ~ 1577.14 ~ _ _~_. ... .w. 0.00 E 1500.00 ° _ . . . _ 0.00' ~__ ~ , 0.00; ~ e. _ -4.07: -408.74 ;9.625in Casin Intermediate g . ._ s ._, 0.00~ . _ : 5433.96 _... ,~ _ 5433 96~ ~ ,.. ~ . ___._. 0.00° 5277.00; .. ~ . ~ 0.00, e ,r_ ;v 0.00~ _ ..._,.._ . -8.86, _ ~ _._ _. _w... -890.36 , . i3.5in Casing Production _. _ 0.00= . 7738.96: __ 7738.96~ _ ~.. ;._ 0.00~ 7582.00 . ._._~_ 0.00=~ 0.00~ _. . -8.86~ ....... u..~, -890.36 ~~~ Wellpath Design Summary Report ~~~(~~ Wellpath: KBU34-6 Version 1 ~V~irNE~ ~~~~~~~H Page 1 of 2 INTE(~ ~ ~ ;MARATHt~H Wellpath Design Summary Report Wellpath: KBU34-6 Version 1 Page 2 of 2 ~~~ ~AK~R ~IY~NES ~~T~r~ ~ ; 6042 00 ~ 8.79; 889 67; 274050.00 ~ 2362153 001 60 27 35.479N~ 151 15 06 344W { circle Lower Beluga ~... .. ....~.. . .,,, ..~ ,..w ~. . . _.. . . ,_... „ .. n.. K_..m ..... .... ...._ . . u ~~ __... ~ ._._.~~M .~,_. .~~. _.~.~ Tyonek a 7182.00 8.791-889.67 ~ 274050.001 y W y 2362153.00 ~ 60 27 35 479N~ 151 15 06 344W; circle ~ ..._~,.. ,~ ~. ~~ .. ..~~ ~~ _ . a, . ,M,~.v wa.a TD ~ 7582.00' 8 79~ -889.67~ 274050 00? 2362153 00~ 60 27 35 479N3 151 15 06344W ~ circle z..~..e._. _....,_, ,... .a ~ .. . ~.~~ ._ _ ~.....~~ ~~~..~ ~,.~~v..~. _~~ ~,~~, , s~........~. _ _ ~_ _ ~. ._... ~...~ ,... ... .._ _. ~. _M _~.__ ... , ~. ~_,_._ _... ~URVEY PROGRAM Ref Wellbore KBU34 6 Ref Wellpath: KBU34-6 Versian 1 ~ fi.~~ ~_ ~ Start MD End MD 9 ~ Positional Uncertainty Model ~~ ~ _~ Log Name/Comment f~~~ ~~~~~~~~Wellbore [feet] [feet] ~ ~ ' .- . ~ ,~ .~.~ _. ~~ z_„~. y~ ~_ti.~ ~.~._. __«„u~.. ~.._.e~.....~~~~~.,-_,~.~v~,._. _.,- ~~_.~,-.~~_.,...~ 0 00~ 1520 OONaviTrak (Standard) ~KBU34 6 .. .. ~ ~a~,_~. ~ ~ ~ _ _ x ~w . _._.__ v_~~ ~~ u~~ , a ~.~.~ ~~ ~~~. ~1520 00~'~ 7738.96aNaviTrak (Standard) ~ ~~~ ~ ~ ~~~~~~ ~ ~~ ~ ~ ~KRTT~4-F "~~ ~ ~~"' _ _._. _.___ .. _...,. . ._ ._ ... ~__ .~...nr_ ,. __ , _ ... .._.__ _,_..:._.. ._..w... __. _.._..... .. _w._....... .__, TARGETS ~ » _ T . ..._. ~ ,. a.~ ~. ~ ~~,.~ ~.._. . , n..~. .. r w~. u , w..z_, . __ .~~ . .,._. ~ , . ~ , ~~~ . ~~ .=~2 ~" ~. ~.. ~ . , _~.a ~ ~ Name ; MD TVD North ~ East Gnd East ~ Grid North d Latitude ~Long-tude Shapey~ t ; [feet] [feet] , [feet] ~ [feet] [us survey feet] ~ [us survey feet] ~ (°) [°] ~ _~ .~ ,.._ _~... .~_ - ~ ,K.~~ ~ n ~~ ~- ~ ~ 2 _ ~ _ _~ ' ~ 7 5297.00, 8 79 ~ 889 67 274050.00 ~ 2362153.00 ~ 60 27 35 479N~ 151 15 06 344W ~ circle ~ ;KU34-6 Middle Beluga _, .~ , a. ~. _. _.~ ~ ,_~ . a~ ,. . , a ~ ~ Fb ..~ ~ ~ ,~. . , ._~_ ~ ~~ s _ n ~ . ~ ~ . e~ ~.,~,. . .,a.. a.__ ~. __ ,~ M MARATHOM , ,~~~ - ,oo ~~ -1200 e -1150 -1100 -1050 -1000 MARATHON Oil Company Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: slot# KBU34-6 Field: Kenai Gas Field Well: KBU34-6 Facilit : Pad 41-7 Wellbore: KBU34-6 Easting (ft) O C. l„ ~ A N G J p p ~ ~ O KBU34-6 ~ ' 50 Z 0 - S O ~. vs -50 -100 ~~ as 30 15 ~ G O ~ 3 0 ~' ~ ~ -75 -30 -45 A O V N A O ~ r A x O O ~ ~ -300 ~~~~ BAKER NYGNES INTEQ Easting (ft) ~,h~ 3on MARATNON • • MARATHON Oil Company Location: Cook Inlet, Alaska (Kenai Penninsula) SIoC slo[# KBU34-6 Field: Kenai Gas Field F i i : ad 41-7 Well: KBU34-6 Wellbore: KB -6 m, iRr~ , ~sow~, u Ni (Ri) nn Re~erenca ~T rctlRil~~ ~ ne(FnrJllly'PaEat-i)~o Traveling Cylinder: Map North ~~ ~i BAKER MY6NES INTEQ • ! NIARATHt?N Clearance Report Closest Approach KBU34-6 Version 1 Page 1 of 51 ~r~~ BAKEi~ ~uc~N~s INTE(~ POSITIONAL UNCERTAINTY CALCULATION SETTINGS HOLE & CASING SECTIONS Ref Wellbore: KBU34-6 Ref Wellpath: KBU34-6 Version 1 String/Diameter ~ Start MD ` End MD Interval ~ Start TVD ~ End TVD Start N/S ` Start E/W ! End N/S ~ End E/W ~ , -- ~- [feet] - [feet] ~ _ , ~ [feet] ;, [feet] ; ~ [feet] ~ [feet] ` [feet] ; [feet] a : [feetj 13.375in Casin g Surface ,u . ~.. 0.00 . 157714 ~ 1577.14 0.00: . . 1500.00 ,._ 0.00• _~ ~ ~ ._,..~ ,. . . ~. 0.00 -4.07; - ,,,. .~ -408.74 ._ 9.625in Casing Intermediate - = . .. ~ ~ 0.00; _ ~_ ~.~ ; 5433.96: .__. __ __,~_ . 5433.96; 0.00; ~ . ,.~~ ......~. 5277.00. _ . ~ . O.OOr ~_ ~..~ _.. 0.00~ 8.86; _.., , 89036 . 3.Sin Casing Production ~ ~ 0.00, ~ 7738.96: -- . . 7738 96' 0.00~ . . 7582.00~ _:. 0.00 _ . ;. . 0.00: -8.86; ~. _. -89036 ~ ~ ~Y1~~tATl~~-~1 Clearance Report Closest Approach KBU34-6 Version 1 Page 2 of 51 SURVEY PROGRAM Ref Wellbore: KBU34-6 Ref Wetlpath: KBU34-6 Version 1 v ~ , . ~ ~_,~_ u . ~.~ . _~ ~ ~ ~ s u = __ - . . ~. ~ ~ v _~ ~ Start MD ~ End NID ; Positional Uncertainty Model ~~ Log Name/Comment [feetl ; Ifeet] y ~ ~.,. _ -.,..~ . x . __......... ..u..~....-e ~ .. „ ...,. .,.... . . _,~ . .,...i._ , _., ~.. . .._...., g. ...,,.. . , . , ~ . ... .,, ....w , . .,.. ., „e -... 0 004 1520.OO;NaviTrak (Standard) ~ 1520.00~ 7738.96fI~TaviTrak (Standardl~~ ~ ~ ~~~~~~ ~ ~ ~ ~ ~~~~ ~ ~ ~~ ~ ~~ ~ ~ ~~ ~ c Il'~1~TEQ Wellbore • MARATHON Clearance Report Closest Approach KBU34-6 Version 1 Page 3 of 51 EtATHON Oil Company ',Slot .~~_____~ __~. k Inlet, Alaska (Kenai Penninsula) Well _«~_ ai Gas Field ',Wellbore --._ . _ __._~_~ ----- 41-7 _ _ --- KBU34-6 ~~~~ ~~KE~ ~~~~~~ _ _ __ -_ -- _ IIV~TEQ CALCULATION RANGE & CUTOFF ~ _ __ - __ _ .,~ From: 0.00 MD To: 7738.96 MD GC Cutoff: 200.00 feet OFFSET WELL CLEARANCE SUMMARY (47 Offset Wellpaths selected) ; Offset Offset Offset Offset Offset Ref Min C-C Diverging Ref MD of Min C-C Min GC ACR ~ Facility Slot Well Wellbore Wellpath MD Clear Dist from MD Min C-C Ell Sep Ell Sep Status i; [feet] [feet] [feet] Ell Sep [feet] Dvrg from [feet] [feet] _ ; Pad 14- . Slot #KBU ~ ~ i~~ i~ ` ~ T 6 23-~ i KBU 23-7 ~ KBU 23-7 ; MWD <0-9320> ; 0.00 j 2929.16 ! 0.00 { 0.00 , 2627.80 ~ 0.00 ; PAS S~ ~ _ _~ . ~ _ _ ~ „ _ KBU22-6 ~ ~MWD <0-8855> ~ ~ 0.00 ~ 2776.66 ~ _ ,.. _ ... ° . __ ~_ .~ Pad 14 .Slot , `~gU22_6 , 0 00 ; 0.00 ~ 2475.03 ~ 0 00 ~PASS ~ 6 °_#KBU22-6 ~ _ ; ~ : _ __ _ , _ ~_. _ ._ _- __- ~_ _ -_.. °- _. , _--- - __._ _ F Pad 14- Slot# €ggUl l-7 ~KBU11-7 ~MWD <0-7900> 0.00 : 2976 48 ; 0.00 0.00 2674.85 0 00 ~PASS ~ 6 =KBU11-7 _ -__ _ ~ _ ' ' ~ _ -- ; -- ~~ ~ ' _ , . _____ __ _ _ ~ --- - ~ -- ~- = g Pad 14- ' Slot# ~U24-6 KBU24-6 MWD <0-7500> 0.00 ! 2773.88 0.00 0.00 2472.25 ' 0.00 F PASS ~ 6 KBU24-6 Pad l4- ~i~at~ KB~~'~4- I K1~U2F~-6t~~ :vlVu'D~3464-7~:~t~~- O.OL~ 2?73.~~ ' 4~.~~t:~ ~.OCI ~~7~,"~:~ 4~.~~d~" ~~~Yk b i~3t1'?4-6 6Rd K Pad 14- Slot# KU21- ;KU21-~X ,KU21-7X MWD <193-5032> 0.00:; 2715.49 0.00» 0.00 2414.14: 0.00,PASS ° 6 ? 7X ; _ _ . . . _ ;. _, _ _ . ; ` __ v _ ` ~ . ~_ _ __ . _. _ _ _ i ~~ Pad 14- ', slot #KBU KBU23X- ' ~ 6 '23X-6 ~( `~U23X-6 GMS<0-6950> 0.00j 2824.13 0.00' 0.00 2523.34' 000?PASS ~ ~ j ._. _ _~ - _ _ __ : _, _~ _ ~ _ _ _ ~ ~ Pad14- ~slot#KBU '.~U31-7 ?KBU31-7 GMS<0-7375> ~ 0.00` 2735.39, 0.00.~~ 0.00 2434.59 000'PASS + 6 ;31-7 a ? _. .,.. . .. _ _ _.. , _ . ~ _ _ _. ._ .. . _ _ _ ~ Pad 14- ~slot #KBU 1 ; , _. 6 '31_~ KBU31-7 `KBU31-7Rd 'MWD<5814-7575> ; 0.00~ 2735.39 0.00 0.00 2434.59 O.OO~PASS ° bad l4- slot #ICDU 1 KDti-1 KDU-1 ~ISS <0-9895~ 0.00 3119.b9 O.fl4 O.QU 2$18.33 O.Ot~ P~S~~' Pad 14- ,slot #I{DU 8!KU14X-6 'KU14X-6 GMS <0-9500>, MSS 0.00. 2895.37 0.00 0.00 2594.01 0.00 PASS ~ 6 <9776-10225> _ ~ __ _ _ _ _ .. _ _ ~ . _ , __ ~__ ~ Pad 14- slot #KU 13- KU13-6 KU13-6 MSS <0-5500> 0.00 275536 0.00 0.00 2454.00 0.00 -PASS :; 6 6 - __ . Pad 14- slot #KU 14- . KU14-6 KU14-6 Totco Incl. Surveys Q00- 0.00 3067.80 0.00 0.00 2766.44 0.00 -PASS ~ 6 :6 15047'> Pad 14- . slot #KU 21- , KU21-7 ' KU21-7 MSS<0-4453> i 0.00 ~ 3022,84 0.00 0.00 2721.48 0.00 . PASS ` 6 7 i'ad 1~- 51ot #KU 31- i- ~~ 6 7 1CU 31-7 ', KU 31-7 '~IWD <0-S79D} 0.~0 2701.46 4~.UU. 0.0~ ~4t?t3.10 (}~€}, P~~~; ,__ Pad 14- slot #KU 43- KU43-12 KU43-12 MSS <0-6530> 0.00 3052.63 0.00 0.00 2751.84 O.OO PASS ' 6 `12 Pad 41- ; Slot KBU33- ~U33-6X MWD <0-8405> 200.00 143.72 200.00 207.50 130.57' 207.50 ~ PASS :. 7 i #KBU33-6X ' 6X Pad41- Slot ggU41-6 KBU41-6 MWD<0-9733> - 672.87 76.74 672.87 676.83 62.07 676.83:PASS ' 7 #KBU41-6 - _ - _ _ _-- - _ _ _ _ __ Pad 41- Slot ~U42-6 KBU42-6 MWD <0-8624> 215.63 188.16 215.63 222.94 174.94 222.94. PASS ' 7 #KBU42-6 i = ; • ~ • Paci~}1- Slc~t KBU~}3- KBU43-7X 1~I~L)~=C1-~(~i0~ 450.50 102.~3 ~~C~.SQ 450.50 88.'~2 43C~.~~ PA.S~ ' 7 ~:KI~I:~:i-7~ 7X . - - Pad 41 KTU2~- ' ' ~~ ~ ~ slot #24-6 ~ 6H ~ KTU24-6H ~ MWD <0-10960> ~ 0 00 ~ 216 09 ; 0.00 ~ 0.00 ~ 202 98 ~ 0 00 ~ PASS - ~-. °__ __~ -,_ __~___._._ ~ a--~.~._, ~__...,_.. ._..,.__ r .. ~._v._, ~_._~~. ~-~__~~~~~ . _.~.__, ~_s_Y ~_~ _.~ .~.._.w....v~ ~Pad 41- KTU24- KTU24-6H ~ ~slot #24-6 6~ ~ ~(pilot) ~~KN <8820-9010> ( 0.00 ~ 216.09 { 0.00 ~ 0.00 ~ 202.98 ~ 0.00;PASS ,_.. ~._i _~,.~~~ ~ _~~_ _ .__ .~_.~___.__.~_a~ _. _-_--_ __ _~ _.~.__~.~ ~~~~._.. .. _ __. _ _~__._.._.._ ~ _~..__~~ ~ Pad 41- j ~6HU24 ~~ 24-6H ~ ~ 0 00 ~ 216 09 ~ 0 00 ~ 0.00 I 202.98 0 00 ~PASS ~slot #24-6 ~ MWD <8844 8940> __ . W~~ ~,..e._. .~~~. ~_.. _ v.r. ._ ..__._ . , ., ~~ .A~. ..~.. w~.. __ ~ __.~.,~ ~ , , . .. m ~ ~~ _..__~_ _..._..__ ~ , _.... a~._. _.,.~ ~ ~.~n.__. ~~~Pad 41- ~ ~ ,slot #32-7 ~KTU32-7 ~KTU32-7 MWD <0-8864> ~ 0.00 j 26330 ~ 0.00 ~ 0.00 j 250.18 i 0.00?PASS jPad 41- ?slot ~~BUl l ~KgUI l 8X ~MWD <0 7659> ~ 0 00 234 73 ~ 0 00 0 00 221 61 ~ 0 009PASS ~ ~7 rt ~#KBUlI-8X ~8X ~. _.,.~..._._._.._ __.~ _. _.._~._. __.___.. ___. ___~.._ ~ _..M_~ __~... ._~~ __.._._ ___ _ _. __ .___ _ ._ - Pad 41 i slot ~NaviTrak <212-1890 ><2014 ~ ~ ~ A~ ~ ~ ~m ~~ rv m KBU12-5 KBU12-5 778 i l 74.51 778.11 779.43 59.20 779.43 PASS ! 7 ~#KBU12-5 6496'x6607 ~~~> ~ __ . _ ~ ~__--- ---a --- ---- --_ __ ~I- _~_~_ _-- __ I -___~ ___ _ ___.I____ _ _.~_ ______ ti ~___ ,~_~_ ~ __.. ._.. __ Pad 41- ~ slot GMS <0-7902>, MWD ~ ( ~ ~ ` ~ ' ~7 ~#KBU33-6 ~U33-6 KBU33-6 ~~~902-8110> j 0.00 ~ 173.52 ~ 0.00 I 0.00 ~ 160.40 ~ 0.00'PASS __ _ ___~. _ _ -- --- 1 ~__ __._ E _.- _ ~ _ _ ~ ~_ ~_ .____ _.__~ _~._ -.~- ~ ---- - -----~~---- ~-~- ~-~ -~----~ - ~-- ~--- Pad 41- :slot ,~U41 ~j{gU41-7X ~MWD <0-5300> ~ 0.00' 486.87 ~` 0.00' 0.00'~ 473 75' 0 00 ~PASS ~ ~7 ~~~U~i-7X 7Y ~ ~ ~ _~ 41- *~it3t KBU~2-7 RBL~~-7 1,1t~~~~-cC1-757(7> 225.y) :~?.h6 ?2~.~~3; Z3~.9~J 1<«$,=#£) 225,~9 FAS~ ' -.~~.~~;~2-? ~ • ~ 1YIARATHOM ~r MARATHON Oil Cc Cook Inlet, Alaska (I _ -- -- Kenai Gas Field ---- -_ Pad 41 7 Clearance Report Closest Approach KBU34-6 Version 1 Page 4 of 51 Penninsula) CALCULATION RANGE & CUTOFF 0.00 MD --- . ,_.._.._..~.._.~_~.__~_.__ 7738.96 MD KBU34-6 ~~~~ BAKER Huc~N~s INTEQ C-C Cutoff: 200.00 feet OFFSET WELL CLEARANCE SUMMARY (47 Offset Wellpaths selected) Offset Offset Offset Offset Offset Ref Min GC Diverging Ref MD of Min GC Min GC ACR ~ Facility Slot Well Wellbore Wellpath MD Clear Dist from MD Min GC Ell Sep Ell Sep Status ~ [feet] [feet] (feet] EIl Sep [feet] Dvrg from ~ [feet] [feet] Pad 41- ~slot #KBU44- ! ~ > >~ f KBU 44-6 KBU 44-6 MWD <0-74 _ ~ _, .__ ~. _ ~ ~ 6 ~ @ 40> 0.00 ~ 307 99 ~ 0.00 ~ 0.00 ~ 294 88 ~ 0 00 °PASS ~ a i j . _ s.v m ....~ ad 41- , v ~ .~_~~_ _ ~ ~ , ~ P ~ ~ _.~ _. ,~_. _ . _... MSS<0-10522_,. , ~. . ° _ ~ . .. ~ _.__ ~ slot #KDU 2~KDU#2 KDU#2 > ; 0.00 ? 539.66 ~ 0 00 i 0.00 ~ 526.54 g 0.00 ~PASS ~ ~ < ~~ ; y ... ' ...... ..... ._______ .' . : . __..... . ,. .... ..___--__ r... '. ._..__' _ 4.._.... ~ .. i s E ' 3 ~ .,.~.. Pad 41- ;,slot #KDU 4 ~KDU4 ` ~ ~ ~ ~ ~ ~ ' ~ ~ ~ KDU4 GMS <0-5549> 0.00 ~ 435.52 0.00' 0.00 422.40: 0.00',PASS ~ , , -- _ ;_ _; _ _ :,_ _ - _ ___ _- _ __ __ __ _ ._- - Pad41- ` ~ ! ~ 'slot #KDU 4'KDU4Rd KDU4Rd 'MSS<4320-10810> ~ 0.00 435.52' 0.00 0.00 ~ 422.40 0.00 PASS ~ ~aci ~l , sic~i#KTU13 t=l~l3-~ ,, KLI13-5 ': U.00 3?9.~1 " D:OtI tl.t)t.~ 31~.~? ~.00' P~1S~ ' ~ 5 ~ Pad 41- ~Ht #KTU32 ~HU32- ~ KTU32-7H ; O.OO i 363.79 ,~ 0.00 : 0.00 , 350.68 ~ 0.00'~ PASS ~ ~ ~.. . ~„_ , . ...~..., ~ . .~,. , . . Y i .~., a ... .....~v... ~~ __ I ~ 5 .. _ ,.... ... P .. ....= a ,. ..,... . -. _,,,. . ~ Pad 41 ~slot #KTiJ43- KTU43- , KTU43-6X : ~ 0.00 ~ 389.251 0.00 ~ 0.00 ~ 376.14 ~ 0.00 ~~~ PASS ~ 7 E6X ;6X ~ ~ ~ Pad 41- ; slot #KTU43- ? KTU43- ~ KTU43- ', MWD ~~~00-9470> 0.00 ; 389.25 0.00 0.00 ; 376.51 ; 0.00 ; PASS ' 7 6X ~ 6X ~ 6XRD2 ~ Pad 41- ? s(ot #KTU43- KTU43- KTU43- i~D <7670-9464> 0.00 389.25 0.00 0.00 376.14' 0.00 ; PASS n 7 ;6X ~6X '6XRd ~ ~ . . ~~, . ~ __ _ . ±.. _ ._ _ Pad 41 ' _._~_ __ Yslot #KU 24-5 KU24-5 KU24 ~ ` -5 ,: GMS <0-5900> . _ .: ~~ ~ ., _ ( _ r 564 00 28 I 0 .:.. . ~ .. _ ~ .~,....~.. ._ . .. ,, . ~ ~ . 00 ; 551 0 00 ~ 0 72 ~..:_ , ~ 6 .. 0 00 PASS ~ ~ . _ . , . . . . j Pad 41- 7 ; slot #KU 24-5 KU24-5 KU24-SRd MWD<3470-4816> 0.00 564.28 0.00 0.00 551.72 0.00 `PASS =. £ Pad 41- slot #KU 43-6 :KU43-6 KU43-6 GMS<0-4129>, MSS<4174- 0 00 407 76 0 00 0 00 395 20 0 00'PASS < ~ 'S701> . . . . . . Pad 41- 7 _ _ __ , slot #KU 43-6 KU43-6 . . KU43-6Rd MWD <4250-5740> 0.00 _ _ 407.76 0.00 0.00 _ 395.20 ~ 0.00 -PASS '. F`ad ~1- T stot #KU 43- 6A ; I K~~~-fr~ KU43-6A I, MSS ~f1-5300> C1.04 ~#~~~f~~ O.DU 0.4A ' ~$~.~~ ' ; a° 0.04 PRS'~',~ Pad 41- 7 , slot #KU 43-7 KU 43-7 KU 43-7 MSS <0-5707> - 0.00 ' ,.-. S80.68 . _ 0.00 _ 0.00 ? .. 567.56 r 0.00' PASS + Pad 41- 7 ;'slot# KBUI l- KBU 11- 8Y 8Y ~U 11-8Y MWD <0-8220> 0.00 270.17 0.00 0.00 256.78 0.00'PASS ' ~ ~ ~'~ Marathon Oil Company ~ Well Name: KBU 34-6 Location: Kenai, Alaska. ~~~~~ ~~~'~ ~~~~~~ ~N~~I~E~~~~N~ Pf~~~~~~ P1_~N. M~ ~1~A~A~~ ,~ . .._ _ ~ Prepared For: MAR.ATHON OIL COMPANY Prepared by: Jim Dwyer Reviewed by: Hal Martens Presented to: Will Tank May 7, 2007 Revision 1 Well KBU 34-6 Kenai Peninsula, Alaska • • '~ Marathon Oil Company Well Name: KBU 34-6 _ Location: Kenai, Alaska. Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATT'N: Will Tank Will Enclosed is the revised drilling fluid program for the KBU 34-6 Well to be drilled this year as per your email on May 7th. The following is a brief synopsis of the program. Overview: KBU 34-6 is a EXCAPE well in the Kenai Gas Field. Flo-Pro fluid will be used for the intermediate and production intervals. , Surface Interval: The surface interval will be drilled with the standard Gel/Gelex spud mud. No problems were noted in this interval while drilling the offset wells. 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 modified Flo-Pro KCl fluid. While the urogram calls for the standard SafeCarb brid~ing material, Mix II should be added to the mud svstem nrior to drilling the Sterling A8 sand (+/- 3708' MDI. This is a highly porous depleted zone that has contributed to losses of whole mud in the past. 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. Based on offset well history, mud wei~hts above 10.0 PPG mav be required. 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. Jim Dwyer Project Engineer /M-I SWACO Reference Wells: KBU 22-6; KBU 11-8Y; KBU 41-6; KBU 11-7 NOTE: This program is nrovided as a~uide onlv. Well conditions will alwavs dictate fluid Lroperties required. Revision 1 ~ ~ Marathon Oil Company ~~ ~ Well Name: KBU 34-6 _ Location: Kenai, Alaska. _~~.~ ~~~~~~ ~ i.~~~~~~ Our overall goal is no spills and no incidents while providing fluids and solids ~fi~` ~ control services to Marathon Oii Company. ~ - ., E~ur g~a~l fcar ~Bl~ 34-6 is fo rem~v~ dril~ solids ~r~rr~ t6~~ rnud syst~m at a cQ$t of .;~~ ~~~s ~h~n ~Q.34 p~r ~a~un~. ~ 1fltith the revisecl f1u~d fQrm~ala~ion (utilizing the intermed~ate interval fluid for the Rrc~du~t~e~~ ~~,~~rv~~), ~v~ ~ae~aect to atr~tf t~i~ ~e~ll fQ~ ~~a~odu~t c~r~~ a~ 1~~~ than ~~6.Q~ p~e fo~t. We estimate the use of less that 6149 barrels to complete this well, not ~ withstanding any un-anticipated losses to the formation. ~~'~ Use of the MI-SWACO centrifuge van for the last five years has provided an estimated savings in dilution and disposal costs to Marathon Oil of over ~;~ $1,250,000. WFth continued usage of our equipment, we expect to provide more ~ savings to you during future operations. In addition, the instailation of Mongoose ~ shakers has allowed the utilization of finer mesh screens on intermediate and production intervals. Running finer mesh screens has reduced the need for the centrifuge van. Revision 1 ~ ~ Marathon Oil Company ~~= , Well Name: KBU 34-6 Location: Kenai, Alaska. ~nter~a~ ~~~~~~~.rl~s ~~d Tar~~~~ Drilling Intervals I]epth Benchmark 1 Benchmark 2 Benchmark 3 Benchmark 4 fnterval (ft~ Fluid cost per foot Volume Usage Solids Removal 0- 1577' <$5.15 ft < 1969 bbls 1577 - <$45.50 < 3165 bbis 5434' 5434' - < $27.64 ft < 1015 bbls 7665' Total Avg. Max. Project <$36.05 ft <6149 bbls <$0.34 Ib No Spilfs from Targets for Centrifuge Van Drilling Operation Interval Revision 1 • • ~\e'~ Marathon Oil Company - Well Name: KBU 34-6 Location: Kenai, Alaska. Proj ec~ Sumn~ary Casi~e~ Hofe Casing il,e~la TVD ~ilard ~Autl Sum Int~vai 593~ $~Z~'2 ~~'~t~f~73': u~~7'5~31i'J ~£f.i,j~'1~ ~z~ji5 ~31~~435'~ ~9~3~ {!~'9j 1"~a ~f~] $~O~~t~'S ~~L+~~7fl~ ~~.i~~ ~ 13-3/8" 16" 1577' 1500' Gel/Gelex Spud - Mud 8.6 - 9.4 6 $8,116.18 `f-~. _:'` Screens 165/175 ~ mesh , `''` ` r: Desilter ~ _ ,~.,. ~ - ~~: ;:;~-: Centrifuge Van 9-5/8" 12-1/4" 5434' S277' Flo-Pro _ w/SafeCarb 9.0 - 7 $175,511.28 Screens 200 mesh < 9.5 Desilter Centrifuge Van 3-1/2" 8-1/2" 7739' 7582' Flo-Pro w/SafeCarb 9.4 - 6 $63,719.86 Screens 200 - 230 10.6+/- mesh Desilter Centrifuge Van 3 1/2" 8-1/2" Completion 7739' 7582' 6% KCl 8.55 4 $6824.34 - 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 provision for whole mud losses in the intermediate interval (367 barrels) - Cost includes 2% Lubetex concentration in intermediate and production interval. Revision 1 ~ - ~ ~~ ~~ • Marathon Oil Company Well Name: KBU 34-6 Location: Kenai, Alaska. ~st:im~.~~~ ~'~~~~~~ ~~~.g~e ~~~~na~~ ~_ p`~~i~~'~ _ ~~~~~~~ _1~r~' ~~ : ~~~~~~ I2-1~~~' f ~ ~~~~~~~ : ~ ~-~f~'~ ~~~F~,~~~~ - ~-1~~ ~ ~~~1 ~s~ ~~~ ~ ~. ,To~€I ~~~ M-I Bar 0 316 406 0 722 2.21 M-I Gel 394 0 0 0 394 1.53 Gelex 25 0 0 0 25 015 Soda Ash 10 16 10 0 36 0.25 Caustic Soda 10 47 20 0 77 1.28 Conqor 404 0 9 5 0 14 6.67 Sodium Meta Bisulfate 20 32 20 2 74 1.88 Bicarb 0 16 10 0 26 0.25 Conqor 303 0 0 0 4 4 0.75 F1oVis 0 222 61 0 283 22.72 Desco CF 8 0 0 0 8 0.14 Polypac UL 10 111 36 0 157 . 9.52 KCl 0 1329 426 42 1797 12.91 Safecarb 0 1424 304 0 1728 12.83 Lubetex 0 50 16 0 66 18.98 Mix II 0 127 0 0 127 1.23 SteelLube 0 0 6 0 6 2.06 Citric Acid 0 0 20 0 20 0.92 Defoam X 0 7 6 0 12 0.46 Engineer Service 6 7 6 4 23 Revision 1 ~ • Marathon Oil Company ~~"`~" ~~ Well Name: KBU 34-6 Location: Kenai, Alaska. Q~f~~t ~~~1~ ~~~o~~nation Well Hole Size Depth PPG PV YP FL Comments KBU 22-6 16 182 8.7 14 35 14,6 Spud in, drill ahead 1550 9.2 14 22 6.4 Drlg ahead 1680 9.2 14 20 7.8 Drlg to casing point, run surface casing 12.25 3453 9.3 8 11 9.2 Drig out, displace to FloPro, Run LOT, drlg ahead 4649 9.4 12 14 8.8 Drlg ahead 5338 9.2 14 18 5.8 ~ ~sf partial ?eturns @ 492~i' s~t,i 51) bbf LC~'I ,~ili; reyain rsYurns 6032 9.3 14 16 5.4 L~~t ~7artial retum~ ~c~ 58~tii', add LCIV1 tr~ n~~an ~ 6535 9.6 17 19 5.2 Ft~clia+ae p~g, p~am~ LC~M ~iils, run casin~, ~err~~rrt same 8.5 7095 9.85 17 21 5.8 Drlg out cmt, LOT, drlg ahead 8136 9.85 17 23 5 Drlg ahead, short trip OK, drlg ahead 8855 10.3 19 21 5.2 Drig to csg point, short trip, some tight spots, POH for logs 8855 10.45 19 22 5,8 Logging well 8855 ]U.6~ 19 20 5,2 F~ihi- wsight up fr~ 1+~i.~ PPG, ~ondition mud, F'ON 8855 10.65 19 19 5.8 Run excape string, cement same, no losses, disp to brine KBU 11-8Y 16 498 8.65 11 16 17 Spud in, drill ahead 1550 9 9 16 8.8 Drlg to csg point, short trip OK, POH 1550 9.1 9 19 10.6 Run & cement surface casing 12.25 3774 9.1 9 17 7 Drlg out, disp to FloPro, drlg ahead 5033 9.3 13 15 7.8 Drlg to 3884', short trip OK, drlg ahead 5820 9.45 17 23 5.8 ~rYy t<~ ~~y pr~int, ad~ 3°!~ Luoete~ (tr~rque}, P~i-i ~ 5820 9.55 19 22 5.8 Log well, wiper trip, 5820 9.7 20 26 5.4 R~~n cs~, ,~errie~ ~? setr~e; i~st pariiai returns 8.5 5840 9.3 14 18 6.2 C~rlg out; L~T, drlq ahea~; acid ENiI-920 and t.ubetex fior torque 7574 9.75 17 27 5 Drig ahead 8220 iti 16 27 5.4 Urfy to I-u, increase PN~ to 10,U i~r gas 8220 10,n 17 28 5.8 PC1H, wireline w?II; increa~e PPG t~. 1~.5 for c~a~ 8220 10.5 17 26 5.2 Run and cement excape string, disp to brine RevisiOn 1 ~ ~ ~- Marathon Oil Company o Well Name: KBU 34-6 ~~' _ Location: Kenai, Alaska. ~3ff~~t ~~~el~ I~~c~~~atlon Well Hole Size Depth PPG PV YP FL Comments KBU 41-6 16 1616 9.05 18 24 9.6 Spud in, drill ahead 1862 9.3 16 17 7.8 Drig to casing point, run surface casing 1862 9.3 12 14 7.2 Cement surtace casing 12.25 3431 9.3 12 16 8 Drlg out, displace to FloPro, Run LOT, drlg ahead 5044 9.2 13 17 8.4 Drig to 4206', wiper trip OK, drlg ahead, pump sweeps every 500 ft 6289 9.2 13 49 7.4 tiriu t„ 52?8' lost ret+~rri;; stopped ~,vith LGiVI, clrly aheaci 7105 9.3 14 23 7.6 Drlg to 6897', wiper trip OK, drlg ahead 7220 9.3 11 23 8.6 Drlg to casing point, wiper trip Ok, POH to run casing 7220 9.8 12 18 8.4 Run 9-5/8" csg, cement same, bump plug 8.5 7374 9 12 17 6.4 Drlg out, disp to new fluid, LOT = 16.0 PPG, drlg ahead 7735 9.2 10 16 5.3 Trip for core #1 7776 9.3 12 13 5.1 Core #1 7835 9.5 14 14 5.2 Core #2 8445 9.7 14 16 5 Drlg to core point 8535 9.95 14 19 5 Core #3 8807 10.1 16 20 4.6 Ciriy ahe~d. tncrease Lubetex to 4',%~, 9733 10.3 16 19 4.6 TD well, 9733 10.6 15 1$ 4.4 Wi~ier t~ip; inc PPG to 1G.6 for gas, P~IH for i~>g~ ~ 9733 10.8 15 20 5.2 Lc;q welf; wipe~ trip, treat for running c~als; PCiH 9733 10.8 14 21 5.6 Run and cemertt excape string, disp to brine KBU 11-7 16 987 8.7 7 28 16 Clean out conductor, spud in 1477 9 8 23 9.2 Drlg ahead 1725 9.2 9 20 6.2 Drlg to casing point, run surface casing 1725 9.3 8 22 7.4 Cement casing, no losses, BOP's 12.25 2822 9.4 8 18 7.2 Drlg out, displace to FloPro, Run LOT = 15.2 PPG, drlg ahead 4460 9.1 11 18 7.S Drlg ahead with miminal losses 5080 9.3 9 9 15 8.6 Short trip, OK, drlg to core point @ 5080' 5160 9.4 12 20 7.5 Core #1 5249 9.3 15 20 6.7 Core #2 5449 9.4 15 12 7 Open core runs to 12-1/4", drig ahead 5585 9.6 17 23 7.3 Logging 5585 9.5 16 24 7 Fish far Ft~T tooi parts 5585 9.5 17 21 7.4 Recover fish, log with RFT tools 5585 9.5 17 22 8.2 Run & cmt 9-5/8" casing 8.5 5869 9.5 22 26 6.8 Drlg out, LOT = 15.2 PPG, drlg ahead 6940 9.9 21 23 5.8 ~ ~~~:;, ;eiat; ;~, f„r g~;, wipe= triN, kr~:;i ,~~ai7uriy need~d 7770 10.3 26 27 6 ki~ ;+~ii~! ar~ea~: u~;eiyi~t ;~p i;~~ stebility, adcl a:cph~sol fqr cr.>al~ 7900 10.5 27 29 5.8 E~ ~i:~:.,' ,~_,. riGS _._n-~,.s~~,~a ~~~~krua ii+~t~. F` t..~ i.;~t~ i!~~~ 7900 10.5 23 23 5.8 Log well on drig pipe 7900 10.6 26 30 5.1 Cleanout run prior to compleiton. 7900 10.65 26 28 5.2 Run and cement excape string, disp to brine Revision 1 C~ ~ _~' ~ Marathon Oil Company Well Name: KBLJ 34-6 Location: Kenai, Alaska. ~~c~.~~ ~ ~~'~~~~ll~'£S ~ 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 Sterling A8 and Upper & Middle 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 su~cient fluid loss agent additions, this may require adequate dilution of the mud system in order to keep reactive drill solids to a minimum . ~ INTERMEDIATE INTERVAL - ~ 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. ~ IVIIXING CONDITIONS - Whenever possible all treatments to the mud system should be made as pre-mix additions. Polymers and KC! should first be mixed in fresh water in that order and then, blended into the active system over one or finro 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 (dissolved oxygen) 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 - A!I 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. Remove 325 mesh shaker screens when adding Barite. Revision 1 . ~~'~ . Marathon Oil Company Well Name: K~U 34-6 Location: Kenai, Alaska. Int~r~~~ ~~~~a~~ ~ ~~" hole 0 -1577' ~ri~li~~ ~~~i~ ~v~t~~r- Gel/Gelex Spud Mud K~y ~r~~~i~t~ MI Gel / Gelex / Soda Ash / Caustic Soda / MI Bar / PolyPac Supreme UL / Sodium Meta Bisulfate Sc~li~~ Cantrt~l Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 165 mesh P~te~tiat Prcabl~nas Lost circulation, coal sloughing, drill solids build-up, hole cleaning. nterval Drilling Fluid Properties __ D~epth 1VIud F~nnel ~'iel~ A~'I Drill Intervai "GVeight Viscositv 1'ai~at Fluid Lc,ss pFi Solids (ft) (ppg) ~sec,/qt) {Ib./1t~Oft~) {~nU30nlin) ~%) 0- 1577' 8.6 - 9.4 60 - 100 25 - 35 NC - 12 +/- 9.5 < 7.5% - 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 IVleta Bisulfate to maintain a DO (dissolved oxygen) of < 3 PPM. - Condition mud prior to cementing casing to reduce yield point and gel strengths. - Estimated volume usage for interval - 1969 barrels. - Estimated haul off volume - 3137 barrels. Revision 1 ^ =~ 1 • Marathon Oil Company Well I~1ame: KBU 34-6 Location: Kenai, Alaska. I~ter~~.1 ~~~~~.r~ -1~-1~~" h~le 1577' - 5434' ~~'l~Iill~ F~' Ililt~ ~~'S~~III Flo-Pro Fluid Key Prv~t~acts Flo-Vis / PolyPac Supreme UL / KCl / SafeCarb 10, 40, 250 / Mix II /MI Bar / Caustic Soda / Conqor 404 / Sodium Meta Bisulfate Lubetex S~li~is ~C"c~ntr~l Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 200 mesh 1'~tential Prablems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval D~rilling Fiuid P~operties Depth Mud Plastic LSRV API Dril9 Ir1te~°val Weight Viscosity 1 m~~ Flu~d Loss MBT Sol~ds (ft} (ppg) (~p,) {cps) (~nU3~min) {%) 1577 - 5434' 9.0 -< 9.5 8- 12 40,000+ 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. Pre-heat makeup water with steam hoses as much as ~ossible. - After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test - As mud heats up, increase FloVis concentration to 2 PPB as needed. - NOTE: Be prepared for whole mud losses in the Stepling A8 sands (+/- 3700' MD). - If torque ar sliding problems occur, add 1- 3% Lubetex. - NOTE: This fluid will be used in the nroduction interval. It is inherent to maintain proner fluid pro~erties for that purpose. - Estimated volume usage for interval - 3165 barrels. - Estimated haul off volume - 3373 barrels. - Condition mud priar to running 9-5/8" casing. NOTE; Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. Revision 1 ~ ~ Marathon Oil Company ~~ 1~ Well Name: KBU 34-6 Location: Kenai, Alaska. ~'~~~d ~'or~~~~. -12~1~~'~ Interv~l ~~ ~~~ ~- MUDCALC 4.5 - Water-Based Mud Calcuiation ~ n- ~ 12.25" Intermediate Hole M-I L.L.C. Innut Description KBU 34-6 Mud Wei ht 9.0 - 9.5 Preh drated Gel No Wei ht Material Code SafeCarb Preh drated Ge1 Conc. Wei ht Material SG 2.8 KCI Wt% 6 NOTE: Pre-heat makeup water with steam hoses as much as possible. Out ut -1 bbl Order of Products ' Concentration Volume Product Addition Field, Ib Lab, rn Fiefd:, bbl Lab; rnl llsa e 1 Water 298.70 298.70 0.853 298.70 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 Flovis 1.25 1.25 0.003 0.83 Viscosit 4 Pol ac Su reme UL 2.00 2.00 0.004 1.25 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 H Control 6 Potassium Chloride 19.07 19.07 0.023 7.98 Inhibition 7a SafeCarb 10 4.00 4.00 0.040 1.44 Brid in A ent 7b SafeCarb 40 12.00 12.00 0.012 4.32 Brid in A ent 7c SafeCarb 250 4.00 4.00 0.004 1.44 Brid in A ent 8 KlaGard 4.00 4.00 0.008 2.25 Inhibition Plan on addin 2.5 - 5 PPB Mix II to the mud s stem rior to drillin into the Sterlin A8 sand +/- 3708' MD 9 Mix II 5.00 5.00 0.010 3.12 LCM If tor ue becomes a roblem, or slidin is difficult add 1- 3% of the followin : 10 Lubetex 14.00 14.00 0.041 14.43 Lubricit If bit ballin becomes a roblem, add the followin : 11 D-D CWT 1.00 1.00 0.003 1.00 Reduce BHA Ballinq Total 399 399 1.000 350 Calculated Mud Wei ht 9.500 Estimated Volume Usa e 3165 Totaf Chloride 29600 Revision 1 • • ~ Marathon Oil Company ~ _____`~'~ Well Name: KBU 34-6 Location: Kenai, Alaslca. ~ridging Formu~a -12-1/4" hole ~- - ,-li ~7YWKV~.~. C O .' d m ~ m N y c~ u C A a > .~ 7 E U Max Permeabillty : 1000 mDarcy Sand Control Devioe : o~` . o~o - ~9a D10 Target I Blend: 1.3 I 1.7 microns D50 Target / Blend: 31.6 I 29.7 microns D90 Target / Blend: 102.5 I 142.9 mlcrons ~ptlm~~m B!=n~1 =:rr ~ to 1r;r _ Brand Name Bridalno Aqentllblbbtl Vol % B=Safe-Cai'b 10 (F) 0.0 0.00 C=Safe-Carb 20 24.6 49.22 D=Safe-Carb 40 (M) 25.4 50.78 E=Safe•Carb 250 (C) 0.0 0.00 c ~ 49.2 % } ' o : 50.8°k ~ars8c~: Wtarathon Oil Gampany OPTIBRIDGET"" ~~~~~: ~~~ Locffii~: Kenai Paninsula 0 1999-200fi M•I l.l.C.-All Rights Reserved $;p~~8nqs; ppiimum Blend Optimu~ 8ridq~n~ ~g~~~ ~~~~~' PaRicle Size (microns) Simulation Accuracy Calclum Carbonate added : Avg Error 0-100 °6 CPS Rsnge : Maz Error 0-100 k CPS Range : 50 Iblbbl 7.63 % 17.28 °/. ReV1S10R 1 ~ ~ Marathon Oil Company ~~ , Well Name: KBU 34-6 0 Location: Kenai, Alaska. In~~~v~~ ~~~~~r~ - ~~1~~~' hol~ 5434 - 7739' ~~iiii~~ F~~~i~ ~~~~~~~~ Flo-Pro Fluid Ke~% Pr~~lu~ts Flo-Vis / Polypac Supreme UL / KCl / SafeCarb / MI Bar / Caustic Soda / Conqor 404 / Sodium Meta Bisulfate / SteelLube / Lubetex Solicis Cor~trt~l Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens - 200 - 230 mesh Pat~nti~l Prc~blerns Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Flu~d ~'roperties Depth Inter~~al ~~~) Mutl Weight {PP~) Plasti~ Viseosity ~~P•) L~R~' 1 rr~~r~ ~~P~) ~PI ~'luid Lt~ss ~mll~i~~ni~) MBT DriIl Solids (~°/a) 5434 - 7739' 9.4+/- 10 - 14 30,000+ 6- 8 < 7.5 +/- 5% 7339 - 7739' 10.0 - 10e6 12 ---16 30,OU0+ 5-'T < 7.5 +/~ 5°l~ - 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 as needed. Run 325 mesh screens on shakers if reusing all fluid from 12.25 " interval. Reinove 325 mesh before adding barite. ~ 1'~~`I'E: YlatY an iticre~sin~ the niud wei~hts to 1~.0 - l~.b PPG tin cantrot aressw~es in the Tvonek farmatiai~ (-"!~ 7339' MD). However, mud weight iucreases should': not be needed while drillin~ the ir~rr~et Belu~~ foi°niatioiY. - NOTE: If inetal-to-metal toraue is a nroblem after drillin~ out the 9-5/8" casin~, then add 0.5 - 1% SteelLube prior to addin~ Lubetex. - If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. - Estimated additional volume for interval - 562 barrels. - Estimated haul off volume - 2225 barrels. - Condition mud prior to running 3-1/2" casing. I~iOTE: Follovv ~OSC'O guidelines when adciing biocide, oxygen scavenger and corrosion inhibitor. Revision 1 ~ ~ t - ~ Marathon Oil Company Well Name: KBU 34-6 Location: Kenai, Alaska. I~ilu~~~n ~`c~~~n~l~. - ~~1~~" In~erv~1 ~~ ~~~~~-~ ~- MUDCALC 4.5 - Water-Based Mud Calculation 8.5" Production Intervai M-I L.L.C. Innut Descri tion . Marathon Oil Com an Mud Wei ht 10 Preh drated Gel ` No Wei ht Material Code MI Bar Preh drated Gel Conc. VVei ht Material SG 4.2 KCI Chloride ; 30000 Wei ht Material'Price KCI Wt% 6 Out ut - 1 bbl # Products Concentration Volurn e Product Field, Ib Lab, m Field, bbl Lab; ml Usa e 15 Water 304.66 304.66 0.870 304.66 1 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 2 Flovis Plus 2.00 2.00 0.004 1.33 Viscosit 3 POLYPAC UL 2.00 2.00 0.004 1.25 Fluid Loss Control 4 SafeCarb 40 5.00 5.00 0.005 1.85 Brid in A ent 11 SafeCarb 10 15.00 15.00 0.096 5.56 Brid in A ent 5 CONQOR 404 2.00 2.00 0.004 1.43 Corrosion Control 6 Caustic Soda 0.50 0.50 0.001 0.23 H Control 7 Sodium Metsbisul hite 0.50 0.50 0.001 0.24 Ox en Scaven er 13 MI Bar 55.14 55.14 0.038 13.13 Wei htin a ent 12 Potassium Chloride 19.45 19.45 0.023 8.14 Inhibition If hi h tor ue while slidin becomes a problem, add 1- 3% of the following: 9 LubeTex 7.00 7.00 0.019 6.67 Lubricit If slou hin coals become a roblem, add 2- 4 b of the followin o 10 ASPHASOL SUPREME 3.00 3.00 0.007 2.50 Wellbore Stability ~Totaf I 420 ~ 420 ~ 1.000 ~ 350 ~ _~ Calculated Mud Weiqht 10.000 Estimated volume usaqe 1015 ~ Revision 1 • ~ ~'~ Marathon Oil Company = - Well Name: KBU 34-6 Location: Kenai, Alaska. Interval Summary - Completion Procedures Corrosion Control Additive in Casing x Tubing Annulus Well KBU 34-6 Volumes: Tubing Volume 3-v2° Tubing 67.30 barrels Annular Volume Casing x Tubing 333.14 barrels 3.50 x 2.992 x 7739 ft 9.625 x 8.681 @ 5434 ft M D 8.500 x 3.50 @ 7739 ft M D Treatment Procedures. Open Hole x Tbg 134.35 barrels Total Annular Volume 467.79 Tubing Volume s~.3o Total Hole Volume 535.09 1. After the 3-1/2" tubing is run and the drilling fluid is circulated and conditioned for the cement job, circulate an additional 400 barrels of drilling fluid. 2. Add 1 drum of Conqor 303A and 1 sack of Sodium Meta Bisulfate for each 100 barrels of drilling fluid pumped (4 drums & 4 sacks total) ~ 3. After the 400 barrels of drilling fluid with corrosion inhibitors have been pumped downhole, begin the cement job. 4. This procedure will place corrosion control in the 3-1/2" x 9-5/8" annulus. Revision 1 ~ ~ ~~'~ Marathon Oil Company Well Name: KBU 34-6 Location: Kenai, Alaska. ~~~ ~~~u~eS HANDLING OF DRILLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. 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. Revision 1 s • '~ Marathon Oil Company Well Name: KBU 34-6 Location: Kenai, Alaska. 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. Revision 1 • . ~e'~ Marathon Oil Company Well Name: KBU 34-6 ~ Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS M-I BAR M-I GEL GELEX FLOVIS DUAL-FLO HEC ~fe-Carb 10,40,250 Nut Plug M-I Seal F, M, C Mix II F,M,C SALT (Solar) POTASSIUM CHLORIDE CAUSTIC SODA SAPP SODA ASH SODIUM BICARBONA CITRIC ACID BIOBAN BP-PLUS GREEN CIDE 25G - DEFOAM X - G-SEAL LUBE TEX D-D CWT Concor404 Asphasol Supreme ~ ~~~7a~96~a Me~a l~e~eAsfi~~~ i Function Weighting Agent Bentonite Extender Modified Starch Loss Circulation Material idging and weighting agent Loss circulation Material Dispersant Densifier Shale Inhibitor Alkalinity control Inorganic Borate Sodium Pyrophosphate Alkalinity control Alkalinity control pH Adjuster Biocide Defoamer Sized graphite LCM Lubricant Lubricant Corrosion Inhibitor ~~te,~g~a°~ ~ca~~~nc~e~ Health 1 Flammabil *1 U *1 1 1 1 't 1 1 1 *1 1 1 1 *1 0 *1 1 *1 1 *1 1 1 1 1 0 1 0 3 0 1 0 *1 0 1 1 1 0 1 0 *2 0 3 0 1 1 1 1 1 1 1 1 2 1 1 1 1 1 1 1 1 1 PPE E E E E E E E E E E E E E E X E E E E E J J J E J J J J J J J Product Health and Safety Reference Revision 1 • ~ ~ Marathon Oil Company ~~ ~ Well Name: KBU 34-6 - Location: Kenai, Alaska. ~~~~ ~~~~~ ~~~~~ HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (gIMIS) HAZARD ItATINGS 4 - Severe hazard 3 - Serious hazard 2 - Moderate hazard 1- Slight hazard 0 - Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PE1tSONAL PROTECTIVE EQUIPMENT INDE7~ 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 Revision 1 ~ ~ Marathon Oil Company ~~' Well Name: KBU 34-6 Location: Kenai, Alaska. ~ ~~~~~~~ Contact Title e-mail Work Cellular Pete Berga Drilling pkberga@marathonoil.com 907 565-3032 907 231-0663 Marathon Superintendent Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398 Marathon Jim Dwyer Project Engineer ttykalsky@miswaco.com 907 274-5011 907 317-4556 MI SWACO Bob Myles Warehouse Manager rmyles@miswaco.com 907 776-8722 907 252-4218 MI SWACO Oliver Amend Field Engineer 907 283-0895 907 398-9474 MI SWACO (home) Locke Rooney Field Engineer lrooneyl@alaska.net 907 235-0598 907 398-9474 MI SWACO (home) John Nicholson / Dan Drilling Foremen alaska_drilling@marathon 907 283-1312 Byrd oit.com Marathon Resp~nsibilities - 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 ~i MI SWACO) 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. Revision 1 c~»~k ~ cn~k oete e~ s~,k r,~ v~o~ Marathon Oil Company • a~~t ~~~~m: Hndl ACCOU~S PAYABIE DEPARTMENT 9 P. O. Box 22164 Accts Payable Contact Center 1269534 05ro9/2007 NCBAS 7780 5001123 ruisa,oK ~a~z~-ztsa P~~e: 918_~5~~ AL 100.00 AL: (FOLD ON PERFORATION BELOW AND DETACH CHECK STUB BEFORE DEPOSITING) i~'000 L 269534~~' ~:04 i 203895~: 0 L83484ii' ~ ~ i TRANSMIT~'AL LET'T~R CH~CKLIST WELL ~iANIE ~LT~V ~~ ~{- ~ PTD# ~!l - ~(a y ~Development Service Explorato • Strati ra hic ~Y g p T'est iYon-Conv~ation$[ Wett Circle 4ppropriate Letter / Pacagraphs to be included in Transm~ital Letter ~ CE~CK i ADD-ONS ; T'EXT FOR APPRO~'AL LETTER ~ ; WHAT ~ (OPTIONS) ; ~ ; APPLIES ~ ~ ' , I MULTI LATERAL , The perrnit is for a new wellbore segment of existing ~ well ~ ~(If last two digits in I Permit ~fo. , AP[ No. ~0- ~ API number are ; ' + , between 60-69) Production ;houfd coatinue to be reported as a function of the + i ~ original 4PI number stated above. ~ ~ P[LOT E[OLE i[n accoc~dance with 20 A.AC 25.OU~(~, ali records, data and lo~s ~ 1 ~ acquired for the Pilot hote must be clearty diffecenti~ted in both ~ ~ ; well name ( PE~ and API n~uctber ~ ; '(SO- - -_) from records, data and logs ~ ~ ~ ~ acquired for we(1 ~ . SPACIlYG The pcrmit is approved subject to fiall compiiance with 20 AAC EXCEPTION ( ~ 2~.05~. Approval to pecfocate and produce / inject is contingent ~ I upon issuance of a conservation ocder approving a spacing i I exception s ' . a sumes the i liability of any protest to the spacing exc~ption that may occur. i E - Non-Conventiortat VVe l l Rev: 1!2~i06 C:`jody~cransmitta! checklist Please note the fo(lowing specia! condition oP this permir: production ar production testing of coa! bed methane is not a1(owed foc (name of well~ until after (Cornaany Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing ,-,,~ , , _ _ _ ` i DRY DCtCH ~ Al[ dry ditch sample sets submitted to the-Eommission must be ';in ~ i SA.NIPLE i no greater tttan 30' sample intervals from betow the permafro~t or ; ~ ! I from where samples are first caught and 10' sample intervals ; ~ ; ; ~ through target zones. ; ~ ~ ^^ ~ y ~ ~ ~ , ~ ~ ~ , ~ ~ ~ , ~ ~ ,, . , ~ , ~ , ~ ~ , ~ , , ~ ~ , , . . ~ , ~ , ~ ~ , , , , ~ , ~ ~ ~ . ~ ~ ~ . ~ i ~ ~ ~ ~ , , p) O N a , , ~ ~ , ~ , ~ ~ ~ ~ ~ , , . , , . ~ ~ ~ ~ ~ ~ ~ ~ ~ , , ~ ~ ~ , , ~ ~ - ~ , . ~ , ~ ~ ~ ~ . ~ y . ~ . ~ ~ ~ ~ ~ ~ ~ .. ~ , ~ ~ ~ ~ ~ ~ ~ , . , ~ ~ , . 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