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207-149
Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 2/8/2024 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20240208 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 13-08 50133203040000 177029 10/11/2023 AK E-LINE TUBING CUT KBU 14-6Y 50133205720000 207149 10/24/2023 AK E-Line PLUG/PERF MPU B-28 50029235660000 216027 1/10/2024 HALLIBURTON MFC40 MPU F-65 50029227520000 197049 1/19/2024 HALLIBURTON MFC40 MPU I-12 50029230380000 201163 1/30/2024 HALLIBURTON Coilflag MPU J-08A 50029224970100 199117 1/21/2024 HALLIBURTON Coilflag Please include current contact information if different from above. T38488 T38489 T38490 T38491 T38492 T38493 2/8/2024 KBU 14-6Y 50133205720000 207149 10/24/2023 AK E-Line PLUG/PERF Kayla Junke Digitally signed by Kayla Junke Date: 2024.02.08 10:05:37 -09'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,600 feet See Schematic feet true vertical 7,573 feet 7,115 (fill) feet Effective Depth measured 3,593 feet N/A feet true vertical 3,579 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 7,571' MD 7,544' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Chad Helgeson, Operations Engineer 323-490 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 chelgeson@hilcorp.com 907-777-8405 N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 1100 Size 129' 0 4201700 0 00 1256 9-5/8" 3-1/2" Intermediate 20" 13-3/8" 129' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 207-149 50-133-20572-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028142 Kenai Field / Sterling Gas Pool 3 Kenai Beluga Unit (KBU) 14-6Y Production Liner 5,318' 7,571' Casing Structural 5,291' 7,544' 5,318' 7,571' 129'Conductor Surface 1,504' TVD measured Packer Plugs Junk measured Length 3,090psi 10,540psi 3,060psi 3,450psi 5,750psi 10,160psi 1,504' 1,503' Burst Collapse 1,500psi 1,950psi measured true vertical PL G Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.12.21 10:23:07 - 09'00' Noel Nocas (4361) Page 1/3 Well Name: KEU KBU 14-06Y Report Printed: 12/19/2023www.peloton.com Well Operations Summary Jobs Actual Start Date:4/2/2023 End Date:10/3/2023 Report Number 9 Report Start Date 9/10/2023 Report End Date 9/11/2023 Operation PJSM, ARRIVE AT OFFICE DISCUSS OPERATIONS WITH AK-ELINE & SCLUMBERGER N2. DRIVE TO LOCATION. SPOT IN & RIG UP EQUIPMENT (REHEAD TO 7/2). CHECK WELLHEAD PRESSURES PRODUCTION STRING-10 PSI, INNER ANNULUS-500 PSI, SURFACE- 83 PSI. PFRESSURE TEST LUBRICATOR 250 PSI LOW, 4000 PSI HIGH-GOOD TEST. MAKE UP TOOL STRING AND RUN IN HOLE WITH CCL, GPT, CIBP. \nRUN IN HOLE FLUID LEVEL @ 1970' \nCONTINUE TO 3329.9' TAG FILL, MAKE MULTIPLE ATTEMPTS TO PASS. UNABLE TO PASS. \nPULL OUT OF HOLE WITH GPT-PLUG COMBO\nPICK-UP SLIM HOLE NO JEWLERY \nRUN IN HOLE WITH SLICK PASS THRU BRIDGE AT 3329.9' WITH 1500 PSI ON WELLBORE, RUN TO 3550' TAG NO CHANGE IN PRESSURE HOLDING 1500 PSI. PULL OUT OF HOLE WITH SLICK ASSEMBLY & LAY DOWN\nPICK UP 2.77" GAUGE RING RUN IN HOLE TO 3517' TAG, CHECK WELLHEAD PRESSURE 1300 PSI PRESSURE BACK UP TO 1500 PSI. WORK WIRELINE MULTIPLE TIMES \nPULL OUT OF HOLE WITH 2.77" GAUGE RING AND LAY DOWN, PICK UP GPT TOOLS \nRUN IN HOLE TO CHECK FLUID LEVEL DROPPED 2012' TOP OF FLUID. TAG SOLID @ 3517'\nPULL OUT OF HOLE WITH GPT & LAY DOWN \nRIG DOWN WIRELINE PRESSURE UP TO 2000 PSI ON PRODUCTION STRING & HOLD, RIG DOWN SCHLUMBERGER N2 \nSHUT IN & SECURE WELL\nRELEASE AK ELINE. HOLD SCHLUMBERGER N2 UNIT ON STANDBY Report Number 10 Report Start Date 9/12/2023 Report End Date 9/13/2023 Operation PJSM @ KGF office \nTravel to location \nSpot in & rig up equipment \nRun in hole with 2.5 GR to 3473' slm & tag \nPull out of hole \nRun in hole with 2.5 dd bailer to 3473' slm & tag \nPull out of hole 1' of cement in bailer \nPick up & run 2" x 4' bailer to 3474' slm & tag \nPull out with plugged bottom of bailer with cement /clay\nRun in hole with .75" x 14" external wire grab to 3542' slm & tag \nPull out of hole Pick up & run 2.5" x 8' dd bailer run in hole 3532' slm, \nPull out with full bailer\nRun in & make 4 x run with 2.5" x 8' bailer (total 32 ft of sand returned)\nLay down lubricator \nShut in & secure well Report Number 11 Report Start Date 9/17/2023 Report End Date 9/18/2023 Operation Ak E-line arrive on location. PTW, JSA with Hilcorp Rep's. Spot in equipment Rig up E-line. E-line drum back spooled. Fix loose wraps. Stab on well. PT lubricator and wire line valves 250/4000 psi. Open well 600 psi WHP. RIH w cable Head/weight bar x 2, GPT logging tool, and 2.77" gauge ring. Fluid depth found at 1170ft. Tag obstruction (sand/fill) at 3525'. pick up and repeat tag twice. POOH to surface. 584 psi WHP. Talked to town engineer and decision made to set CIBP at 3525'. Make up 2.7" OD CIBP and setting tools. Open well. RIH. 500psi WHP, 2.75" OD Plug for 3.5" Pipe. Fluid depth found at 1080ft. Tagged 3525' end of tool string. Pull correlation pass and get on depth. Set plug at 3525' center of element. Good cap break and weight loss after 1.5 minutes. POOH to surface. Lay down tools. Setting sleeve stroked CIBP remains at depth. Rig up cement dump bailer. Mix cement and rig up BHA. 2 gallons of cement added to dump bailer equaling 5' of cement once placed in 3.5" tubing. Stab on well. RIH and pull up string weight above CIBP and dump cement at 3524.6'. Good indication of cement dump. Pick up slowly 1' and stop. Continue until 6' and out of cement. POOH to surface. Close master swab. Pop off well and confirm fire. Break down tool string. Rig down AK E-line. Location secure. Depart location. Report Number 12 Report Start Date 9/20/2023 Report End Date 9/21/2023 Operation AK Eline and SLB arrive in field office. Complete permit & JSA.\nRU N2 truck, PT to 4000 psi\nRU Eline and PT 250L/4000H psi, pass\nPressure up well with N2 to 973 psi.\nPU 2.5" HC x 18ft gun w/ GR/CCL\nRIH and tagged plug. Pulled correlation log, Send log to Geo/RE, On depth, no adjustment made.\nPerforated Sterling Pool 3 A6L sand (3492-3510') with 973 psi on well, post perf pressures 5 min - 1309 psi, 10 min - 1310 psi, 15 min - 1314 psi\nTools temporarily detained after firing, worked tools and pulled to surface. Worked tools above master valve by hand until able to close master valve. Removed lubricator and the Eline tool string was not in lubricator. (29ft OAL toolstring lost downhole) Inspected wire and there was frayed wire in grease tubes and the end of the wire had pulled out of the rope socket.\nSecured well, rig down Eline. Call out for Slickline in the morning. Leave well shut-in. Report Number 13 Report Start Date 9/21/2023 Report End Date 9/22/2023 Operation Pollard SL arrived, completed PTW & JSA\nRU SL & PT lubricator to 2500 psi, good.\nRIH w/ LIB to 3495'KB, POOH w/ impression of rope socket offcentered\nRIH w/ 1-3/8" JDC & could not latch, POOH\nRIH w/ 1-7/16" OS baited w 2-1/2" GR, pull up to 1000# came free, POOH and LD guns\nTurn well over to ops, RDMO. Report Number 14 Report Start Date 10/2/2023 Report End Date 10/3/2023 Operation Ops Rig up triplex test pump to IA on KBU 14-06Y\nConduct JSA, Start pressures, 576/660/85 psi - T/I/O\nPT lines, started pumping in IA. Pressured annulus to 2,156 psi. Held pressure for 1hr monitoring system, every 15 min. (2137, 2126, 2116, 2108 psi readings every 15 min).\nRD test pump, bled casing to 475 psi Report Number 15 Report Start Date 10/24/2023 Report End Date 10/25/2023 Operation Ak Eline departed shop Arrived a production office PTW & PJSM API: 50-133-20572-00-00 Field: Kenai Gas Field Sundry #: 323-490 State: Alaska Rig/Service:Permit to Drill (PTD) #:207-149 Page 2/3 Well Name: KEU KBU 14-06Y Report Printed: 12/19/2023www.peloton.com Well Operations Summary Operation Arrived at well site, spot equpment and rigging up Swab valve not holding ,call out valve tech, grease and function swab, upper and lower master, swab valve not holding Rigging down E line equipment, to move to KTU 32-7H production found a new replacement valve, will install same Rig down Eline secure well for night. Report Number 16 Report Start Date 10/25/2023 Report End Date 10/26/2023 Operation AK E line arived office, PTW & PJSM Arrived at well site, spot and rig up equipment Check out tools stab on well , line line up to pressue test Trouble shoot man lift, shutting down while operator in air with basket Tripping circuit breaker , call for mechanic able ot operate from ground console unable to pump N2 into flow line appears to be a Ice plug Call for heater =, pump methonal in flow line and thaw out Line thawed out pressure test lubricator to 250 psi low and 4000 psi high all good open well, RIH with 21 ft tool string, x 2 weight bars, GPT ( OAL 21', MAX OD- 2") to 3500 ft. no water found Run correlcation log pass up at 50 fpm, Pooh AT surface, close swab, bleed off, unstab, set up to run plug Check tool. arm CIBP, stab on well Open well, RIH with R/S, WT BAR X 2, GUN GAMMA, 1.69 setting tool, 2.75 plug (OAL 28', MAX OD 2.75 ) Run correlation pass from 3500 ft. send in for approval Run setting pass CCL stop depth 3461'CCL to middle Element- 14 ft. set plug at 3475 ft. ELM, wait 5 minutes pick up 10 ft s et down on plug to verify plug set . log up POOH , at surface lay down setting tools pick up 2" x 20 bailer,check tools, fill bailer with 4.2 gallons neo slurry cmt kit, stab on well Open well, RIH with R/S, CCL, 2.5 X 20' cement bailer, (OAL - 25', Mac OD- 2.5) Unable to make it down thru tree, set down , double check valve line up, (Good) work line by hand no luck getting down sounds like bailer hitting flange above swab valve, bump up, unstab from well, found cmt bailer glass disk broken dumping cmt in top of tree, Gather tools, lay down bailer, made up 2" wt bars, with at 2.86 gauge ring, put 4" nerf wiper ball in tree, RIH with R/S, 3 WT BARS, CCL, Spang jars, 2.86 swedge gauge ring, set down at 663 ft, worked multiple times, at multiple speeds set down same spot each time pooh At surface lay down tool string, change same Stab on RIH with R/s, 2 2" WT bar, CCL, SPANG JARS, 2" WT BAR, ( OAL 28 FT MAX OD 2.12) Rih saw a bump at 663, conitnue in hole lightly tagging CIBP at 3475 ft. POOH Change tool string, make up 2.50 gauge ring, put another 4" wiper ball in tree, stab on open well RIH with R/S, (2) WT BARS, CCL , SPANG JARS, 2" WT BAR , 2.50 GAUGE RING, oaL AT 29 FT. MAX OD 2.5 " unable to make past 486', tried multiple speeds set down in same spot, pooh , at surface laid down the 2.50 gauge, ring, RIH with 2" tools string, push wiper ball to bottom lightly tagging plug at 3475 ft. ELM pooh Fill out PTW, PJSM, rig down off 11-17x and RU on KBU 14-06Y. PT 2000 PSI - Pass Report Number 17 Report Start Date 10/26/2023 Report End Date 10/27/2023 Operation RIH with 2.25" DD bailer to 390' WLM, w/t to 403' WL. Continue to work tools cleaning cement to 351'- 410'. PU 2.3 & 2.6" star bit. Clean out well to 650'. Change tools and work to 3475' WL. Drift tubing with 2" spent guns to 3463'. RDMO well. Report Number 18 Report Start Date 10/27/2023 Report End Date 10/28/2023 Operation AK E-line arrives on at office , PTW, PJSM. Arrive at well rigging up E-line Swing motor froze up, get heater and thaw same Continue rigging up on well , stacking lubricator, Op check tools, arm gun, stab on well, line out to pressure test lubricator to 250 and 1500 psi Test pump methanol tank empty, get test pump from coil unit, start egnine and warm up. Fill and pressure test lubricator to 250 & 1500 psi (Good) test , drain lubricator to blow down tank Open swab valve, RIH with rope socket, weight bar, gun gamma, shock sub, 2" gun loaded with 8 ft of 6 spf at 60° phasing 7 gram charges ( OAL - 26' Max OD 2") to 3450 ELM Run correlation pass, send to town, on depth log guns of depth CCL stop depth 3378.8' CCL to top shot 10.2 ft. top shot at 3389.0 pref the P3 A6 upper sand F/ 3389 ft to 3397 ft. good indication gun fired. log up t/ 3250 ft. Initial pressure reading 1240 psi 5 minute reading 1241 psi, 10 minute reading 1241 psi, 15 minute reading 1240 psi, out of hole reading 1240 psi Pooh Rig down lubricator, crane load out equipment and depart location turn well over to production Report Number 19 Report Start Date 11/15/2023 Report End Date 11/16/2023 API: 50-133-20572-00-00 Field: Kenai Gas Field Sundry #: 323-490 State: Alaska Rig/Service: Run correlation pass, send to town, on depth log guns of depth CCL stop depth 3378.8' CCL to top shot 10.2 ft. top shot at 3389 3389 ft to 3397 ft. good indication gun fired. log up t/ 3250 ft. Initial pressure reading 1240 psi 5 minute reading 1241 psi Unable to make it down thru tree, set down , double check valve line up, (Good) work line by hand no luck getting down sounds l swab valve, bump up, unstab from well, found cmt bailer glass disk broken dumping cmt in top of tree, Page 3/3 Well Name: KEU KBU 14-06Y Report Printed: 12/19/2023www.peloton.com Well Operations Summary Operation Ops tried to flow well again. Used echometer to shoot fluid level. Zone is wet, no production from last zone. API: 50-133-20572-00-00 Field: Kenai Gas Field Sundry #: 323-490 State: Alaska Rig/Service: A6 A6L A8 A10 B1U B2A B4B B5A Lease: State:Alaska Country:USA Angle/Perfs: Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 C Helgeson Well Name & Number: 12/13/2023Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCL 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 2305' (10/02/21 CBL) Permit #: 207-149 API #: 50-133-20572-00-00 Prop. Des: ADL - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60°27' 36.75" N Longitude: 151°15' 54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 PA #: 891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt. (10-01-21) IA cement job w 95 bbls 15.3ppg cmt PBTD 3,951' MD 3,933' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: - 15 Excape modules system - Green control line: cemented with 1.5 gallons on 7/2/21 - Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 5,382' - 5,392' (1/17/2008) Module 14 5,442' - 5,452' (1/17/2008) Module 13 5,808' - 5,818' (1/17/2008) Module 12 5,850' - 5,860' (1/17/2008) Module 11 6,027' - 6,037' (1/17/2008) Module 10 6,192' - 6,202' (1/16/2008) Module 9 6,301' - 6,311' (1/16/2008) Module 8 6,422' - 6,432' (1/16/2008) Module 7 6,580' - 6,590' (1/16/2008) Module 6 6,625' - 6,635' (1/16/2008) Module 5 6,733' - 6,743' (1/16/2008) Module 4 6,794' - 6,804' (1/16/2008) Module 3 6,884' - 6,894' (1/16/2008) Module 2 6,994' - 7,004' (1/16/2008) Module 1 7,128' - 7,138' (1/15/2008) Perforations: Sand Pool MD TVD Date_______ Sterling A6 3 3,389' - 3,397' 3,377' - 3,385' 10/27/23 Sterling A6 L 3 3,492' - 3,510' 3,469' - 3,497' 09/20/23 Isolated Sterling A8 3 3,551' - 3,556' 3,537' - 3,542' 08/18/23 Isolated Sterling A10 3 3,619' - 3,638' 3,604' - 3,623' 08/13/23 Isolated Sterling B1U 4 3,778' - 3,784' 3,762' - 3,768' 08/10/23 Isolated Sterling B2A 4 3,852' - ,3870' 3,834' - 3,852' 10/08/21 Isolated Sterling B4B 5.1 4,122 - 4,132' 4,101' - 4,111' 08/05/21 Isolated Sterling B5A 5.2 4,168 - 4,178' 4,147' - 4,157' 02/03/21 Isolated 5330' CIBP w/ 35' of cement (2/2/21) 3951' PBTD (tagged during CBL 10/2/21) 3970' Jet Cut (9/28/21) 4115' Set CIBP w/ 25' of cement (9/28/21) 4150' CIBP w/ 10' of cement (8/5/21) 3825' CIBP (8/10/23) 3750' CIBP w/ 25' of cement (8/12/23) TOC @ 3725' 3605' CIBP w/ 12' of cement (8/17/23) TOC @ 3593' 3525' CIBP w/ 6' of cement (TOC @ 3519' - 9/17/23) 3475' CIBP(Partial dumped bailer of cement) From:Jacob Flora To:Brian Glasheen Subject:FW: Cementing Follow Up Report: Excape Control Lines Date:Wednesday, October 25, 2023 10:24:20 AM Boom From: Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent: Monday, July 12, 2021 2:20 PM To: bryan.mclellan@alaska.gov Cc: Taylor Wellman <twellman@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Jake Flora - (C) <Jake.Flora@hilcorp.com> Subject: Cementing Follow Up Report: Excape Control Lines Bryan, Below are the ¼” control lines we squeezed with the grease pump and Halliburton’s FineCem squeeze cement on the Excape IA squeezed wells we did in early January 2021. As you will notice the lines took a varying amount of cement. The 0.25” lines have an ID of 0.152” and capacity of 0.00094 gllons/ft. 2 gallons equates to 2127’ of control line. I plan on updating the WBDs and notating the cement volume pumped on each. Let me know if there is anything additional you would like to see here- Thanks, Jake PTD Well cement volume pumped date cemented 202-091 KBU 11-08Y 2 gallons on each line (7/2/2021) 205-141 KBU 41-06 1.5 gal red, 2 gal yellow and 2 gal green (7/2/2021) 204-209 KBU 42-06 2 gal yellow, 1.5 green and 1 gal red (7/2/2021) 200-179 KBU 44-06 1 gal red and 2 gal green (7/2/2021) 207-149 KBU 14-06Y 1.5 gal green and 0.5 gal red (7/2/2021) 203-217 KBU 23-07 1 gal red, .5 gal green and 1 gal yellow (7/2/2021) 203-025 BCU-11 2 gallons on each line (7/3/2021) 207-149 KBU 14-06Y 1.5 gal green and 0.5 gal red (7/2/2021) Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 10/17/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231017 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BRU 212-26 50283201820000 220058 9/2/2023 AK E-LINE Perf KBU 14-6Y 50133205720000 207149 9/18/2023 AK E-LINE GPT/Plug KBU 23-05 50133206300000 214061 9/9/2023 AK E-LINE GPT/Perf MP S-21 50029230650000 202009 10/7/2023 READ CaliperSurvey MPU C-23 50029226430000 196016 9/21/2023 AK E-LINE Perf MPU M-22 50029236450000 219111 9/20/2023 AK E-LINE Mechanical Cutter Paxton 7 50133206430000 214130 9/8/2023 AK E-LINE Tubing Punch/RCT PBU 06-16B 50029204600200 223072 10/7/2023 HALLIBURTON RBT PBU D-18B 50029206940200 215001 9/14/2023 BAKER RPM PBU J-19 50029216290000 186135 9/26/2023 AK E-LINE TTBP/Cement PBU J-23A 50029217120100 204193 10/4/2023 BAKER SPN PBU N-18A 50029209060100 208175 9/4/2023 BAKER SPN PBU P1-02A 50029217790100 202065 9/11/2023 BAKER SPN PBU P1-13 50029223720000 193074 9/15/2023 HALLIBURTON IPROF PBU R-12A 50029209210100 211055 9/7/2023 BAKER SPN Please include current contact information if different from above. T38062 T38063 T38065 T38064 T38066 T38067 T38068 T38069 T38070 T38071 T38072 T38073 T38074 T38075 T38076 10/20/2023 KBU 14-6Y 50133205720000 207149 9/18/2023 AK E-LINE GPT/Plug Kayla Junke Digitally signed by Kayla Junke Date: 2023.10.20 08:34:04 -08'00' 1. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: N2 Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,600 feet See Schematic feet true vertical 7,573 feet 7,115 (fill) feet Effective Depth measured 3,593 feet N/A feet true vertical 3,579 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 7,571' MD 7,544' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Chad Helgeson, Operations Engineer 323-437 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 chelgeson@hilcorp.com 907-777-8405 N/A Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 60 Size 129' 0 160 0 00 18 9-5/8" 3-1/2" Intermediate 20" 13-3/8" 129' STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 207-149 50-133-20572-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028142 Kenai Field / Sterling Gas Pool 3 Kenai Beluga Unit (KBU) 14-6Y measured true vertical Production Liner 5,318' 7,571' Casing Structural 5,291' 7,544' 5,318' 7,571' 129'Conductor Surface 1,504' TVD 3,090psi 10,540psi 3,060psi 3,450psi 5,750psi 10,160psi 1,504' 1,503' Burst Collapse 1,500psi 1,950psi measured Packer Plugs Junk measured Length p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 12:20 pm, Aug 28, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.25 15:28:32 - 08'00' Noel Nocas (4361) Rig Start Date End Date 8/10/23 8/18/23 08/10/2023 - Thursday PTW, PJSM, Transfer N2 from transport onto pump truck & mobe to 14-06y, spot eq. source companion flange for job. R/U pump lines, check well pressures, WHP 1000psi, IA 30psi. Bring on n2 pump at 750scf, pressure build to 1470 then broke over and tapered down to 1200psi, cont pump pressure dropped to 750, SD & SI pressure 750, Y/J on location spotting eq.(Pressure cont. to drop t/500psi). R/U YJ e-line w/ GPT tool string. M/U lubricator P/T 250/3500 good. RIH w/ GPT found fluid level @ 3870', good. POOH. M/U CIBP tool string, plug od 2.75", (WHP pressure 415psi). RIH t/3825. & log up for tie in. Send log to engineering for verification, good. Pull plug into position, CCL @ 3809.5, CCL distance to plug 15.5', placing plug @3825', Set plug, good indication plug set. P/U 20' RIH tag plug on depth, POOH. Pressure up well w/N2 to against plug t/850psi. OOH, P/U 2 3/8" 6' gun, 5SPF, RIH t/3806'log up for correlation tie in, send to engineering for verification. Pull gun up into position, 3768 @ ccl, ccl to top shot 10', placing shots for P4 B1 Upper @ 3778-3784', fire gun good indication gun fired at surface. monitor pressure:POOH Pre-shot- 850psi Inital shot- no visible change. 5 min- 825psi 10min-790psi 15 min- 700 psi ooh 20 min- 650psi. OOH all shots fired, gun was dry, secure well, RDMO E-line. 08/13/2023 - Sunday YJ arrive, conduct PJSM, review permit with Ops RU & RIH w/ 19' of 2-3/8" 5 SPF HC gun with well at 630 psi. RU N2 unit and pressure up well to 1036 psi with N2. Tie in log sent to town, Geo confirmed on depth, no adjustments made Perforated Sterling Pool 3 A-10 Sand from 3619'-3638'. 0 min = 1036 psi, 5 min = 781 psi, 10 min = 627 psi, 15 min = 522 psi. POOH and guns were dry. RD YJ Eline. 08/12/2023 - Saturday MIRU YJ e-line, R/U GPT tool string, M/U lubricator, PT250/3500 good. RIH Find fluid level @ 3786', Tagged BTM @~3786' POOH. P/U CIBP, f/3 1/2", RIH Pull correlation log, send to engineering for verification of log, good. pull plug into position ccl depth 3734.5', 15.5' to plug from CCL, placing plug @ 3750', Set plug, good indication plug set, pick up 20', RIH & tag on depth, POOH, AOGCC plug tag witness waived by Jim Regg 8-12-23. M/U 20' of 2.5" cmt bailer & fill w/4.6gal RIH tag top of CIBP p/u & dump bailer, TOC 3737.5', re-dress & run 2nd bailer w/4.6gal of cmt, Dump @TOC, making 25' of cmt TOC @ 3725', POOH bailer mt, secure well SDFN 08/17/2023 - Thursday MIRU YJ E-line, PTW and PJSM, M/u tools stab on lubricator and PT 250-2500psi. RIH w/GPT locate fluid @ 2990. R/u Fox N2 eq. Started pumping broke over at 500psi, pushed fluid away. Log GPT locate fluid at 3632. POOH. RIH w/CIBP, f/3-1/2" tbg, RIH Pull correlation log, sent to town confirmed on depth, set top of CIBP at 3605', tag plug confirm set. POOH. RIH w CCL & 22' OF 2.5" Dump Bailed 4.5 GAL. of cement on top of CIBP. (12') Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 14-06Y 50-133-20572-00-00 207-149 Rig Start Date End Date 8/10/23 8/18/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 14-06Y 50-133-20572-00-00 207-149 08/18/2023- Friday PTW and PJSM with YJ and FOX. R/u Fox N2 eq. Pressure up on Tbg to 1554psi. R/d Fox N2. M/u tools stab on well, PT 2500psi. RIH w/GR/CCL and 2-3/8" x 5' HSC 5SPF Gun CCL to top shot=15.5'. Made correlation pass, sent log to town confirmed to depth. Fired gun and perforate 3551-3556'. POOH confirmed all shot fired. RDMO EL. Production to bleed N2 and flow well to sales. A8 A10 B1U B2A B4B B5A Lease: State:Alaska Country:USA Angle/Perfs: Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 D Ambruz Well Name & Number: 8/25/2023Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCL 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 2305' (10/02/21 CBL) Permit #: 207-149 API #: 50-133-20572-00-S1 Prop. Des: ADL - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60°27' 36.75" N Longitude: 151°15' 54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 PA #: 891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt. (10-01-21) IA cement job w 95 bbls 15.3ppg cmt PBTD 3,951' MD 3,933' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: - 15 Excape modules system - Green control line: cemented with 1.5 gallons on 7/2/21 - Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 5,382' - 5,392' (1/17/2008) Module 14 5,442' - 5,452' (1/17/2008) Module 13 5,808' - 5,818' (1/17/2008) Module 12 5,850' - 5,860' (1/17/2008) Module 11 6,027' - 6,037' (1/17/2008) Module 10 6,192' - 6,202' (1/16/2008) Module 9 6,301' - 6,311' (1/16/2008) Module 8 6,422' - 6,432' (1/16/2008) Module 7 6,580' - 6,590' (1/16/2008) Module 6 6,625' - 6,635' (1/16/2008) Module 5 6,733' - 6,743' (1/16/2008) Module 4 6,794' - 6,804' (1/16/2008) Module 3 6,884' - 6,894' (1/16/2008) Module 2 6,994' - 7,004' (1/16/2008) Module 1 7,128' - 7,138' (1/15/2008) Perforations: Sand Pool MD TVD Date_______ Sterling A8 3 3,551' - 3,556' 3,537' - 3,542' 08/18/23 Open Sterling A10 3 3,619' - 3,638' 3,604' - 3,623' 08/13/22 Isolated Sterling B1U 4 3,778' - 3,784' 3,762' - 3,768' 08/10/23 Isolated Sterling B2A 4 3,852' - ,3870' 3,834' - 3,852' 10/08/21 Isolated Sterling B4B 5.1 4,122 - 4,132' 4,101' - 4,111' 08/05/21 Isolated Sterling B5A 5.2 4,168 - 4,178' 4,147' - 4,157' 02/03/21 Isolated SCHEMATIC 5330' CIBP w/ 35' of cement (2/2/21) 3951' PBTD (tagged during CBL 10/2/21) 3970' Jet Cut (9/28/21) 4115' Set CIBP w/ 25' of cement (9/28/21) 4150' CIBP w/ 10' of cement (8/5/21) 3825' CIBP (8/10/23) 3750' CIBP w/ 25' of cement (8/12/23) TOC @ 3725' 3605' CIBP w/ 12' of cement (8/17/23) TOC @ 3593' 1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2.Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number):10. Field: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,600'7,115' (fill) Casing Collapse Structural Conductor 1,500 psi Surface 1,950 psi Intermediate 3,090 psi Production 10,540 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi):Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 207-149 50-133-20572-00-00 Hilcorp Alaska, LLC Proposed Pools: 9.3# / L-80 TVD Burst 7,571' 10,160 psi 1,503' Size 129' 9-5/8"5,318' 1,500' MD See Attached Schematic 5,750 psi 3,060 psi 3,450 psi 129' 5,291' 129' 1,504' September 11, 2023 3-1/2" 7,571' Perforation Depth MD (ft): 5,318' 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 14-6YCO 510C Same 7,544'3-1/2" ~1,189psi 7,571' See Schematic Length N/A; N/A N/A; N/A 7,573'3,593'3,579' Kenai Gas Field Sterling Gas Pool 3 20" 13-3/8" See Attached Schematic m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 10:32 am, Aug 29, 2023 323-490 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.28 16:17:45 - 08'00' Noel Nocas (4361) BJM 9/5/23 Passing MITIA to 2000 psi is required for continued production beyond 30 days after perforating. 10-404 MDG 8/31/2023 X DSR-8/29/23*&: JLC 9/5/2023 09/05/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.09.05 21:29:51 -08'00' RBDMS JSB 090823 Well: KBU 14-06Y Date: 8/28/23 PTD: 207-149 Well Name: KBU 14-06Y API Number: 50-133-20572-00-S1 Current Status: SI Gas Producer Permit to Drill Number: 207-149 First Call Engineer: Chad Helgeson (907) 777-8405 (o) (907) 229-4824 (c) Second Call Engineer: Jake Flora (907) 777-8442 (o) (720) 988-5375 (c) Expected BHP: Maximum Expected BHP: 1,538 psi @ 3,497’ TVD Based on 0.44 psi/ft TVD Maximum Potential Surface Pressure: 1,189 psi @ 3,497’ TVD Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Well Summary KBU 14-06Y was drilled and completed in 2008 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making 3.5 MMCFD. The well went offline in 2020 due to sand production. The well cum’d just under 3.7 BCF and 187 MBW of water from the original completion. In February 2021, the Sterling B5A was perforated coming online over 10MMCFD and flowed for 5 months making 1.1 BCF before watering out. The Sterling B5A was isolated with a plug and the B4B was tested wet. In October 2021 the Sterling B2A sand in Pool 4 was perforated and flowed for 9 months, until it loaded up with water and unable to sustain production. In August 2023, additional Pool4 sands were unsuccessful, and Pool 4 was isolated. Pool 3 A8 and A10 sands were perforated and tested wet. The goal of this project is to plug existing open pool3 sands and add new perforations in the Sterling Pool3 Sand. Notes Regarding Wellbore Condition x Cement Bond Log in 3-1/2” x 9-5/8” annulus Cement top @ 2,305’ (10/2/21) x Calculated Cement top in 9-5/8” w/ 25% washout is 2,606’ x Current Well Conditions: SI Producer T/IA – 16/60 psi x Max Inclination = ~1 degrees x Currently open in Sterling Pool 3 E-Line procedure 1. MIRU N2 Pump and E-line with pressure control equipment 2. PT lubricator and pump lines to 250psi low / 4,000 psi high 3. MU CIBP with GPT tool. 4. Pressure up with N2 and push water away, verifying depth of water with GPT (water must be ~3,550’) 5. RIH and set 4-1/2” CIBP plug at ±3,542’ MD (avoiding collar at 3538’) 6. RIH and dump bail 10’ of cement on top of plug (est ToC ±3,532’ MD) 7. RIH and perforate Kenai Sterling Gas Pool 3 sand with 1,000 psi of N2 Pool Sand Perforation Top (MD) Perforation Bottom (MD) Total Footage (MD) Pool 3 A6L ±3,492’ ±3,510’ ±18’ Pool 3 A6 ±3,389’ ±3,397’ ±8’ a. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist (Daniel Yancy) and Reservoir Engineer (Reid Edwards) for confirmation. b. Verify PTs are open to SCADA or Krystal gauge installed before perforating. Record a tubing surface pressure before and after gun firing at 0, 5, 10, 15 min reading intervals. The goal of this project is to plug existing open pool3 sands and add new perforations in the Sterling Pool3 Sand. Well: KBU 14-06Y Date: 8/28/23 PTD: 207-149 8. Turn well over to operations and flow the well. Post-Perf MIT-IA 9. Perform MIT-IA to 2000psi once job is complete and well has been brought online within 30 days. Contingencies I) Coil Tubing & Nitrogen Procedure (Contingency if fill is encountered after perforating): 1. MIRU Coiled Tubing, notify AOGCC 48 hours in advance of BOP test, PT BOPE to 2000 psi 2. Clean out to TD 3. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU II) E-line Procedure (Contingency if water is encountered after perforating): 1. MIRU E-Line, PT lubricator to 2000 psi 2. RIH and set plug above the perforations OR set patch over the wet perforations. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure – N2 Operations A8 A10 B1U B2A B4B B5A Lease: State:Alaska Country:USA Angle/Perfs: Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 D Ambruz Well Name & Number: 8/25/2023Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCL 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 2305' (10/02/21 CBL) Permit #: 207-149 API #: 50-133-20572-00-S1 Prop. Des: ADL - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60°27' 36.75" N Longitude: 151°15' 54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 PA #: 891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt. (10-01-21) IA cement job w 95 bbls 15.3ppg cmt PBTD 3,951' MD 3,933' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: -15 Excape modules system -Green control line: cemented with 1.5 gallons on 7/2/21 -Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Module 2 ĺ 6,994' - 7,004' (1/16/2008) Module 1 ĺ 7,128' - 7,138' (1/15/2008) Perforations: Sand Pool MD TVD Date_______ Sterling A8 3 3,551' - 3,556' 3,537' - 3,542' 08/18/23 Open Sterling A10 3 3,619' - 3,638' 3,604' - 3,623' 08/13/22 Isolated Sterling B1U 4 3,778' - 3,784' 3,762' - 3,768' 08/10/23 Isolated Sterling B2A 4 3,852' - ,3870' 3,834' - 3,852' 10/08/21 Isolated Sterling B4B 5.1 4,122 - 4,132' 4,101' - 4,111' 08/05/21 Isolated Sterling B5A 5.2 4,168 - 4,178' 4,147' - 4,157' 02/03/21 Isolated SCHEMATIC 5330' CIBP w/ 35' of cement (2/2/21) 3951' PBTD (tagged during CBL 10/2/21) 3970' Jet Cut (9/28/21) 4115' Set CIBP w/ 25' of cement (9/28/21) 4150' CIBP w/ 10' of cement (8/5/21) 3825' CIBP (8/10/23) 3750' CIBP w/ 25' of cement (8/12/23) TOC @ 3725' 3605' CIBP w/ 12' of cement (8/17/23) TOC @ 3593' 8/13/2023 MDG A6 A8 A10 B1U B2A B4B B5A Lease: State:Alaska Country:USA Angle/Perfs: Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 C Helgeson Well Name & Number: 8/28/2023Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCL 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 2305' (10/02/21 CBL) Permit #: 207-149 API #: 50-133-20572-00-S1 Prop. Des: ADL - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60°27' 36.75" N Longitude: 151°15' 54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 PA #: 891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt. (10-01-21) IA cement job w 95 bbls 15.3ppg cmt PBTD 3,951' MD 3,933' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: -15 Excape modules system -Green control line: cemented with 1.5 gallons on 7/2/21 -Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Module 2 ĺ 6,994' - 7,004' (1/16/2008) Module 1 ĺ 7,128' - 7,138' (1/15/2008) Perforations: Sand Pool MD TVD Date_______ Sterling A6 3 ±3,389' - 3,397' ±3,377' - 3,385' Proposed Sterling A6 L 3 ±3,492' - 3,510' ±3,469' - 3,497' Proposed Sterling A8 3 3,551' - 3,556' 3,537' - 3,542' 08/18/23 Isolated Sterling A10 3 3,619' - 3,638' 3,604' - 3,623' 08/13/22 Isolated Sterling B1U 4 3,778' - 3,784' 3,762' - 3,768' 08/10/23 Isolated Sterling B2A 4 3,852' - ,3870' 3,834' - 3,852' 10/08/21 Isolated Sterling B4B 5.1 4,122 - 4,132' 4,101' - 4,111' 08/05/21 Isolated Sterling B5A 5.2 4,168 - 4,178' 4,147' - 4,157' 02/03/21 Isolated PROPOSED 5330' CIBP w/ 35' of cement (2/2/21) 3951' PBTD (tagged during CBL 10/2/21) 3970' Jet Cut (9/28/21) 4115' Set CIBP w/ 25' of cement (9/28/21) 4150' CIBP w/ 10' of cement (8/5/21) 3825' CIBP (8/10/23) 3750' CIBP w/ 25' of cement (8/12/23) TOC @ 3725' 3605' CIBP w/ 12' of cement (8/17/23) TOC @ 3593' ~3540' CIBP w/ 10' of cement (TOC @ ~3530') 8/13/2023 MDG STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/24/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230824 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 14-6Y 50133205720000 207149 8/10/2023 YELLOW JACKET GPT/Plug/Perf KBU 14-6Y 50133205720000 207149 8/12/2023 YELLOW JACKET GPT/Plug/Perf KBU 14-6Y 50133205720000 207149 8/17/2023 YELLOW JACKET GPT/Plug/Perf KBU 22-06 50133205500000 205054 8/3/2023 YELLOW JACKET Gamma Ray KBU 22-06 50133205500000 205054 8/6/2023 YELLOW JACKET Gamma Ray KBU 22-06 50133205500000 205054 8/11/2023 YELLOW JACKET GPT/Plug/Perf MPU J-29A 50029236880100 221023 8/19/2023 READ Caliper Survey PBU S-42A 50029226620100 215055 8/11/2023 READ MAPP PBU PSI-09 50029230950000 202124 7/28/2023 HALLIBURTON WFL-TMD3D Please include current contact information if different from above. T37955 T37955 T37955 T37956 T37956 T37956 T37957 T37958 T37959 8/28/2023 YELLOWKBU 14-6Y 50133205720000 207149 8/10/2023 JACKET GPT/Plug/Perf YELLOWKBU 14-6Y 50133205720000 207149 8/12/2023 JACKET GPT/Plug/Perf YELLOWKBU 14-6Y 50133205720000 207149 8/17/2023 JACKET GPT/Plug/Perf Kayla Junke Digitally signed by Kayla Junke Date: 2023.08.28 15:49:42 -08'00' 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 7,600' 7,115' (fill) Casing Collapse Structural Conductor 1,500 psi Surface 1,950 psi Intermediate 3,090 psi Production 10,540 psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng N/A; N/A N/A; N/A 7,573' 3,951' 3,933' Kenai Gas Field Sterling Gas Pool 4 20" 13-3/8" See Attached Schematic 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 14-6YCO 510B & possibly Sterling Gas Pool 3 7,544'3-1/2" ~3,626psi 7,571' 4115; 4150', 5330' Length August 9, 2023 3-1/2" 7,571' Perforation Depth MD (ft): 5,318' See Attached Schematic 5,750 psi 3,060 psi 3,450 psi 129' 5,291' 129' 1,504' Size 129' 9-5/8"5,318' 1,500' MD Hilcorp Alaska, LLC Proposed Pools: Sterling Gas 4 9.3# / L-80 TVD Burst 7,571' 10,160 psi 1,503' Tubing MD (ft):Perforation Depth TVD (ft): Subsequent Form Required: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 207-149 50-133-20572-00-00 Tubing Size: PRESENT WELL CONDITION SUMMARY Chad Helgeson, Operations Engineer AOGCC USE ONLY Tubing Grade: chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: m n P s 66 t 2 N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 3:19 pm, Aug 01, 2023 323-437 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.08.01 11:31:12 - 08'00' Noel Nocas (4361) MDG 8/8/2023 10-404 DSR-8/4/23BJM 8/8/23 X 1232 psi -bjm Provide AOGCC opportunity to witness MITIA to 2000 psi. GCW 08/09/2023JLC 8/9/2023 Well: KBU 14-06Y Date: 7/25/23 PTD: 207-149 Well Name: KBU 14-06Y API Number: 50-133-20572-00-S1 Current Status: SI Gas Producer Permit to Drill Number: 207-149 First Call Engineer: Chad Helgeson (907) 777-8405 (o) (907) 229-4824 (c) Second Call Engineer: Jake Flora (907) 777-8442 (o) (720) 988-5375 (c) Expected BHP: Maximum Expected BHP: 1,594 psi @ 3,623 TVD Based on 0.44 psi/ft TVD Maximum Potential Surface Pressure: 1,232 psi @ 3,623 TVD Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Well Summary KBU 14-06Y was drilled and completed in 2008 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making 3.5 MMCFD. The well went offline in 2020 due to sand production. The well cumd just under 3.7 BCF and 187 MBW of water from the original completion. In February 2021, the Sterling B5A was perforated coming online over 10MMCFD and flowed for 5 months making 1.1 BCF before watering out. The Sterling B5A was isolated with a plug and the B4B was tested wet. In October 2021 the Sterling B2A sand in Pool 4 was perforated and flowed for 9 months, until it loaded up with water and unable to sustain production. The goal of this project is to test the top sand in the Kenai Sterling Pool 4 sands, if they are unsuccessful plug back Pool 4 and add new perforations in the Sterling Pool 3 Sands. These Sands will not be commingled between Pools. The well will be perforated in one Pool at a time. Notes Regarding Wellbore Condition Cement Bond Log in 3-1/2 x 9-5/8 annulus Cement top @ 2,305 (10/2/21) Calculated Cement top in 9-5/8 w/ 25% washout is 2,606 Current Well Conditions: SI Producer T/IA 0/60 psi Fluid level @ 2900 (4/2/23) Max Inclination = ~1 degrees Currently open in Sterling Pool 4 Pool Tops in KBU 14-06Y based on KU 21-6 reference well in CO 510B Pool 3 Top 3547 MD (3533 TVD) Pool 4 Top 3775 MD (3759 TVD) Pool 5.1 Top 3917 MD (3899 TVD) E-Line procedure 1. MIRU N2 Pump and E-line with pressure control equipment 2. PT lubricator and pump lines to 250psi low / 3,500 psi high 3. MU CIBP with GPT tool. 4. Pressure up with N2 and push water away, verifying depth of water with GPT (water must be ~3,800) 5. RIH and set 4-1/2 CIBP plug at ±3,825 MD (avoiding a collar) 6. Bleed pressure down to <100 psi (perform negative test on plug) 7. RU perf guns and RIH and perforate B1 Upper sand in Pool 4. The goal of this project is to test the top sand in the Kenai Sterling Pool 4 sands, if they are unsuccessful plug back Pool 4 and add new perforations in the Sterling Pool 3 Sands. Well: KBU 14-06Y Date: 7/25/23 PTD: 207-149 Pool Sand Perf Top (MD) Perf Bottom (MD) Perf Top (TVD) Perf Bottom (TVD) Total Footage (MD) Pool 4 B1 Upper ±3,778 ±3,784 ±3,762 ±3,768 ±6 a. Proposed perfs also shown on the proposed schematic in red font. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c. Use Gamma/CCL to correlate. d. Verify PTs on well are open to SCADA before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. e. These sands are in the Kenai Sterling Gas Pool 5.1 per CO 510B. 8. Turn well over to operations and flow the well. Contingency if Kenai Sterling Gas Pool 4 sand is not productive: a. MIRU N2 Pump and E-line with pressure control equipment b. PT lubricator and pump lines to 250psi low / 2,500 psi High c. MU CIBP with GPT tool. d. Pressure up with N2 and push water away, verifying depth of water with GPT (water must be deeper than 3,700) e. RIH and set 3-1/2 CIBP plug at ±3,750 MD (notify State 24hrs to witness test) i. Regulations require plug to be set within 50 of Sterling P4 perfs (3,778 MD) ii. Tag CIBP iii. Do not set plug across a collar f. RIH and dump bail 25 (~ 10 gal) of cement on top of plug (est ToC ±3,725 MD) g. RIH and perforate Kenai Sterling Gas Pool 3 sands Pool Sand Perf Top (MD) Perf Bottom (MD) Perf Top (TVD) Perf Bottom (TVD) Total Footage (MD) Pool 3 A 8 ±3,551 ±3,556 ±3,537 ±3,542 ±5 Pool3 A 10 ±3,619 ±3,638 ±3,604 ±3,623 ±19 i. Perf tubing pressure based on Reservoir engineer requirement, approximately 1000psi ii. If A10 sand is nonproductive, a plug will be set before perforating the A 8 sand iii. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to Geologist (Daniel Yancy) and Reservoir Engineer (Reid Edwards) for confirmation. iv. Verify PTs are open to SCADA before perforating. Record a tubing surface pressure before and after gun firing at 0, 5, 10, 15 min reading intervals. Pool 4. -bjm Well: KBU 14-06Y Date: 7/25/23 PTD: 207-149 h. Turn well over to operations and flow the well. Post-Perf MIT-IA 9. Perform MIT-IA to 2000psi once job is complete and well has been brought online within 30 days. Attachments: 1. Current schematic 2. Proposed Schematic 3. Standard Well procedure N2 Operations B2A B4B B5A Lease: State:Alaska Country:USA Angle/Perfs: 10/19/2021Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCLDated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Donna Ambruz Well Name & Number: 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 2305' (10/02/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60°27' 36.75" N Longitude: 151°15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt. (10-01-21) IA cement job w 95 bbls 15.3ppg cmt PBTD 3,951' MD 3,933' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291'12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: - 15 Excape modules system - Green control line: cemented with 1.5 gallons on 7/2/21 - Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 5,382' - 5,392' (1/17/2008) Module 14 5,442' - 5,452' (1/17/2008) Module 13 5,808' - 5,818' (1/17/2008) Module 12 5,850' - 5,860' (1/17/2008) Module 11 6,027' - 6,037' (1/17/2008) Module 10 6,192' - 6,202' (1/16/2008) Module 9 6,301' - 6,311' (1/16/2008) Module 8 6,422' - 6,432' (1/16/2008) Module 7 6,580' - 6,590' (1/16/2008) Module 6 6,625' - 6,635' (1/16/2008) Module 5 6,733' - 6,743' (1/16/2008) Module 4 6,794' - 6,804' (1/16/2008) Module 3 6,884' - 6,894' (1/16/2008) Module 2 6,994' - 7,004' (1/16/2008) Module 1 7,128' - 7,138' (1/15/2008) Perforations: Sand Pool MD TVD Date_______ Sterling B2A 4 3852' - 3870' 3834' - 3852' 10/08/21 Open Sterling B4B 5.1 4122 - 4132' 4101 - 4111' 08/05/21 Isolated Sterling B5A 5.2 4168 - 4178' 4147 -4157' 02/03/21 Isolated SCHEMATIC 5330' CIBP w/ 35' of cement (2/2/21) 3951' PBTD (tagged during CBL 10/2/21) 3970' Jet Cut (9/28/21) 4115' Set CIBP w/ 25' of cement (9/28/21) 4150' CIBP w/ 10' of cement (8/5/21) A 8 A 10 B1 B2A B4B B5A Lease: State:Alaska Country:USA Angle/Perfs: 7/25/2023Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCLDated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Chad Helgeson Well Name & Number: 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 2305' (10/02/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60°27' 36.75" N Longitude: 151°15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt. (10-01-21) IA cement job w 95 bbls 15.3ppg cmt PBTD 3,951' MD 3,933' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291'12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: - 15 Excape modules system - Green control line: cemented with 1.5 gallons on 7/2/21 - Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 5,382' - 5,392' (1/17/2008) Module 14 5,442' - 5,452' (1/17/2008) Module 13 5,808' - 5,818' (1/17/2008) Module 12 5,850' - 5,860' (1/17/2008) Module 11 6,027' - 6,037' (1/17/2008) Module 10 6,192' - 6,202' (1/16/2008) Module 9 6,301' - 6,311' (1/16/2008) Module 8 6,422' - 6,432' (1/16/2008) Module 7 6,580' - 6,590' (1/16/2008) Module 6 6,625' - 6,635' (1/16/2008) Module 5 6,733' - 6,743' (1/16/2008) Module 4 6,794' - 6,804' (1/16/2008) Module 3 6,884' - 6,894' (1/16/2008) Module 2 6,994' - 7,004' (1/16/2008) Module 1 7,128' - 7,138' (1/15/2008) Perforations: Sand Pool MD TVD Date_______ Sterling A8 3 ±3,551' - 3,556' ±3,537' - 3,542' If necessary Sterling A10 3 ±3,619' - 3,638' ±3,604' - 3,623' If necessary Sterling B1 U 4 ±3,778' - 3,784' ±3,762' - 3,768' Proposed Sterling B2A 4 3,852' - ,3870' 3,834' - 3,852' 10/08/21 Open Sterling B4B 5.1 4,122 - 4,132' 4,101' - 4,111' 08/05/21 Isolated Sterling B5A 5.2 4,168 - 4,178' 4,147' - 4,157' 02/03/21 Isolated PROPOSED 5330' CIBP w/ 35' of cement (2/2/21) 3951' PBTD (tagged during CBL 10/2/21) 3970' Jet Cut (9/28/21) 4115' Set CIBP w/ 25' of cement (9/28/21) 4150' CIBP w/ 10' of cement (8/5/21) 3825' CIBP 3750' CIBP w/ 25' of cement (if necessary) STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/13/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230713-2 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 14-6y 50133205720000 207149 4/2/2023 HALLIBURTON TMD3D MPU C-02 50029208660000 182194 4/29/2023 YELLOW JACKET JET CUT SRU 213B-15 50133206540000 215130 5/9/2023 YELLOW JACKET GPT/PERF SRU 213B-15 50133206540000 215130 4/24/2023 YELLOW JACKET PLUG SRU 231-33 50133101630100 223008 4/25/2023 YELLOW JACKET PERF/GPT/PLUG Please include current contact information if different from above. T37845 T37846 T37847 T37847 T37848 KBU 14-6y 50133205720000 207149 4/2/2023 HALLIBURTON TMD3D Kayla Junke Digitally signed by Kayla Junke Date: 2023.07.13 14:54:16 -08'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 11/02/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 14-6Y (PTD 207-149) Cement Bond Log 10/03/2021 Please include current contact information if different from above. 37' (6HW Received By: 12/07/2021 By Abby Bell at 3:36 pm, Dec 07, 2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 14-06Y (PTD 207-149) PLUG/JET CUT 9/28/2021 Please include current contact information if different from above. 11/02/2021 Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 10/27/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 14-06Y (PTD 207-149) Perf 10/08/2021 Please include current contact information if different from above. 11/02/2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Cement IA Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: 4,115; Total Depth measured 7,600 feet 4,150; 5,330 feet true vertical 7,573 feet 7,115 (fill) feet Effective Depth measured 3,951 feet N/A feet true vertical 3,933 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 7,571' MD 7,544' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Contact Email: Authorized Title:Contact Phone: 3,090psi 10,540psi 3,060psi 3,450psi 5,750psi 10,160psi Burst Collapse 1,500psi 1,950psi 129' 1,503' 5,291' 7,544' 5,318' 7,571'3-1/2" measuredPlugs Junk measured N/A Length 129' 1,504' Size Conductor Surface Intermediate 20" 13-3/8" 9-5/8" Production Liner 5,318' 7,571' Casing STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 207-149 50-133-20572-00-00 N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA028142 Kenai Field / Sterling Gas Pool 4 Hilcorp Alaska LLC 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 3. Address: Kenai Beluga Unit (KBU) 14-6Y measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 159 1,220998 0 4 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 129' 1,504' 285 Structural TVD 321-463 Sr Pet Eng:Sr Pet Geo:Sr Res Eng: Authorized Name and Digital Signature with Date: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 0 51 Jake Flora, Operations Engineer jake.flora@hilcorp.com 907-777-8442Dan Marlowe, ASC Team Operations Manager, 907-283-1329 t Fra O 6. A PG , R Form 10-404 Revised 10/2021 Submit Within 30 days of Operations By Samantha Carlisle at 8:13 am, Oct 20, 2021 Digitally signed by Dan Marlowe (1267) DN: cn=Dan Marlowe (1267), ou=Users Date: 2021.10.19 14:27:47 -08'00' Dan Marlowe (1267) Perforate New Pool SFD 10/20/2021 DSR-10/20/21BJM 10/28/21 RBDMS HEW 10/21/2021 Rig Start Date End Date 9/28/21 10/13/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 14-06Y 50-133-20572-00-00 207-149 09/30/2021 - Thursday 09/28/2021 - Tuesday PTW, JSA with YJES. Move in Yellow Jacket and hot oil truck. Spot 2x 400 bbl Rain for Rent tanks. Rig up 1502 return line to IA. Rig up Hot oil pump line to E-line pump in sub. make up 2.75" gauge ring BHA assembly. Stab on well. Fill stack for PT. Low pt noticed drip from E-line bowen, blow back stack. Pop off and change out lubricator 0-ring. Stab on well. PT stack 250/3,500 psi. Tubing 0 psi, IA 320 psi, OA 50 psi. RIH with CCL, junk catcher and 2.75" gauge ring, solid tag twice at 4,132.5'. POOH to surface. (possible fluid level seen at 850'). Make up 2.75" (3.5" CIBP). Ran log from 4,118'-3,785'. Send log to town. Town wanted 300' more logged. Re log from 4,118'-3,350' and send to town. Confirm on depth. Set CIBP @ 4,115'+A40, 800 lbs on wire. After set weight dropped to 450 lbs. PU and tag CIBP. Plug set. POOH to surface. Make up 2.5" OD x 40' dump bailer and mix 2 cement kits of 9.25 gals for 25' of cement column in 3.5" tubing. RIH tag CIBP at 4,115' pick up and dump cement. Top of cement 4,090' POOH to surface. Make up Jet cutter asembly. RIH with 2.5" OD titan jet cutter. Logged into position. Pressure up tubing to 2,500 psi for over balanced tubing cut. Open IA to return tank. 300 psi IA pressure was small gas/air pocket. No flow. Monitor WHP and IA return tank. Cut tubing @ 3,970' as per sundry. Pressure dropped from 2,500 psi to 800 psi. No fluid at return tank. POOH to surface. SITP 600 psi. Install night cap on E-line valves. Online down tubing with hot oil truck at 2 bbls/min 2,500 psi break over. Returns established from IA. Circulate 15 bbls. Consistent pressure at 2 bbls/min 2,350 psi. Shut down and freeze protect lines, rig down YJES. Location secure. SDFN. Rain for Rent supply tank loaded with 400 bbls of fresh water. Ready for circulation in the AM. 10/01/2021- Friday PTW, JSA. Online down IA with Hot oil truck taking returns from tubing to Rain for Rent tank. Pumping fresh water at 3 bbls/min 1,748 psi. Returns are thick and dark grey. Good indication of the original drilling mud. Returns cleaned up after 390-410 bbls pumped for the day. Continue circulation. Total fluid pumped for IA circulation 1,053 bbls. Shut down truck. Continue hauling dirty returns to G&I. Rig down Hot oil truck and 1 Rain for Rent tank. Move tank over to KDU-1 for Petrospec CTU blow down. Location secure. SDFN. 09/29/2021 - Wednesday PTW, JSA. Supply tank loaded with 400 bbls of fresh water. WHP 0 psi, IA 0 psi, OA 250 psi. Rig up hot oil truck and pump in sub to wellhead. Rig Return line into IA and Rain for Rent tank. PT pump lines to swab valve 250 psi low, 4,500 psi high. Online down tubing taking returns up IA at 3 BPM, 1,586 psi for 20 bbls. Shut down and rig up to reverse out. Pump line hooked up to IA . Return line hooked up to tubing. Online down IA at 3 bbls/min @ 1,566 psi. Tank is showing good 1:1 returns. Shut down for the day. Cruz 170 bbl tanker truck hauling fluids for supply tank to prep for tomorrows circulation. 65 bbl vac truck hauling original IA drilling mud to G&I. Total 514 bbls pumped. Returns were thick and dark. SDFN. PTW, JSA with Halliburton cement crews, Cruz construction vac truck drivers. Perform SIMOPS with both HES E-line and YJOS E-line working next to us. Spot in equipment. Rig up iron to wellhead. Hold pre pumping tail gate meeting. Fill pump and lines at 4 BPM 215 psi. Low pt 250 psi. High PT 4,100 psi. Cement wet at 0840 hrs. Pump 10 bbls of water ahead, confirm well is full and getting 1:1's. Mixed and pumped 440 SKS (95 bbls) of 15.3 ppg cement at 3 bbls/min starting at 70 psi. Shut down and launch wiper plug. Pump displacement of 35 bbls @ 4 BPM 660 psi. Clean up cementing equipment. haul returns to G&I. HES cementers off location. Mixed and pumped 440 SKS (95 bbls) of 15.3 ppg cement a Pump displacement of 35 bbls @ Cut tubing @ 3,970' as per sundry. P CIBP/cement was pressure tested for 30 min to 1500 psi while Pressure up to 2500 psi. See attached email and test chart bjm PU and tag CIBP. Set CIBP @ 4,115'+ RIH tag CIBP at 4,115' pick up and dump cement. Top of cement 4,090' POOH to surface. Rig Start Date End Date 9/28/21 10/13/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 14-06Y 50-133-20572-00-00 207-149 10/13/2021 - Wednesday MITIA 3-1/2 x 9-5/8 annulus to 1600 psi with field triplex, passed. 10/08/2021- Friday YJOS E line crew arrive on location. PTW, JSA. Rig up. (Previous night rigged up to start pressuring up well with sales line gas of 650 psi). Stab on well. PT stack 250/3,500 psi. RIH with 1-11/16" x 7' Weight bar, 1-11/16" GG and 18' of 2-1/8" Owen spiral strip gun loaded 3 spf. 7' ccl to top shot. Send log to town, shift 2' and ok to perf. Pull into position park CCL depth at 3,845'. WHP 650 psi, IA 50 psi, OA 250 psi. Shoot P4-B2A sands from 3,852'-3,870'. Lost 50 lbs on weight gauge. POOH. Tagged up. Pop off well and install night cap. All shots fired. Strip gun was empty. No partial charge bodies remain. Debris left downhole. Start flowing well, rate starting to level out and remain consistent at 625 MCFD @ 30.6 psi. After 1.5 hours from flowing well has unloaded 6.5 bbls of water. Town good with the perf. Ok to rig down E-line unit. Rig down YJES. Location walk around complete. Wellsite secure. Permit closed and turned in. 10/02/2021 - Saturday RU Yellowjacket. Log 3.5in CBL. PBTD 3,951', TOC 2,305'. TOC 2,305'. MITIA 3-1/2 x 9-5/8 annulus to 1600 psi with field triplex, passed. Log 3.5in CBL. Shoot P4-B2A sands from 3,852'-3,870'. B2A B4B B5A Lease: State:Alaska Country:USA Angle/Perfs: 10/19/2021Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCLDated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Donna Ambruz Well Name & Number: 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 2305' (10/02/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60°27' 36.75" N Longitude: 151°15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt. (10-01-21) IA cement job w 95 bbls 15.3ppg cmt PBTD 3,951' MD 3,933' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: -15 Excape modules system -Green control line: cemented with 1.5 gallons on 7/2/21 -Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Module 2 ĺ 6,994' - 7,004' (1/16/2008) Module 1 ĺ 7,128' - 7,138' (1/15/2008) Perforations: Sand Pool MD TVD Date_______ Sterling B2A 4 3852' - 3870' 3834' - 3852' 10/08/21 Open Sterling B4B 5.1 4122 - 4132' 4101 -4111' 08/05/21 Isolated Sterling B5A 5.2 4168 - 4178' 4147 -4157' 02/03/21 Isolated SCHEMATIC 5330' CIBP w/ 35' of cement (2/2/21) 3951' PBTD (tagged during CBL 10/2/21) 3970' Jet Cut (9/28/21) 4115' Set CIBP w/ 25' of cement (9/28/21) 4150' CIBP w/ 10' of cement (8/5/21) Sand Pool MD TVD Date_______ Sterling B2A 4 3852'-3870'3834'-3852'10/08/21Open Sand Pool MD TVD Date Sterling B2A 4 3852 3870 3834 3852 10/08/21 Open Notes:MIT CIBP to 1500 psi for 30 minutes. Customer:Hilcorp Customer Contact:Cole Bartlewski LSD: Job #: Date: Fluid Pumped: KBU 14-06Y CIBP MIT WATER 2021-09-28 19:44 Ticket #: Phone #: Operator:COLE BARTLEWSKI 907-690-2854 Total Fluid Pumped:121.8 USG Date Comment Sep 28, 2021 - 05:42:10 PM P2 DIS PRESS: 1735 PSI, MIT CIBP. Sep 28, 2021 - 06:05:38 PM P2 DIS PRESS: 1646 PSI, end MIT . Final Readings (2021-09-28 18:14): B1 TOTAL: 0 USG PUMP TOTAL: 121.8 USG 1 Winston, Hugh E (CED) From:Jacob Flora <Jake.Flora@hilcorp.com> Sent:Thursday, October 28, 2021 9:12 AM To:McLellan, Bryan J (CED) Cc:Aras Worthington Subject:RE: [EXTERNAL] KBU 14-6Y (PTD 207-149) MIT Attachments:2021-09-28 KBU 14-06Y_CIBP_MIT_1500psi_30min.pdf Bryan, It was done, please see attached report. It wasn’t clear in the well operations summary report that it occurred but the 1500 psi MIT took place prior to continuing to pressure up to 2500 psi, prior to jet cutting the tubing. Thanks, Jake From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Wednesday, October 27, 2021 4:43 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Cc: Aras Worthington <Aras.Worthington@hilcorp.com> Subject: [EXTERNAL] KBU 14‐6Y (PTD 207‐149) MIT Jake, The 10‐404 for Sundry 321‐463 does not mention an MIT of the CIBP/cement plug that was set to isolate the Sterling Gas Pool 5.1 (step 3 of the Sundry). Was this test done? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Winston, Hugh E (CED) From:McLellan, Bryan J (CED) Sent:Tuesday, October 5, 2021 11:02 AM To:Jacob Flora Subject:RE: KBU 14-06Y CBL - AOGCC 10-403 321-463 PTD 207-149 Approved 09-22-21 Thanks Jake. The CBL looks good. You have approval to proceed with perforating per the Sundry 321‐463. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Jacob Flora <Jake.Flora@hilcorp.com> Sent: Monday, October 4, 2021 7:32 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: KBU 14‐06Y CBL ‐ AOGCC 10‐403 321‐463 PTD 207‐149 Approved 09‐22‐21 Good Morning Bryan, Attached is the CBL we ran on KBU 14‐06Y post IA cement job. It looks pretty good and shows TOC about 150’ higher than the planned 2500’. Our next steps are to swab the well down and perforate. We will then do a MITIA after returning it to production. Thanks, Jake From: Roy Wright <rwright@yjosllc.com> Sent: Sunday, October 3, 2021 11:08 PM To: Jacob Flora <Jake.Flora@hilcorp.com> Subject: [EXTERNAL] KBU 14‐06Y CBL KBU 14‐06Y CBL, TAGGED @ 3951’, TOC @ 2305’ Roy Wright SR Wireline Engineer Mobile. 907.690.4612 Web. www.yjosllc.com Addr. 53341-B Sandy Lane Kenai, Alaska 99611 This message contains confidential information and is intended only for the individual named. If you are not the named addressee you should not disseminate, distribute or copy this e-mail. Please notify the sender 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Cement IA 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,600'6100' (fish) Casing Collapse Structural Conductor 1,500 psi Surface 1,950 psi Intermediate 3,090 psi Production 10,540 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: September 23, 2021 3-1/2" 7,571' Perforation Depth MD (ft): 5,318' See Attached Schematic 7,571' 7,544'3-1/2" 20" 13-3/8" 129' 9-5/8"5,318' 1,500' 3,060 psi 3,450 psi 129' 1,503' 5,291' 129' 1,504' 9.3# / L-80 TVD Burst 7,571' 10,160 psi MD 5,750 psi Length Size CO 510B Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 207-149 50-133-20572-00-00 Kenai Beluga Unit (KBU) 14-6Y Kenai / Sterling Gas Pools 4, 3 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic jake.flora@hilcorp.com 7,573'7,115'7,573'505 psi 4150', 5330' N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: Perforate Repair Wepair Well Exploratory BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic13. Well Class after proposed work: Development ServiceStratigraphic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:34 am, Sep 10, 2021 321-463 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.09 14:15:40 -08'00' Taylor Wellman (2143) Variance to 20 AAC 25.112(g) is granted with conditions written into attached procedure. Perforate New Pool SFD 9/10/2021 10-404 CT Sterling Gas Pools 4, 3 DSR-9/13/21 CT BOP test to 3000 psi. BJM 9/20/21 Sterling Gas Pools 3 and 4 cannot be open at the same time without first obtaining an order from the AOGCC authorizing downhole commingling of those pools in this well. X dts 9/22/2021 JLC 9/22/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.22 13:26:46 -08'00' RBDMS HEW 9/24/2021 Well Prognosis Well: KBU 14-06Y Date: 9-09-2021 Well Name:KBU 14-06Y API Number:50-133-20572-00 Current Status:Shut in Gas well Leg:N/A Estimated Start Date:09/23/2021 Rig:E-line Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:207-149 First Call Engineer:Jake Flora (907) 777-8442 (O)(720) 988-5375 (C) Second Call Engineer:Ted Kramer (907) 777-8420 (O)(985) 867-0665 (C) AFE Number: Maximum Expected BHP: ~ 543 psi @ 3,776’ TVD (Based on offset well KBU 44-06 pressure data) Max. Potential Surface Pressure: ~ 505 psi Well Status SI Gas Producer offline since 7/24/2021 (watered out) Brief Well Summary KBU 14-06Y drilled and completed in 2008 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making 3.5 MMCFD. The well went offline in 2020 due to sand production. The well cum’d just under 3.7 BCF and 187 MBW of water from the original completion. In February 2021, the Sterling B5A was perforated coming online over 10MMCFD. It was online over 5 months making 1.1 BCF before watering out. The Sterling B5A was isolated with a plug and the B4B was perf’d but came in wet and would not flow. Last tag at 4,122’ RKB on 8/8/2021 w/ a 2.5” JDC recovering lost tool string. Min ID: 2.992” (3-1/2” L80, 9.3#, 8rd EUE) 3-1/2” x 9-5/8” TOC @ 4030’ MD – CBL 1/17/2021 Variance Request: x A variance to 20 AAC 25.112(g) requiring pressure testing of plugs is requested due to the need to keep water off of sensitive formations, and the mechanical unfeasibility of pressure testing each CIBP with water and not having a way to then remove that water from the wellbore. Each plug will be tagged once after setting and again during cement bailing. This request is for potential plugs set in the process of testing the different zones after the cement job. The plug proposed at 4115’ will be tested to 1500 psi with fluid. x A variance to 20 AAC 25.112(c)(1)(E) requiring 25’ cement over a CIBP is requested due to the close proximity of the perforations being plugged and added. Hilcorp requests to place 10’ of cement over plug back CIBPs set between zones. Wellbore Condition 1/17/2021 CBL logged, TOC in 3-1/2” x 9-5/8” annulus is 4030’ 3/15/2021 MITIA to 1500psi passed 7/2/2021 Control lines cemented from surface Procedure 1. MIRU E-line, PT lubricator to 2,000 psi High. 2. Set CIBP at ~4115’ (above existing perforations), dump bail 10 ft cement on plug. A variance is granted to 20 AAC 25.112(g) for the plug set above the top Sterling Gas Pool 4 to eliminate the pressure test with the condition that the CIBP is tagged before cementing and the TOC is verified by tagging after cement has set up. - bjm 7/2/2021 Control lines cemented from surface Existing perfs are part of Sterling Pool 5.1 and need to be isolated with plug and 25' of cement. The plugs set above the top of existing Pool 5.1 perfs and proposed Pool 4 perfs require 25' of cement dump-bailed on top. There is plenty of room to comply with the regulation without a variance. Any other plug between the proposed perforations will not require cement since the perfs would be within the same pool. bjm. 3/15/2021 MITIA to 1500psi passed 25 ft Well Prognosis Well: KBU 14-06Y Date: 9-09-2021 3. RU Pump truck, MIT CIBP to 1500 psi, record data. 4. Pressure tubing to 2500 psi. 5. Jet cut tubing above TOC at ~3970’. 6. If unable to establish circulation discuss with OE, it may be necessary to jet cut higher at ~3900’. 7. Circulate IA clean. 8. MIRU cement truck. 9. Mix and pump 95 bbls of 15.3 ppg cement down the tubing, drop wiper ball, displace cement to the jet cut with 34.5 bbls water, shut in at wellhead, close all valves. x 95 bbls = 1500’ of 3 ½ x 9 5/8 annular capacity x Planned TOC is 2500’. 10. WOC 3 days. 11. MIRU E-line, PT lubricator to 2,000 psi High. Log CBL, send results to the AOGCC. Coil Tubing Milling Contingency (if cement is left too high in 3.5” tubing) a. MIRU CTU, 24hr notice for BOP test b. Conduct BOP test 250psi low, 3000psi high c. RIH w milling BHA, mill out cement to ~10’ above jet cut depth d. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU. 12. RU slickline, PT lubricator, swab well dry. 13. Pressure up well with field gas prior to perforating. 14. RU E-line, PT lubricator. 15. Perforate the below sand(s): Sterling Sand Top MD Bottom MD Top TVD Bottom TVD Total MD P3_A8 ±3,557’±3,585’±3,543’±3,571’±28’ P3_A9 ±3,606’±3,615’±3,592’±3,601’±9’ P4_B1A ±3,793’±3,811’±3,776’±3,794’±18’ P4_B2A ±3,852’±3,870’±3,835’±3,853’±18’ a) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. b) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c) Use Gamma/CCL to correlate. d) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals after firing gun. e) The listed Sands are governed by Conservation Order 510a. f) Isolation between pools is required. 16. POOH. 17. RD e-line. 18. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) 19. MITIA to 1500 psi within 14 days of initial production. 510B MITIA within 10 days of initial production - consistent with previous approvals for similar work. bjm SFD 9/10/2021 K Sterl Gas Pool 3 ------------------------ K Sterl Gas Pool 4 gy Isolation between pools is required. P4_ Log CBL, send results to the AOGCC. A plug with at least 25' of cement dump bailed on top, tagged and pressure tested to 1500 psi is required per 25.112(c)(1)(E) & (g)(2) is required between Sterling Gas Pools 3 and 4 perfs. bjm P3_ Verified Cement calcs and displacement. No new cement planned inside tubing. Cement will be displaced to the cut depth. Expect some contaminated cement in the annulus just above the cut. Good cement in the annulus between Pools 3 & 4 will be required. bjm SFD 9/10/2021 Well Prognosis Well: KBU 14-06Y Date: 9-09-2021 E-line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 3. RIH and set 3-1/2” Casing Patch or set 3-1/2” CIBP above the zone and dump 10’ of cement on top of the plug. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic Lease: State:Alaska Country:USA Angle/Perfs: 9/8/2021Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCLDated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Jake Flora Well Name & Number: 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 4030' (1/17/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60° 27' 36.75" N Longitude: 151° 15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt PBTD 5,295' MD 5,268' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: - 15 Excape modules system - Green control line: cemented with 1.5 gallons on 7/2/21 - Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Perforations: Sand MD TVD Date Sterling B4B 4122 - 4132' 4101 - 4111' 08/05/21 Sterling B5A 4168 - 4178' 4147 - 4157' 02/03/21 SCHEMATIC 5330' CIBP w/ 35' of cement (2/2/21) 4150' CIBP w/ 10' of cement (8/5/21) Lease: State:Alaska Country:USA Angle/Perfs: Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Trudi Hallett Well Name & Number: 9/8/2021Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCL 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 4030' (1/17/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60° 27' 36.75" N Longitude: 151° 15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt PBTD 5,295' MD 5,268' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: - 15 Excape modules system - Green control line: cemented with 1.5 gallons on 7/2/21 - Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Perforations: Sand MD TVD Date Sterling B4B 4122 - 4132' 4101 - 4111' 08/05/21 Sterling B5A 4168 - 4178' 4147 - 4157' 02/03/21 PROPOSED 5330' CIBP w/ 35' of cement (2/2/21) ~3970' Jet Cut (proposed) ~4115' Set CIBP w/ 10' of cement (proposed) PLANNED Sterling PERFORATIONS: 3557' - 3870' 4150' CIBP w/ 10' of cement (8/5/21) 25' of cement required on CIBP @ 4115'. bjm A plug with 25' of cement is required between Sterling Gas Pool 3 and Sterling Gas pool 4 perfs. bjm 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,600 feet 4,150; 5,330 feet true vertical 7,573 feet 7,115 (fill) feet Effective Depth measured 4,140 feet N/A feet true vertical 4,120 feet N/A feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 7,571' MD 7,544' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Jake Flora Authorized Title:Operations Manager Contact Email: Contact Phone:777-8442 jake.flora@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 3,060psi 10,160psi 129' 1,503' 5,750psi 3,450psi Collapse 1,500psi 1,950psi 3,090psi 10,540psi Casing Structural 20" 13-3/8" 9-5/8" Length 129' 1,504' 5,318' 7,571' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 146 Casing Pressure Liner 0 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-380 5 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 150 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 207-149 50-133-20572-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 76199 Kenai Beluga Unit (KBU) 14-6Y N/A FEDA028142 5,318' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Field / Sterling Gas Pool 5.1N/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 3-1/2"7,571' 5,291' 7,544' WINJ WAG 17 Water-Bbl MD 129' 1,504' 0 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Meredith Guhl at 2:03 pm, Sep 03, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.03 13:53:30 -08'00' Taylor Wellman (2143) DSR-9/3/21 Perforate New Pool RBDMS HEW 9/3/2021 SFD 9/7/2021BJM 10/28/21 Rig Start Date End Date E-Line 8/5/21 8/5/21 Daily Operations: 08/05/2021 - Thursday Sign in and mobe to location. Spot equipment and rig up lubricator. PT to 250 psi low and 3,000 psi high. RIH w/ 2.80" GR, junk basket and sat down at 4,142'. FL was at 2,250'. Hit down on obstruction twice. Ran correlation log and send to town. Town said to add 8'. Added 8'. Bled air out of pack-off line. RIH w/ 2.75" CIBP and tie into OHL. Tag at 4,150'. Run correlation log and send to town. Get ok to set plug at 4,150'. Spotted and set plug. Pick up 30' and went back down and tagged plug. POOH. good set. Mix cement. RIH w/ 2-1/2" bailer x 15' Cement dump bailer (3.7 gal, 10') with 16 ppg cement and tagged plug at 4,150'. Pick up 4', dump cement and pick up another 8' and let cement pour out. Lost 30 lbs of weight. POOH. Good cement dump. CIP 1200 noon. TOC - 4,140'. WOC. RIH w/ 2-1/8" x 10' Spiral Strip Gun, 3 spf, and tie into Plug log. Tag top of cement at 4140' and run correlation to town. Send log to town. Get ok to perf from 4,122' to 4,132' w/637'. Spot and fire gun. After 5 min - 635 psi, 10 min - 632 psi and 15 min 630 psi. POOH. All shots fired. Rig down lubricator and equipment and turn well over to field. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 14-06Y 50-133-20572-00-00 207-149 o perf from 4,122' to 4,132' w The well did not flow, so the MITIA after return to production was not required. bjm o set plug at 4,150' Tag top of cement at 4140' a Lease: State:Alaska Country:USA Angle/Perfs: Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Donna Ambruz Well Name & Number: 8/11/2021Last Revison Date: Completion Fluid: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCL 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 4030' (1/17/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60°27' 36.75" N Longitude: 151°15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt PBTD 4,140' MD 4,120' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: -15 Excape modules system -Green control line: cemented with 1.5 gallons on 7/2/21 -Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Perforations: Sand MD TVD Date Sterling B4B 4122 - 4132' 4101 - 4111' 08/05/21 Sterling B5A 4168 - 4178' 4147 - 4157' 02/03/21 SCHEMATIC 4150' CIBP w 10' cement (8/5/21) 5330' CIBP w/ 35' of cement (2/2/21) Sterling B4B 4122 - 4132' 4101 - 4111' 08/05/21 Sterling B5A 4168 - 4178' 4147 -4157' 02/03/21 David Dempsey Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-5245 E-mail: david.dempsey2@hilcorp.com Please acknowledge receipt and return one copy of this transmittal. Received By: Date: Hilcorp North Slope, LLC Date: 08/26/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL: KBU 14-06Y (PTD 207-149) FTP Folder Contents: Log Print Files and LAS Data Files: Please include current contact information if different from above. 37' (6HW Received By: 08/30/2021 By Abby Bell at 4:52 pm, Aug 26, 2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 7,600'6100' (fish) Casing Collapse Structural Conductor 1,500 psi Surface 1,950 psi Intermediate 3,090 psi Production 10,540 psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15.Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: August 15, 2021 3-1/2" 7,571' Perforation Depth MD (ft): 5,318' See Attached Schematic 7,571' 7,544'3-1/2" 20" 13-3/8" 129' 9-5/8"5,318' 1,500' 3,060 psi 3,450 psi 129' 1,503' 5,291' 129' 1,504' 9.3# / L-80 TVD Burst 7,571' 10,160 psi MD 5,750 psi Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 207-149 50-133-20572-00-00 Kenai Beluga Unit (KBU) 14-6Y Kenai / Beluga - Sterling Gas Pool(s) 5.1 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic jake.flora@hilcorp.com 7,573'7,115'7,573'1,185 5330' N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: Perforate Repair Wepair Well Exploratory BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic13. Well Class after proposed work: Development ServiceStratigraphic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 8:29 am, Jul 30, 2021 321-380 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.07.29 21:12:05 -08'00' Taylor Wellman (2143) Perforate New Pool CO 510B DSR-8/2/21 Variance to 20 AAC 25.112(g) approved on the condition that the CIBP is tagged w/ WL after setting and TOC is tagged w/ WL after cement sets up. SFD 7/30/2021 BJM 8/2/21 SFD 7/30/2021 Variance to 20 AAC 25.112(c)(1)(E) approved. X Notifiy AOGCC to witness MITIA to 1600 psi within 10 days of return to production after perforating. dts 8/2/2021 JLC 8/2/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.08.02 13:56:20 -08'00' RBDMS HEW 8/3/2021 10-404 Well Prognosis Well: KBU 14-06Y Date: 7-28-2021 Well Name: KBU 14-06Y API Number: 50-133-20572-00 Current Status: Shut in Gas well Leg: N/A Estimated Start Date: 08/15/2021 Rig: N2 / E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-149 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: 1600 psi @ 4,198’ TVD (Based on offset well BHP data) Max. Potential Surface Pressure: 1185 psi @ 4,198’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Well Status SI Gas Producer offline since 7/24/2021 (watered out) Brief Well Summary KBU 14-06Y drilled and completed in 2008 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making 3.5 MMCFD. The well went offline in 2020 due to sand production. The well has cum’d just under 3.7 BCF and 187 MBW of water. In January 2021 the Beluga was plugged back and the Sterling B5A successfully perforated producing 1.0 BCF before watering out. Wellbore Condition 1/17/2021 CBL logged, TOC in 3-1/2” x 9-5/8” annulus is 4030’ 3/15/2021 MITIA to 1500psi passed 7/2/2021 Control lines cemented from surface Variance Request A variance to 20 AAC 25.112(g) requiring pressure testing of plugs is requested due to the need to keep water off of sensitive formations, and the mechanical unfeasibility of pressure testing each CIBP with water and not having a way to then remove that water from the wellbore. Each plug will be tagged once after setting and again during cement bailing. E-Line Procedure 1. MIRU E-line, PT lubricator to 3,000 psi High. 2. Depress fluid level with field gas. If necessary RU Nitrogen to pressure up on well prior to setting CIBP. 3. Set CIBP at ~4160’, dump bail 10ft cement on plug. (cement height reduced due to minimal distance from existing perforations) 4. Perforate the below sand: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Plan to Shoot P5.1_B4A ±4,020' ±4,054' 34' ±4,001' ±4,035' Top 20' P5.1_B4B ±4,122' ±4,150' 28' ±4,102' ±4,130' Top 20' a) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. b) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Variance to 20 AAC 25.112(c)(1)(E) approved due to lack of space for 25-ft of cement between pools. bjm Set CIBP at ~4160’, d Kenai Sterling Gas Pool 5.1 P5.1_ SFD 7/30/2021 Variance approved on the condition that the CIBP is tagged after setting and TOC is tagged after cement sets up. bjm In January 2021 the Beluga was plugged back and the Sterling B5A successfully perforated producing 1.0 BCF before watering out. TOC is below proposed perf interval. P5.1_ s 4030’ Well Prognosis Well: KBU 14-06Y Date: 7-28-2021 c) Use Gamma/CCL to correlate. d) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals after firing gun. e) The listed Sands are governed by Conservation Order 510a. 5. POOH. 6. RD e-line. 7. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) E-line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 3. RIH and set 3-1/2” Casing Patch or set 3-1/2” CIBP above the zone and dump 35’ of cement on top of the plug. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Nitrogen Pumping Procedure 510B MITIA to 1600 psi required within 10 days of return to production after perforating. Notify AOGCC to witness MIT. - bjm SFD 7/30/2021 Lease: State:Alaska Country:USA Angle/Perfs: Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Jake Flora Well Name & Number: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field ~ 1º 6% KCL 7/27/2021Last Revison Date: Completion Fluid: 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 4030' (1/17/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60° 27' 36.75" N Longitude: 151° 15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt PBTD 5,295' MD 5,268' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: - 15 Excape modules system - Green control line: cemented with 1.5 gallons on 7/2/21 - Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Module 2 ĺ 6,994' - 7,004' (1/16/2008) Perforations: Sand MD TVD Date Sterling B5A 4168 - 4178' 4147 - 4157' 02/03/21 SCHEMATIC 5330' CIBP w/ 35' of cement (2/2/21) All isolated SFD 7/30/2021 Lease: State:Alaska Country:USA Angle/Perfs:~ 1º 6% KCL 7/27/2021Last Revison Date: Completion Fluid: Well Name & Number: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Jake Flora 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 4030' (1/17/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60° 27' 36.75" N Longitude: 151° 15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt PBTD 5,295' MD 5,268' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape System Details: - 15 Excape modules system - Green control line: cemented with 1.5 gallons on 7/2/21 - Red control line: cemented with 0.5 gallons on 7/2/21 Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Module 2 ĺ 6,994' - 7,004' (1/16/2008) Perforations: Sand MD TVD Date Sterling B5A 4168 - 4178' 4147 - 4157' 02/03/21 PROPOSED 4160' CIBP w 10' cement PLANNED 5330' CIBP w/ 35' of cement (2/2/21) All isolated SFD 7/30/2021 SFD 7/30/2021 Will be Isolated Proposed Sterling B4A 4020' - 4054' MD Proposed Sterling B4B 4122' - 4150' MD STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: N2 Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 7,600 feet 5,330 feet true vertical 7,573 feet 7,115 (fill) feet Effective Depth measured 5,295 feet N/A feet true vertical 5,268 feet N/A feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 7,571' MD 7,544' TVD Packers and SSSV (type, measured and true vertical depth)N/A N/A N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Jake Flora Authorized Title:Operations Manager Contact Email: Contact Phone:777-8442 jake.flora@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 3,060psi 10,160psi 129' 1,503' 5,750psi 3,450psi Collapse 1,500psi 1,950psi 3,090psi 10,540psi Casing Structural 20" 13-3/8" 9-5/8" Length 129' 1,504' 5,318' 7,571' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 630 Casing Pressure Liner 10,990 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-055 929 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 310 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 207-149 50-133-20572-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 270 Kenai Beluga Unit (KBU) 14-6Y N/A FEDA028142 5,318' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Field / Up Tyonek Beluga GasN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 3-1/2"7,571' 5,291' 7,544' WINJ WAG 0 Water-Bbl MD 129' 1,504' 0 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 12:20 pm, Mar 23, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.03.23 12:05:28 -08'00' Taylor Wellman (2143) DSR-3/23/21BJM 4/26/21 SFD 3/24/2021RBDMS HEW 3/26/2021 Rig Start Date End Date 1/28/21 3/15/21 Daily Operations: 01/28/2021 - Thursday JSA with Cruz vac truck operator. Rig up Hot oil truck to IA. PT lines 250/3,500 psi. Open IA valve attempt to fluid pack. Pumps tripped after .5 bbls away. Possible ice plug moving through lines. Line up to circulate to pump truck tank. Start heating fluids. 165°F noticed valve flange and body spraying fluid. Shut down pump and isolate fluid path. 2" ball valve seal parted. All flange bolts and valve body bolts hand tight, ball valve seals compromised. Locate new valve from MRC. Install new valve and gaskets. Pressure test valve. Report spill. Safety Rep indicating 5 gallons of water with 10% methanol. Clean location. Initial pressure on IA 320 psi. Bleed to tank. All returns are gas. Pump 24 bbls of fluid until first sign of catching fluid. Shut down and swap to 60/40. Pressure up IA to 1,600 psi. Hold test pressure for 30 minutes and record with hot oil acquisition. Test started 1517 hrs at 1,602 psi. Test ended at 1552 hrs at 1,594 psi. Good IA MIT. Rig down hot oil truck. Confirmed good data for graph. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 14-06Y 50-133-20572-00-00 207-149 03/15/2021 - Monday 3 days prior filled IA void with 9 bbls with two loads from the field triplex. MIRU HAK hot oil truck to IA. Pressure test pump lines 250/4,500. Fill void with 4 bbls of 60/40 to catch fluid. Pressure up to 1,595 psi. Start 30 min test. End pressure 1,475. Below our 1,500 psi required pressure. Bleed down to zero. Pressure up IA to 1,695 psi for 30 minutes. End pressure 1,639 psi. Good test. Rig down.;send pressure test graph and daily report to town. 02/02/2021 - Tuesday AK Eline conduct JSA and approve PTW. MIRU equipment. PT lubricator to 250/3,000 psi. RU jumper line and stack out gas on well. TP = 850 psi. RIH with Spartek GPT. Find fluid level at 3,050'. RIH with 2.75" CIBP. Falling slowly, getting hung up/sticky. Get to 500' and decide to POOH and MU 2.79" gauge ring and junk basket. RIH with gauge ring/junk basket to 5,400', no issues. POOH. RIH with 2.75" CIBP plus 2 wt bars. No issues RIH. Send correlation data to Geo and subtract 3' from log. RIH and set CIBP in middle of joint at 5,330'. POOH. Start to bleed down well for drawdown test per AOGCC requirements. Starting pressure = 806 psi. Bleed down to 191 psi and hold for 15 minutes to confirm plug is holding. RIH with 2.5" x 30' cement dump bailer and dump on top of CIBP. RIH with 2.5" x 30' cement dump bailer and dump on top of CIBP. Total of 35' of cement. TOC = 5,295'. Cable back spooled on drum. Need to cut cable and get wraps spooled on correctly. Install night cap and will resume tomorrow. 02/03/2021 - Wednesday AK E-line on location. Conduct JSA and approve PTW. MU new cable head to perforating toolstring. Stab onto well and PT lubricator. RIH with 10' spiral perf gun with 2.5" and 25 gram charges. 4 spf, 60 deg phasing. Send correlation log to Geo, on depth. Pressure tubing to 700 psi and perforate 4,168 - 4,178'. Initial pressure = 700 psi, 5 min press = 750 psi, 10 min press = 750 psi, 15 min press = 750 psi. POOH. Confirm shots fired. RDMO. Hand well over to Ops. Good IA MIT. Start to bleed down well for drawdown test per AOGCC requirements. S 3/16/21: MITIA to 1600 psi for 30 minutes passed. Reported 3/19/21: The Excape lines were bled after perforating the well and pressures built back up, indicating the lines were penetrated during perforating. Hilcorp has committed to pump cement down these lines. bjm e up IA to 1,695 psi for 30 minutes. End pressure 1,639 psi. Good test. Total of 35' of cement. TOC = 5,295'. RIH with 2.75" CIBP plus 2 wt bars. set CIBP in middle of joint at 5,330' Pressure up IA to 1,600 psi. RIH with 2.75" CIBP. perforate 4,168 - 4,178'. Lease: State:Alaska Country:USA (TVD): Angle/Perfs: 4,147' - 7,799' ~ 1º 6% KCL 2/22/2021Last Revison Date: Completion Fluid: Well Name & Number: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field Perforations (MD):4,168' - 7,138' Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 Donna Ambruz 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 4030' (1/17/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL - 028142 KB elevation:87' (21' AGL) WBS #: Latitude:60°27' 36.75" N Longitude: 151°15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE Top Bottom MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE Top Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt PBTD 5,295' MD 5,268' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape Flapper Details: Module 1 - no flapper Module 2-15 = Disappearing flapers Module # Depths (MD) Module 15 5,401 Module 14 5,461 Module 13 5,827 Module 12 5,869 Module 11 6,046 Module 10 6,211 Module 9 6,320 Module 8 6,441 Module 7 6,599 Module 6 6,644 Module 5 6,752 Module 4 6,813 Module 3 6,903 Module 2 7,013 Module 1 NA Excape System Details: - 15 Excape modules system -Green control line fired module 1 through 7 -Red contol line fired modules 8 thru 15 -Yellow connecting lines activate reclosing flappers Perfs MD (RKB) (All Beluga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Module 2 ĺ 6,994' - 7,004' (1/16/2008) Module 1 ĺ 7,128' - 7,138' (1/15/2008) Fill tagged @: 7,203' ELM (1/15/2008) 7,115' CTM (2/25/2010) 7,155' WLM (1/24/2014) 880' of cap string fish at 6,100' (est) 3/15/2016 Sterling Perf Adds 4,168' - 4,178' MD SCHEMATIC CIBP @ 5,330' MD w/ 35' of cement 2/2/21 TOC @ 5,295' Customer:Hilcorp Customer Contact:Cole Bartlewski LSD: Job #: Date: Fluid Pumped: KBU 14-06Y WATER - 50/50 methanol 2021-03-16 02:22 Ticket #: Phone #: Operator: KBU 14-06Y IA MIT 1500 FOR 30 COLE BARTLEWSKI 907-690-2854 Total Fluid Pumped:168 USG Date Comment Mar 16, 2021 - 12:08:10 AM P2 DIS PRESS: 1595 PSI, start IA PT 1500 psi for 30 minutes Mar 16, 2021 - 12:38:20 AM P2 DIS PRESS: 1475 PSI, End 30 minute PT. Below 1500 psi. Mar 16, 2021 - 12:54:32 AM P2 DIS PRESS: 1695 PSI, start IA PT 1500 psi for 30 minutes. Mar 16, 2021 - 01:54:47 AM P2 DIS PRESS: 1639 PSI, End IA pressure test. Final Readings (2021-03-16 02:04): B1 TOTAL: 0 USG PUMP TOTAL: 168 USG P2 DIS PRESS: 19 PSI 5 DATE: JOB: LEASE:KEU KBU 14-06Y 212-00124 FIELD:COUNTY / PARISH / API#:Kenai/50-133-20572-00-00 Alaska AFE Budget: FUNC DUE: DAILY LOSS: SIZE:WT:DEPTH:ID:SIZE/WT/THD://GRADE ID: SIZE:WT:DEPTH:ID:// SIZE:WT:DEPTH:ID:// SIZE:WT:DEPTH:ID:// SIZE/DEPTH: DEPTH:ID:SCSSV: DEPTH:ID: DEPTH:ID: DEPTH:ID: DEPTH:ID: PROD TREE: SMALLEST ID:DEPTH:PBTD:ELEVATION:WD: Packer Fluid: FROM 19:00 1:00 PREVIOUS DAILY PREVIOUS CUM $900 $900 $27,762 $27,762 $1,700 $1,700 $2,163 $2,163 TANGIBLE COSTS CUM. JOB COST: HILCORP ENERGY COMPANY DAILY OPERATIONS REPORT REPORT NO. 3/16/2021 FEDA028142 WELL: AFE/PROJ NO: 212-00124 KBU 14-06Y RTP Add Perf B5 907-690-2854 CONTRACTOR / RIG #:/0 Kenai Gas Field STATE: PRESENT OPERATION AT REPORT TIME:MIRU HAK HOT OIL TRUCK FOR IA MIT. DAILY COST: $72,163$32,525 CASING DATA PRODUCTION TUBING EQUIPMENT DATA / Packer: NIPPLES: NIPPLES: NIPPLES: NIPPLES: TBG HD/FLANGE: PRESENT PERFS:0 to 0 TO ACTIVITY SUMMARY (Chronological order for the last 24 hrs.) 1:00 3 days prior filled IA void with 9 bbls with two loads from the field triplex. MIRU HAK hot oil truck to IA. Pressure test pump lines 250/4500. Fill void with 4 bbls of 60/40 to catch fluid. Pressure up to 1595 psi. Start 30 min test. End pressure 1475. Below our 1500 psi required pressure. Bleed down to zero. Pressure up IA to 1695 psi for 30 minutes. End pressure 1639 psi. Good test. Rig down. 1:30 send pressure test graph and daily report to town. CUM ACCIDENTS? Code - Description Job Type Cap WO DAILY INTANGIBLE COSTS Job Type Cap WO Code - Description ICC - Contract Labor/Services ICC - Perforating ICC - Supervision/Consultant ICC - Completion Overhead FLUID:TYPE:WEIGHT:CUM LOSS: LAST BOP TEST:NEXT BOP TEST: REPORTED BY:Cole Bartlewski CONTRACTOR REP: PHONE 5 DATE: JOB: LEASE:KEU KBU 14-06Y 212-00124 FIELD:COUNTY / PARISH / API#:Kenai/50-133-20572-00-00 Alaska AFE Budget: CUM. JOB COST: HILCORP ENERGY COMPANY DAILY OPERATIONS REPORT REPORT NO. 3/16/2021 FEDA028142 WELL: AFE/PROJ NO: 212-00124 KBU 14-06Y RTP Add Perf B5 907-690-2854 CONTRACTOR / RIG #:/0 Kenai Gas Field STATE: PRESENT OPERATION AT REPORT TIME:MIRU HAK HOT OIL TRUCK FOR IA MIT. DAILY COST: $72,163$32,525 REPORTED BY:Cole Bartlewski CONTRACTOR REP: PHONE $32,525 $32,525 $32,525 $32,525 PREVIOUS DAILY PREVIOUS CUMCode - Description CUM Code - Description DAILY TANGIBLE COSTS INTANGIBLE COSTS COST CONTINUED TOTAL TANGIBLE COSTS TOTAL JOB COST TOTAL INTANGIBLE COSTS 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: _Nitrogen______ 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 7,600'6100' (fish) Casing Collapse Structural Conductor 1,500 psi Surface 1,950 psi Intermediate 3,090 psi Production 10,540 psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Jake Flora Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: February 10, 2021 3-1/2" 7,571' Perforation Depth MD (ft): 5,318' See Attached Schematic 7,571' 7,544'3-1/2" 20" 13-3/8" 129' 9-5/8"5,318' 1,500' 3,060 psi 3,450 psi 129' 1,503' 5,291' 129' 1,504' 9.3# / L-80 TVD Burst 7,571' 10,160 psi MD 5,750 psi Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 207-149 50-133-20572-00-00 Kenai Beluga Unit (KBU) 14-6Y Kenai / Beluga - Sterling Gas Pool 5.2 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic jake.flora@hilcorp.com 7,573'7,115'7,573'1,185 N/A N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: Perforate Repair Wepair Well Exploratory BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic13. Well Class after proposed work: Development ServiceStratigraphic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:44 am, Jan 27, 2021 321-055 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.26 16:51:42 -09'00' Taylor Wellman SFD 1/27/2021gls 1/28/21 10-404 Perforate New Pool * MIT-IA to 1500 psi after Sterling B5A perforations _Nitrogen____ Plug Perforations DSR-1/27/21 GAS Comm 1/29/21 dts 1/29/2021 JLC 1/29/2021 RBDMS HEW 2/1/2021 Well Prognosis Well: KBU 14-06Y Date: 1-19-2021 Well Name: KBU 14-06Y API Number: 50-133-20572-00 Current Status: Shut in Gas well Leg: N/A Estimated Start Date: 02/10/2021 Rig: N2 / E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 207-149 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: 1600 psi @ 4,198’ TVD (Based on offset well BHP data) Max. Potential Surface Pressure: 1185 psi @ 4,198’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KBU 14-06Y drilled and completed in 2008 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making 3.5 MMCFD. The well went offline in 2020 due to sand production. The well has cum’d just under 3.7 BCF and 187 MBW of water. The objective of this sundry is to perforate the Sterling B5A which is produces in the offset KBU 22-06 and KBU 23-07 at a rate of 8.3 MMCFD and 4.1 MMCFD, respectively. Wellbore Condition 1/17/2021 CBL logged, TOC in 3-1/2” x 9-5/8” annulus is 4030’ 12/19/2020 D&T @ 5820’ w/ a 2.5” blind box and 1.75 DD bailer Max deviation = 8 degrees at 4000’ Pre-Sundry Work 1. MITIA to 1500psi for 30 minutes. 2. RU Wellhead gas, depress fluid level. E-Line Procedure 3. MIRU E-line, PT lubricator to 3,000 psi High. 4. Set CIBP at ~5350’, dump bail 35ft cement on plug. 5. If necessary pump Nitrogen to depress the fluid level and provide pressure for perforating. 6. Perforate the below sand: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Reservoir Pressure P5.2_B5A ±4,170' ±4,190' ~15 ±4,149' ±4,169' 1600 psi a) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. b) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c) Use Gamma/CCL to correlate. d) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals after firing gun. e) The listed Sands are governed by Conservation Order 510a. 7. POOH. (chart) MIT plug for 15 min 1500 psi / chart CIBP at 5350 ft (isolate Beluga)Sterling objective of this sundry is to perforate the Sterling B5A w Well Prognosis Well: KBU 14-06Y Date: 1-19-2021 8. RD e-line. 9. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Standard Well Procedure – N2 Operations Verify control line integrity after perforating. report to AOGCC results. Note:MIT -IA after perforating the B5A sterling sand. 1500 psi /30 min / chart gls Lease: State:Alaska Country:USA (TVD): Angle/Perfs: Perforations (MD):5,382' - 7,138' Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 T.Hallett Well Name & Number: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field 5,355' - 7,799' ~ 1º 6% KCL 1/18/2021Last Revison Date: Completion Fluid: 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 4030' (1/17/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL -028142 KB elevation:87' (21' AGL) WBS #: Latitude:60°27' 36.75" N Longitude: 151°15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE Top Bottom MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE Top Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt PBTD 7,476' MD 7,449' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape Flapper Details: Module 1 - no flapper Module 2-15 = Disappearing flapers Module # Depths (MD) Module 15 5,401 Module 14 5,461 Module 13 5,827 Module 12 5,869 Module 11 6,046 Module 10 6,211 Module 9 6,320 Module 8 6,441 Module 7 6,599 Module 6 6,644 Module 5 6,752 Module 4 6,813 Module 3 6,903 Module 2 7,013 Module 1 NA Excape System Details: - 15 Excape modules system -Green control line fired module 1 through 7 -Red contol line fired modules 8 thru 15 -Yellow connecting lines activate reclosing flappers Perfs MD (RKB) (All Belu ga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Module 2 ĺ 6,994' - 7,004' (1/16/2008) Module 1 ĺ 7,128' - 7,138' (1/15/2008) Fill tagged @: 7,203' ELM (1/15/2008) 7,115' CTM (2/25/2010) 7,155' WLM (1/24/2014) 880' of cap string fish at 6,100' (est) 3/15/2016 Schematic Lease: State:Alaska Country:USA (TVD): Angle/Perfs: Perforations (MD):5,382' - 7,138' Dated Completed: Revised by: Angle @ KOP and Depth:~ 0.67º / 100 ft @ 1,100' MD 1/15/2008 T.Hallett Well Name & Number: County or Parish: Kenai Beluga Unit 14-6Y Kenai Peninsula Borough Kenai Gas Field 5,355' - 7,799' ~ 1º 6% KCL 1/18/2021Last Revison Date: Completion Fluid: 9-5/8" TOC @ 2606' (calculated w 25% washout) 3-1/2" x 9-5/8" TOC @ 4030' (1/17/21 CBL) Permit #:207-149 API #:50-133-20572-00-S1 Prop. Des:ADL -028142 KB elevation:87' (21' AGL) WBS #: Latitude:60°27' 36.75" N Longitude: 151°15' 54.42" W Spud:11/29/2007 TD:1/15/2008 Rig Released:06:00hrs 12/26/2007 PA #:891006367C KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Drive Pipe 20" K-55 133 ppf PE Top Bottom MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE Top Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt PBTD 7,476' MD 7,449' TVD Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt TD 7,600' MD 7,573' TVD Excape Flapper Details: Module 1 - no flapper Module 2-15 = Disappearing flapers Module # Depths (MD) Module 15 5,401 Module 14 5,461 Module 13 5,827 Module 12 5,869 Module 11 6,046 Module 10 6,211 Module 9 6,320 Module 8 6,441 Module 7 6,599 Module 6 6,644 Module 5 6,752 Module 4 6,813 Module 3 6,903 Module 2 7,013 Module 1 NA Excape System Details: - 15 Excape modules system -Green control line fired module 1 through 7 -Red contol line fired modules 8 thru 15 -Yellow connecting lines activate reclosing flappers Perfs MD (RKB) (All Belu ga Zones): Module 15 ĺ 5,382' - 5,392' (1/17/2008) Module 14 ĺ 5,442' - 5,452' (1/17/2008) Module 13 ĺ 5,808' - 5,818' (1/17/2008) Module 12 ĺ 5,850' - 5,860' (1/17/2008) Module 11 ĺ 6,027' - 6,037' (1/17/2008) Module 10 ĺ 6,192' - 6,202' (1/16/2008) Module 9 ĺ 6,301' - 6,311' (1/16/2008) Module 8 ĺ 6,422' - 6,432' (1/16/2008) Module 7 ĺ 6,580' - 6,590' (1/16/2008) Module 6 ĺ 6,625' - 6,635' (1/16/2008) Module 5 ĺ 6,733' - 6,743' (1/16/2008) Module 4 ĺ 6,794' - 6,804' (1/16/2008) Module 3 ĺ 6,884' - 6,894' (1/16/2008) Module 2 ĺ 6,994' - 7,004' (1/16/2008) Module 1 ĺ 7,128' - 7,138' (1/15/2008) Fill tagged @: 7,203' ELM (1/15/2008) 7,115' CTM (2/25/2010) 7,155' WLM (1/24/2014) 880' of cap string fish at 6,100' (est) 3/15/2016 Sterling Perf Adds ±4170' - ±4190' MD Proposed CIBP @ ±5,350' MD TOC 4030 ft MIT-IA to 1500 psi post perfs STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. STATE OF ALASKA A90KA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon I I Plug PerforationsH Fracture Stimulate Ll Pull Tubing 11 Operations shutdown Ll Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: Pull Cap String ❑✓ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Hilcorp Alaska, LLC Development ❑� Stratigraphic ❑ Exploratory L-1207-149 Service ❑ L "' gob , 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage, AK 99503 50-133-20572-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028142 Kenai Beluga Unit 14-6Y 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 11. Present Well Condition Summary: RECEIVED Total Depth measured 7,600 feet Plugs measured N/A feet true vertical 7,573 feet Junk measured 6,100 & 7,115 feet ,PR 13 2016 Effective Depth measured 6,100 feet Packer measured N/A feet INOGCC true vertical 6,073 feet true vertical N/A feet v Casing Length Size MD TVD Burst Collapse Structural Conductor 129' 20" 129' 129' 3,060psi 1,500psi Surface 1,500' 13-3/8" 1,500' 1,500' 3,450psi 1,950psi Intermediate 5,337' 9-5/8" 5,337' 5,312' 5,750psi 3,090psi Production 7,570' 3-1/2" 7,570' 7,543' 10,160psi 10,540psi Liner Perforation depth Measured depth See Attached Schematic SCA0APR 2 9 2016 True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / L-80 7,570'(MD) 7,543'(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 0 0 370 63 Subsequent to operation: 0 1200 37 375 168 14. Attachments (required per 20 AAC 25.070. 25.071, & 25.283) 15. Well Class after work: Daily Report of Well Operations ❑ Exploratory ❑ Development ❑✓ Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas ❑✓ WDSPL ❑ Printed and Electronic Fracture Stimulation Data ❑ IGSTOR ❑ WINJ ❑ 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: N/A Contact Taylor Nasse - 777-8354 Email tnasse hIICOrp.Com Printed Name Chad Helgeson Title Operations Manager ,17 Signature -/,I1 � Phone 907-777-8405 Date Vulle- Form 10-404 Revised 5/2015 0R 14 2016 Submit Original Only Permit #: 207-149 API #: 50-133-20572-00-S1 Prop. Des: ADL - 028142 KB elevation: 87' (21' AGQ WBS #: Latitude: 60° 27'36.75" N Longitude: 151° 15'54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 PA #: 891006367C KOP A1,100' MD/TVD Build -0.67°/100 from 1,100'- 4,500' Top of Cement (est.) @ - 5,300' MD - 18' above 9-5/8" shoe Excape Flapper Details: Module 1 - no flapper Module 2-15 = Disappearing flapers Country: I USA Module # Depths (MD) Module 15 5,401 Module 14 5,461 Module 13 5,827 Module 12 5,869 Module 11 6,046 Module 10 6,211 Module 9 6,320 Module 8 6,441 Module 7 6,599 Module 6 6,644 Module 5 6,752 Module 4 6,813 Module 3 6,903 Module 2 7,013 Module 1 NA 880' of cap string fish at 6,100' (est) 3/15/2016 Fill tagged 0: 7,203' ELM (1/15/2008) 7,115' CTM (2/25/2010) 7,155' WLM (1/24/2014) KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11 W, S.M. TD PBTD 7,600' MD 7,476' MD 7,573' TVD 7,449' TVD 11 Hilcorp Alaska Drive Pioe 20' K-55 133 ppf PE TOP Bottom MD 0' 129' TVD 0' 129' Surface Casino 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Intermediate Casing 9-5/8" L-80 40 ppf BTC TOR Bottom MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE Top Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt Excape System Details: 15 Excape modules system control line fired module 1 through 7 contol line fired modules 8 thru 15 connecting lines activate reclosing flappers Perfs MD (RKB) (All Beluga Zones): Module 15 - 5,382'- 5,392' (1/17/2008) Module 14 5,442'- 5,452' (1/17/2008) Module 13 -, 5,808'- 5,818' (1/17/2008) Module 12 -, 5,850'- 5,860' (1/17/2008) Module 11 -> 6,027'- 6,037' (1/17/2008) Module 10 6,192'-6,202' (1/16/2008) Module 9 -> 6,301'- 6,311' (1/16/2008) Module 8 - 6,422'- 6,432' (1/16/2008) Module 7 6,580'- 6,590' (1/16/2008) Module 6 -. 6,625'- 6,635' (1/16/2008) Module 5 - 6,733'- 6,743' (1/16/2008) Module 4 6,794'- 6,804' (1/16/2008) Module 3 -> 6,884'- 6,894' (1/16/2008) Module 2 6,994'- 7,004' (1/16/2008) Module 1 -. 7,128'-7,138' (1/15/2008) Well Name & Number: Kenai Beluga Unit 14-6Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: I USA Perforations (MD): 5,382'- 7,138' (TVD): 5,355' - 7,799' Angle @ KOP and Depth: - 0.67° / 100 ft @ 1,100' MD Angle/Perfs: - 10 Dated Completed: 1/15/2008 Completion Fluid: 6% KCL Revised by: Taylor Nasse Last Revison Date: 4/1/2016 0 0 Hilcorp Alaska, LLC Weekly Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 14-06Y I NA 50-133-20572-00-00 207-149 3/14/16 3/16/16 Daily Operations: 03/14/2016 - Monday Arrive @ KGF. JSA/TGSM. Spot up crane and spooler. Pick well house. Bleed off SS clamp and pull with crane, comes slow max pull 6,100 Ib. Hold 6,000 Ib, blow down well, no change. Pump down 3-1/2" w/ 2 Triplex loads, can't pressure up. Pull 100' total, leave clamped overnight. Head in. 03/16/2016 - Wednesday Arrive @ KGF. JSA/TGSM. Spot up crane and spooler. Work line with crane. RU, swab tank, blow down well (dead). Drop Kinley cutter, work line lightly. Work line with crane, comes free. POOH with spooler @ 6,101' with Kinley cutter. OOH. RD, head back, leave line at main office. 0 . Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. 0 - 1 Well History File Identifier Organizing (done) RESCAN Color Items: VGreyscale Items: ❑ Poor Quality Originals: ❑ Other: r] Two-sided 111111111111111111 DIGITAL DATA ❑ Diskettes, No. ❑ Other, No/Type: Re,canNeeaea uuimiuiuuiu OVERSIZED (Scannable) ❑ Maps: ❑ Other Items Scannable by a Large Scanner OVERSIZED (Non -Scannable) ❑ Logs of various kinds: NOTES: ❑ Other:: BY: Maria Date: If7 lo- /s/ Project Proofing__N ymp III IIIIIIIIIII IIIII BY: Maria Date: /s/ Scanning Preparation 4- x 30 = + 15' = TOTAL PAGES (Count does not include cover sheet) BY: Maria Date: t710(? /s/ Production Scanning II ((I'I II I I III I (III Stage 1 Page Count from Scanned File: _ (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: _ZYES NO BY:Maria Date: /s/ Stage 1 If NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. II I II �I II I II II I I III ReScanned III IIIIIIIIIII IIIII BY: Maria Date: /s/ Comments about this file: QualityChecked iuumiiuuiiii 10/6/2005 Well History File Cover Page.doc STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Lj Repair Well Lj Plug Perforations L Perforate Other � Install Capstring 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 ❑✓ Stratigraphic ❑ Exploratory ❑ Service ❑ 207-149 3. Address: 3800 Centerpoint Drive, Suite 100 6. API Number: Anchorage, Alaska 99503 • 50-133-20572-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028142 ! - Kenai Beluga Unit 14-6Y 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A .4' Kenai Field / Up Tyonek Beluga Gas 11. Present Well Condition Summary: Total Depth measured 7,600 feet Plugs measured N/A feet true vertical 7,573 feet Junk measured 7,115 (Fill) feet Effective Depth measured 7,115 feet Packer measured N/A feet true vertical 7,088 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 129' 20" 129' 129' 3,060psi 1,500psi Surface 1,500' 13-3/8" 1,500' 1,500' 3,450psi 1,950psi Intermediate 5,337' 9-5/8" 5,337' 5,312' 5,750psi 3,090psi Production 7,570' 3-1/2" 7,570' 7,543' 10,160psi 10,540psi Liner SCANNED OCT 31 2014, RECEIVED Perforation depth Measured depth 5,382'-7,138' FEB 21 2014 True Vertical depth 5,355' - 7,111' Tubing true depth) , 9.3# / L-80 7,570'(MI1 `%0 43'(TVD) (size, grade, measured and vertical 3-1/2" 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 RBDM MAY 11 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 23 0 71 Subsequent to operation: 0 875 34 0 45 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ❑ Development ❑✓ Service ❑ Stratigraphic ❑ 16. Well Status after work: Oil Gas ✓ WDSPL Daily Report of Well Operations N/A IGSTOR ❑ 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)hllcorp.com Printed Name Paul Chan Title Operations Engineer Signature Y=="Phone 907-777-8333 Date 2/17/2014 Form 10-404 Revised 10/2012 Submit Original Only Permit #: 207-149 'API #: 50-133-20572-00-S1 Prop. Des: ADL - 028142 13 elevation: 87' (21' AGL) WBS #: Latitude: 60° 27'36.75" N Longitude: 151 ° 15' 54.42" W i Spud: 11/29/2007 TD: 1/15/2008 Riq Released: 06:00hrs 12/26/2007 PA #: 891006367C KOP 0 1,100' MD/TVD Build -0.670/100 from 1,100'- 4,500' Top of Cement (est.) @ - 5,300' MD - 18' above 9-5/8" shoe Excape Flapper Details: Module 1 - no flapper Module 2-15 = Disappearing flapers Perforations (MD): Module # Depths (MD) Module 15 5,401 Module 14 5,461 Module 13 5,827 Module 12 5,869 Module 11 6,046 Module 10 6,211 Module 9 6,320 Module 8 6,441 Module 7 6,599 Module 6 6,644 Module 5 6,752 Module 4 6,813 Module 3 6,903 Module 2 7,013 Module 1 NA Install Cap string to 7,090'2/13/2014 Fill tagged (&: 7,203' ELM (1/15/2008) 7,115' CTM (2/25/2010) 7,155' WLM (1/24/2014) KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11 W, S.M. .y Kenai Beluga Unit 14-6Y I "F M f 3 County or Parish: Kenai Peninsula Borough A...a Country: I USA Perforations (MD): 5,382' - 7,138' a 5,355' - 7,799' 'Y i - 0.67° / 100 ft @ 1,100' MD Angle/Perfs: aM x 1/15/2008 Completion Fluid: 6% KCL Revised by: 1 i Last Revison Date: 1/23/2014 { Y TD E744 TD 7,600' MD M D 75' TD , TVD H Hilcarp Alaska Drive Pipe 20" K-55 133 ppf PE TOP Bottom MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC LOP Bottom MD 0' 1,504' TVD 0' 1,503- 1 6" ,503'16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% retums Intermediate Casing 9-5/8" L-80 40 ppf BTC TOR Bottom MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE TOP Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8-112" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G curt Excape SVstem Details: 15 Excape modules system Green control line fired module 1 through 7 Red contol line fired modules 8 thru 15 connecting lines activate reclosing flappers Perfs MD (RKB) (All Beluga Zones): Module 15 - 5,382'- 5,392' (1/17/2008) Module 14 5,442'- 5,452' (1/17/2008) Module 13 -+ 5,808'- 5,818' (1/17/2008) Module 12 --. 5,850'- 5,860' (1/17/2008) Module 11 - 6,027'- 6,037' (1/17/2008) Module 10 -> 6,192'- 6,202' (1/16/2008) Module 9 6,301'- 6,311' (1/16/2008) Module 8 - 6,422'- 6,432' (1/16/2008) Module 7 6,580'- 6,590' (1/16/2008) Module 6 6,625'- 6,635' (1/16/2008) Module 5 - 6,733'- 6,743' (1/16/2008) Module 4 -. 6,794'-6,804' (1/16/2008) Module 3 -+ 6,884'- 6,894' (1/16/2008) Module 2 6,994'- 7,004' (1/16/2008) Module 1 -, 7,128'-7,138' (1/15/2008) Well Name & Number: Kenai Beluga Unit 14-6Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: I USA Perforations (MD): 5,382' - 7,138' (TVD): 5,355' - 7,799' Angle @ KOP and Depth: - 0.67° / 100 ft @ 1,100' MD Angle/Perfs: - 1° Dated Completed: 1/15/2008 Completion Fluid: 6% KCL Revised by: 1 Craig Rang Last Revison Date: 1/23/2014 STATE OF ALASKA AV A OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon H Repair Well Li Plug Perforations U Perforate H Other Remove Capstring 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 ❑✓ Stratigraphic ❑ Exploratory ❑ Service ❑ . 207-149 3. Address: 3800 Centerpoint Drive, Suite 100 6. API Number: Anchorage, Alaska 99503 50-133-20572-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028142 • Kenai Beluga Unit 14-6Y 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 11. Present Well Condition Summary: Total Depth measured ? 7,600 feet Plugs measured N/A feet true vertical 7,573 feet Junk measured 7,115 (Fill) feet Effective Depth measured 7,115 feet Packer measured N/A feet true vertical 7,088 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 129' 20" 129' 129' 3,060psi 1,500psi Surface 1,500' 13-3/8" 1,500' 1,500' 3,450psi 1,950psi Intermediate 5,337' 9-5/8" 5,337' 5,312' 5,750psi 3,090psi Production 7,570' 3-1/2" 7,570' 7,543' 10,160psi 10,540psi Liner DECEIVED Perforation depth Measured depth 5,382'- 7,138' NED MAY 2 9 2014 JAN 2 3 2014 True Vertical depth 5,355'- 7,111' O ��� size, rade, measured and true vertical depth) Tubing C 9 P) 3-1/2" ` 9.3# / L-80 7,570'(MD) 7,543'(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 and final N/A RBDMS9� MAY 18 2014 used pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 664 23 0 71 Subsequent to operation: 0 3.8 0 0 66 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run N/A Exploratory ❑ Development Q e Service ❑ Stratigraphic ❑ Daily Report of Well Operations N/A 16. Well Status after work: Oil Gas ✓ WDSPL Lj IGSTOR ❑ 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: N/A Contact Jeremy Mardambek Email jmardambek(W-hilcorp.com Printed Name Jeremy Mardambek Title Reservoir Engineer Signature ; ' Phone 907-777-8388 Date 1/23/2014 let ✓A Form 10-404 Revised 10/2012 Submit Original Only Permit #: 207-149 API #: 50-133-20572-00-S1 Prop. Des: ADL - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27'36.75" N Longitude: 151' 15'54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 PA #: 891006367C KOP an 1,100' MD/TVD ' Build -0.670/100 from 1,100'- 4,500' Top of Cement (est.) @ - 5,300' MD - 18' above 9-5/8" shoe Excape Flapper Details: Module 1 - no flapper Module 2-15 = Disappearing flapers State: Alaska Module # Depths (MD) Module 15 5,401 Module 14 5,461 Module 13 5,827 Module 12 5,869 Module 11 6,046 Module 10 6,211 Module 9 6,320 Module 8 6,441 Module 7 6,599 Module 6 6,644 Module 5 6,752 Module 4 6,813 Module 3 6,903 Module 2 7,013 Module 1 NA Fill tagged Ca): 7,203' ELM (1/15/2008) 7,115' CTM (2/25/2010) KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R1 1W, S.M. TD PBTD 7,600' MD 4� 7,573' TVD 7,449' TVD State: Alaska Country: I USA Perforations (MD): 5,382' - 7,138' (TVD): 5,355'- 7,799' Angle @ KOP and Depth: - 0.67° / 100 ft @ 1,100' MD rr - 10 Dated Completed: 1/15/2008 Completion Fluid: 6% KCL Revised by: I Craig Rang Last Revison Date: i a' =•j r 1 ' til F fir" a. t c, 3 1� a TD PBTD 7,600' MD 7,476' MD 7,573' TVD 7,449' TVD H Hilcorp Alaska Drive Pipe 20" K-55 133 ppf PE Top Bottom MD 0' 129' TVD 0' 129' Surface Casino 13-3/8" J-55 68 ppf BTC Lop Bottom MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% retums Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt Production Tubing 3-112" L-80 9.3 ppf Mod EUE Top Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt Excape System Details: 15 Excape modules system Green control line fired module 1 through 7 contol line fired modules 8 thru 15 connecting lines activate reclosing flappers Perfs MD (RKB) (All Beluga Zones): Module 15 5,382'- 5,392' (1/17/2008) Module 14 5,442'- 5,452' (1/17/2008) Module 13 5,808'- 5,818' (1/17/2008) Module 12 --> 5,850'- 5,860' (1/17/2008) Module 11 6,027'- 6,037' (1/17/2008) Module 10 6,192'-6,202' (1/16/2008) Module 9 6,301'- 6,311' (1/16/2008) Module 8 6,422'- 6,432' (1/16/2008) Module 7 6,580'- 6,590' (1/16/2008) Module 6 - 6,625'- 6,635' (1/16/2008) Module 5 -+ 6,733'- 6,743' (1/16/2008) Module 4 6,794'- 6,804' (1/16/2008) Module 3 ---> 6,884'- 6,894' (1/16/2008) Module 2 -. 6,994'- 7,004' (1/16/2008) Module 1 --> 7,128'-7,138' (1/15/2008) Well Name & Number: Kenai Beluga Unit 14-6Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: I USA Perforations (MD): 5,382' - 7,138' (TVD): 5,355'- 7,799' Angle @ KOP and Depth: - 0.67° / 100 ft @ 1,100' MD Angle/Perfs: - 10 Dated Completed: 1/15/2008 Completion Fluid: 6% KCL Revised by: I Craig Rang Last Revison Date: 1/23/2014 Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 14-6Y 50-133-20572-00-00 1 207-149 1/22/14 1/22/14 Daily Operations: 1/22/2014 - Wednesday RU Dynacoil unit. Remove slips. Remove 3/8" capstring and from 7,109'. Shut in swab valve. Remove capstring master valve and pack -off. RD and return to production. 1/23/2014 - Thursday No operations to report. 1/24/2014 - Friday No operations to report. 1/25/2014 -Saturday No operations to report. 1/26/2014 -Sunday No operations to report. 1/27/2014 - Monday No operations to report. 1/28/2014 -Tuesday No operations to report. MICROFILMED 6/30/2010 DO NOT PLACE ANY NEW MATERIAL UNDER THIS PAGE C:\temp\Temporary Internet Files\OLK9\Microfilm_Marker.doc aMarathon Alaska Production LLC March 2, 2010 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 14-6Y ,jf� MAR U2M Dear Mr. Aubert: Marathon Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 R0- Aft wuEIVED MAR 0 5 2010 Aleske 01 & rasa Cees. Commission Ancharopr Attached for your records is the10-404 Report of Sundry Well Operations for KBU 14-6Y well. This report covers the work performed to lower the capillary string down hole 59'. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon L Repair Well L Plug Perforations L Stimulate L Other L2✓1 Adjust capillary Performed: Alter Casing ❑ Pull Tubing ❑ Perforate New Pool ❑ Waiver❑ Time Extension ❑ string depth Change Approved Program ❑ Operat. Shutdown ❑ Perforate ❑ Re-enter Suspended Well ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Marathon Alaska Production LLC Development ❑✓ Exploratory El Stratigraphic ❑ Service ❑ 207-149 3. Address: PO Box 1949 6. API Number: Kenai Alaska, 99611-1949 50-133-20572-00-S1 7. Property Designation (Lease Number): 8. Well Name and Number: A - 028142 1 Kenai Beluga Unit 14-6Y 9. Field/Pool(s): Kenai Gas Field / Beluga Pool 11. Present Well Condition Summary: Total Depth measured 7,600' feet Plugs (measured) NA feet true vertical 7,573' feet Junk (measured) NA feet Effective Depth measured 7,476' feet Packer (measured) NA feet true vertical 7,449' feet (true vertical) NA feet Casing Length Size MD TVD Burst Collapse Structural Conductor 108' 20" 129' 129' 3,060 psi 1,500 psi Surface 1,479' 13-3/8" 1,500' 1,500' 3,450 psi 1,950 psi Intermediate 5,316' 9-5/8" 5,337' 5,312' 5,750 psi 3,090 psi Production 7,549' 3-1/2" 7,570' 7,543' 10,160 psi 10,550 psi Liner Perforation depth: Measured depth: 5,382' - 7,138' True Vertical depth: 5,355' - 7,111' Excape 3-1/2" L-80 7,571' MD 7,544' TVD Tubing (size, grade, MD & TVD): Capillary String 3/8" 2205 Stainless Steel 7,109' MD 7,082' TVD SSSV: NA NA MD NA TVD Packers and SSSV (type, MD & TVD): Packers: NA NA MD NA TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): The capillary string was adjusted to a setting depth of 7,109' MD. Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,075 110 1 113 Subsequent to operation: 0 1,150 - 1 309 13. Attachments: 14. Well Class after work: Copies of Logs and Surveys Run Exploratory ❑ Development ❑✓ Service ❑ Daily Report of Well Operations X 15. Well Status after work: Oil L Gas ✓ WDSPL IGSTOR[:] WAG ❑ GINJ❑ WINJ ❑ SPLUG ❑ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: NA Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Technician •C� SignatureJ V Phone (907) 283-1371 Date March 2, 2010 kBDMS MAR 0 5 Z0lo Form 10-404 Revised 7/2009 Submit Original Only fj Ma Operations Summary Report by Job A�toN .OilCompany Well Name: KENAI BELUGA UNIT 14-6Y Qtr/Qtr, Block, Sec, Town, Range Field Name License No. State/Province Country KENAI ALASKA USA Daily Operations Report Date: 2/24/2010 Job Category: R&M MAINTENANCE 24 Hr Summary MIRU BJ Dynacoil and pull 3/8" capillary string to run PL survey. String previously set @ 7,050' MD RKB pulled free w/ 2200# (300# overpull). RD BJ Dynacoil. MIRU Expro wireline to prepare well for PL survey. RIH w/ 2.25" centralizer and 1.6" swage and tag PBTD @ 7,136'. RD Expro for night. &tart bAwrime our (hrs) Activity Code Ops Status Trouble code Comment 07:30 08:30 1.00 SAFETY MTG AF Held PJSM w/ BJ Dynacoil and operator. Discussed slippery conditions, crane hazards, and environmental awareness. Obtained safe work permit. 08:30 10:30 2.00 RURD COIL AF RU Dynacoil truck and equipment. Load tubing spool on truck, split injector, load tubing in chains, and land injector on wellhead. 10:30 12:00 1.50 RUNPUL COIL AF POOH 3/8" capillary string (set @ 7050 MD RKB) w/ 2200# (300# overpull). No issues. 12:00 13:00 1.00 RURD COIL AF Pull injector from wellhead and land on truck. Spot unit on edge of pad and wait to re -run capillary string. RD equipment and secure well. Sign out, turn in safe work permit and leave location. 13:00 13:45 0.75 SAFETY MTG AF Held PJSM w/ Expro and operator. Discussed slippery conditions, emergency operations, and lifting techniques. Obtained safe work permit. 13:45 14:30 0.75 RURD ELEC AF RU wireline truck and equipment, MU lubricator and tool string, and stab on well. 14:30 14:45 0.25 TEST BOPE AF PT lubricator to 2000 psi. Good test. 14:45 16:00 1.25 RUNPUL ELEC AF RIH w/ CCL, 14' weight bars, OJ, LSSJ, 2.25" centralizer, and 1.6" swage. Tag PBTD @ 7136', WT and no progress. POOH. 16:00 17:00 1.00 RURD ELEC AF LD lubricator and RD wireline equipment for night. Secure well, sign out, turn in safe work permit, and leave location. Report Date: 2/25/2010 Job Cate o : R&M MAINTENANCE _ 24 Hr Summary RU Expro wireline. Perform PL survey w/ 120, 90, and 60fpm flowing down passes (spinner quitting on up passes, unable to get good data). SI well and perform 60 fpm passes 1, 2, 4, and 8 hours after shut in. RD Expro. StertTafine End TiriYES psi5d Asiv�ty Citde Cie ent 07:30 08:30 1.00 SAFETY MTG AF Held PJSM w/ Expro. Discussed emergency operations, teamwork, and job operations. Obtained safe work permit. 08:30 09:15 0.75 RURD ELEC AF RU wireline truck and equipment. PU tool string and air test (12.3psia & 16.4degF). Stab lubricator on well. 09:15 09:30 1 0.25 TEST BOPE AF PT lubricator to 1500psi. Good test. www.peloton.com Page 1/3 Report Printed: 3/1/2010 1 A Marathon Operations Summary Report by Job .OilCompany Well Name: KENAI BELUGA UNIT 14-6Y www.peloton.com Page 2/3 Report Printed: 3/1/2010 FitY., :,'trt.hts) Ops Code Activity Code Ops Status 7r Code; Comment =. r 09:30 22:00 12.50 LOG PROD AF Perform PL survey as follows: 5 min bench at tubing hanger (21' MD RKB) start: 115.2psia & 56.1degF end: 124.8psia & 59.1degF RIH 120fpm and start 60fpm down pass @ 5000' 416.5psia & 109.1degF End 60fpm down pass @ 7100', begin 60fpm up pass 566.7psia & 121.8degF Spinner quit @ 6420'. PUH t/ 5000' and begin 90fpm down pass 489.5psia & 109.6degF & 26.7RPS (stationary) End 90fpm down pass @ 7100', begin 90fpm up pass 549.3psia & 121.3degF Spinner quit @ 6420'. PUH t/ 5000' and begin 120fpm down pass 449.7psia & 109.6degF End 120fpm down pass @ 7100', begin 120fpm up pass 507.6psia & 121.2degF Spinner quit @ 6420'. PUH t/ 5000' and shut well in. After 1 hour shut in, begin down pass @ 60fpm 693.6psia & 108.2degF End pass @ 7100', PUH t/ 5000' 965.8psia & 121.3degF After 2 hours shut in, begin down pass @ 60fpm 789.8psia & 108.1degF End pass @ 7100', PUH t/ 5000' 1064.Opsia & 122.OdegF After 4 hours shut in, begin down pass @ 60fpm 950.2psia & 108.3degF End pass @ 7100', PUH t/ 5000' 1124.3psia & 121.8degF After 8 hours shut in, begin down pass @ 60fpm 1039.1 psia & 108.4degF End pass @ 7100', POOH 1190.5psia & 121.7degF At tubing hanger- 950.Opsia & 47.3degF 22:00 23:00 1.00 RURD ELEC AF LD lubricator and RD wireline truck and equipment. Sign out, turn in work permit, and leave location. Daily Operations Report Date: 2/26/2010 Job Category: R&M MAINTENANCE 24 Hr Summary MIRU BJ DynaCoil unit. www.peloton.com Page 2/3 Report Printed: 3/1/2010 '� Mam"M Operations Summary Report by Job ,�„'��' 'ONComPaaN Well Name: KENAI BELUGA UNIT 14-6Y Start Titer End Time Dur (hrs) Qps Code Activity Code Ops Q Status Trouble Code � Comment 09:00 09:30 0.50 SAFETY MTG AF Arrive location, obtain work permit. PJSM - review JSA's, assign jobs, slips, trips, falls, overhead loads, changing weather, ice under snow, pressure testing packoff, environmental issues with soap and methanol, emergency numbers, emergency vehicles, muster area, red lights for fire, blue lights for gas emission, sirens for audible, buddy rule, three second rule. Keep the focus. 09:30 11:15 1.75 RURD COIL AF Rig up coil unit, set beaver ponds under units, manlift. Set Fluid Control valve opening value at 3500#. Test rebuilt packoff for operation. Attack packoff and FC V to capillary string. Pull test connection 600# - test successfull. Set packoff and injector head onto wellhead. Prepare to pressure test wellhead to 1900# - test successfull. 11:15 13:15 2.00 RUNPUL COIL AF Run into well with capillary string. Tag bottom at 7115' measured depth on CTU counter. Pull up 30 feet and tag bottom second time at same depth. Pull Fluid Control Valve up to 7109' MD and set string. Pressure up packoff and set injector head back into cradle. 13:15 14:15 1.00 RURD COIL AF Rig down BJ DynaCoil unit and prepare to turn well back over to production. 14:15 14:30 0.25 SECURE WELL AF secure wellhead, prepare turnover paperwork to production, move to KBU 33-6X www.peloton.com Page 3/3 Report Printed: 3/1/2010 Permit #: 207-149 API #: 50-133-20572-00-S1 Prop. Des: ADL - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27'36.75" N Longitude: 151' 15'54.42" W Sr TC Ri P� KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T41N, R11W, S.M. KOP C& 1,100' MD/TVD Build -0.670/100 from 1,100'- 4,500' a TD PBTD 7,600' MD 7,476' MD 7,573' TVD 7,449' TVD M MARATNOM Drive Pipe 20" K-55 133 ppf PE Top Bottom MD 0' 129' TVD 0' 129' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,318' TVD 0' 5,291' 12-114" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt Production Tubing 3.1/2" L-80 9.3 ppf Mod EUE Top Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8.1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt Excape System Details: 15 Excape modules system Green control line fired module 1 through 7 - Red contol line fired modules 8 thru 15 connecting lines activate reclosing flappers Perfs MD (RKB) (All Belucaa Zones): Module 15 -> 5,382'- 5,392' (1/17/2008) Module 14 -> 5,442'- 5,452' (1/17/2008) Module 13 -> 5,808'- 5,818' (1/17/2008) Module 12 - 5,850'- 5,860' (1/17/2008) Module 11 - 6,027'- 6,037' (1/17/2008) Module 10 - 6,192'- 6,202' (1/16/2008) Module 9 - 6,301'- 6,311' (1/16/2008) Module 8 -> 6,422'- 6,432' (1/16/2008) Module 7 -> 6,580'- 6,590' (1/16/2008) Module 6 -> 6,625'- 6,635' (1/16/2008) Module 5 - 6,733'- 6,743' (1/16/2008) Module 4 - 6,794'- 6,804' (1/16/2008) Module 3 - 6,884'- 6,894' (1/16/2008) Module 2 - 6,994'- 7,004' (1/16/2008) Module 1 - 7,128'-7,138' (1/15/2008) Well Name & Number: Kenai Beluga Unit 14-6Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: I USA Perforations (MD): 5,382' - 7,138' (TVD): 5,355' - 7,799' Angle @ KOP and Depth: - 0,67'/ 100 ft @ 1,100' MD Angle/Perfs: - 1° Dated Completed: 1/15/2008 1 1 Completion Fluid: 6% KCL Revised by: Kevin Skiba I Last Revison Date: 1 3/2/2010 DATA SUBMITTAL COMPLIANCE REPORT 12/15/2008 Permit to Drill 2071490 Well Name/No. KENAI BELUGA UNIT 14-6Y Operator MARATHON OIL CO MD 7600 TVD 7573 Completion Date 1/18/2008 Completion Status 1 -GAS Current Status 1 -GAS REQUIRED INFORMATION Mud Log No Samples No DATA INFORMATION Log Media Types Electric or Other Logs Run: Quad -Combo, Mult formation test, CBL, GR Well Log Information: Received Log/ Electr Data Digital Dataset Col Tye Med/Frmt Number Name og Mud Log Log Mud Log 2 og Induction/Resistivity �og Induction/Resistivity C 3/3/2008 Log Neutron Log Neutron 1 5317 .Cog Sonic /09 See Notes tog Caliper log VLog Induction/Resistivity 5290 7567 Well Cores/Samples Information: API No. 50-133-20572-00-00 UIC N Directional Survey Yes (data taken from Logs Portion of Master Well Data Maint Log Scale Log Media Run No Interval Start Stop OH/ CH Received Comments 2 Col 175 7600 Open 3/3/2008 TVD Drilling Dynamics 2 Col 175 7600 Open 3/3/2008 TVD Formation Log 2 Col 1 5317 7594 ` Open 3/3/2008 MD Array Induction Vectar 2 Col 1 5290 7567 , Open 3/3/2008 TVD Array Induction Shallow Focussed 2 Col 1 5317 7548/ Open 3/3/2008 MD Photo Density Dual Spaced Nuetron 2 Col 1 5317 7548 Open 3/3/2008 TVD Photo Density Dual Spaced Nuetron, CTHRU Processing 2 Col 1 5317 7548 Open 3/3/2008 MD Comp Sonic 2 Col 5317 7594 Open 3/3/2008 MD Compact Quad Combo Quicklook Log Col 1 5317 7548 Open 3/3/2008 MD Hole Volume Caliper Log 2 Col 1 5317 7594 Open 3/3/2008 MD Array Induction Vshallow Focussed i Sample Interval Set Name Start Stop Sent Received Number Comments Cores and/or Samples are required to be submitted. This record automatically created from Permit to Drill Module on: 11/7/2007. DATA SUBMITTAL COMPLIANCE REPORT 12/15/2008 Permit to Drill 2071490 Well Name/No. KENAI BELUGA UNIT 14-6Y Operator MARATHON OIL CO API No. 50-133-20572-00-00 MD 7600 TVD 7573 Completion Date 1/18/2008 Completion Status 1 -GAS Current Status 1 -GAS ADDITIONAL INFORMnN Well Cored? Y Daily History Received? � Q' Chips Received? `7.717` Formation Tops � N Analysis �f-Fides Received? Comments: - 0 w, Pik" Compliance Reviewed By: UIC N Date: -A, k _Du_ g _ 40 ja s • M Marathon MARATHON Oil Company November 11, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7" Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 14-6Y Dear Mr. Maunder: • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Attached for your records is the10-404 Report of Sundry Well Operations for KBU 14-6Y well. The information supplied in this report covers the work performed to install the capillary string in KBU 14-6Y well under Sundry #308-332. This sundry submission was initially submitted on November 6, 2008. 1 inadvertently attached a copy of the 10-403 instead of the 10-404. Please utilize this 10-404 Sundry information for your records along with the well information supplied with the original submittal. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Engineering Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Kenai Well File KJS STATE OF ALASKAA ALAOIL AND GAS CONSERVATION COM ON REPORT OF SUNDRY WELL OPERAT10144S 1. Operations Abandon L Repair Well L Plug Perforations L S i6l6j&LJ"r Oth,.qr L��] Install Capillary Performed: Alter Casing F-1 Pull Tubing F Perforate New Pool ❑ WaiverE time Ektenti'on ❑ String Change Approved Program [:] Operat. Shutdown ❑ Perforate ❑ Re-enter Suspended Well ❑ 2. Operator Name: Marathon Oil Company 4. Well Class Before Work: 5. Permit to Drill Number: Development 2 Exploratory El Stratigraphic El Service E 207-149, 3. Address: PO Box 1949 6. API Number: Kenai Alaska, 99611-1949 50-133-20572-60W 7. KB Elevation (ft): 9. Well Name and Number: 87' (21- AGL) Kenai Beluga Unit 14-15Y' 8. Property Designation: 10. Field/Pool(s): A - 028142 Kenai Gas Field / Tyonek & Upper Beluga 11. Present Well Condition Summary: Total Depth measured 7,600' feet Plugs (measured) NA true vertical 7,573' feet Junk (measured) NA Effective Depth measured 7,476— feet true vertical 7,449'- feet Casing Length Size MID TVD Burst Collapse Structural Conductor 108, 20" 129' 120' 3,060 psi 1,500 psi Surface 1,479- 13-3/8" 1,500. 1,500- 3,450 psi 1,950 psi Intermediate 5,316- 9-5/81, 5,337- 5,312- 5,750 psi 3,090 psi Production 7,549- 3-1/2" 7,570- 7,543- 10,160 psi 10,550 psi Liner Perforation depth: Measured depth: 5,382' - 7,138' True Vertical depth: 5,355- - 7,111' Tubing: (size, grade, and MD) 3/8" 2205 Stainless Steel 7,050' Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): A 3/8" capillary string was installed to facilitate foam injection. The bottom of the capillary string was set to 7,050' MD. Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,970 147 0 122 Subsequent to operation: 0 1,895 0 114 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory E Development ServicesS� 0)0' Daily Report of Well Operations X 16. Well Status after work: Oil F1 Gas 21 - WAGE] GINJ ❑ WINJ [-I WDSPL ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 1 308-332 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technician Vow Signature Phone (907) 283-1371 Date November 6, 2008 Form 10-404 Revised 04/2V6M2 0 2009 Submit Original Only AL , F, N' 9 M Marathon MARATHON Oil Company November 6, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 14-6Y Dear Mr. Maunder: Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Attached for your records is the10-404 Report of Sundry Well Operations for KBU 14-6Y well. This report covers the capillary string installation performed under Sundry #308-332. The capillary string was installed on 10/29/2008 at a depth of 7,050' MD. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Engineering Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS STATE OF ALASKA ALA OIL AND GAS CONSERVATION COWSON APPLICATION FOR SUNDRY APPROVALS,, ; 20 AAC 25.280 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown❑ Perforate ❑ Waiver 1. Other❑✓ Iter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension Install Capillary Change approve program ❑ Pull Tubing ❑ Perforate New Pool ❑ Re-enter Suspended We String 2. Operator Name: Marath Oil Company 4. Current Well Class: 5. Permit to ill Number: Development ❑ Exploratory ❑ Stratigraphic ❑ Service ❑ 207-149 3. Address: PO Box 1949 6. AP7,510-133-20572-00-Sl mber: Kenai Alaska, 611-1949 7. If perforating, closest approach in pool(s) ened by this operation to nearest 8. Well Name and Number: property line where ownership or landowner ip changes: ❑ ❑� K ai Beluga Unit 14-6Y Spacing Exception Required? No 9. Property Designation:10. KB Elevation (ft): 11. Field/Pool(s): A- 028142 87' (21' AGL) Kenai GO/Field / Tyonek & Upper Beluga 12• PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effeca Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 7,600' 7,573' ,476' 7,449' NA NA Casing Length Size MD D Burst Collapse Structural Conductor 108' 20" 129' 120' 3,060 psi 1,500 psi Surface 1,479' 13-3/8" 1,500' 1,500' 3,450 psi 1,950 psi Intermediate 5,316' 9-5/8" ,337' 5,312' 5,750 psi 3,090 psi Production 7,549' 3-1/2" 7X,70' 7,543' 10,160 psi 10,550 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5,382' - 7,138' 5,355' - 7,111' 3/ 2205 Stainless Steel 7,050' Packers and SSSV Type: 0106ackers d SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ❑ 14. Well Classproposed work: fter Detailed Operations Program ❑✓ BOP Sketch ❑ Exploratory Development Service ❑ 15. Estimated Date for 16. Well Status after roposed work: Commencing Operations: September 30, 2008 Oil ❑ GPlugged ❑ Abandoned ❑ WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. Verbal Approval: Date: Commission Representative: tot 18. 1 hereby certify that the foregoing is true and correctbest of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technicia Signature _ P e' (907) 283-1371 Date September 15, 2008 COMMISSION USE ONLY t a representative may witness Sundry Numbe Conditions of approval: N/Tes Plug Integrity ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: ._ _ _ ,..:.. Subsequent Form Require_ ,, ,,__—`!✓_-......_ —„. , APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Form 10-403 Revised 06/20061 ” i` A L Submit in Duplicate ��■■ Marathon "RU- Operations Summary Report " r Oil Company Well Name: KENAI BELUGA UNIT 14-6Y Report Date: 1013012008 Job Category: R&M MAINTENANCE 24 H r Swunary MIRU BJ Dyna coil, run 3�8" capillary string. ops SYUrffhe EidTlne Dir (irs) ox code AoW Code Stals TrMOb Code CMMert 08:00 09:00 1.00 SAFETY MTG AF Uptain work permit, held PJSM and discussed daily operations. 09:00 12:00 3.00 RUP,D COIL AF Move in equipment, spot up around well. Stretch out equipment. MU 30" cap string to dyna coil injector. Install new tree connection fitting to our exsistinq tree cap. 12:00 14:00 2.00 RUP,D COIL AF MU BHA below injector, set centralized chemical pump sub to 3700 psia release pressure. PT tree connection and threaded pack off to 2500 psig with 50150 Methanol water. Good test. 14:00 17:00 3.00 WORK COIL AF Open well, RIH with 30' capillary string down to 7050' KBD. Set pack off o secured tubing. removed injector. Racked up injector to truck. Set reel in tote. 17:00 19:00 2.00 RURD COIL -11F Filled capillary string while running in well. Rigged down and picked up around well. Replaced wellhouse back on well. BJ left lease. www.peloton.com Report Printed: 11.W2008 Permit #: 207-149 API #: 50-133-20572-00-S1 Prop. Des: ADL - 028142 KB elevation: 87' (21' AGL) 60° 27'36.75" N 151 ° 15'54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 PA #: 891006367C Tree cxn = Top of Cement (est.) @ - 5,300' MD - 18' above 9-5/8" shoe KOP (a) 1,100' MD/TVD Build -0.671/100 from 1,100' - 4,500' Module Number Flapper Valve Depths (MD) Module 15 5,405.49 Module 14 5,466.08 Module 13 5,831.34 Module 12 5,875.67 Module 11 6,053.97 Module 10 6,218.48 Module 9 6,326.81 Module 8 6,448.14 Module 7 6,607.44 Module 6 6,652.70 Module 5 6,761.61 Module 4 6,824.39 Module 3 6,912.14 Module 2 7,023.00 Module 1 not applicable Fill tagged (a) 7,203' ELM (1/15/2008) KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. TD PBTD 7,600' M D Drive Pipe 7,573' TVD 7,449' TVD I 20" K-55 133 ppf PE 5,382' - 7,138' (TVD): 5,355' - 7,799' Top Bottom - 0.67° / 100 ft @ 1,100' MD Angle/Perfs: MD 0' 129' 1/15/2008 F Completion Fluid: 60% KCL TVD 0' 129' Kevin Skiba Last Revison Date: 1 11/6/2008 Surface Casing - 13.3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,504' - TVD 0' 1,503' F 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns i Capillary String lk 3/8" 2205 Stainless Steel 5. Top Bottom MD 0' 7,050' TVD 0' 7,023' Intermediate Casing V., 9-5/8" L-80 40 ppf BTC - 4, Top Bottom 1!. MD 0' 5,318' s jl TVD 0' 5,291- 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt Production Tubing i 3.1/2" L-80 9.3 ppf Mod EUE Top Bottom 8rd `+ MD 0' 7,571' • TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt TD PBTD 7,600' M D 7,476' MD 7,573' TVD 7,449' TVD Excape System Details -15 Excape modules system -Green control line fired module 1 through 7 - Red cont line fired modules 8 thru 15 connecting lines activate reclosing flappers Perfs MD (RKB) (All Beluoa Zones): Module 15 5,382' - 5,392' (1/17/2008) Module 14 --> 5,442' - 5,452' (1/17/2008) Module 13 -> 5,808' - 5,818' (1/17/2008) Module 12 - 5,850' - 5,860' (1/17/2008) Module 11 6,027'- 6,037' (1/17/2008) Module 10 6,192'- 6,202' (1/1612008) Module 9 6,301' - 6,311' (1/16/2008) Module 8 6,422'- 6,432' (1/16/2008) Module 7 6,580' - 6,590' (1/16/2008) s Module 6 6,625' - 6,635' (1/16/2008) Module 5 6,733' - 6,743' (1/16/2008) Module 4 6,794' - 6,804' (1/16/2008) Module 3 6,884' - 6,894' (1/16/2008) Module 2 6,994' - 7,004' (1/16/2008) Module 1 7,128'- 7,138' (1/15/2008) Well Name & Number: Kenai Beluga Unit 14-6Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska T Country: I USA Perforations (MD): 5,382' - 7,138' (TVD): 5,355' - 7,799' Angle @ KOP and Depth: - 0.67° / 100 ft @ 1,100' MD Angle/Perfs: Dated Completed: 1 1/15/2008 F Completion Fluid: 60% KCL Revised by: I Kevin Skiba Last Revison Date: 1 11/6/2008 6 0 Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Monday, November 10, 2008 11:24 AM To: 'Skiba, Kevin J.' Cc: 'Chasity R Smith' Subject: KBU 14-6Y (207-149) Kevin, We have received a document for this well. Your letter states that you are submitting a 404 but the form submitted was a 403. Could you submit the 404? No need to resend the attachments. Call or message with any questions. Tom Maunder, PE AOGCC 11/10/2008 0 0 2 ITA E 0 AIASKA / SARAH PALIN, GOVERNOR CONSERVATION OILND GAS 333 W 7th AVENUE, SUITE 100 •� li t.o`r lii•1i1111 O ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 Kevin SMba FAX (907) 276-7542 Engineering Technician Marathon Oil Company PO Box 1949 Kenai AK 99611-1949 ao%- 14 Re: Kenai Gas Field, Upper lyonek/Beluga Gas Pool, 14-6Y Sundry Number: 308-332 Dear Mr. Skiba: 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 Corrunission 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. Chair DATED this day of September, 2008 Encl. Marathon Oil Company Alaska Asset Team M Marathon P.O. Box 1949 Kenai, AK 99611 ARATH MON OSI Company Telephone 907/283-1371 Fax 907/283-1350 September 15, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission' 333 W 7t" Ave ellZ1 ��'�� Anchorage, Alaska 99501 Oil & Gas consC'v �h hOt, .,� miss ar Reference: 10-403 Application for Sundry Approvals Field: Kenai Gas Field, Pad 14-6 + C� Well: Kenai Beluga Unit 14-6Y I !! Dear Mr. Maunder: Marathon proposes to run a 3/8" capillary string in KBU 14-6Y to mitigate water loading. Setting depth of the capillary string should be roughly 7,000' MD. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Engineering Technician Enclosures: 10-403 Sundry Notice Current Well Schematic Detailed Operations Program cc: AOGCC Houston Well File Kenai Well File KJS MDD STA E OF P ALASOIL AND GASTCONSEALASKA AT ON COMMISSION D� RECEIVED APPLICATION FOR SUNDRY APPROVALS`" N 20 AAC 25.280 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown❑ Perforate ❑ "1/3dfv P �` "� 6144' Alter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ❑ Time Extension �Fhor%stall Capillary Change approved program ❑ Pull Tubing ❑ Perforate New Pool ❑ Re-enter Suspended Well ❑ String ' 2. Operator Name: Marathon Oil Company p y 4. Current Well Class: 5. Permit to Drill Number: Development ❑, Exploratory ❑ Stratigraphic ❑ Service ❑ 207-149- 07-149-3. 3.Address: PO Box 1949 6. API Number: Kenai Alaska, 99611-1949 50-133-20572-00-00 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: ❑ Kenai Beluga Unit 14-6Y Spacing Exception Required? Yes No 9. Property Designation:10. KB Elevation (ft): 11. Field/Pool(s): ,q4- A-028142 87' (21' AGL) Kenai Gas Field / Tyonek & Upper Beluga 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): 7,600' 7,573' - 7,476'. 7,449' _ NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 108' 20" 129' 120' 3,060 psi 1,500 psi Surface 1,479' 13-3/8" 1,500' 1,500' 3,450 psi 1,950 psi Intermediate 5,316' 9-5/8" 5,337' 5,312' 5,750 psi 3,090 psi Production 7,549' 3-1/2" 7,570' 7,543' 10,160 psi 10,550 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5,382' - 7,138' 5,355'. 7,111' Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ❑ 14. Well Class after proposed work: Detailed Operations Program ❑� BOP Sketch ❑ Exploratory ❑ Development Q - Service ❑ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: September 30, 2008 Oil ❑ Gas Q Plugged ❑ Abandoned ❑ WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. Verbal Approval: Date: Commission Representative: 18. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technician Signature _ one Date (907) 283-1371 September 15, 2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: .30 301 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Subsequent Form Required: O APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: A '001 -4 i raLnn►1%j Warne rrLUUb Submit in Duplicate Form 10-403 Revised 06/2006 0 2008 Capillary String Installation Page 1 2008 Capillary String Installation Program #2 KGF, SU, NGF KBU 24-7X - Requested KBU 14-6Y - Requested KBU 31-7RD - Requested SU 41-15RD - Requested FC 3 - Requested NS 3 - Requested NS 1 - Requested Obiective 1) Install six new CICM's (injection skids) with 545 gallon totes of foamer at wellheads. 2) Install capillary strings (3/8" 2205 0.049" WT) into seven wells for delivering foamer to alleviate liquid loading. Procedure Companies involved: BJDC, BJCS, UOSS, Big G Installation Procedure: 1) BJCS and ASRC: (PJSM & JSA) a) Place 6 new CICM skids at listed wells (BJCS, Steve Bolton, 252-9864) - deliver with truck (Oilfield Hotshot Service, Billy Hill, 398-4827) - unload CICM from truck with loader (ASRC Hardline Group, Tony, 294-0548) - unbolt and remove CICM roof with loader and place 545 gal foamer tote with loader - replace CICM roof with boom truck (UOSS, Tom David) and bolt roof b) Install CICM internals (BJCS, Steve Bolton, 252-9864). 2) COGZ work order (contact Senette'srg_oup) a) Electrical hookup of CICM. b) Tubing hookup of CICM. Setting Setting String Estimated Depth Depth Spool Setting Fluid Maximum Tag Above Under PT Max Order Well Length Depth Level Perf Depth Depth Fill Water Well Notes ID ran 1 KBU 24-7X 9000' 7965' 7850' 8141' 8165' 300' 115' Exca a 1.75 2 KBU 14-6Y 8000' 7050' 7000' 7138' 7132' 82 50' Exca a 1.69 3 KBU 31-7RD 8000' 7220' 7120' 7534' 7392' 172 100' 1.75 4 SU 41-15RD 12000' 10400' 10300' 11506' 11498' 98 100' Exca a 1.75 5 FC 3 10000' 2720' 2615' Gas from SS 7770' N/A 105' Lon strip 6 NS 3 11000' 9785' 1 9550' 10862' 10970' 1185' 235' 4-1/2" 2 7 NS 1 9000' 8733' None 8956' 10220' 1487 0 4-1/2" 2 Installation Procedure: 1) BJCS and ASRC: (PJSM & JSA) a) Place 6 new CICM skids at listed wells (BJCS, Steve Bolton, 252-9864) - deliver with truck (Oilfield Hotshot Service, Billy Hill, 398-4827) - unload CICM from truck with loader (ASRC Hardline Group, Tony, 294-0548) - unbolt and remove CICM roof with loader and place 545 gal foamer tote with loader - replace CICM roof with boom truck (UOSS, Tom David) and bolt roof b) Install CICM internals (BJCS, Steve Bolton, 252-9864). 2) COGZ work order (contact Senette'srg_oup) a) Electrical hookup of CICM. b) Tubing hookup of CICM. • 2008 Capillary String Installation Page 2 3) UOSS - pull well house 4) BJDC, UOSS (PJSM and JSA): • 1. Have on site: proper spool, Wayne's Well Head Adapter (long/short both), Sundry. Well Control Standards Sheet. 2. MIRU BJ Dyna -Coil unit. 3. Shut swab valve, pull tree -cap flange, remove snap ring and OTIS blanking plug. Replace plug with WWHA (note o -ring). MU flange. 4. P/U Dyna -Coil injector with UOSS crane, install BJDC packoff assembly into 2-7/8" female connection. NOTE: a wrench or tongs may be needed to hold the adapter 5. Set Fluid Control Valve release (set based upon TVD, but OVER) 6. MU BHA with centralizers and secure to 3/8" string. 7. SHUT IN WELL AT WING VALVE to prevent BHA from traveling into flow -tee and down flowline. NOTE: Operator or Company Supervisor may bring well back on after string is below flow -tee 8. RIH to setting depth. 9. Set Rattiguns. Leave 1.5 times SITP (or greater per BJDC) on hydraulic pack off. 10. OPEN WELL TO PRODUCTION 11. Leave remaining spool of tubing outside of well in plastic tote for soap injection skid hookup. 12. Cap the tubing with a Swagelok cap, Swagelok valve, and pressure gauge and HP filter. 13. Lockout Swab, Upper Master and Lower Master as per Capstring Lockout Procedure. 14. Hookup injection line to CICM. NOTE: Start foamer at 1/2 gpd, slowly raising the level to planned rate as the week progresses. CHECK FOR FOAM RETURNS. 15. RDMO. Cleanup site. Sign -out. NOTE: When replacing well house, be careful of the tubing "bend" if it extends through the roof 5) UOSS - replace well house Permit #: 207-149 API #: 50-133-20572-00-S1 Prop. Des: ADL 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27'36.75" N Longitude: 151' 15'54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 PA #: 891006367C Tree cxn = Top of Cement (est.) @ - 5,300' MD - 18' above 9-5/8" shoe KOP (a) 1,100' MD/TVD Build -0.670/100 from 1,100' - 4,500' Module Number Flapper Valve Depths (MD) Module 15 5,405.49 Module 14 5,466.08 Module 13 5,831.34 Module 12 5,875.67 Module 11 6,053.97 Module 10 6,218.48 Module 9 6,326.81 Module 8 6,448.14 Module 7 6,607.44 Module 6 6,652.70 Module 5 6,761.61 Module 4 6,824.39 Module 3 6,912.14 Module 2 7,023.00 Module 1 not applicable Fill tagged (aI 7,203' ELM (1/15/2008) KB U 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11 W, S.M. f w � 1 I V i Perls MD (RKB) (All Beluga Zones): Module t? Module 15 -+ 5,382'- 5,392' (1/17/2008) 1 Module 14 - 5,442' - 5,452' (1/17/2008) 1 � Module 13 -• 5,808' - 5,818' (1/17/2008) 4 -. 6,794'- 6,804' (1/16/2008) Module 12 - 5,850'- 5,860' (1/17/2008) 3 -� 6,884'- 6,894' (1/16/2008) 0 '' MARATHON Drive Pipe 20" K-55 133 ppf PE Top Bottom MD 0' 129' TVD 0' 129' Surface Casing 13.3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,504' TVD 0' 1,503' 16" hole Cmt w/ 486 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Intermediate Casing 9-518" L-80 40 ppf BTC Top Bottom MD 0' 5,318' TVD 0' 5,291' 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt Production Tubing 3-1/2" L-80 9.3 ppf Mod EUE Top Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8-112" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt Excape System Details 15 Excape modules system control line fired module 1 through 7 contol line fired modules 8 thru 15 connecting lines activate reclosing flappers TD Module Perls MD (RKB) (All Beluga Zones): Module 7 -. 6,580'- 6,590' (1/1612008) Module 15 -+ 5,382'- 5,392' (1/17/2008) 1 Module 14 - 5,442' - 5,452' (1/17/2008) 5 - 6,733'- 6,743' (1116/2008) Module 13 -• 5,808' - 5,818' (1/17/2008) 4 -. 6,794'- 6,804' (1/16/2008) Module 12 - 5,850'- 5,860' (1/17/2008) 3 -� 6,884'- 6,894' (1/16/2008) Module 11 -. 6,027'- 6,037' (1/17/2008) bi �. Module 10 -> 6,192'- 6,202' (1/16/2008) - Module 9 -• 6,301' - 6,311' (1116/2008) TD Module 8 - 6,422'- 6,432' (1/16/2008) 7,476' MID Module 7 -. 6,580'- 6,590' (1/1612008) State: Alaska Module 6 - 6,625'- 6,635' (1/16/2008) 5,382' - 7,138' Module 5 - 6,733'- 6,743' (1116/2008) Angle @ KOP and Depth: Module 4 -. 6,794'- 6,804' (1/16/2008) Module 3 -� 6,884'- 6,894' (1/16/2008) Completion Fluid: Module Module 2 -� 6,994' - 7,004' (1116/2008) 1 7,128'- 7,138' (1115/2008) Kevin Skiba Last Revison Date: - TD PBTD 7,600' MID 7,476' MID 7,573' TVD 7,449' TVD Well Name & Number: Kenai Beluga Unit 14-6Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: I USA Perforations (MD): 5,382' - 7,138' (TVD): 5,355' - 7,799' Angle @ KOP and Depth: - 0.67-1100 ft @ 1,100' MD Angle/Perfs: Dated Completed: 1 1/15/2008 Completion Fluid: 6% KCL Prepared by: 1 Kevin Skiba Last Revison Date: 7/31/2008 0 Marathon MARATHON ®'i Company February 28, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Field: Kenai Gas Field Well: Kenai Beluga Unit 14-6Y Dear Mr. Maunder: Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 FREC"'EIVED 1 0 ; y pc'¢ c : e Enclosed please find the Well, Mud, and Open Hole Logs for Kenai Gas Field well KBU 14-6Y. Please call me at (907) 283-1371 if you have any questions or require additional information. Sincerely, a �v Kevin J. Ski a Production Technician Enclosures: Epoch Formation Log TVD Epoch Drilling Dynamics Log TVD Weatherford TVD Array Induction Shallow Focused Log Weatherford MD Photo Density Dual Spaced Neutron Log Weatherford MD Array Induction Vectar Processing Log Weatherford MD Array Induction Shallow Focused Log Weatherford MD Hole Volume Caliper Log Weatherford MD Compact Quad Combo Quicklook Log Weatherford MD Compensated Sonic Log Weatherford TVD Photo Density / DSN CTHRU Processing Log Weatherford MD Photo Density / DSN CTHRU Processing Log • M Marathon MARATHON Oil Company February 21, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7tn Ave Anchorage, Alaska 99501 Reference: 10-421 Open Flow Potential Test Report Field: Kenai Gas Field Well: Kenai Beluga Unit 14-6Y Dear Mr. Maunder: C; Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1360 FEB 2 6 2008 Alaska Oil & Gas Cons. Commission Anchorage Enclosed is the Open Flow Potential Test Report 10-421 for well KBU 14-6Y. This well was spud on November 29, 2007 and completed into the Beluga formation. This well is operating at line pressure which limits our ability to vary the flow rate. As a result, the information in this report was obtained from a one point test. If you have any questions or require additional information, please call me at (907) 283- 1371. Sincerely, r - G 44 Kevin J. Skiba Production Technician Enclosures: 10-421 Open Flow Report (90q — t e-0 cc: Houston Well File Kenai Well File KJS CLR STATE OF ALASKA 0 - ALASRIOIL AND GAS CONSERVATION COMMISSION GAS WELL OPEN FLOW POTENTIAL TEST REPORT r 1a. Test: I Initial Annual Special 1b. Type Test: L�✓j Stabilized Lj Non Stabilized Lj Multipoint Temperature ❑ Constant Time ❑ Isochronal ❑ Other 2. Operator Name: 5. Date Completed: 11. Permit to Drill Number: Marathon Oil Company T Tr z Gas 1/20/2008 207-149 3. Address: PO BOX 1949 6. Date TD Reached: 12. API Number: Kenai, Alaska 99611-1949 12/12/2007 50- 133-20572-00-00 4a. Location of Well (Governmental Section): 7. KB Elevation (ft): 13. Well Name and Number: Surface: 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. 87' above MSL Kenai Beluga Unit 14-6Y Top of Productive Horizon: 8. Plug Back Depth(MD+TVD): 14. Field/Pool(s): 294' FSL, 1,053' FWL, Sec 6, T4N, R11W, S.M. 7,476' MD 7,449' TVD Kenai Gas Field / Total Depth: Beluga & Upper Tyonek Pools 9. Total Depth (MD + TVD): 267' FSL, 1,074' FWL, Sec 6, T4N, R11W, S.M. 7,600' MD 7,573' TVD 4• 4b. Location of Well (State Base Plane Coordinates): 10. Land Use Permit: 15. Property Designation: Surface: x- 272,048 Y- 2,362,530 Zone- 4 A - 028142 TPI: x- 272,056 Y- 2,362,246 Zone- 4 16. Type of Completion (Describe): Total Depth: x- 272,080 Y- 2,362,221 Zone- 4 Excape Completion Process (Multi -Zone, Frac Stimulated) 17. Casing Size Weight per foot, Ib. I.D. in inches Set at ft. 19. Perforations: (MD) From To 3-1/2" 9.3# L-80 2.992" 7,571' MD 5,382' 7,138' 15 Excape Modules 18. Tubing Size Weight per foot, Ib. I.D. in inches Set at ft. NA NA NA NA 20. Packer set at ft: 21. GOR cf/bbl: 22. API Liquid Hydrocardbons: 23. Specific Gravity Flowing Fluid (G): NA - - 0.56 24a. Producing through: 24b. Reservoir Temp: 24c. Reservoir Pressure: 24d. Barometric Pressure (Pa): ❑ Tubing ❑✓ Casing 128.5 F° 487 psia @ Datum 7,449' TVDSS 14.73 psia 25. Length of Flow Channel (L): Vertical Depth (H): Gg: %CO2: % N2: % H2S: Prover: Meter Run: Taps: 0.56 0.347 0.215 0 1 Facility 26. FLOW DATA TUBING DATA CASING DATA No. Prover Choke Line X Orifice Pressure Diff. Temp. Pressure Temp. Pressure Temp. Duration of Flow Size (in.) Size (in.) psig Hw F° prig F° psig F° Hr. 1 • 3.826 X 1.000 417 48.5 64 - - - - 38.00 2• X 0.00 3. X 0.00 4. X 0.00 5. X Basic Coefficient No. Flow Temp. Pressure Gravity Factor Super Comp. Rate Flow (24 -Hour) h� Factor Pm Fg Factor Oi Mcfd Fb or Fp Ft Fpv 1. 71.0 55.71355 431.73 1.00 1.336 1.028689 3956 2. 0 3. 0 4. 0 5. Form 10-421 Revised BRA VAR 0'1RYPTINUED ON REVERSE SIDE � ( � Submit in Duplicate Temperature for Separator for Flowing No. Pr T Tr z Gas Fluid Gg G 1. 0.64 524 1.53 0.945 0.56 2. 3. Critical Pressure 673.1 4• Critical Temperature 343.2 5. Form 10-421 Revised BRA VAR 0'1RYPTINUED ON REVERSE SIDE � ( � Submit in Duplicate Po 2315 Pf 25. AOF (Mcfd) 4,098 Remarks: Excape well. Well not shut-in during test. SIWHP estimated at 2300 psig. Test suspended due to excessive water production I hereby certify that the foregoing is true d correct to the best of my knowledge. Signed Title Senior Completions Engineer DEFINITIONS OF SYMBOLS 1.000 Date 2/21/2008 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 Mcfd/psia Fg Specific gravity factor, dimensionless Fpv Super compressibility factor= � dimensionless Ft Flowing temperature factor, dimensionless G Specific gravity of flowing fluid (air=1.000), dimensionless Gg Specific gravity of separator gas (air=1.00), dimensionless GOR Gas -oil ratio, cu. ft. of gas (14.65 psia and 60 degrees F) per barrel oil (60 degrees F) hw Meter differential pressure, inches of water H Vertical depth corresponding to L, feet (TVD) L Length of flow channel, feet (MD) n Exponent (slope) of back -pressure equation, dimensionless Pa Field barometric pressure, psia Pc Shut-in wellhead pressure, psia Pf Shut-in pressure at vertical depth H, psia Pm Static pressure at point of gas measurement, psia Pr Reduced pressure, dimensionless Ps Flowing pressure at vertical depth H, psia Pt Flowing wellhead pressure, psia Pw Static column wellhead pressure corresponding to Pt, psia Q Rate of flow, Mcfd (14.65 psia and 60 degrees F) Tr Reduced temperature, dimensionless T Absolute temperature, degrees Rankin Z Compressibility factor, dimensionless Recommended procedures for tests and calculations may be found in the Manual of Back- Pressure Testing of Gas Wells, Interstate Oil Compact Commission, Oklahoma City, Oklahoma. Form 10-421 Revised 1/2004 Side 2 Marathon Oil Company Alaska Asset Team M Marathon P.O. Box 1949 Kenai, AK 99611 MARATHON OII COmpany Telephone 907/283-1371 Fax 907/283-1350 February 20, 2008 Mr. Tom Maunder RECEIVE Alaska Ohl & Gas Conservation Commission FEB 2 g 2008 333 W 7 Ave Anchorage, Alaska 99501 Alaska oil & Gas Cons. Commission Anchorage Reference: 10-407 Well Completion Report Field: Kenai Gas Field Well: Kenai Beluga Unit 14-6Y Dear Mr. Maunder: Enclosed please find the 10-407 Well Completion Report and Log for Kenai Gas Field well KBU 14-6Y. The well was completed into the Beluga zone. Gas production was initiated on January 20, 2008 with a present production rate of 2,520mcf at 373psi. Please call me at (907) 283-1371 if you have any questions or require additional information. Sincerely, V a'ct) Kevin J. kiba Production Technician Enclosures: 10-407 Well Completion Report Well Schematic Operations Summary Directional Survey Multi Formation Test Surface Plat cc: Houston Well File Kenai Well File KJS CLR STATE OF ALASKA RECEIVED �V ALASKA O1L AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND US& 2 6 2008 1a. Well Status: Oil ❑ Gas ❑ Plugged ❑ Abandoned ❑ Suspended ❑ 20AAC 25.105 20AAC 25.110 GINJ❑ WINJ❑ WDSPL❑ WAGE]Other❑ No. of Completions: 2. Operator Name: 5. Date Comp., Suspor OW12. Marathon Oil Company Abend.: 1/1008 1b. Well Class: Alaska Oil & Gass.C Development ❑✓ ExpI ato L Service ❑ Stratigraph�g8 Permit to Drill Number: 207-149 3. Address: PO Box 1949, Kenai Alaska, 99611-1949 6. Date Spudded: 11/29/2007 13. API Number: 50-13320572-00-00 " 4a. Location of Well (Governmental Section): Surface: 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Top of Productive Horizon: 294' FSL, 1,053' FWL, Sec 6, T4N, R11W, S.M. Total Depth: 267' FSL, 1,074' FWL, Sec 6, T4N, R11W, S.M. 7. Date TD Reached: 12/12/2007 14. Well Name and Number: KBU 14-6Y " 8. KB (ft above MSL): 871, Ground (ft MSL): 66' 15. Field/Pool(s): Kenai Gas Field Beluga & Upper Tyonek Pools 9. Plug Back Depth(MD+TVD): 7,476' MD ' 7,449' TVD 4b. Location of Well (State Base Plane Coordinates, NAD 27): Surface: x- 272,048 y- 2,362,530 Zone- 4 TPI: x- 272,056 y- 2,362,246 Zone- 4 Total Depth: x- 272080 y- 2,362,221 Zone- 4 10. Total Depth (MD + TVD): 7,600' MD " 7,573' TVD 16. Property Designation: ,, A-028142 - 11. SSSV Depth (MD + TVD): NA 17. Land Use Permit: 18. Directional Survey: Yes ✓ No H (Submit electronic and printed information per 20 AAC 25.050) 19. Water Depth, if Offshore: NA (ft MSL) 20. Thickness of Permafrost (TVD): NA 21. Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): Quad -Combo Multi Formation Test, CBL, GR 22. CASING, LINER AND CEMENTING RECORD WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD CASING FT TOP BOTTOM TOP BOTTOM HOLE SIZE AMOUNT CEMENTING RECORD PULLED 0 20" 133# K-55 0' 129' 0' 129' Driven NA NA 13-3/8" 68# J-55 0' 1,504' 0' 1,503' 16" 486 sks, Type 1 NA 0 40# L-80 0' 5,318' 0' 95/8'.12-1/4" 5,291'--T- 320 sks, Class G NA 3-1/2" 1 9.3# L-80 0' 7,571' 0' 7,544' 8-1/2" 1,070 sks, Class G NA 23. Open to production or injection? Yes ❑✓ No ❑ If Yes, list each interval Q,,en (MD+TVD of Top,& Bottom; perforation Size and Nu eerr): ;✓p h iC�V�►St-s� I p "l� 5,382' - 5,392' 5,355' - 5,365' 5,442' - 5,452' 5,415' - 5,425' 5,808' - 5,818' 5,781' - 5,792' 5,850' - 5,860' 5,823' - 5,833' 6,027' - 6,037' 6,000' - 6,010' 6,192' - 6,202' 6,165' - 6,175' 6,301' - 6,311' 6,274' - 6,284' 6,422' - 6,432' 6,395' - 6,405' 6,580' - 6,590' 6,553' - 6,563' 6,625' - 6,635' 6,598' - 6,608' 6,733' - 6,743' 6,706' - 6,716' 6,794' - 6,804' 6,767' - 6,777' 6,884' - 6,894' 6,857' - 6,867' 6,994' - 7,004' 6,967' - 6,977' 7,128' - 7,138' 7,101' - 7,111' 24. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD) 0 0 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 5,382'- 5,392' 26,345# 20/40 Ottawa sand & 3,760# Flex sand 5,442' - 5,452' 16,522# 20/40 Ottawa sand & 2,358# Flex sand 5,808' - 5,818' 17,787# 20/40 Ottawa sand & 2,110# Flex sand 5,850' - 5,860' 710# 20/40 Ottawa sand & 71# Flex sand 6,027' - 6,037' 12,149# 20/40 Ottawa sand & 1,728# Flex sand 6,192' - 6,202' 4,120# 20/40 Ottawa sand & 687# Flex sand 6,301' - 6,311' 28,283# 20/40 Ottawa sand & 4,037# Flex sand 6,422' - 6,432' 30,1621120/40 Ottawa sand & 4,304# Flex sand 6,580' - 6,590' 40,457# 20/40 Ottawa sand & 5,776# Flex sand 6,625' - 6,635' 29,320# 20/40 Ottawa sand & 4,187# Flex sand 6,733' - 6,743' 5,821# 20/40 Ottawa sand & 832# Flex sand 6,794' - 6,804' 42,804# 20/40 Ottawa sand & 2,113# Flex sand 6,884' - 6,894' 5,373# 20140 Ottawa sand & 796# Flex sand 6,994' - 7,004' 11,204# 20/40 Ottawa sand & 1,602# Flex sand 7,128' - 7,138' 1 22,820# 20/40 Ottawa sand & 4,887# Flex sand 26. PRODUCTION TEST Date First Production: 1/20/2008 Method of Operation (Flowing, gas lift, etc.): Flowing Date of Test: 2/1/2008 Hours Tested: 24 Production for Test Period __10. Oil -Bbl: 0 Gas -MCF: 3,930 Water -Bbl: 256 Choke Size: 64/64 Gas -Oil Ratio: 100% Gas Flow Tubing Press. 412 Casing Press: 0 Calculated 24 -Hour Rate .-► Oil -Bbl: 0 Gas -MCF: 3,930 Water -Bbl: 256 Oil Gravity - API (corr): NA 27. CORE DATA Conventional Core(s) Acquired? Yes ❑ No Q 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. Form 10-407 Revised 2/2007 14,61. CONTINUED ON REVERSE Immission *1`�Clo 4T?*f 9C. 28. GEOLOGIC MARKERS (List all formations and m= encountered): 29. = FORMATION TESTS NAME MD TVD Well tested? ✓ Yes No If 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 Sterling A8 3,551' 3,537' MFT pressure tests collected through Middle/Lower Beluga and Tyonek. Please see Upper Beluga 3,703' 3,687• attached summary. Middle Beluga 5,358' 5,331' Lower Beluga 6,080' 6,053' Tyonek 7,251' 7,224' Formation at total depth: Tyonek 7610 7583 30. List of Attachments: Well Schematic, Operations Summary, Well logs in paper and digital, Directional survey 31. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Kevin Skiba (907) 283-1371 Printed Name: Craig L. Rang Title: Senior Completions Engineer Signature: etn:�Phone: (907) 283-1372 Date: February 19, 2008 U U 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-Altemating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing 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). Rem 20: Report true vertical thickness of permafrost in Box 20. Provide MD and TVD for the top and base of permafrost in Box 28. Rem 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: R this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: 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 Permit #: 207-149 API #: 50-133-20572-00-00 Prop. Des: ADL 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27'36.75" N Longitude: 151° 15'54.42" W Spud: 11/29/2007 TD: 1/15/2008 Rig Released: 06:00hrs 12/26/2007 Tree cxn = Top of Cement (est.) @ - 5,300' MD - 18' above 9-5/8" shoe KOP (a-) 1,100' MD/TVD Build -0.671/100 from 1,100'- 4,500' Module Number Flapper Valve Depths (MD) Module 15 5,405.49 Module 14 5,466.08 Module 13 5,831.34 Module 12 5,875.67 Module 11 6,053.97 Module 10 6,218.48 Module 9 6,326.81 Module 8 6,448.14 Module 7 6,607.44 Module 6 6,652.70 Module 5 6,761.61 Module 4 6,824.39 Module 3 6,912.14 Module 2 7,023.00 Module 1 not applicable Fill tagged (aD 7,203' ELM (1/15/2008) KBU 14-6Y Pad 14-6 482' FSL, 1,121' FWL, Sec. 6, T4N, R11 W, S.M. a 'M� MARATHON Drive Pipe 20" K-55 133 ppf PE Top Bottom MD 0' 129' TVD 0' 129' Surface Casing 13.3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,504' TVD 0' 1,503- 1 6" ,503'16" hole Cmt w/ 466 sks (210 bbl) of 12.0 ppg, Type 1 cmt, 100% returns Intermediate Casing 9-518" L-80 40 ppf BTC Top Bottom MD 0' 5,318' TVD 0' 5,291- 12-1/4" hole Cmt w/ 320 sks (189 bbls) of 10.5 ppg, class G cmt Production Tubing 3-112" L-80 9.3 ppf Mod EUE Top Bottom 8rd MD 0' 7,571' TVD 0' 7,544' 8-1/2" hole Cmt w/ 1,070 sks (221 bbls) of 15.8 ppg, class G cmt Excape System Details 15 Excape modules system control line fired module 1 through 7 contol line fired modules 8 thru 15 connecting lines activate reclosing flappers TD Perfs MD (RKB) (All Beluga Zones): 7,600' M D Module 15 -. 5,382'- 5,392' (1/1712008) 7,573' TVD Module 14 -. 5,442' - 5,452' (1/17/2008) b1 I Module 13 - 5,808' - 5,818' (1/17/2008) ;� Module 12 -+ 5,850'- 5,860' (1/1712008) 5,355' - 7,799' Module 11 - 6,027' - 6,037' (1117/2008) - 0.67° / 100 ft @ 1,100' MD Module 10 -+ 6,192'- 6,202' (1/16/2008) �1 Module 9 - 6,301' - 6,311' (1/16/2008) , Module 8 - 6,422' - 6,432' (1/16/2008) Ell , Module 7 - 6,580' - 6,590' (1/16/2008) ? Module 6 - 6,625'- 6,635' (1/1612008) W r Module 5 - 6,733' - 6,743' (1/16/2008) ? r Module 4 - 6,794'- 6,804' (1/16/2008) Module 3 -. 6,884' - 6,894' (1116/2008) r Module 2 - 6,994' - 7,004' (1/16/2008) Module 1 - 7,128' - 7,138' (1/1512008) TD PBTD 7,600' M D 7,476' MD 7,573' TVD 7,449' TVD Well Name & Number: Kenai Beluga Unit 14-6Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 5,382' - 7,138' (TVD): 5,355' - 7,799' Angle @ KOP and Depth: - 0.67° / 100 ft @ 1,100' MD Angle/Perfs: Dated Completed: 1/15/2008 Completion Fluid: 6% KCL Prepared by: Kevin Skiba Last Revison Date: 2/6/2008 9 SCALE 0 100 200 FEET 1. BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD27 ZONE 4 DETERMINED BY A DIRECT TIE TO USC&GS TRI STA AUDRY HAVING A PUBLISHED POSITION OF LAT. 60"30'50.559" N LONG. 151°16'37.445"W N:2382045.42 E:269866.75 2) BASIS OF VERTICAL DATUM IS MEAN SEA LEVEL 3) SOUTHWEST CORNER SEC. 6 COORDINATES DETERMINED FROM DIRECT SURVEY TIE TO THE TO EXISTING BLM SECTION CORNER W.C. RECOVERED AND NOT THE PROTRACTED SECTION CORNER VALUES. EDGE PAD FOOTPRINT X--271 692.58 CP -3 ® TOP O BE RM \V=2,382,592.02 X 71.*A' BU 14-6Y AS -BU ELEV.=62.21' x=2.W2,6(.9] TOP EDGE PAD \I Y=2'362'IPEE AD27 ASP ZONE 4 TOP e' PIPE EL.�2.62' ORDUNDEL.-81.5' I TOP GRAVEL TOP2"PIPE EL.=62.41' l GRID N:2362537.643 PILE AUTOGATE GRID E:272040.729 LATITUDE: 60°27'38.889"N \ 1122' FWL LONGITUDE: 151 °15'46.552"W _ --3 ELEV.: 65.5 FT. SITE EMERGENCY 2O . - K.B.U. 228 SHUTDOWN 8' DIA. WELL CELLAR 18'OSLO O SWITCH x=271,98026 WDIA. WELL CELLAR ®K.U. 21-7X V=2,382,537.15 V=2,382,627.32 X -172,18D.56 6'DIA.WELL CEL 00 F(1_ r/ V=2,382,523.31 Ro K.T.U. 13-0 y b 18a' PRODUCTION WELL 14'3' WELL HOUSE 0 \ am K.U. 14XO x 72,20461 O1 • PRO. 14X-6 WELL YX a72, 4A P WELL HOUSE O K.D.0-1 WATER WELL X=2)2,062.8] S 5 14.SO SILO 8'CABING V=2382p]1.48 18Ax18.0'THREE SIDED O K.B.U. 31-7 N GUARD PIPE ® K.B.U. 23-7 WELL HOUSE r r VALVE X=z1z,22194 BLDG. O 8' 0 SILO Y -2,362,453.W 10.3' V=2,382,462.91 a K.U. 21-7 (X=272,019.41) IWOSLo(Y=2,362,371.79) K.B.U. 248 10'0 PIPE a x=271,928.94 WELL HOUSE U) V=2,362,41496 O X=272,1]429 LPIPELINE 9.tl OLD JUMP • V=2a62,WS7 • f'- MILEPGSTSIGN 1❑OVERBLOG REVISED 14.+ Z \ MILE'0' \ E272010.90 K.B.u.z3x-06 F K.U. 31-7X N 2362378.29 +a+' w \6•GPIPE PROWCELL�S REVISED GAS INJECTION WELL Lu VALVE W x=z]2,,zz 20 • E 272239.78 WELL HOUSE Z 3.8'X39' WARD PIPE Y=z,362.WT41 N 2362377.96 (X=272,247.95) K.U. 148 10' 0 WELL H J BE (Y=2,362,373.05) O W Z X=27,.6762. 483' OY=z,382308.68 _ e.ox\e.r colic. PADS 1-_ \ K.G.F. PAD 14-6 TELE PHONE CABLE BOX U WITH 5x6' WARD PIPE 384 ,2.5x3.01 GLYCOL ELEVATION = 65.6' M.S.L. REBOILER 6N TOp ED 'W'A^ BLDG. HEATEXCIIANGER 8.2x8:1' GEP 46.1' �"� 3.zx5.7 METAL 8.2x6.1' COVER PLATE _ PIPE RACK O K.U. 43-12 1&2IMET f GE PAD FOOTPRINTADL. Y6 AND OH. 14.6'0SIL0 BLDG. ERRE-BOILER PIPES x=271,888.18 BLDG. OL PT. CP -24N M.C" BLDG T.B.M. IN P.P. 65' 169.16SPIIO=NP.P. V`2,362,224.53U.o METER 6 P' CONIC 46.Y 65,6T75 3.0 coot➢ / 85.8T $1$7 8.0x12.0' VALVE " BUILDING r PAD 4.0x4./ PIPE RIM II UTILITY - \ 20.3' 56.0 OR PAy 'METAL 1921 9EOOER I I • B.Oxe.O FIRE PLATE ❑ 4.0 N HOSE BLDG. O.H. PIPE - 24.0 12.6'X3.0' 12.0X9.0 .4x12.3' CONC. PAD GLYCOL HEAT HEATER CONTROL SWITCHGEAR 28.0 .,...... .. EXCHANGER W ®14 BLDG. BLDG. ROK b ,:.n t ^"-...t„ WASTE VALVE W/ 3'0 GUARD �.� CENTAURONTACTORCOMPRESSORSW COR WATER GUARD �i1Mli BLDG.BLDG. GUARD PIPE PIPE jy BLDG.42.Y14.0 E - UTILLTITY331DED3x3'O'Fl� BLDG. d GUARD PIPEz N 2362069.27 OFOR GUY AIR 5i6'WIREFILTERS 6 E 270908.10 s CENTAURVENT VALVEPIPE SUPPORTS O f VO 0N 5.0X6.0 OVERHEAD PIPE SUPPORTS CONCRETE PA 12 7 / ROOM..183 6.7X .9 / O.H. PAN 3.0x5.0 METAL 18'PIPE 1 DIESEL v 39.3' VALVE COVER PLATE t" m TAN( 9.2' 2jT BLDG. / 202' SATURN 6 / COMOFFICE SHOP 36,A5 BLDG. BLDG. CONTACTOF2 49.4' BLOW OONMT/ \ BLDG. AIR PAD PRESSOR FRO WARD PIPE 26.T FROM 16.0 FILTERS PIPE CONTINUING UNDERGROUND 3.0 GUARD PIPE PROJECT REVISION: 1 M MMATHON KBU 14-6Y WELL ON KGF PAD 14-6 DATE: 2/18/08 OH, CONFAY AS -BUILT SURFACE LOCATION DIAGRAM DRAWN BY: MSM ARATHON NAD27 FOR INFORMATIONAL PURPOSES • ��A SCALE: 1"=100' ONLY PROJECT NO. 073140 ENGINEERING /MAPPING /SURVEYING /TESTING BOOK NO. 07-24 COMULtin9 IncP.O. BOX 468 SOLDOTNA, AK. 99 LOCATION SHEET Vol 966 CE: (907)283-4218 FAX: (907)283-3285 EMAIL: S6 T4N R11 W SEWARD MERIDIAN, ALASKA ') OF 1 SAMCLANE@MCLANECG.COM • ., •. 19-Feb08 at 06:22:27 MARATHON Oil Company Cook Inlet, Alaska (Kenai Penninsula) Kenai Gas Field (NAD83) Pad 14-6 slot#KBU 14-6Y KBU14-6Y KBU14-6Y NavTrak MWD<148 -76005 12/17/2007 (none) Jonethoh Minimum curvature Actual Well ath Geo ra hic Re ort • - 11IM3 r • • • • LIMA I M.. • • NAD83 / TM Alaska State Plane, Zone True 0.999959 Slot Glacier #1 (RKB) Glacier#1 (RKB) Mean Sea Level 87.00 It 87.00 ft 0.00 ft E 0.00 ft N 0.00 ft 176.83' 488.97 1121.54 1412067.87 1410937.15 2362291.67 2361824.52 60'2736.746"N 60'2731.931"N 151'15'54.417'W 151'16'16.783'W " NAD 83 coordinates are converted to NAD 27 usunp Cor scon 6.0 .1 US Arm Co s of En losers TVID from Inclination Azimuth TVD Fid Ref North East Grid East 0.00 81.76 0.00 87.00 0.00 0.00 1412087.87E Grid North 2362291.67 1410937.15 272047.6 2362530.419 2361824.52 Latitude Lonclitude 60'2736.746'N 151'15'54.417"W DILS rr 0.00 Toolface 81.76 60'2T31.931"N Build Rate Turn Rate ri rr 0.00 0.00 151.16'16.783"W Vert Sect Comment, 0.00 148.00 0.35 81.76 148.00 61.00 0.06 0.45 UU068.32-j 2362291.73 272048.05 1 2362530.479 60'27'36.746"N 151'15'54.408'W 0.24 7329 024 0.00 -0.04 273.00 0.37 90.09 273.00 186.00 0.12 123 1412069.10 2362291.77 272048.83 2362530.519 60'2736.74771 151'15.54.392 W 0.04 -35.26 0.02 6.66 -0.05 452.00 0.47 81.86 451.99 364.99 022 2.53 1412070.41 2362291.84 272050.14 2362530.589 60.27'36.748"N 151'1654.3661N 0.07 25.86 0.06 -4.60 -0.08 633.00 0.77 9228 632.98 545.98 0.28 4.48 1412072.36 2362291.86 272052.091 2362530.609 60.27'36.749"N 151'1654.327W 0.18 0.81 0.17 5.76 -0.03 817.00 881.00 120 1.11 92.57 90.68 816.95 880.94 729.95 793.94 0.14 0.11 7.64 8.93 1412075.51 1412076.80 2362291.67 2362291.60 272055.241 272056.531 2362530.419 2362530.348 60°2T36.747"N 151'1954.264'W 60°2T36.747N 151'1654.239'W 023 0.15 -158.00 178.80 023 -0.14 0.16 -2.95 0.28 0.39 944.00 0.87 91.01 943.93 856.93 0.09 10.02 1412077.89 2362291.57 272057.621 2362530.318 60°2T36.74T'N 151'15'5421 0.38 -161.32 -0.38 0.52 0.46 1007.00 1 0.56 79.85 1 1006.93 919.93 1 0.14 10.80 1412078.67 2362291.60 272058.401 2362530.348 60"2T36.747N 151.1654201 0.54 -166.91 -0.49 -17.71 0.46 1070.00 1134.00 022 0.83 308.14 295.25 1069.93 1133.92 982.93 1046.92 026 0.54 11.01 10.49 1412078.88 1412078.37 2362291.72 2362292.01 272058.611 272058.101 2362530.46860°2736.748"N 2362530.758 151'15'54.197-W 60°2T36.751"N 151'15'S4.208'W 1.15 0.96 1 -17.45 -9.61 -0.54 0.95 1 -209.06 -20.14 0.35 0.04 1197.00 1.50 290.94 1196.91 1109.91 1.03 9.31 1412077.20 2362292.52 272056.931 2362531268 60.2T36.756"N 151'15'54231"W1.07 -2.87 1.06 -6.84 -0.51 1260.00 2.30 289.94 1259.87 1172.87 1.75 7.35 141207526 2362293.28 272054.991 2362532.029 60'2736.763"N 151'15'54270'W 1.27 -2.74 127 -1.59 -1.34 1323.00 3.20 289.17 1322.80 1235.80 2.76 4.50 1412072.43 2382294.34 272052.161 2362533.089 60.2T36.773N 151'15'54.327W 1.43 -24.27 1.43 -122 -2.51 1386.00 3.93 284.45 1385.68 1298.68 3.88 0.75 1412068.70 2362295.53 272048.43 2362534.279 60'2736.784"N 151'15'54.402"W 125 -6.44 1.16 -7.49 -3.83 1463.00 4.90 283.17 1462.45 1375.45 529 -5.00 1412062.97 2362297.05 272042.7 53 23625.8 60'27'36.798'N 151'15'54.517"W 127 -17.90 1.26 -1.66 -5.55 1560.00 5.42 281.40 1559.06 1472.06 7.14 -13.53 1412054.48 2362299.06 27203421 2362537.81 60*2r36.816"N 151'15'54.687"W 0.56 -103.14 0.54 -1.82 -7.87 1623.00 5.34 276.99 1621.78 1534.78 8.08 -19.36 1412048.67 2362300.12 272028.399 2362538.871 60'2736.825"N 11511-115-54.80-W 0.67 -10.74 -0.13 -7.00 -9.14 1686.00 5.96 275.86 1684.47 1597.47 8.77 -25.52 1412042.52 2362300.93 272022249 2362539.681 60'27'36.832N 151'15'54.928 1.00 1.90 0.98 -1.79 -10.17 1749.00 6.66 276.06 1747.09 1660.09 9.49 -32.41 1412035.65 2362301.78 272015.379 2362540.532 60'27'36.83WN 151'15'55. 1.11 -10.70 1.11 0.32 -11.27 1812.00 6.83 275.79 1809.65 1722.65 1025 -39.77 1412028.31 2362302.69 272008.038 2362541.443 60'2736.847"N 151'15'S5.210'W 027 -24.01 0.27 -0.43 -12.44 1875.00 7.15 274.65 1872.19 1785.19 10.95 -47.40 1412020.69 2362303.53 272000.418 2362542.283 60'2736.854'N 151'15'55.362"W 0.55 -111.69 0.51 -1.81 -13.56 1938.00 7.04 272.27 1934.70 1847.70 11.42 -55.17 1412012.94 2362304.15 271992.667 2362542.904 60'2736.858"N 151.15'S5.517'W 0.50 -70.60 -0.17 -3.78 -14.46 2001.00 7.19 269.11 1997.22 191022 11.51 -62.97 1412005.14 2362304.39 271984.867 2362543.145 60'2736.859"N 151'15'55.673W 0.67 -70.97 0.24 5.02 -14.98 2065.00 7.49 263.28 2060.69 1973.69 10.96 -71.11 1411996.98 2362304.00 271976.707 2362542.755 60'2736.854"N 151.15'S5.835"W 1.25 -117.30 0.47 -9.11 -14.88 2128.00 7.34 260.91 2123.17 2036.17 9.85 -79.17 1411988.91 2362303.03 271968.636 2362541.786 60'27'36.843N 151.15'S5.996"W 0.54 -139.18 -024 -3.76 -14.21 2AKOO 6.66 255.63 2184.71 2097.71 8.33 -86.56 1411981.49 2362301.66 271961.216 2362540.417 60'2T36.828"N 151.15'56.143-W 1.51 -153.38 -1.10 -8.52 -13.11 5.62 250.17 2248.34 2161.34 6.34 -93.10 1411974.91 2362299.80 271954.635 2362538.557 60'2736.808"N 151'1656.274W 1.86 -142.98 -1.63 -8.53 -11.49 4.94 243.95 2311.07 2224.07 4.11 -98.44 1411969.53 2362297.67 271949.255 2362536.428 60'2736.786"N 151'1656.380"W 1.41 -52.12 -1.08 -9.87 -9.55 2380.00 5.04 242.51 2373.83 2286.83 1.64 -103.33 1411964.59 2362295.29 271944.315 2362534.048 60'2736.762"N 151'1656.478W 0.25 -115.97 0.16 -2.29 -7.35 2443.00 4.85 237.43 2436.60 2349.60 -1.07 -108.03 1411959.84 2362292.67 271939.564 2362531.429 60'2736.735'N 151'15'56.5719N 0.78 707.15 -0.30 8.06 4.91 2506.00 2569.00 4.68 4.81 22829 219.01 2499.38 2562.17 2412.38 2475.17 -422 -7.98 -112.20 -115.78 1411955.62 1411951.97 2362289.61 2362285.92 271935.344 271931.694 2362528.369 2362524.68 60.2T36.704'N 151'1656.654"W 60'2T36.667"N 151'1W56.726W 1.23 123 -85.03 -125.31 -027 0.21 -14.51 -14.73 -2.00 1.56 2632.00 425 206.24 2624.97 2537.97 -12.13 -118.47 1411949.19 2362281.82 271928.914 2362520.58 60.2736.626"N 151'15'56.779"W 1.83 -96.58 -0.89 -20.27 5.55 2696.00 425 193.04 2688.80 2601.80 -16.56 -120.06 1411947.52 2362277.42 271927.244 2362516.181 60.2P36.583"N 151'1656.811"W 1.53 -63.83 0.00 -20.63 9.89 2759.00 4.74 182.78 1 2751.60 2664.60 1 -21.44 -120.71 1411946.78 2362272.56 271926.504 2362511.321 60"2T36.535'N 151'1656.824W 1.49 -89.19 0.78 -16.29 14.72 2821.00 4.77 177.10 2813.39 2726.39 -26.57 -120.70 1411946.69 2362267.42 271926.414 2362506.181 60.2T36.484"N 151.1656.824W 0.76 -57.381 .05 -9.16 19.85 2885.00 5.17 170.71 2877.15 2790.15 -32.07 -120.10 1411947.18 2362261.91 271926.903 2362500.671 60.2736.430-N 151.1&56.812"W 1.07 -58.14 0.62 -9.98 25.38 2947.00 5.54 164.99 2938.88 2851.88 -37.72 -118.88 1411948.30 238225624 271928.023 2362495.001 60'2736.374"N 151'1556.787'W 1.05 -49.48 0.60 -9.23 31.08 3010.00 5.92 160.85 3001.57 2914.57 -43.73 -117.02 1411950.03 2362250.20 271929.753 2362488.961 80'27'36.315'N 151'1656.751"W 0.89 -43.81 0.60 5.57 37.18 3072.00 6.28 157.77 306321 2976.21 -49.89 -114.69 141195225 2362244.00 271931.974 2362482.761 60'2736254"N 151.1656.704"W 0.78 51.91 0.58 -4.97 43.46 3136.00 6.96 151.09 3126.79 3039.79 56.52 -111.49 1411955.32 2362237.30 271935.044 2362476.061 60'2T36.189N 151.1656.640"W 1.60 -38.53 1.06 -10.44 50.26 3199.00 7.54 147.65 3189.28 3102.28 -63.36 -107.43 1411959.24 2362230.39 271938.964 2362469.151 60'2T36.122"N 151.1656.559"W 1.15 -7.53 0.92 -5.46 57.31 3261.00 8.33 146.93 3250.69 3163.69 -70.56 -102.81 1411963.73 2362223.10 271943.454 2362461.861 60'2T36.051"N 151.15'56.467"W 128 -4322 127 -1.16 64.76 3323.00 1 8.92 143.45 1 3311.99 3224.99 -78.18 -97.49 1411968.90 2362215.38 271948.624 2362454.14 60'2735.976"N 151.1656.361"W 127 100.14 0.95 -5.61 72.66 3386.00 8.90 144.20 3374.23 3287.23 -86.06 -91.73 1411974.50 2362207.39 271954.224 2362446.15 60'2735.898"N 151'15'56246"W 0.19 159.57 -0.03 1.19 80.85 3449.00 8.83 144.37 3436.48 3349.48 -93.94 -86.07 1 1411980.02 2362199.40 271959.745 1 2362438.16 60'27'35.821'N 151'15'56.133W 0.12 4722 -0.11 0.27 1 89.03 3512.00 9.09 146.12 3498.71 3411.71 -102.00 -80.48 1411985.45 236219124 271965.175 2362430 60'27'35.741"N 151'1656.022"W 0.60 -152.88 0.41 2.78 97.39 3575.00 8.68 144.72 3560.95 3473.95 -110.01 -74.96 1411990.82 2362183.12 271970.545 2362421.879 60'2T35.662"N 151'1655.912'W 0.74 93.51 -0.65 -2.22 105.70 3638.00 8.67 150.48 3623.23 353623 -118.03 -69.87 1411995.75 2362175.01 271975.475 2362413.769 60'2735.583"N 151'15'55.810"W 1.38 -83.69 -0.02 9.14 113.98 3700.00 8.76 146.42 3684.52 3597.52 -126.03 -64.96 1412000.51 2362166.92 271980.235 2362405.679 60.2T35.5D5"N 151'15'55.712'W 1.00 10429 0.15 -6.55 12224 3763.00 8.55 153.86 3746.80 3659.80 -134.23 -60.24 1412005.07 2362158.63 271984.795 2362397.389 60'2735.424"N 151°15'55.61 1.81 52.91 -0.33 11.81 130.69 3826.00 8.60 154.30 3809.10 3722.10 -142.68 -56.13 1412009.01 2362150.10 271988.736 2362388.859 60.27'35.341'N 151'15'55.536 0.13 165.39 0.08 0.70 139.35 3888.00 8.28 154.86--,-3870.43 3783.43 -150.90 -52.23 1412012.75 141.81 271992.476 2362380.569 60'27'35.260"N 151°15'55. 0 147.77 Page 1 of 2 9 Page 2 of 2 0 Marathon KBU 14-6Y FORMATION TESTER TEST SUMMARY Test No. Depth TVD Hyd Pres Before Hyd Pres After Volume Drawdow Tool Flow n Rate Press Final Shut - in Press Permeab Remarks 1 5000.20 4973.52 2794.00 2794.00 4.0 1.0 9.00 GOOD 2 7210.02 7183.12 4027.00 4026.00 2.0 1.0 3751.00 GOOD 3 7210.50 7183.00 4029.00 4029.00 5.0 0.5 4015.00 NO SEAL 4 7139.10 7112.13 3987.00 3988.00 5.0 0.5 3359.00 GOOD 4 7139.10 7112.13 3987.00 3988.00 15.0 1.0 3344.00 GOOD 5 7113.11 7086.14 3973.00 3973.00 5.0 0.5 3477.00 GOOD 6 7076.06 7049.14 3952.00 3952.00 5.0 0.5 2497.00 NO SEAL 7 7078.10 7051.14 3954.00 3954.00 5.0 0.5 46.00 TIGHT 8 7001.04 6974.15 3926.00 3911.00 5.0 0.5 3119.00 GOOD 9 6892.03 6865.16 3849.00 3855.00 5.0 0.5 2846.00 GOOD 10 6843.96 6817.17 3822.00 3822.00 5.0 0.5 3822.00 NO SEAL 11 6839.01 6812.00 3819.00 3819.00 5.0 0.5 35.00 TIGHT 12 6800.01 6773.18 3797.00 3797.00 5.0 0.5 3350.00 GOOD 13 6784.00 6757.18 3787.00 3788.00 5.0 0.5 2841.00 GOOD 14 6740.06 6713.19 3763.00 3763.00 5.0 0.5 2332.00 1 GOOD 15 6630.02 6603.20 3701.00 3701.00 5.0 0.5 2291.00 GOOD 16 6588.01 6561.20 3677.00 3677.00 5.0 0.5 1863.00 GOOD 17 6429.97 6403.22 3587.00 3587.00 5.0 0.5 2623.00 GOOD 18 6309.00 6282.23 3519.00 3519.00 5.0 0.5 171.00 TIGHT 19 6301.01 6274.25 3514.00 3581.00 5.0 0.5 2590.00 GOOD 20 6199.99 6173.25 3511.00 3547.00 5.0 0.5 2511.00 GOOD 21 6158.03 6131.25 3433.00 3434.00 5.0 0.5 1689.00 GOOD 22 6122.14 6095.25 3411.00 3416.00 5.0 0.5 1428.00 GOOD 22 6122.14 6095.25 3411.00 3416.00 15.0 1.0 1421.00 GOOD 23 6035.99 6009.26 3367.00 3367.00 5.0 0.5 2352.00 GOOD 23 6035.99 6009.26 3367.00 3367.00 15.0 1.0 2350.00 GOOD 24 6032.10 6005.26 3365.00 3364.00 5.0 0.5 2409.00 GOOD 25 5938.00 5911.26 3312.00 1 3312.00 5.0 0.5 2463.00 GOOD 25 5938.00 5911.26 3312.00 3312.00 15.0 1 1.0 2463.00 GOOD 26 5934.01 5907.26 3309.00 3309.00 5.0 0.5 2464.00 GOOD 27 5854.02 5827.27 3264.00 3264.00 5.0 0.5 2286.00 GOOD 27 5854.02 5827.27 3264.00 3264.00 15.0 1.0 2285.00 GOOD 28 1 5850.07 5823.27 3262.00 3262.00 5.0 0.5 2287.00 GOOD 29 1 5814.02 5787.28 3241.00 3241.00 5.0 0.5 1797.00 GOOD 29 5814.02 5787.28 3241.00 3241.00 15.0 1.0 1795.00 GOOD 30 5810.03 5783.28 3239.00 3239.00 5.0 0.5 1795.00 GOOD 31 5486.00 5459.31 3056.00 3055.00 5.0 0.5 2330.00 GOOD 31 5486.00 5459.31 3056.00 3055.00 15.0 1.0 2327.00 GOOD 32 5444.03 5417.32 3032.00 3032.00 5.0 0.5 2265.00 GOOD 32 5444.03 5417.32 3032.00 3032.00 15.0 1.0 2263.00 GOOD 33 5383.99 1 5357.32 1 2998.00 3027.00 1 5.0 0.5 639.00 TIGHT 34 5381.00 5354.32 2997.00 1 2995.00 5.0 0.5 1 1855.00 GOOD 34 5381.00 5354.32 2997.00 1 2995.00 15.0 1.0 1 1854.00 GOOD Marathon Oil Company Page 1 of 7 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL DRILLING Start: 10/30/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Sub Date From -To Hours Code Code Phase Description of Operations 10/31/2007 06:00 - 06:00 1 24.00 RURD_ RIG_ MIRU I Move sub, carrier and Mud Boat and spot over 14-6Y. Rig up camp. Set 11/1/2007 06:00 - 12:00 1 6.00 RURD_ RIG_ IMIRU 11/27/2007 110:00-12:00 1 2.00 1 RURD J EQIP I MIRU 00:00 - 06:00 1 6.00 NUND IBOPE MIRU 11/28/2007 06:00 - 15:00 1 9.00 NUND IBOPE MIRU 15:00 -18:00 1 3.001 RURD_1 RIG_ I MIRU 00:00 - 06:00 1 6.001 REPAIR I RIG_ MIRU 11/29/2007 06:00 - 08:00 1 2.00 NUND IBOPE SURDRL 08:00 - 00:00 I 16.001 PULD I DP I SURDRL 07:30 - 08:00 1 0.501 CLEAN_ I RIG_ I SURDRL shop units. R/U pits and pump units. PJSM: Crane safety ( note wait on wind to start crane work 25-30mph gusts) Set stairs and wind walls. set dog and choke houses. Set trip tank, beaver slide and catwalk. Set fuel tank. Run service lines, electrical steam and water. Fire boiler. Unload trailers. R/U exterior lighting. Set shop and parts trailers and erect shop. Continue rig up. set #3 mud pump. Install berms. Run electrical lines. Complete rig up GD -1 at 1200hrs 10-31-2007. Move to rig maintenance phase Set MI centerfuge van and mud lab/ sleeper. Set cement van and R/U lines. Make final cut on 20" conductor and set starting head. Unload mud products and stage. Set Epoch and MWD cabin. Nipple up diverter. N/U Bell nipple and Diverter line. Install trip tank lines and flow line. Complete N/U diverter system Winterize Cellar Install 165 Shaker screens. Unload trailers with mud products, Casing tools. P/U pipe handling tools ,floor valves and crossovers Fill stack with water Knife valve leaked. N/D Diverter line and repair PJSM : Remove diverter line ,clean up knife valve. N/U valve and chain down diverter line., Function test diverter. PJSM; P/U drift stand back and tally 5" drillpipe HWDP and jars 7070' total. Mix spud mud. Program PLC and Controls. Continue to Mix spud mud. Rack Drift 13 3/8 Casing. Mix spud mud 500bbls. Load pipe racks drift tally 37jts 13 3/8 Csg. Calibrate gas alarms. Function test accumlator and diverter system test gas alarms. Continue mix spud mud Hold weekly safety meeting with both crews. Discuss start up hazards after rig maintenance. Install gasket in #3 mud pump suction line. Clear and pump through shear relief line #3 mud pump. Test #3 mud pump WU 16" clean out assy Clean 20" conductor from 21' to 128'. Spud well at 1630hrs 11/29/2007 Drill from 128' to 175' POH and lay down Clean out bha PJSM; WU 16" directional bha Scribe motor/ mwd, rih to 175' Directionally drill ahead from 175' to 495' Directional drill from 495' ro 1518'. TD'd 16" hole section @ 21:45 hrs. ART: 8.6 hrs., AST: 1.6 hrs. Circulate bottoms up. Shakers clean after 7800 stks. Monitor well. Wiper trip. POH 6 stds, blow down top drive, continue POH to 148'. No gains/ losses. No tight spots, SLM, No corrections. Service rig, top drive, grease crown & carrier. RIH from 148' to 1518', tagged bottom, no fill. No gains/ losses. Hole slick. Circulate bottoms up. Check flow (static). GPM: 620 gpm, RPM: 70 rpm, SPP: 1550 psi, P/U wt: 70 klbs, S/O wt: 70 klbs, ROT wt: 70 klbs. TOH w/ bha #2. Hole slick, No gains/losses. Rack back monel drill collars. Lay down shock sub & x/o subs. Continue to lay down 16" BHA. UD Stablizer , Pony collar,And MWD . B/O bit and lay down motor Clean clear rig floor Printed: 1/31/2008 8:27:29 AM 00:00 - 06:00 6.00 MIX_ MUD_ SURDRL 11/30/2007 06:00 - 09:30 3.50 MIX MUD SURDRL 09:30 - 12:00 2.50 TEST BOPE SURDRL 12:00 - 13:00 1.00 SAFETY MTG SURDRL 13:00 - 16:00 3.00 REPAIR RIG_ SURDRL 16:00 - 16:30 0.50 TRIP_ BHA_ SURDRL 16:30 -17:30 1.00 CLNOUT CSG_ SURDRL 17:30 - 19:30 2.00 DRILL_ ROT_ SURDRL 19:30 - 20:00 0.50 TRIP_ BHA_ SURDRL 20:00 - 00:00 4.00 TRIP_ BHA_ SURDRL 00:00 - 06:00 6.00 DRILL_ ROT_ SURDRL 12/1/2007 06:00 - 21:45 15.75 DRILL ROT SURDRL 21:45 - 22:15 0.50 CIRC_ MUD_ SURDRL 22:15 - 00:30 2.25 TRIP WIPR SURDRL 00:30 - 01:00 0.50 SERVIC RIG_ SURDRL 01:00 - 01:45 0.75 TRIP WIPR SURDRL 01:45 - 03:00 1.25 CIRC MUD SURDRL 03:00 - 05:00 2.00 TRIP_ BHA_ SURDRL 05:00 - 06:00 1.00 PULD_ BHA_ SURDRL 12/2/2007 06:00 - 07:30 1.50 PULD BHA SURDRL 07:30 - 08:00 1 0.501 CLEAN_ I RIG_ I SURDRL shop units. R/U pits and pump units. PJSM: Crane safety ( note wait on wind to start crane work 25-30mph gusts) Set stairs and wind walls. set dog and choke houses. Set trip tank, beaver slide and catwalk. Set fuel tank. Run service lines, electrical steam and water. Fire boiler. Unload trailers. R/U exterior lighting. Set shop and parts trailers and erect shop. Continue rig up. set #3 mud pump. Install berms. Run electrical lines. Complete rig up GD -1 at 1200hrs 10-31-2007. Move to rig maintenance phase Set MI centerfuge van and mud lab/ sleeper. Set cement van and R/U lines. Make final cut on 20" conductor and set starting head. Unload mud products and stage. Set Epoch and MWD cabin. Nipple up diverter. N/U Bell nipple and Diverter line. Install trip tank lines and flow line. Complete N/U diverter system Winterize Cellar Install 165 Shaker screens. Unload trailers with mud products, Casing tools. P/U pipe handling tools ,floor valves and crossovers Fill stack with water Knife valve leaked. N/D Diverter line and repair PJSM : Remove diverter line ,clean up knife valve. N/U valve and chain down diverter line., Function test diverter. PJSM; P/U drift stand back and tally 5" drillpipe HWDP and jars 7070' total. Mix spud mud. Program PLC and Controls. Continue to Mix spud mud. Rack Drift 13 3/8 Casing. Mix spud mud 500bbls. Load pipe racks drift tally 37jts 13 3/8 Csg. Calibrate gas alarms. Function test accumlator and diverter system test gas alarms. Continue mix spud mud Hold weekly safety meeting with both crews. Discuss start up hazards after rig maintenance. Install gasket in #3 mud pump suction line. Clear and pump through shear relief line #3 mud pump. Test #3 mud pump WU 16" clean out assy Clean 20" conductor from 21' to 128'. Spud well at 1630hrs 11/29/2007 Drill from 128' to 175' POH and lay down Clean out bha PJSM; WU 16" directional bha Scribe motor/ mwd, rih to 175' Directionally drill ahead from 175' to 495' Directional drill from 495' ro 1518'. TD'd 16" hole section @ 21:45 hrs. ART: 8.6 hrs., AST: 1.6 hrs. Circulate bottoms up. Shakers clean after 7800 stks. Monitor well. Wiper trip. POH 6 stds, blow down top drive, continue POH to 148'. No gains/ losses. No tight spots, SLM, No corrections. Service rig, top drive, grease crown & carrier. RIH from 148' to 1518', tagged bottom, no fill. No gains/ losses. Hole slick. Circulate bottoms up. Check flow (static). GPM: 620 gpm, RPM: 70 rpm, SPP: 1550 psi, P/U wt: 70 klbs, S/O wt: 70 klbs, ROT wt: 70 klbs. TOH w/ bha #2. Hole slick, No gains/losses. Rack back monel drill collars. Lay down shock sub & x/o subs. Continue to lay down 16" BHA. UD Stablizer , Pony collar,And MWD . B/O bit and lay down motor Clean clear rig floor Printed: 1/31/2008 8:27:29 AM Marathon Oil Company Page 2 of Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y 2.50 Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL DRILLING Start: 10/30/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Sub Date From - To Hours Code Code Phase Description of Operations 12/2/2007 08:00 - 10:30 2.50 RURD_ CSG_ SURCSG PJSM: C/O bails, elevators & rig tongs. R/D pipe spinners. R/U fillup PJSM: R/D cement head, 13-3/8" flow line & false rotary. Haul off mud. hose & Weatherford casing tongs & slips. Insert long snub post. Stage Clean pits 01:00 - 03:00 2.00 TRIP_ DP_ centralizers on rig floor. PJSM: TOH w/ 5" cement inner string. UD pups & stabin tool. 10:30 -14:45 4.25 RUN_ CSG_ SURCSG P/U & M/U 13-3/8" float shoe, shoe track & float collar. Check floats. PJSM: N/D diverter line, knife line, bleeder line, trip tank line & actuator Continue RIH w/ 13-3/8", 68 #/ft, J-55, BTC casing. Run total 35 jts to tumbuckles. Continue cleaning pits 12/3/2007 06:00 - 09:30 3.50 NUND BOPE 1504.49', float collar @ 1461.37', shoe @ 1504.49'. No gains/losses. Continue Nipple down diverter. Make cut on 20" conductor and final cut Correct displacement. on 13 3/8 casing ( Cement in annulus) Dress final cut. Complete 14:45 -17:00 2.25 RURD_ CSG_ SURCSG Set false rotary. Rig down casing tools. C/O bails & elevators. Circulate cleaning pits 09:30 - 12:30 3.00 NUND WLHD bottoms up at 5bbl min full returns PJSM: Install vetco 13 5/8 5000 X 13 3/8 SO multibowl wellhead. 17:00 - 18:30 1.50 TRIP_ DP_ SURCSG WU inner string cement stab -in assembly. TI w/ 5" drill pipe through Pressure test to 1500psi for 10min. Good test. Fill pits with heated false rotary. To 1461' Top of float collar. Sting in and space out. water begin mixing flow pro mud. 18:30 - 19:00 0.50 RURD_ CMT_ SURCSG Install cement head and line. and R/U pitcher nipple. Hold PJSM PJSM : Nipple ubope. Remove lower pipe ram from stack. Install discuss Hazards with cementing. spacer spool & set stack. R/U kill line, check valve, choke line & 19:00 - 20:00 1.00 PUMP_ CMT_ SURCSG Pump 40bbl sap spacer w/ rig pump. Swap to BJ pump 5bbls H2o,test extensions, pitcher nipple, bleeder, fillup line, drip pan, mud box & flow lines to 3000psi. line adapter. 20:00 - 21:30 1.50 PUMP_ CMT_ SURCSG Pump 486 sks Type 1 cement w/ 22% LW -6, 20% MPA -1, 2% CaCI, PJSM: P/U test jt & test plug. Rig up to test bope. 21:30 - 02:00 4.50 REPAIR RIG_ 1% SMS, 0.3% CD -32, 0.05% Static Free, 1ghs FP -6L, 12ppg, 2.481 Replace oteco ring seal on choke hose. Pull test jt & replace o -ring from cu.ft./sk yield, 10.335 gal water/sk, 5:18 pumping time, 210 bbl slurry, mud cross to choke house. 02:00 - 06:00 4.00 TEST_ BOPE 115.16 mixing water. Drop dart & displace w/ 23.5 bbls mud. Bleed off Test bope & all related components f/ 250/3000 psi for 10 min. Test & check floats. Cement in place @ 21:14 hrs. 100% returns. 30 bbls to Printed: 1/31/2008 8:27:29 AM 21:30 - 00:00 2.50 CIRC_ MUD_ SURCSG Sting out of float collar. Circulate out 2-1/2 bbis cement. Flush stack w/ citric fluid. Empty pits, clean cellar & flush lines. 00:00 - 01:00 1.00 RURD_ CMT_ SURCSG PJSM: R/D cement head, 13-3/8" flow line & false rotary. Haul off mud. Clean pits 01:00 - 03:00 2.00 TRIP_ DP_ SURCSG PJSM: TOH w/ 5" cement inner string. UD pups & stabin tool. 03:00 - 06:00 3.00 NUND BOPE SURCSG PJSM: N/D diverter line, knife line, bleeder line, trip tank line & actuator tumbuckles. Continue cleaning pits 12/3/2007 06:00 - 09:30 3.50 NUND BOPE SURCSG Continue Nipple down diverter. Make cut on 20" conductor and final cut on 13 3/8 casing ( Cement in annulus) Dress final cut. Complete cleaning pits 09:30 - 12:30 3.00 NUND WLHD SURCSG PJSM: Install vetco 13 5/8 5000 X 13 3/8 SO multibowl wellhead. Pressure test to 1500psi for 10min. Good test. Fill pits with heated water begin mixing flow pro mud. 12:30 - 21:00 8.50 NUND BOPE SURCSG PJSM : Nipple ubope. Remove lower pipe ram from stack. Install spacer spool & set stack. R/U kill line, check valve, choke line & extensions, pitcher nipple, bleeder, fillup line, drip pan, mud box & flow line adapter. 21:00 - 21:30 0.50 TEST_ BOPE SURCSG PJSM: P/U test jt & test plug. Rig up to test bope. 21:30 - 02:00 4.50 REPAIR RIG_ SURCSG Replace oteco ring seal on choke hose. Pull test jt & replace o -ring from mud cross to choke house. 02:00 - 06:00 4.00 TEST_ BOPE SURCSG Test bope & all related components f/ 250/3000 psi for 10 min. Test alarms LEL & 1-12S. Test flow & PVT alarms. Perform accumulator drawdown test. Witness waived by Chuck Schevee AOGCC & Tim Lawlor BLM. 12/4/2007 06:00 - 07:00 1.00 TEST_ BOPE SURDRL Complete testing bop. 07:00 - 07:30 0.50 TEST_ CSG_ SURDRL Test 13 3/8 casing to 1500/ 30min. test good 07:30 - 08:30 1.00 RUNPUL WBSH SURDRL Set wear bushing. Blow down Choke and mud line 08:30 - 10:30 2.00 CLEAN_ TANK SURDRL Clean excess cement and frozen mud from cuttings tank. 10:30 - 12:30 2.00 PULD—BHA _ SURDRL Make up 12 1/4 directional bha 12:30 - 14:00 1.50 PULD_ BHA_ SURDRL Found bad pin on 6 5/8 regX 6 5/8 H-90 non -mag crossover and bad box on mwd tool. Lay down. P/U New crossover and mwd. Scribe motor/mwd Printed: 1/31/2008 8:27:29 AM 0 0 Marathon Oil Company Page 3 of 7 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL DRILLING Start: 10/30/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Sub Date From - To Hours Code Code Phase Description of Operations 12/4/2007 14:00 - 15:30 1.50 TRIP_ DP_ SURDRL RI with HWDP and 5" drillpipe to 1360' 15:30 - 17:15 1.75 SLPCUT DLIN SURDRL PJSM Slip and cut drilling line 17:15 - 18:00 0.75 REPAIR RIG_ SURDRL Repair check valve in flowline to trip tank. 18:00 - 20:00 2.00 DRILL_ CMT_ SURDRL TIH. Tag cement @ 1456'. Wash down to top of float collar @ 12:00 - 18:00 1 6.00 1 DRILL_ I ROT_ JlN1DRL 18:00 - 00:00 1 6.001 DRILL_ I ROT_ JIN1DRL 00:00 - 06:00 1 6.001 DRILL_ I ROT_ JINIDRL 12/6/2007 20:00 - 20:30 0.50 DRILL_ ROT_ SURDRL 1.50 20:30 - 22:00 1.50 CIRC MUD SURDRL SERVIC 22:00 - 23:00 1.00 TEST_ LOT_ SURDRL WIPR 23:00 - 23:30 0.50 DRILL ROT IN1DRL IN1DRL 23:30 - 00:30 1.00 REPAIR RIG_ IN1DRL 00:30 - 06:00 5.50 DRILL ROT IN1DRL 12/5/2007 06:00-12:00 6.00 DRILL ROT IN1DRL 12:00 - 18:00 1 6.00 1 DRILL_ I ROT_ JlN1DRL 18:00 - 00:00 1 6.001 DRILL_ I ROT_ JIN1DRL 00:00 - 06:00 1 6.001 DRILL_ I ROT_ JINIDRL 12/6/2007 06:00 - 07:30 1 1.50 DRILL_ IROT_ INIDRL 1.50 07:30 - 08:20 0.83 CLEAN TANK 1.50 SERVIC 08:20 - 13:10 4.83 DRILL ROT �INIDRL IN1DRL 13:10-14:00 0.83 CIRC_ MUD_ IN1DRL 14:00-15:30 1.50 TRIP WIPR IN1DRL 15:30 - 17:00 1.50 SERVIC RIG IN1DRL 17:00 - 18:30 1.50 TRIP_ WIPR IN1DRL 18:30 - 00:00 5.50 DRILL ROT IN1DRL 00:00 - 06:00 1 6.00 DRILL_ I ROT_ JlN1DRL 12/7/2007 106:00 - 09:00 1 3.001 DRILL_ ROT_ IN1DRL 1461'.Drill out cement & float equipment f/ 1461'- 1504'. Clean out 16" rat hole f/ 1504'- 1518'. i Drill 20' new formation for F.I.T ART: 0.2 hrs. Circulate bottoms up. Rinse & fill pit #4 w/ 35 bbls water & pump down hole. Pump 40 bbl hi -vis sweep & displace hole w/ flo-pro mud. Perform F.I.T. MWT 9.1 ppg @ 1503' tvd, 461 psi = 15.0 ppg EMW. Directional drill ahead 12-1/4" hole f/ 1538'- 1553'. Lost throttle to carrier engines. ART: 0.2 hrs. Troubleshoot throttle to carrier engines. Drill ahead as per directional driller f/ 1553'- 1790'. ART: 1.9 hrs., AST: 1.2 hrs. Directional drill f/ 1790'- 1995' Up Wt. 77k. Dn wt. 75k Rt. Wt. 76k Tq 4.5k. 65 rpm. 297spm 576gpm 1240psi. Art = 2.3 hr. Ast=1.2 hr. No Gain/ Loss. Continue to build mud volume while drilling ahead. Directional drill f/ 1995'-2372'. Up Wt: 84k, Dn Wt: 82k, Rt Wt: 83k, RPM: 70, Tq: 5-6k, WOB: 3-10k, GPM: 610 @ 308 spm, SPP: 1400 psi, ART: 1.8 hrs, AST: 1.2 hrs. Increase pump rate to 590 gpm @ 12:30 hrs. & 610 gpm @ 14:30 hrs. No Gains / Losses. Directional drill f/ 2372'-2688'. Up Wt: 90k, Dn Wt: 90k, Rt Wt: 90k, RPM: 70, Tq: 3-7k, WOB: 5-10k, GPM: 610 @ 308 spm, SPP: 1500 psi, ART: 1.8 hrs, AST: 1.8 hrs. No Gains / Losses. Directional drill f/ 2688'-3002'. Up Wt: 98k, Dn Wt: 90k, Rt Wt: 95k, RPM: 60-70, Tq: 4-6k, WOB: 2-8k, GPM: 610 @ 308 spm, SPP: 1500 psi, ART: 2.3 hrs, AST: 1.7 hrs. No Gains / Losses. Directional drill f-3002'- 3170'. ART: 0.3 hrs. Cuttings tank full, Pump tank out, over shakers to recover mud. Mix 2 LCM blanked off shakers. Circ and clean up mud Directional drill f/ 3170'-3316'. Up Wt: 100k, Dn Wt: 90k, Rt Wt: 100k, RPM: 60-70, Tq: 4-7k, WOB: 2-8k, GPM: 610 @ 308 spm, SPP: 1500 psi, ART: 2.1 hrs, AST: 1.4 hrs. No Gains / Losses. Note: Held safety meeting with crews, epoch and asrc, discussed monitoring of mud pits and cuttings tank to prevent spills. Circulate B/U. Monitor well, Pump dry job POH ( wiper trip ) f 3255'-1491' Hole slick, no over pulls. Correct hole fill. Static loss: 1 bph. Lube rig. Blocks, Top drive and crown. Service carrier. ck. drive lines same. Test load on rig generator with Mi centrifuge van on line RIH f-1491'- 3254' Wash down to 3316'. No fill. Directional drill f/ 3316'-3575'. Up Wt: 105k, Dn Wt: 105k, Rt Wt: 105k, RPM: 77, Tq: 3-5k, WOB: 5-10k, GPM: 620 @ 315 spm, SPP: 1400 psi, ART: 2.3 hrs, AST: 1.2 hrs. Pumped 30 bbl hi -vis sweep @ 3379'. 300% cuttings increase. Trip Gas: 28 units. Max Gas: 223 units. Directional drill f/ 3575-3850'. Up Wt: 110k, Dn Wt: 100k, Rt Wt: 105k, RPM: 70, Tq: 3-5k, WOB: 3-5k, GPM: 620 @ 315 spm, SPP: 1700 psi, ART: 2.8 hrs, AST: 1.1 hrs. Average losses @ 10 bph. Reduced flow to minimize losses: 565 gpm @ 04:50 hrs. Directional drill f/ 3850'-4071'. GPM: 535 @ 285 spm, SPP: 1600 psi, WOB: 3-7k, RPM: 70, Tq: 3-5k, P/U: 112k, S/O: 101k, Rot: 108k, ART: 1.8 hrs, AST: 0 hrs. Average losses @ 10 bph. Printed: 1/31/2008 8:27:29 AM 0 0 Marathon Oil Company Page 4 o 7 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Event Name: ORIGINAL DRILLING Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From -To Hours Code Sub Code Phase 12/7/2007 09:00 - 10:00 1.00 CIRC MUD IN1DRL 10:00-13:25 3.42 TRIP WIPR IN1DRL 13:25-16:00 2.58 REPAIR RIG_ IN1DRL 16:00- 18:00 2.00 TRIP_ DP_ IN1DRL 18:00 - 00:00 6.00 DRILL ROT IN1DRL 00:00 - 06:00 6.00 DRILL ROT IN1DRL 12/8/2007 06:00 - 12:00 6.00 DRILL ROT IN1DRL 12:00 - 18:00 6.00 DRILL ROT IN1DRL 18:00 - 22:45 4.75 DRILL_ ROT_ IN1DRL 22:45 - 02:30 3.75 CIRC MUD IN1DRL 02:30 - 06:00 3.50 TRIP DP IN1DRL 12/9/2007 06:00 - 09:00 3.00 TRIP_ BHA_ IN1DRL 09:00 - 10:00 1.00 CLEAN_ RIG_ IN1DRL 10:00-10:30 0.50 RUNPUL WBSH IN1CSG 10:30-13:30 3.00 TEST CSG IN1CSG 13:30-19:00 5.50 RURD CSG_ IN1CSG 19:00 - 06:00 11.00 RUN CSG IN1CSG 12/10/2007 06:00 - 06:40 0.67 RUN_ CSG_ IN1CSG Spud Date: 11/29/2007 Start: 10/30/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations Circ B/U spot 100bbl LCM pill from 4071-3650' Pump at 535gpm 1450psi. Loss to Hole 10bbls per hr. Monitor well POH to 3350', Pump dry job, Continue POH to 1491' Hole slick. Fluid loss to hole 6bbls. Troubleshoot and run generators in parallel. Work on control issues. Monitor fluid loss with trip tank. Total loss 5bbis in 4.5hrs Rih f-1491'- 4003' Wash f-4003-4071' No fill Hole slick. No losses Directional drill f/ 4071'-4511'. GPM: 535 @ 270 spm, SPP: 1500 psi, WOB: 5-10k, RPM: 75, Tq: 3-6k, P/U: 115k, S/O: 115k, Rot: 115k, ART: 3.0 hrs, AST: 0.9 hrs. Trip gas: 78 units, Max gas: 238 units. Average background gas: 35 units. Average losses @ 15 bph. Directional drill f/ 4511'-4720'. GPM: 575 @ 290 spm, SPP: 1700 psi, WOB: 2-12k, RPM: 60-70, Tq: 3-6k, P/U: 140k, S/O: 115k, Rot: 125k, ART: 1.4 hrs, AST: 2.2 hrs. Average losses @ 15 bph. Minimum flow 510 to 550 gpm to control losses. Average background gas 15 units. Directional drill f/ 4720'4975 GPM: 565 @ 285 spm, SPP: 1550 psi, WOB: 2-12k, RPM: 60-70, Tq: 3-6k, P/U:140 k, S/O:120 k, Rot: 135 k, ART: 1.9 hrs, AST: 1.8 hrs. Minimum flow 535 to 565 gpm to control losses. Average losses @ 6 bph. Directional drill f/'4975-5097' GPM: 545 @ 274 spm, SPP: 1700 psi, WOB: 2-12k, RPM: 60-70, Tq: 3-6k, P/U: k, S/O: k, Rot: k, ART: 0.7 hrs, AST: 2.7 hrs. Average losses @ 6 bph. Minimum flow 535 to 565 gpm to control losses. Pump hi vis sweep at 4979'. Sweep returned 200stks past caculated. Slight increase in cuttings returned over shakers. Add 1 % Lube tex for slides. . Directional drill f/ 5097'-5326. GPM: 565 @ 285 spm, SPP: 1650 psi, WOB: 5-22k, RPM: 75, Tq: 3-7k, P/U: 143k, S/O: 130k, Rot: 132k, ART: 2.3 hrs, AST: 1.0 hrs. Max gas 329 units. Average background gas 15 units. No fluid loss to formation. Circulate bottoms up sample for Geologist @ 5326'. Pump 40 bbl hi -vis sweep around & con't circulating until shakers clean. No significant cuttings increase over shakers. Spot 50 bbl LCM pill. Monitor well, pump dry job & prepare to POH. 9-5/8" casing pt. confirmed by Jennifer Enos. POH f/ 5326-1200'. SLM. No tight spots. No overpull. No gains or losses to hole. POH Stand back hwdp. Lay down 8" monels, pony collar, stablizer, MWD tool. Break out bit and lay down motor Clean, clear floor, blown down mud lines Pull wear bushing Change out pipe rams to 9 5/8 casing rams, P/U 9 5/8 test joint and plug. Attempt to test. pull test joint and replace o- ring on test plug 2x times. Install new o -ring, test 9 5/8 casing rams 250/ 1500psi 5 min. test good. Lay down test joint. Adjust torque tube R/U stabbing board C/O bails and elevators. Rig up weatherford Fill up tool, Elevators ,Spider and Casing tongs. Make gage run with 9 5/8 hanger. P/U & M/U 9-5/8" float shoe, shoe track & float collar. Check floats. Con't RIH w/ 9-5/8", 40 #/ft, L-80, BTC casing. Run total 130 jts w/ 34 total centralizers. Float shoe @ 5317.76', float collar @ 5235.93'. Circ csg volume @ 1504'& bottoms up @ 3000'. Wash fill to bottom f/ 5274'- 5305'@ 06:00 hrs. 15 bbl mud loss while washing to bottom. Continue to wash 9 5/8 csg. f- 5305'-5317' .Land out with 162K on Printed: 1/31/2008 8:27:29 AM 0 0 Marathon Oil Company Page 5 of Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL DRILLING Start: 10/30/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From -To Hours Code Sub Code Phase Description of Operations 12/10/2007 06:00 - 06:40 0.67 RUN_ CSG_ IN1CSG hanger. No Gain/ loss 06:40 - 08:30 1.83 CIRC MUD_ INICSG Circ. at 6bbls per min 465psi while Bj batch mixes 189bbl 10.5ppg cement. No Gain loss Hold PJSM: discuss Hazards of cementing and review procedures. R/U BJ plug dropping/ cement head and lines. Pump 5 bbls water ahead. Test cmt lines to 3000 psi. Drop bottom plug. Pump 30 bbl Sealbond spacer followed by 320 sks of 10.5 ppg class G cmt w/ 47% LW -6,15% BA -90, 0.5% SMS, 1 % CD -32,1.2% FL -52, 0.005% Static Free, 1ghs FP -6L, 3.32 cu.ft./sk yield, 12.667 gal water/sk, 6:26 hrs thickening time, 189 bbl slurry, 98.38 mixing water. Drop top plug & kick out w/ 5 bbls water. Switch to rig pumps & displace w/ 393 bbls mud. Bumped plug @ 8450 stks w/ 1050 psi. Cement in place @ 11:38 hrs. Bleed off & check floats. 6 bbls mud lost during entire job. Top plug tattle -tale malfunction. Appeared top plug did not go down. Stop displacing @ 390 stks to open cmt head & verify plug went down. PJSM: Blow down mud line to pits & cmt lines back to slop tank. Blow down top drive. Rig down cement & casing equipment. Install 9-5/8" x 13-3/8" pack -off. Test to 5000 psi for 10 minutes. Change out rams f/ 9-5/8" to 3-1/2" x 5" variables. Set test plug. Test bope & all related components to 250/3000 psi for 5 minutes.. Check gas alarms, flow & PVT equipment. Perform accumulator drawdown test. Install wear bushing. Service rig. Blow down mud lines. C/O hydraulic lines in pump motor room. Pick up & make up 8-1/2" directional bha. Scribe motor & MWD. Shallow test MWD. Continue TIH w/ 5" drill pipe to 5005' (200' above float collar). WOC. Perform rig service & maintenance. Continue WOC. Service rig. Test 9 5/8 csg. to 1500/ 30 min. Test Good. Blow down lines RIH f--5003' to 5235' Tag up on Float collar Drill Shoe track f- 5235' to 5317', Drill firm cement F- 5235-5317 Clean out old hole f-5317'-5326'. Drill / Rotate f-5326'-5346' Circ B/U. Perform FIT test @ 5299'tvd, 9.4ppg mw, 991 psi=,13ppg EMW. After 10 min Pressure at 945psi. Drill 8-1/2" vertical hole f/ 5346'-5772'. GPM: 535 @ 270 spm, SPP: 1600 psi, WOB: 2-11k, RPM: 80, Tq: 3-6k, P/U: 135k, S/O: 120k, Rot: 130k, ART: 3.2 hrs, AST: 0 hrs. No fluid loss to formation. Max gas: 173 units. Avg background gas: 15 units. Hydraulic line on pump # 2 leaking. Circulate bottoms up. PJSM: POH into 9-5/8" casing shoe for rig repair.. Change out hydraulic lines between Denison pumps & Hagglunds motors on mud pumps #1 & #2. Fixed Epoch RPM sensor while waiting on repairs. RIH. Tag up @ 5757'. Wash 15' fill to bottom. Drill f/ 5722'-6026'. GPM: 535 @ 270 spm, SPP: 1600 psi, WOB: 2-8k, RPM: 80, Tq: 5-7k, P/U: 155k, S/O: 145k, Rot: 150k, ART: 6.4 hrs, AST: 0 hrs, Trip gas: 120 units, avg conn gas: 80 units, avg background gas: 15 units. Printed: 1/31/2008 8:27:29 AM 08:30 - 09:00 0.50 RURD CMT IN1CSG 09:00 - 12:00 3.00 PUMP CMT IN1CSG 12:00 - 15:00 3.00 RURD CMT IN1CSG 15:00 - 16:00 1.00 TEST_ WLHD INICSG 16:00 - 20:30 4.50 TEST_ ROPE INICSG 20:30 - 21:30 1.00 RUNPUL WBSH IN1CSG 21:30 - 00:00 2.50 SERVIC RIG IN1CSG 00:00 - 02:00 2.00 PULD_ BHA_ INICSG 02:00 - 04:30 2.50 TRIP_ DP_ INICSG 04:30 - 06:00 1.50 WAITON CMT_ IN1CSG 12/11/2007 06:00 - 11:30 5.50 WAITON CMT_ INICSG 11:30 -12:30 1.00 TEST_ CSG_ INICSG 12:30 - 12:50 0.33 TRIP_ DP_ INICSG 12:50 - 14:45 1.92 DRILL CMT IN1CSG 14:45 -15:00 0.25 DRILL_ ROT_ INICSG 15:00-16:00 1.00 TEST LOT IN1CSG 16:00 - 21:00 5.00 DRILL_ ROT_ PR1DRL 21:00 - 21:45 0.75 CIRC_ MUD_ PR1DRL 21:45 - 22:15 0.50 TRIP_ DP_ PR1DRL 22:15 - 01:30 3.25 REPAIR RIG PR1DRL 01:30 - 02:00 0.50 TRIP_ DP_ PR1DRL 02:00 - 06:00 4.00 DRILL ROT PRIDRL cement. No Gain loss Hold PJSM: discuss Hazards of cementing and review procedures. R/U BJ plug dropping/ cement head and lines. Pump 5 bbls water ahead. Test cmt lines to 3000 psi. Drop bottom plug. Pump 30 bbl Sealbond spacer followed by 320 sks of 10.5 ppg class G cmt w/ 47% LW -6,15% BA -90, 0.5% SMS, 1 % CD -32,1.2% FL -52, 0.005% Static Free, 1ghs FP -6L, 3.32 cu.ft./sk yield, 12.667 gal water/sk, 6:26 hrs thickening time, 189 bbl slurry, 98.38 mixing water. Drop top plug & kick out w/ 5 bbls water. Switch to rig pumps & displace w/ 393 bbls mud. Bumped plug @ 8450 stks w/ 1050 psi. Cement in place @ 11:38 hrs. Bleed off & check floats. 6 bbls mud lost during entire job. Top plug tattle -tale malfunction. Appeared top plug did not go down. Stop displacing @ 390 stks to open cmt head & verify plug went down. PJSM: Blow down mud line to pits & cmt lines back to slop tank. Blow down top drive. Rig down cement & casing equipment. Install 9-5/8" x 13-3/8" pack -off. Test to 5000 psi for 10 minutes. Change out rams f/ 9-5/8" to 3-1/2" x 5" variables. Set test plug. Test bope & all related components to 250/3000 psi for 5 minutes.. Check gas alarms, flow & PVT equipment. Perform accumulator drawdown test. Install wear bushing. Service rig. Blow down mud lines. C/O hydraulic lines in pump motor room. Pick up & make up 8-1/2" directional bha. Scribe motor & MWD. Shallow test MWD. Continue TIH w/ 5" drill pipe to 5005' (200' above float collar). WOC. Perform rig service & maintenance. Continue WOC. Service rig. Test 9 5/8 csg. to 1500/ 30 min. Test Good. Blow down lines RIH f--5003' to 5235' Tag up on Float collar Drill Shoe track f- 5235' to 5317', Drill firm cement F- 5235-5317 Clean out old hole f-5317'-5326'. Drill / Rotate f-5326'-5346' Circ B/U. Perform FIT test @ 5299'tvd, 9.4ppg mw, 991 psi=,13ppg EMW. After 10 min Pressure at 945psi. Drill 8-1/2" vertical hole f/ 5346'-5772'. GPM: 535 @ 270 spm, SPP: 1600 psi, WOB: 2-11k, RPM: 80, Tq: 3-6k, P/U: 135k, S/O: 120k, Rot: 130k, ART: 3.2 hrs, AST: 0 hrs. No fluid loss to formation. Max gas: 173 units. Avg background gas: 15 units. Hydraulic line on pump # 2 leaking. Circulate bottoms up. PJSM: POH into 9-5/8" casing shoe for rig repair.. Change out hydraulic lines between Denison pumps & Hagglunds motors on mud pumps #1 & #2. Fixed Epoch RPM sensor while waiting on repairs. RIH. Tag up @ 5757'. Wash 15' fill to bottom. Drill f/ 5722'-6026'. GPM: 535 @ 270 spm, SPP: 1600 psi, WOB: 2-8k, RPM: 80, Tq: 5-7k, P/U: 155k, S/O: 145k, Rot: 150k, ART: 6.4 hrs, AST: 0 hrs, Trip gas: 120 units, avg conn gas: 80 units, avg background gas: 15 units. Printed: 1/31/2008 8:27:29 AM 0 Marathon Oil Company Page 6 of 7 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL DRILLING Start: 10/30/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 DateSub From - To Hours I Code Code Phase) Description of Operations 12/12/2007 106:00 - 12:00 6.00 DRILL_ ROT_ PR1DRL Drill f/ 6026'-6374', ART: 4.1 hrs, AST: 0 hrs, GPM: 535 @ 270 spm, 12/13/2007 06:00 - 10:00 4.00 DRILL_ ROT_ SPP: 1600 psi, WOB: 2-10k, RPM: 80-90, Tq: 3-7k, P/U: 155k, S/O: Drill f 7300'-7600', ART=3.6, AST=AST=O, GPM=435 @ 220 stks, 1750 140k, Rot: 150k, avg conn gas: 80 units, avg background gas: 15 units. psi, bit wt.=5-1OK Tq.=6-1 OK, Up wt.=190k, Dn. wt.=155k, max gas 210 units. 12:00 - 17:00 5.00 DRILL_ ROT_ PR1DRL Drill f/ 6374'- 6783', ART: 3.7 hrs, AST: 0 hrs, GPM: 535 @ 270 spm, . TRIP_ DP_ PR1DRL lube-tex to mud. SPP: 1700 psi, WOB: 5-8k, RPM: 86, Tq: 5-9k, P/U: 160k, S/O: 145k, 1.50 CIRC_ MUD_ PR1DRL Circ. bottoms up, TD well @7600', Max. gas 180 units. Rot: 160k, avg conn gas: 200 units, avg background gas: 12 units, max 11:30 - 15:00 3.50 TRIP_ WIPR PR1 DRL gas: 249 units. Begin increasing mud weight f/ 9.3 to 9.8+ @ 6625'. 17:00 - 17:45 0.75 CIRC_ MUD_ PR1DRL Circ B/U at 535gpm 1650psi. Clean up hole for wiper trip. B/U gas 110 Shoe. 15:00 - 16:00 1.00 SERVIC units. 17:45 - 19:40 1.92 TRIP_ WIPR PR1DRL Monitor well, pull 5 stands. Monitor well, Pump dry job POH (wiper trip) WIPR PR1DRL PJSM: RIH f/ 5265'-7544'. Wash last std down f/ 7544'-7600'. 5' fill on 12/14/2007 06:00 - 07:30 f-6783'- 5708' 19:40 - 20:00 0.33 SERVIC RIG—PR1DRL Lube rig. Check carrier drive lines. Service top drive. 20:00 - 20:30 0.50 TRIP_ WIPR PR1DRL RIH f/ 5708'- 6720'. Wash f/ 6720' to 6783'. No fill. No gains or losses. 20:30 - 00:00 3.50 DRILL_ ROT_ PR1DRL Drill f/ 6783'- 6999', ART: 2.5 hrs, AST: 0 hrs, GPM: 535 @ 270 spm, SPP: 1800 psi, WOB: 5-8k, RPM: 86, Tq: 3-9k, P/U: 165k, S/O: 140k, hole to 3000'. No problems RIH. Tagged bottom 6' early. 12:30 - 13:30 1.00 SAFETY Rot: 158k, avg conn gas: 75 units, avg background gas: 20 units, max PR1EVL Conduct weekly safety meeting w/both rig crews. 13:30 - 14:30 1.00 gas: 234 units, trip gas: 255 units. Increase mud wt to 10.0+ ppg. 00:00 - 06:00 6.00 DRILL_ ROT_ PR1DRL Drill f/ 6999'- 7300', ART: 4.0 hrs, AST: 0 hrs, GPM: 435 @ 220 spm, LOG_ OH_ PR1EVL Process data & send logging information to geologist. SPP: 1650 psi, WOB: 5-10k, RPM: 90-95, Tq: 6-10k, P/U: 180k, S/O: 7.50 LOG_ OH_ PR1EVL Pick up RFT tools. RIH to 5000' on wireline. Wait for geologist' pressure 150k, Rot: 160k, avg conn gas: 80 units, avg background gas: 45 units, max gas: 423 units. Begin increasing mud wt. to 10.2 ppg @ 7040', and 22:30 - 06:00 7.50 LOG_ OH_ to 10.4 ppg @ 7240'. (Pump #1 taken offline @ 02:30 hrs, continuous RIH w/ RFT tools & perform RFT's as per geologist. destroking). 12/13/2007 06:00 - 10:00 4.00 DRILL_ ROT_ PR1 DRL Drill f 7300'-7600', ART=3.6, AST=AST=O, GPM=435 @ 220 stks, 1750 psi, bit wt.=5-1OK Tq.=6-1 OK, Up wt.=190k, Dn. wt.=155k, Rot.wt.=166k, Max. gas =180 units, TD Well at 7600'. Added 1% 19:30 - 01:00 5.50 TRIP_ DP_ PR1DRL lube-tex to mud. 10:00 - 11:30 1.50 CIRC_ MUD_ PR1DRL Circ. bottoms up, TD well @7600', Max. gas 180 units. 11:30 - 15:00 3.50 TRIP_ WIPR PR1 DRL PJSM; For pulling out, for short trip.Monitor well, POOH to 5265'Csg. Shoe. 15:00 - 16:00 1.00 SERVIC RIG_ PR1 DRL Serv. rig and equip. Blow down mud lines. 16:00 - 17:30 1.50 TRIP_ WIPR PR1DRL PJSM: RIH f/ 5265'-7544'. Wash last std down f/ 7544'-7600'. 5' fill on 12/14/2007 06:00 - 07:30 1.50 RURD_ ELEC PR1EVL bottom. No gains or losses. Printed: 1/31/2008 8:27:29 AM 17:30 - 19:30 2.00 CIRC_ MUD_ PR1DRL Circ B/U. Pump hi -vis sweep around. No noticable increase in cuttings over shakers. Monitor well (static), Pump dry job. Blow down mud lines. Trip gas: 112 units. 19:30 - 01:00 5.50 TRIP_ DP_ PR1DRL PJSM: POOH f/ 7600'-798'. SLM (no correction). No tight spots. No overpull. No gains or losses to hole. 01:00 - 03:30 2.50 PULD_ BHA_ PR1DRL PJSM: Rack back HWDP. Lay down NM flex collars, cross over subs, MWD, stabilizer, pony collar, mud motor & bit. 03:30 - 04:30 1.00 CLEAN_ RIG_ PR1EVL PJSM: Clear rig floor. Blow down mud lines. 04:30 - 06:00 1.50 RURD_ ELEC PR1EVL PJSM: Rig up to run wireline logs. 12/14/2007 06:00 - 07:30 1.50 RURD_ ELEC PR1EVL Rig up Weatherford quad -combo logging tools.Notified Greg Nooble of logging @ 0700hrs. 07:30 - 12:30 5.00 LOG_ OH_ PR1EVL RIH w/ quad -combo logging tools on wireline to 7594'. Logged out of hole to 3000'. No problems RIH. Tagged bottom 6' early. 12:30 - 13:30 1.00 SAFETY MTG_ PR1EVL Conduct weekly safety meeting w/both rig crews. 13:30 - 14:30 1.00 PULD_ LOG_ PR1EVL POOH & lay down quad -combo logging tools. 14:30 - 15:00 0.50 LOG_ OH_ PR1EVL Process data & send logging information to geologist. 15:00 - 22:30 7.50 LOG_ OH_ PR1EVL Pick up RFT tools. RIH to 5000' on wireline. Wait for geologist' pressure pick points. 22:30 - 06:00 7.50 LOG_ OH_ PR1EVL RIH w/ RFT tools & perform RFT's as per geologist. Printed: 1/31/2008 8:27:29 AM 0 0 Marathon Oil Company Page 7 of 7' Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL DRILLING Start: 10/30/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From - To Hours Code Code Phase Description of Operations 12/15/2007 06:00 - 12:00 6.00 LOG_ OH_ PR1 EVL Running MFT logs with (34) stop points. 12:00 - 13:00 1.00 RURD_ ELEC PR1 EVL PJSM; Lay down MFT logging tools and rig down. Change to completion phase @ 13:00 hrs on 12/14/2007. Printed: 1/31/2008 8:27:29 AM • 0 Marathon Oil Company Page 1 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From -To Hours Code Sub I Code Phase 12/15/2007 13:00 - 17:30 4.50 TRIP_ DP_ PRICSG 17:30 - 18:30 1.00 REAM_ OH_ PRICSG 18:30 - 20:30 2.00 CIRC MUD PRICSG 20:30 - 06:00 9.50 PULD_ DP_ PR1CSG 12/16/2007 06:00 - 07:30 1.50 RURD CSG PRICSG 07:30-12:00 4.50 RURD CSG PR1CSG 12:00 - 06:00 18.00 RUN CSG PR1CSG 12/17/2007 06:00 - 07:30 1.50 RUN CSG PRICSG 07:30 - 09:00 1.50 CIRC MUD PRICSG 09:00 - 09:30 0.50 RURD_ ELEC PRICSG 09:30-12:00 2.50 RUNPU ELEC PR1CSG 12:00 - 14:00 2.00 CIRC MUD PRICSG 14:00 - 17:00 3.00 PUMP CMT_ PRICSG 17:00 - 02:30 9.50 WAITON CMT PR1CSG 02:30 - 06:00 3.50 NUND BOPE PR1CSG 12/18/2007 06:00 - 11:00 5.00 TEST TREE PR1CSG 11:00 - 00:00 13.00 RURD_ RIG_ RDMO Spud Date: 11/29/2007 Start: 12/10/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations PJSM. P/U and M/U 8.5" bit and bit sub. RIH. Tag @ 7527'. Ream down f/ 7500'-7600'. 3' fill on bottom. Circ B/U (300% cuttings increase). Pump hi -vis sweep around (100% cuttings increase). Con't circ until shakers clean. Trip gas: 79 units. Large pieces of sandstone across shakers. Monitor well. Pump dry job. Blow down mud lines. POOH w/ laying down 224 its 5" drill pipe, 21 jts hwdp, jars, bit sub & bit. No tight spots. No gains or losses. PJSM; Clear rig floor, blow down mud lines, pull wear bushing. Change bails, elevators. PJSM; With Weatherford, Expro, Pollard wireline,Rig up to run 3 1/2 Excape completion. with 15 Modules. P/U & M/U 3-1/2" float shoe, shoe track & float collar. Check floats. Con't RIH w/ 3-1/2" 9.3 ppf, L-80, Mod 8rd casing. Run total 202 jts w/ 15 Excape modules, 3 control lines & 1 sacrificial line. Circ 1x csg volume @ 2232'& 1x B/U @ 9-5/8" csg shoe. No gains or losses. Correct displacement. Current depth @ 06:00 hrs is 7093'. Con't RIH w/ 3-1/2" 9.3 ppf, L-80, Mod EUE casing f/ 7093'- 7563'. Run total 217 jts w/ 15 Excape modules, 3 control lines & 1 sacrificial line. Preliminary shoe depth @ 7563'& float collar @ 7526'. No gains or losses during entire job. Correct displacement. Notified BLM @0745 of Cmt. job,Greg Noble, Tim Lawlor,left message PJSM: Circ hole clean for correlation logs. Flow @ 5 bpm (105 spm) w/ 500 psi. PJSM: R/U Expro wireline for Excape module correlations. PJSM: Run Expro correlation logs. PJSM: P/U 6' pup jts & 2" cmt line. Circ hole @ 7570' @ 3.8 bpm w/ 475 psi. Space out Excape modules as per correlation log. R/D & UD Weatherford tongs & Expro control line sheave derrick. R/D circ head. Float shoe set @ 7570.74'. Float collar set @ 7533.39'. PJSM: install cmt head, establish circulation & pump 84 b5ls Concor 404. Pump 5 bbls water ahead & test cmt lines to 4000 psi. Mix & pump 40 bbl Sealbond 11.0 ppg spacer followed by 1070 sks of 15.8 ppg Gass G cmt w/ 1.2% BA -56, 0.5% EC -1, 0.3% CD -32, 0.2% A-2, 0.05% Static Free, lghs FP -6L, 1.16 cu.ft./sk yield, 4.9 gal water/sk, 3:00 hrs thickening time, 221 bbl slurry, 124.8 bbls mix water. Close valve to head, open wash up valve & pump 5 bbls water. Close wash up valve & open to head. Drop plug & kick out w/ 5 bbls water. Displace cmt w/ 60.46 bbls KCL water from vac truck. Bump plug w/ 1000 psi over displacement pressure. Cement in place @ 16:40 hrs. Bleed off & check floats. Turn over to rig. No mud lost. PJSM: WOC. Reconnect flow line adapter & pitcher nipple. Flush choke manifold & mud pumps. R/D hydraulic control lines. Blow down choke line & mud pumps. PJSM: Unbolt spool & lift stack. Set slips (20klbs over). Make rough cut on 3-1/2" csg. UD pitcher nipple. Disconnect koomey lines. Move out stack & drop spool. PJSM: Make final cut on 3-1/2" csg. Install & test packoff to 5000 psi/ 10 min. Ipstall tree & terminate Excape control lines Test upper void to 5000 psi/ 15 min. Test tree to 10,000 psi/ 10 min. R/U & test 3-1/2" csg to 1720 psi/ 15 min. Install back pressure valve. PJSM: Clean pits & trip tank. R/D pop off lines. Remove saver sub for inspection. R/D service loop & keliy hose. C/O quick connect for TD. Printed: 1/31/2008 8:28:05 AM Marathon Oil Company Page 2 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Event Name: ORIGINAL COMPLETION Contractor Name: GLACIER DRILLING Rig Name: GLACIER DRILLING Date From -To Hours Code Sub Code Phase 12/18/2007 11:00 - 00:00 13.00 RURD RIG_ RDMO ELEC 00:00 - 06:00 6.00 RURD RIG RDMO 12/19/2007 06:00 - 09:00 3.00 RURD RIG RDMO 12/27/2007 06:00 - 12:00 6.00 RURD_ RIG_ RDMO 12:00 - 06:00 18.00 RURD RIG RDMO 1/7/2008 111:00 -12:00 I 1.001 LOG_ I CSG_ I MIRU 12:00 -12:30 1 0.50 1 SAFETY I MTG_ J W RLN 12:30 - 12:45 0.25 RURD_ ELEC 12:45 - 13:00 0.25 RUNPU ELEC 13:00 - 17:00 4.00 RUNPU ELEC 17:00 -19:00 2.00 RUNPU ELEC 19:00 - 20:00 1.00 RUNPU ELEC 20:00 - 20:30 0.50 PULD_ LOG_ 1/16/2008 109:00 - 13:00 I 4.001 RURD I STIM 13:00 - 13:30 1/17/2008 08:00 - 08:30 08:30 - 10:00 10:00 - 10:30 10:30 - 11:00 11:00 - 11:15 0.501 PERF_ I CSG_ 0.501 SAFETY I MTG_ 1.501 PREP_ I LOC_ 0.501 TEST_ I EQIP 0.501 PUMP I FRAC 0.251 PERF_ I CSG_ WRLN WRLN WRLN WRLN Spud Date: 11/29/2007 Start: 12/10/2007 End: Rig Release: Group: Rig Number: 1 Description of Operations Inspect tugger lines. Reinstall spool wedge on red tugger. R/D tumbuckles on torque top. Unhang & UD torque tube. R/D "T" bar. Clean pits, cuttings box & more on hanson tank. Suck out degasser & sumps in pump room. Pickle pumps 1, 2, & 3. Load mud products & drill pipe. R/D koomey lines. Remove cylinder socks. Heat 400 bbls water. Clean trip tank. PJSM: R/D mud pump #3 suction & popoff lines. Unplug mud pumps 1 & 2 cooling towers. R/D shock hoses for mud pumps 1, 2 & 3. R/D cuttings tank, gas buster & u -tube. R/D choke lines to gas buster & flow line. Load out 50 bbl hot water for coil tubing operation. Finish UD pop off lines for mud pumps 1 & 2. Organize, band pallets and barrels. R/D auto driller. Pull plugs, check valve, and circ. screens for pumps in pits. Fuel equipment, replace flush fill valve on #1 mud pump. Start rigging down derrick board. R/D Stairs to bop conex. UD beaver slide. Blow down water lines, Pickle test pump. Remove cylinder socks. remove derrick skirt. Replace frozen water line. Start removing carrier tarps. Disconnect utility lines Remove trip tank and cellar grating. Pull wires from dog , choke and carrier. Prep and scope down mast. PJSM: Crane down windwalls, back landing,choke and dog houses. Remove gray iron and back landing. Remove fuel tank and mast house. Move carrier off mud boat. Load out trailers. R/D mud boat. Move sub off well center. Split pits. Layout CBUGR tool on ground and screw sections together PJSM -topics discussed included cold weather/new snow, PPE - hordtoes/FR coveralls, had hat/ gloves / eye protection. Rigging up in cold weather, slips/ trips/ falls. Moving equipment, pinch points, sheaves, cable drums, slippery stairs, ladders, working under crane loads, pick points Rig up crane, sheaves, pack -off, tools Start in hole Tool failure / rope socket failure. Run second tool. Computer issues WRLN Pull tool out of hole WRLN Lay down tools, close tree valves, replace night cap, rig down crane and wireline unit.Leave location MIRU Move in BJ frac crew/ Expro Well Test / Expro Perforating. Warm frac fluid, mix 6 % KCL, move in chem adds, frac van, test communications. Total rig up time 6 days due to sub zero temps, blowing snow. CMPPRF Perforate Module 1 @ 13:15 hours. Pressure 2180# Monitored at wellhead and acoutically CMPSTM slips, trips, falls, muster area, active producing gas pad. Red lights, blue lights, sirens, smoking area, cold slippery yellow containment, 3 second rule, buddy system. flow back CMPSTM Move Expro trailer, 2 lite plants, re -hook control lines to modules, press test control lines CMPSTM Pressure test BJ Services to 9530# - final pressure9456# Passed, Gelled the KCL water and tested viscosity CMPSTM Fracture stimulate module #1- 7128-7138 feet. Pump 15.8 BPM @ 5300# breakdown. Stage 2-4-6-8-10 PPG slurry. Pumped total of 341 BBL slurry, 22,820# of 40/20 Ottawa sand and 4,887# flex sand CMPSTM Perforate Module #2 from 6994 - 7004 feet. Visual and acoustical Printed: 1/31/2008 8:28:05 AM • 0 Marathon Oil Company Page 3 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL COMPLETION Start: 12/10/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From -To Hours Code Sub Code Phase Description of Operations 1/17/2008 11:00 - 11:15 0.25 PERF_ CSG_ CMPSTM confirmation. Pressure 4330# 11:15 - 11:30 0.25 PUMP FRAC CMPSTM Breakdown zone #2 15.8 BPM (@5130# . Staged 2-4-6-8 ppg slurry and then flushed. 2 very noticeable pressure spikes. Total slurry pumped 168 BBL with 11,204# of 20/40 Ottawa sand and 1602# of flex sand Perforate module #3 from 6884 - 6894 feet. Visual and acoustical r confirmation Fracture stimulate Zone #3 at 12.7 BPM. Staged 2-4-7-10 ppg. Screened out just as displacement flush reached zone. Pumped 115 BBI slurry with 5,373 # of 20/40 Ottawa Sand and 796# of Flex Sand Perforated Module #4 from 6794 - 6804 feet_ Visual and Acoustic confirmation. Gun shot at 6230# Fracture stimulation of zone #4. Staged 2-4-6-8-10 ppg slurry. Totatl 294 BBL slurry pumped and 42,804 # of 20/40 Ottawa sand with 2113# of flex sand Perforate Module #5 from 6733-6743 feet. Visual and acoustic confirmation Pressure 7110# fracture stimulate Zone 5. Staged 2-4-6-8 ppg slurry. Pumped total of 121 BBL of slurry at 12.6 BPM. Pumped 5821# of 20/40 Ottawa flex sand and 832 # of flex sand Perforate Module #6 from 6625 - 6635 feet. Visual and acoustic confirmation. Perforated at 8030# fracture stimulate zone #6 Pumping rate of 15.6 BPM. Staged 2-4-6-8 ppg. Pumped 242 BBL of slurry with 4187# of 20/40 Ottawa sand and 4187# of flex sand. Perforate Module #7 from 6580 - 6590 feet. Visual and acoustic - confirmation. Pressure 9110# fracture stimulate zone #7. Stage 2-4-6-8 ppg at 15.5 BPM. Pumped 285 BBL of slurry with 40,457# of 20/40 Ottawa Sand and 577611 of flex sand Perforate Module #8 from 6422 - 6432 feet. Visual and acoustical confirmation. Pressure 2730# fracture stimulate zone #8. Stage 2-4-6-8-10 ppg slurry. Pumped 242 BBL of slurry with 30,162# of 20/40 Ottawa sand and 4304# of flex sand Perforate Module #9 from 6301 6311 feet. visual and acoustic confirmation. Pressure 3750# fracture stimulate zone #9. Staged 2-4-6-8-10ppg slurry at 16 BPM. - Pumped 251 BBL of slurry with 28,283 # of 20/40 Ottawa Sand and 4037# of flex sand.. PorforatP Module #10 from 6192 to 6202 feet. Visual and acoustic confirmation. Pressure 4720# FrarhirP stimulate inn . #10. Stage 2-4-6-8 ppg slurry. Screened out - at 16:30 hours. Called BJ Coil crew to clean out. Pumped 114 BBL of slurry with 13,146 # of 20/40 Ottawa sand and 1879# of flex sand. Calculated 11,020 # of 20/40 sand in casing with 4,807 # of flex sand in casing to be cleaned out. BJ COIL crew in route to location slips trips falls, wind appears to be above 20 mph. Crane is de -rated in winds above 20 mph. Pressure, three second rule, buddy system, active gas producing pad. red light, blue light, sirens, muster area Wait for wind to die down - safety concerns riau_ o CTU. Pressure test - OK after filling tubing Start in hole Run in hole with BJ Coil at 80 feet per minute. Estimed 1400 feet of Printed: 1/31/2008 8:28:05 AM 11:30 - 11:45 0.25 PERF CSG CMPSTM 11:45 - 12:15 0.50 PUMP FRAC CMPSTM 12:15 - 12:30 0.25 PERF CSG CMPSTM 12:30 - 13:00 0.50 PUMP_ FRAC CMPSTM 13:00 -13:15 0.25 PERF CSG CMPSTM 13:15 -13:30 0.25 PUMP_ FRAC CMPSTM 13:30 - 13:45 0.25 PERF_ CSG_ CMPSTM, 13:45 - 14:00 0.25 PUMP FRAC CMPSTM 14:00 - 14:15 0.25 PERF CSG CMPSTM 14:15 - 15:00 0.75 PUMP FRAC CMPSTM 15:00 -15:15 0.25 PERF CSG CMPSTM 15:15 -15:30 0.25 PUMP FRAC CMPSTM 15:30 - 15:45 0.25 PERF CSG CMPSTM 15:45 - 16:00 0.25 PUMP FRAC CMPSTM 16:00 -16:15 0.25 PERF CSG CMPSTM 16:15 -16:30 0.25 PUMP FRAC CMPSTM 16:30 - 17:00 0.50 WAITON EQIP CMPSTM 17:00 - 17:30 0.50 SAFETY MTG CMPSTM 17:30 - 22:00 4.50 WAITON WTHR CMPSTM 22:00 - 23:59 1.98 RURD_ COIL CMPSTM 1/18/2008 00:00 - 02:00 2.00 CIRC CFLD CLNOUT and then flushed. 2 very noticeable pressure spikes. Total slurry pumped 168 BBL with 11,204# of 20/40 Ottawa sand and 1602# of flex sand Perforate module #3 from 6884 - 6894 feet. Visual and acoustical r confirmation Fracture stimulate Zone #3 at 12.7 BPM. Staged 2-4-7-10 ppg. Screened out just as displacement flush reached zone. Pumped 115 BBI slurry with 5,373 # of 20/40 Ottawa Sand and 796# of Flex Sand Perforated Module #4 from 6794 - 6804 feet_ Visual and Acoustic confirmation. Gun shot at 6230# Fracture stimulation of zone #4. Staged 2-4-6-8-10 ppg slurry. Totatl 294 BBL slurry pumped and 42,804 # of 20/40 Ottawa sand with 2113# of flex sand Perforate Module #5 from 6733-6743 feet. Visual and acoustic confirmation Pressure 7110# fracture stimulate Zone 5. Staged 2-4-6-8 ppg slurry. Pumped total of 121 BBL of slurry at 12.6 BPM. Pumped 5821# of 20/40 Ottawa flex sand and 832 # of flex sand Perforate Module #6 from 6625 - 6635 feet. Visual and acoustic confirmation. Perforated at 8030# fracture stimulate zone #6 Pumping rate of 15.6 BPM. Staged 2-4-6-8 ppg. Pumped 242 BBL of slurry with 4187# of 20/40 Ottawa sand and 4187# of flex sand. Perforate Module #7 from 6580 - 6590 feet. Visual and acoustic - confirmation. Pressure 9110# fracture stimulate zone #7. Stage 2-4-6-8 ppg at 15.5 BPM. Pumped 285 BBL of slurry with 40,457# of 20/40 Ottawa Sand and 577611 of flex sand Perforate Module #8 from 6422 - 6432 feet. Visual and acoustical confirmation. Pressure 2730# fracture stimulate zone #8. Stage 2-4-6-8-10 ppg slurry. Pumped 242 BBL of slurry with 30,162# of 20/40 Ottawa sand and 4304# of flex sand Perforate Module #9 from 6301 6311 feet. visual and acoustic confirmation. Pressure 3750# fracture stimulate zone #9. Staged 2-4-6-8-10ppg slurry at 16 BPM. - Pumped 251 BBL of slurry with 28,283 # of 20/40 Ottawa Sand and 4037# of flex sand.. PorforatP Module #10 from 6192 to 6202 feet. Visual and acoustic confirmation. Pressure 4720# FrarhirP stimulate inn . #10. Stage 2-4-6-8 ppg slurry. Screened out - at 16:30 hours. Called BJ Coil crew to clean out. Pumped 114 BBL of slurry with 13,146 # of 20/40 Ottawa sand and 1879# of flex sand. Calculated 11,020 # of 20/40 sand in casing with 4,807 # of flex sand in casing to be cleaned out. BJ COIL crew in route to location slips trips falls, wind appears to be above 20 mph. Crane is de -rated in winds above 20 mph. Pressure, three second rule, buddy system, active gas producing pad. red light, blue light, sirens, muster area Wait for wind to die down - safety concerns riau_ o CTU. Pressure test - OK after filling tubing Start in hole Run in hole with BJ Coil at 80 feet per minute. Estimed 1400 feet of Printed: 1/31/2008 8:28:05 AM Marathon Oil Company Page 4 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL COMPLETION Start: 12/10/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From -To Hours Code Sub I Code Phase Description of Operations 1/18/2008 00:00 - 02:00 2.00 CIRC_ CFLD CLNOUT sand fill on flapper at 6450 feet. Estimated top of fill at 5000 feet. Slow coil down at 4700 feet and wash down to flapper 02:00 - 03:10 1.17 CIRC_ CFLD CLNOUT set down on flapper. Apply weight to break flapper. Circulate under returns are clean and come back out of hole 03:10 - 03:40 0.50 RURD_ COIL CLNOUT RD CTU . Set back injector head onto stand, close valves, install nitecap shut down for evening. CTU crew released from location. 03:40 - 09:00 5.33 SECURE WELL CMPSTM secure well for evening, waiting for daylight to finish fracture stimulation of last 5 intervals. 09:00 - 09:30 0.50 SAFETY MTG_ CMPSTM slips, trips, falls, muster area, active producing gas pad. Red lights, blue lights, sirens, smoking area, cold slippery yellow containment, 3 second rule, buddy system. flow back 09:30 - 10:00 0.50 TEST_ EQIP CMPSTM Pressure test BJ Services to6800# - Passed, Gelled the KCL water and tested viscosity 10:00 - 10:15 0.25 PERF_ CSG_ CMPSTM Perforate Module # 11 from 6027 to 6037 feet. Visual and acoustical . confirmation. Pressure 5340# 10:15 -10:30 0.25 PUMP_ FRAC CMPSTM Fracture stimulate zone #11. Pump 15.9 BPM . Stage 1-2-4-6 PPG slurry. Pumped total of 324 BBL slurry, 12,149 # of 40/20 Ottawa sand and 1728 # flex sand Note: whenever we have a clean out, the pumping into the next zone sends a possible slug of sand and induces a large pressure surge into the formation. We almost lost this interval. 10:30 - 10:45 0.25 PERF_ CSG_ CMPSTM Perforate Module # 12 from 5850 to 5860 feet. Visual and acoustical - confirmation. Pressure 6300 # 10:45 - 11:00 0.25 PUMP_ FRAC CMPSTM attempted to fracture stimulate zone # 12. Immediate pressure spikes during breakdown. Stage 1# slurry to scourormation. umieTp lgr BBL. with 710# of 20/40 Ottawa sand and 71 # of flex sand 11:00 - 11:15 0.25 PERF_ CSG_ CMPSTM Perforate module # 13 from 5808 to 5818 feet. Visual and acoustical - confirmation Pressure 7430# 11:15 - 11:30 0.25 PUMP_ FRAC CMPSTM Fracture stimulate Zone # 13 Staged 2-4-6-8 ppg. Pumped 173 BBL of slung, with 17,787# of 20/40 Ottawa sand and 2110# of flex sand 11:30 - 11:45 0.25 PERF_ CSG_ CMPSTM Perforated Module # 14 from 5442 to 5452 feet. Visual and Acoustic confirmation. Gun shot at 8550# 11:45 - 12:00 0.25 PUMP_ FRAC CMPSTM Fracture stimulation of zone # 14. Staged 2-4-6-8 ppg slurry. Totatl 176 BBL slurry pumped and 16522 # of 20/40 Ottawa sand with 2358# of flex sand 12:00 - 12:15 0.25 PERF_ CSG_ CMPSTM Perforate Module # 15 from 5382 to 5392 feet. Visual and acoustic - confirmation Pressure 9560# 12:15 - 12:30 0.25 PUMP_ FRAC CMPSTM f[acture stimulate Zone 15. Staged 2-4-6-8-10 ppg slurry. Pumped total of 212 BBL of slurry at 16 BPM. Pumped 26,345 # of 20/40 Ottawa flex sand and 3760 # of flex sand 12:30 - 14:00 1.50 RURD_ STIM CMPSTM Rig down frac crew in order to move CTU crew onto wellhead to perform casing cleanout and jet well in 14:00 - 14:30 0.50 SAFETY MTG_ CLNOUT PJSM -BJ CTU crew - 5 personnel, MOC- 2, ASRC - 2 ( 1 crane, 1 vac truck), Expro - 2.. Safety topics, slips trips falls, pressure, cold, buddy system, 3 second rule, pressure, overhead cranes, good housekeeping 14:30 - 15:30 1.00 RURD_ COIL CLNOUT ressure test CTU 15:30 - 19:00 3.50 CIRC_ CFLD CLNOUT Run in hole at 80 feet per minute. Total depth reached 7476 feet. Solid bottom. Circulate 6% KCL water until returns to surface are clean. Kick in 350 cfm of N2. Circulate N2 until N2 reaches bottom, Jet for another 20 minutes and start out of hole at approx.25 feet per minute while jetting. 19:00 - 23:59 4.98 BLOWD COIL CMPFLW Attempt to let in well with N2 across all perforations. Stop coil at 4800 feet and continue jetting well. Hold until N2 returns back to surface and proceed out of hole with coil. Very little fluid returns, no sand. Straight Printed: 1/31/2008 8:28:05 AM Marathon Oil Company Page 5 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y 2.00 Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL COMPLETION Start: 12/10/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From -To Hours Code Sub Code Phase Description of Operations 1/18/2008 19:00 - 23:59 4.98 BLOWDIICOIL SAFETY CMPFLW nitrrogen back to surface, kill nitrogen at 3800 feet and continue back to PR1EVL MIRU wire line unt, held PJSM and discussed operations with flow back surface. Well head pressure 200 - 230#. Well died when coil reached crew. Uptain permit. 07:30 - 09:30 2.00 RURD_ 1000 feet from surface. No returns when reached surface. Start back PR1EVL RU wire line unit, MU 1 11/16" tool string with 2.34" swedge. PT into hole to reject in across perforations. 1/19/2008 00:00 - 02:00 2.00 CLNOUT CSG_ CLNOUT Run in hole to attempt to re -jet well in. PR1EVL 02:00 - 02:45 0.75 CLNOLI CSG_ CLNOUT set down on bridge of sand at top of first set of perforations 5380 - 5390 PR1EVL OOH, MU logging tool. PU go to well. Open well, RIH with logging tool. 10:50 - 12:10 1.33 LOG_ feet. Circulated N2 and washed through it. Hit second bridge at top of PR1EVL &HP = 538 psig, 3.0 MMCFPD rate, 480 BPD water. RIH to 5200'. next set of perforations from 5440 - 5450 feet. Set down on it and made 2 min. bench stops. Start logging at 30 FPM down pass. 12:10 - 13:30 1.33 LOG_ attempted to wash through it 5 times. Depth of bridge on CTU 02:45 - 04:00 1.25 PULL_ EQIP CLNOUT POOH to pick up smaller jetting nozzle. Plan is to go in and clean out to bottom and attempt to re -jet well in. Low on N2 and cannot get re -supplied as all crews are out of hours. Attach smaller jetting nozzle. The wellhead pressure has built up to 100# during this procedure and begins to flow to flowback tank. Plan is to transfer to Expro flow back lines but lines are frozen. Continue to flow back through BJ flowlines. 04:00 - 06:00 2.00 WAITON WTHR CLNOUT 06:00 - 06:30 0.50 RURD COIL CLNOUT 06:30 - 20:00 13.50 FLOW BACK PRDTST 20:00 - 20:45 0.75 SAFETY MTG_ CLNOUT 20:45 - 21:45 21:45 - 23:59 1/20/2008 100:00 - 01:35 1.00 RURD J COIL CLNOUT 2.23 CLNOLICSG_ I CLNOUT 1.581 CLNOUIJ CSG_ I CLNOUT apply air heater to Expro flow lines and Tree. Build tent over tree and heat. Well begins to flow after heating tree for approx. 15 minutes 13ig down BJ Coil. Set back injector head. Install nite cap. Flow well through Expro well test. Well flowing at well head pressure of 250# / good fluids - broken KCL Gel. Continue flow back. Well head pressure 250#. Rate 1.7MMCFPD PJSM BJ Coil. Participants BJ Coil -5, ASRC - 3, Expro - 1, MOC - 1. Safety topics slips / trips / falls, pressure, buddy system, 3 second rule, active gas production pad, blue lites, red lites, sirens, muster areas, overhead loads Rig up BJ CTU, pressure test Coil on bottom - their odometer reading 7485 feet. Returns are 20/40 Ottawa frac sand, flex sand and broken KCL gel. Getting a lot of metal being circulated up from the perforating guns / or flappers. Start out of hole. Start out of hole. BJ odometer for deepest depth attained was 7485 feet. Cut Nitrogen @ 3000 after jetting across all perforations. Wellhead pressure back at surface 430# and climbing. Fluid returns Printed: 1/31/2008 8:28:05 AM 01:35 - 02:30 02:30 - 02:45 0.92 0.25 RURD_ FLOW_ COIL TEST CLNOUT CMPFLW wean witn a smau amount or nex sand. Back to surface. Switch flow to Expro flow lines, close swab valve, rig down injector head, set injector head on stand, set nite cap. Turn well over to Expro Well Test. Initial well test results: Rate - 1.5 MMCFPD, 1200 BWPD - broken frac fluid Wellhead pressure - 460 psi and climbin 02:45 - 23:59 21.23 FLOW BACK CMPFLW Continue flowback to clean up well 1/26/2008 07:00 - 07:30 0.50 SAFETY MTG_ PR1EVL MIRU wire line unt, held PJSM and discussed operations with flow back crew. Uptain permit. 07:30 - 09:30 2.00 RURD_ ELEC PR1EVL RU wire line unit, MU 1 11/16" tool string with 2.34" swedge. PT liubricator prior to opening up well. PT= 1500 psig, good test. 09:30 - 10:12 0.70 WORK ELEC PR1EVL OPen well, RIH tag fill at 7203' ELM. POOH with swedge. 10:12 - 10:50 0.63 LOG_ OTHR PR1EVL OOH, MU logging tool. PU go to well. Open well, RIH with logging tool. 10:50 - 12:10 1.33 LOG_ OTHR PR1EVL &HP = 538 psig, 3.0 MMCFPD rate, 480 BPD water. RIH to 5200'. made 2 min. bench stops. Start logging at 30 FPM down pass. 12:10 - 13:30 1.33 LOG_ OTHR PR1EVL Logging tool down to 7170' made 2 min. stop, made up pass at 30 FPM up to 7000'. Spinner stopped working. RIH to try and free spinner. Start up pass when logging tool at 7170' Start up pass. Printed: 1/31/2008 8:28:05 AM 0 0 Printed: 1/31/2008 8:28:05 AM Marathon Oil Company Page 6 of 6 Operations Summary Report Legal Well Name: KENAI BELUGA UNIT 14-6Y Common Well Name: KENAI BELUGA UNIT 14-6Y Spud Date: 11/29/2007 Event Name: ORIGINAL COMPLETION Start: 12/10/2007 End: Contractor Name: GLACIER DRILLING Rig Release: Group: Rig Name: GLACIER DRILLING Rig Number: 1 Date From -To Hours Code Sub Code Phase Description of Operations 1/26/2008 13:30 - 13:50 0.33 LOG_ OTHR PR1 EVL Spinner quit when logging up to 7070'. RIH with tools to 7170'. PU hole @ 30 FPM. 13:50 - 15:30 1.67 LOG_ OTHR PR1 EVL Logging tool up to 5200', spinner stopped working again. RIH to try and clear debis, no luck. POOH with logging tools. OOH with tools. 15:30 - 16:05 0.58 LOG_ OTHR PR1 EVL Spinner had small coal pieces and gravel lodged ins inner. Cleaned and went to well with Igging tools. Open well, RIH with tool string to 4800', spinner stopped. POOH. 16:05 - 16:40 0.58 LOG_ OTHR PRIEVL OOH, changed the spinner. Spinner had same problem with small pieces lodging in fins. 16:40 - 17:50 1.17 LOG_ OTHR PR1 EVL Go to well with logging tool. PT lubricator. Open well. RIH with TS to 5200' 17:50 - 18:50 1.00 LOG_ OTHR PRIEVL Made down pass at 60 FPM. Pressure at 7170'= 916 psia., Made up pass at 60 FPM to 5200', stop for 3 min. Made 90 FPM down pass. 18:50 - 19:10 0.33 LOG_ OTHR PRIEVL Up pass at 90 FPM to 5200'. Completed all three logging passes at 30, 60, & 90 FPM. Made stationary 3 minute stops at MPP while running in well. 19:10 - 21:10 2.00 LOG_ OTHR PRIEVL Log down to 7150' for 3 min. POOH logging @ 150 FPM. OOH 21:10 - 22:30 1.33 RURD ELEC PR1 EVL RD E -line unit, clean up around well and leave lease. Log indicates that most gas and water coming from module#4, gas from = 540 Psiq, 480 BPD fresh water and 3.0 MMCFPD Printed: 1/31/2008 8:28:05 AM Operations Summary Report by Job •' Well Name: KENAI BELUGA UNIT 14-6Y 'IL41 MarathonOil .� 2 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 19.96 26.37 6.40 11/29/2007 12/14/2007 Daily Operations Report Date: 1/7/2008 Job Category: COMPLETION 24 Hr Summary Run Expro Americas CBL/GR/CCI Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 11:00 12:00 1.00 LOG CSG AF Move in Wireline truck / crane onto location. Layout CBL/GR tool on ground and screw sections together 12:00 12:30 0.50 SAFETY MTG AF PJSM -topics discussed included cold weather/new snow, PPE - hordtoes/FR coveralls, had hat/ gloves / eye protection. Rigging up in cold weather, slips/ trips/ falls. Moving equipment, pinch points, sheaves, cable drums, slippery stairs, ladders, working under crane loads, pick points 12:30 12:45 0.25 RURD ELEC AF Rig up crane, sheaves, pack -off, tools 12:45 13:00 0.25 RUNPUL ELEC AF Start in hole 13:00 17:00 4.00 RUNPUL ELEC TA MDLG Tool failure / rope socket failure. Run second tool. Computer issues 17:00 19:00 2.00 RUNPUL ELEC AF Run CBL/GR from TD to 230' above liner top 19:00 20:00 1.00 RUNPUL ELEC AF Pull tool out of hole 20:00 20:30 0.50 PULD LOG AF Lay down tools, close tree valves, replace night cap, rig down crane and i I wireline unit.Leave location Report Date: 1/16/2008 Job Category: COMPLETION 24 Hr Summary Run Expro Americas Perforate Trouble Start Time End Time .Dur (hr) . Ops Code . Activ&yCode Stelae--' _ Code _ Comb 09:00 13:00 4.00 RURD STIM AF Move in BJ frac crew/ Expro Well Test / Expro Perforating. Warm frac fluid, mix 6 % KCL, move in chem adds, frac van, test communications. Total rig up time 6 days due to sub zero temps, blowing snow. 13:00 13:30 0.50 PERF CSG AF Perforate Module 1 @ 13:15 hours. Pressure 2180# Monitored at wellhead and acoutically Report Date: 1/17/2008 Job Category: COMPLETION 24 Hr Summary Fracture stimulate 15 modules . firvutife. Sta2Titne 'End Time Dur Or Ops£pdo: - -.-Activity Code_--=-:_ a$tatu& Code Com' - 08:00 08:30 0.50 SAFETY MTG AF slips, trips, fails, muster area, active producing gas pad. Red lights, blue lights, sirens, smoking area, cold slippery yellow containment, 3 second rule, buddy system. flow back 08:30 10:00 1.50 PREP LOC CS Move Expro trailer, 2 lite plants, re -hook control lines to modules, press test control lines 10:00 10:30 0.50 TEST EQIP AF Pressure test BJ Services to 9530# - final pressure9456# Passed, Gelled the KCL water and tested viscosity 10:30 11:00 0.50 PUMP FRAC AF Fracture stimulate module #1- 7128'-7138 feet. Pump 15.8 BPM @ 5300# breakdown. Stage 2-4-6-8-10 PPG slurry. Pumped total of 341 BBL slurry, 22,820# of 40/20 Ottawa sand and 4,887# flex sand 11:00 11:15 0.25 PERF CSG AF Perforate Module #2 from 6994 - 7004 feet. Visual and acoustical confirmation. Pressure 4330# 11:15 11:30 0.25 PUMP FRAC AF Breakdown zone #2 15.8 BPM @5130#. Staged 2-4-6-8 ppg slurry and then flushed. 2 very noticeable pressure spikes. Total slurry pumped 168 BBL with 11,204# of 20/40 Ottawa sand and 1602# of flex sand 11:30 11:45 0.25 PERF CSG AF Perforate module #3 from 6884 - 6894 feet. Visual and acoustical confirmation 11:45 12:15 0.50 PUMP FRAC AF Fracture stimulate Zone #3 at 12.7 BPM. Staged 2-4-7-10 ppg. Screened out just as displacement flush reached zone. Pumped 115 BBI slurry with 5,373 # of 20/40 Ottawa Sand and 796# of Flex Sand 12:15 12:30 0.25 PERF CSG AF Perforated Module #4 from 6794 - 6804 feet. Visual and Acoustic confirmation. Gun shot at 6230# 12:30 13:00 0.50 PUMP FRAC AF Fracture stimulation of zone #4. Staged 2-4-6-8-10 ppg slurry. Totatl 294 BBL slurry pumped and 42,804 # of 20/40 Ottawa sand with 2113# of flex sand 13:00 13:15 0.25 PERF CSG AF Perforate Module #5 from 6733-6743 feet . Visual and acoustic confirmation Pressure 7110# www.peloton.com Page 114 Report Printed: 8/2/2011 MarathonOil Operations Summary Report by Job Well Name: KENAI BELUGA UNIT 14-6Y Qtr/Qtr, Block, Sec, Town, Range Field Name License # State/Province Country KENAI I LASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB -Casing Flange Distance (m) KB -Ground Distance (m) Spud Date Rig Release Date 0.00 19.96 26.37 6.40 11/29/2007 12/14/2007 OpsTrouble - Start Time End Time our (hr) - Ops Code Activity Code Status Code Com 13:15 13:30 0.25 PUMP FRAC AF fracture stimulate Zone 5. Staged 2-4-6-8 ppg slurry. Pumped total of 121 BBL of slurry at 12.6 BPM. Pumped 5821# of 20/40 Ottawa flex sand and 832 # of flex sand 13:30 13:45 0.25 PERF CSG AF Perforate Module #6 from 6625 - 6635 feet. Visual and acoustic confirmation. Perforated at 8030# 13:45 14:00 0.25 PUMP FRAC AF fracture stimulate zone #6 Pumping rate of 15.6 BPM. Staged 2-4-6-8 ppg. Pumped 242 BBL of slurry with 4187# of 20/40 Ottawa sand and 4187# of flex sand. 14:00 14:15 0.25 PERF CSG AF Perforate Module #7 from 6580 - 6590 feet. Visual and acoustic confirmation. Pressure 9110# 14:15 15:00 0.75 PUMP FRAC AF fracture stimulate zone #7. Stage 2-4-6-8 ppg at 15.5 BPM. Pumped 285 BBL of slurry with 40,457# of 20/40 Ottawa Sand and 5776# of flex sand 15:00 15:15 0.25 PERF CSG AF Perforate Module #8 from 6422 - 6432 feet. Visual and acoustical confirmation. Pressure 2730# 15:15 15:30 0.25 PUMP FRAC AF fracture stimulate zone #8. Stage 2-4-6-8-10 ppg slurry. Pumped 242 BBL of slurry with 30,162# of 20/40 Ottawa sand and 4304# of flex sand 15:30 15:45 0.25 PERF CSG AF Perforate Module #9 from 6301 - 6311 feet. visual and acoustic confirmation. Pressure 3750# 15:45 16:00 0.25 PUMP FRAC AF fracture stimulate zone #9. Staged 2-4-6-8-10ppg slurry at 16 BPM. Pumped 251 BBL of slurry with 28,283 # of 20/40 Ottawa Sand and 4037# of flex sand.. 16:00 16:15 0.25 PERF CSG AF Perforate Module #10 from 6192 to 6202 feet. Visual and acoustic confirmation. Pressure 4720# 16:15 16:30 0.25 PUMP FRAC AF Fracture stimulate zone #10. Stage 2-4-6-8 ppg slurry. Screened out at 16:30 hours. Called BJ Coil crew to clean out. Pumped 114 BBL of slurry with 13,146 # of 20/40 Ottawa sand and 1879# of flex sand. Calculated 11,020 # of 20/40 sand in casing with 4,807 # of flex sand in casing to be cleaned out. 16:30 17:00 0.50 WAITON EQIP AF BJ COIL crew in route to location 17:00 17:30 0.50 SAFETY MTG AF slips trips falls, wind appears to be above 20 mph. Crane is de -rated in winds above 20 mph. Pressure, three second rule, buddy system, active gas producing pad. red light, blue light, sirens, muster area 17:30 22:00 4.50 WAITON WTHR TA WD Wait for wind to die down - safety concerns 22:00 23:59 1.98 RURD ICOIL TA WD rig up CTU. Pressure test - OK after filling tubing Startin hole Report Date: 1/18/2008 Job Category: COMPLETION 24 Hr Summary Fracture stimulate 5 modules / cleanout well bore Ops Trouble, StartTame End Time Our (hrj-_ Op$ Code Ad r%i ty Code, Status Code Qom 00:00 02:00 2.00 CIRC CFLD AF Run in hole with BJ Coil at 80 feet per minute. Estimed 1400 feet of sand fill on flapper at 6450 feet. Estimated top of fill at 5000 feet. Slow coil down at 4700 feet and wash down to flapper 02:00 03:10 1.17 CIRC CFLD AF set down on flapper. Apply weight to break flapper. Circulate under returns are clean and come back out of hole 03:10 03:40 0.50 RURD COIL AF RD CTU . Set back injector head onto stand, close valves, install nitecap shut down for evening. CTU crew released from location. 03:40 09:00 5.33 SECURE WELL AF secure well for evening, waiting for daylight to finish fracture stimulation of last 5 intervals. 09:00 09:30 0.50 SAFETY MTG AF slips, trips, falls, muster area, active producing gas pad. Red lights, blue lights, sirens, smoking area, cold slippery yellow containment, 3 second rule, buddy system. flow back 09:30 10:00 0.50 TEST EQIP AF Pressure test BJ Services to6800# - Passed, Gelled the KCL water and tested viscosity 10:00 10:15 0.25 PERF CSG Perforate Module # 11 from 6027 to 6037 feet. Visual and acoustical confirmation. Pressure 5340# 10:15 10:30 0.25 PUMP FRAC AF Fracture stimulate zone # 11. Pump 15.9 BPM . Stage 1-2-4-6 PPG slurry. Pumped total of 324 BBL slurry, 12,149 # of 40/20 Ottawa sand and 1728 # flex sand Note: whenever we have a clean out, the pumping into the next zone sends a possible slug of sand and induces a large pressure surge into the formation. We almost lost this interval. 10:45 0.25 PERF CSG AF Perforate Module # 12 from 5850 to 5860 feet. Visual and acoustical r!�- confirmation. Pressure 6300 # www.peloton.com Page 2/4 Report Printed: 8/2/2011 ,/i•N%al Marathon Oil Operations Summary Report by Job Well Name: KENAI BELUGA UNIT 14-6Y 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 19.96 26.37 6.40 11/29/2007 12/14/2007 - Cps Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 10:45 11:00 0.25 PUMP FRAC AF attempted to fracture stimulate zone # 12. Immediate pressure spikes during break down. Stage 1# slurry to scour formation. Pumped 151 BBL. with 710# of 20/40 Ottawa sand and 71 # of flex sand 11:00 11:15 0.25 PERF CSG AF Perforate module # 13 from 5808 to 5818 feet. Visual and acoustical confirmation Pressure 7430# 11:15 11:30 0.25 PUMP FRAC AF Fracture stimulate Zone # 13 Staged 2-4-6-8 ppg. Pumped 173 BBL of slurry, with 17,787# of 20/40 Ottawa sand and 2110# of flex sand 11:30 11:45 0.25 PERF CSG AF Perforated Module # 14 from 5442 to 5452 feet. Visual and Acoustic confirmation. Gun shot at 8550# 11:45 12:00 0.25 PUMP FRAC AF Fracture stimulation of zone # 14. Staged 2-4-6-8 ppg slurry. Totatl 176 BBL slurry pumped and 16522 # of 20/40 Ottawa sand with 2358# of flex sand 12:00 12:15 0.25 PERF CSG AF Perforate Module # 15 from 5382 to 5392 feet . Visual and acoustic confirmation Pressure 9560# 12:15 12:30 0.25 PUMP FRAC AF fracture stimulate Zone 15. Staged 2-4-6-8-10 ppg slurry. Pumped total of 212 BBL of slurry at 16 BPM. Pumped 26,345 # of 20/40 Ottawa flex sand and 3760 # of flex sand 12:30 14:00 1.50 RURD STIM AF Rig down frac crew in order to move CTU crew onto wellhead to perform casing cleanout and jet well in 14:00 14:30 0.50 SAFETY MTG AF PJSM -BJ CTU crew - 5 personnel, MOC- 2, ASRC - 2 ( 1 crane, 1 vac truck), Expro - 2.. Safety topics, slips trips falls, pressure, cold, buddy system, 3 second rule, pressure, overhead cranes, good housekeeping 14:30 15:30 1.00 RURD COIL AF Rig up and pressure test CTU 15:30 19:00 3.50 CIRC CFLD AF Run in hole at 80 feet per minute. Total depth reached 7476 feet. Solid bottom. Circulate 6% KCL water until returns to surface are clean. Kick in 350 cfm of N2. Circulate N2 until N2 reaches bottom, Jet for another 20 minutes and start out of hole at approx.25 feet per minute while jetting. 19:00 23:59 4.98 BLOWDN COIL AF Attempt to jet in well with N2 across all perforations. Stop coil at 4800 feet and continue jetting well. Hold until N2 returns back to surface and proceed out of hole with coil. Very little fluid returns, no sand. Straight nitrrogen back to surface, kill nitrogen at 3800 feet and continue back to surface. Well head pressure 200 - 230#. Well died when coil reached 1000 feet from surface. No returns when reached surface. Start back into hole to reject in across perforations. Report Date: 1/19/2008 Job Category: COMPLETION 24 Hr Summary Clean out well bore Start Tsne - End Time - Dur t - Cps£ode_ . Actndty Cbde . OPS SUtus TrouWe -., Code = 'Com ' 00:00 02:00 2.00 CLNOUT CSG AF Run in hole to attempt to re -jet well in. 02:00 02:45 0.75 CLNOUT CSG AF set down on bridge of sand at top of first set of perforations 5380 - 5390 feet. Circulated N2 and washed through it. Hit second bridge at top of next set of perforations from 5440 - 5450 feet. Set down on it and attempted to wash through it 5 times. Depth of bridge on CTU odometer 5438 feet 02:45 04:00 1.25 PULL EQIP AF POOH to pick up smaller jetting nozzle. Plan is to go in and clean out to bottom and attempt to re -jet well in. Low on N2 and cannot get re -supplied as all crews are out of hours. Attach smaller jetting nozzle. The wellhead pressure has built up to 100# during this procedure and begins to flow to flowback tank. Plan is to transfer to Expro flow back lines but lines are frozen. Continue to flow back through BJ flowlines. Wellhead pressure continues to increase to 150#. 04:00 06:00 2.00 WAITON WTHR AF apply air heater to Expro flow lines and Tree. Build tent over tree and heat. Well begins to flow after heating tree for approx. 15 minutes 06:00 06:30 0.50 RURD COIL AF Rig down BJ Coil. Set back injector head. Install nite cap. Flow well through Expro well test. Well flowing at well head pressure of 250# / good fluids - broken KCL Gel. 06:30 20:00 13.50 FLOW BACK AF Continue flow back. Well head pressure 250#. Rate 1.7MMCFPD 20:00 20:45 0.75 SAFETY MTG AF PJSM BJ Coil. Participants BJ Coil -5, ASRC - 3, Expro - 1, MOC - 1. Safety topics slips / trips / falls, pressure, buddy system, 3 second rule, active gas production pad, blue lites, red lites, sirens, muster areas, overhead loads 20:45 21:45 1.00 RURD 1COIL 1AF Rig up BJ CTU, pressure test www.peloton.com Page 314 Report Printed: 8/2/2011 1 I1N%al, MarathonOil Operations Summary Report by Job Well Name: KENAI BELUGA UNIT 14-6Y Qtr/Qtr, Block, Sec, Town, Range Field Name License # State/Province Country KENAI I LASKA USA Casing Flange Elevation (m)1 Ground Elevation (m) KB -Casing Flange Distance (m) KB -Ground Distance (m) Spud Date Rig Release Date 0.00 19.96 26.37 6.40 11/29/2007 12/14/2007 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 21:45 23:59 2.23 CLNOUT CSG AF Coil on bottom - their odometer reading 7485 feet. Returns are 20/40 Ottawa frac sand, flex sand and broken KCL gel. Getting a lot of metal being circulated up from the perforating guns / or flappers. Start out of hole. Report Date: 1/20/2008 Job Category: COMPLETION 24 Hr Summary Expro Well Test monitoring production / cleaning up well Ops Trouble Start Time End Time _Dur (hr) Ops Code Activity Code Status Code - Com 00:00 01:35 1.58 CLNOUT CSG AF Startout of hole. BJ odometer for deepest depth attained was 7485 feet. Cut Nitrogen @ 3000 after jetting across all perforations. Wellhead pressure back at surface 430# and climbing. Fluid returns clean with a small amount of flex sand. 01:35 02:30 0.92 RURD COIL AF Back to surface. Switch flow to Expro flow lines, close swab valve, rig down injector head, set injector head on stand, set nite cap. Turn well over to Expro Well Test. 02:30 02:45 0.25 FLOW TEST AF Initial well test results: Rate - 1.5 MMCFPD, 1200 BWPD - broken frac fluid, Wellhead pressure - 460 psi and climbing 02:45 23:59 21.23 FLOW BACK AF Continue flowback to clean up well Report Date: 1/26/2008 Job Category: COMPLETION 24 Hr Summary MIRU Expro E -line unit run PLT at 30, 60, 90 FPM. Good data, RD wire line unit. Ops ' Trouble Start Time End Time Dur (hr) Ops Code Activity Code ' '- Status = Code Can . • . - -- 07:00 07:30 0.50 SAFETY MTG AF MIRU wire line unt, held PJSM and discussed operations with flow back crew. Uptain permit. 07:30 09:30 2.00 RURD ELEC AF RU wire line unit, MU 1 11/16"" tool string with 2.34"" swedge. PT liubricator prior to opening up well. PT= 1500 psig, good test. 09:30 10:12 0.70 WORK ELEC AF OPen well, RIH tag fill at 7203' ELM. POOH with swedge. 10:12 10:50 0.63 LOG OTHR AF OOH, MU logging tool. PU go to well. Open well, RIH with logging tool. 10:50 12:10 1.33 LOG OTHR AF WHP = 538 psig, 3.0 MMCFPD rate, 480 BPD water. RIH to 5200'. made 2 min. bench stops. Start logging at 30 FPM down pass. 12:10 13:30 1.33 LOG OTHR AF Logging tool down to 7170' made 2 min. stop, made up pass at 30 FPM up to 7000'. Spinner stopped working. RIH to try and free spinner. Start up pass when logging tool at 7170' Start up pass. 13:30 13:50 0.33 LOG OTHR AF Spinner quit when logging up to 7070'. RIH with tools to 7170'. PU hole @ 30 FPM. 13:50 15:30 1.67 LOG OTHR AF Logging tool up to 5200', spinner stopped working again. RIH to try and clear debis, no luck. POOH with logging tools. OOH with tools. 15:30 16:05 0.58 LOG OTHR AF Spinner had small coal pieces and gravel lodged in spinner. Cleaned and went to well with Igging tools. Open well, RIH with tool string to 4800', spinner stopped. POOH. 16:05 16:40 0.58 LOG OTHR AF OOH, changed the spinner. Spinner had same problem with small pieces lodging in fins. 16:40 17:50 1.17 LOG OTHR AF Go to well with logging tool. PT lubricator. Open well. RIH with TS to 5200' 17:50 18:50 1.00 LOG OTHR AF Made down pass at 60 FPM. Pressure at 7170'= 916 psia. Made up pass at 60 FPM to 5200', stop for 3 min. Made 90 FPM down pass. 18:50 19:10 0.33 LOG OTHR AF Up pass at 90 FPM to 5200'. Completed all three logging passes at 30, 60, & 90 FPM. Made stationary 3 minute stops at MPP while running in well. 19:10 21:10 2.00 LOG OTHR AF Log down to 7150' for 3 min. POOH logging @ 150 FPM. OOH 21:10 22:30 1.33 RURD ELEC AF RD E -line unit, clean up around well and leave lease. Log indicates that most gas and water coming from module#4, gas from 5,6,7. WHP= 540 psig, 480 BPD fresh water and 3.0 MMCFPD www.peloton.com Page 4/4 Report Printed: 8/2/2011 1 Ala-ika Oil and C23 CCMiervation C0mfn'5ii0n- 333 VVe-st 7`� venue, SURL' 100 n.-ho,AK 99501-3539 Whose: (907) 279-1433 Fax: (997) 276-7342 Fax Transmission The information contained in this fax is conitdenda/ and/or privileged. This fax is intended to be reviewed initially by only the individual named below. if the reader of this transmittal page is not the intended recipient or a representative of the intended recipient, you are hereby notified that any review, disseminaddr; or copying of this fax or the information contained herein is prohibited. ff you have received this fax i,7 error, please immediately ryodhj the sander by telephone and return this fax to the sender at the above address. shank you. From:0 Phone #- Subject: message: Date: JCKVI Pages (inciuding cover sheet): 3 -- "� �Wo-�4 f' you -do not r3C2iY� 311 [`'z ;3933 or ^a`!3 3rt/ p�obigrrs with, `tis fax. pfaase ca -'l for asaistanc a {SOT) TS3- 223_ • 0 JOB STATUS REPORT TIME 01/10/2008 09:11 NAME AOGCC FAX# 9072767542 TEL# SER.# BRO2J2502370 DATE,TIME 01/10 09:09 FAX N0./NAME 19072831350 DURATION 00:00:48 PAGE(S) 03 RESULT OK MODE STANDARD ECM 0 ALASKA OIL AND GAS CONSERVATION COMUSSION Craig Rang Senior Completions Engineer Marathon Oil Company PO Box 1949 Kenai, Alaska 99611-1949 0 SARAH PALIN, GOVERNOR 333 W 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KBU 14-6Y Sundry Number: 307-382 Dear Mr. Rang: 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. DATED this f day of January, 2008 Encl. M Marathon MARATHON Oil Company December 3, 2007 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Application for Sundry Approvals Field: Kenai Gas Field Well: KBU 14-6Y Dear Mr. Maunder: Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Enclosed please find the 10-403 Application for Sundry Approvals for KBU 14-6Y well. KBU 14-6Y was drilled and fifteen Excape Module were installed into the Lower Beluga formation. Permission is requested to fracture stimulate all fifteen Excape Modules on January 8- 9th, 2008. The completion procedure is attached. If you have any questions or require additional information, please call me at (907) 283- 1372. Sincerely, Craig Rang Senior Completions Engineer Enclosures: 10-403 Application for Sundry Approvals cc: Houston Well File Well Schematic Kenai Well File KJS CLR AD 74 1(7,) RECEIVE STATE OF ALASKA �� 7�0 ALAS OIL AND GAS CONSERVATION COMMISSION ,'Q APPLICATION FOR SUNDRY APPRO N(& 20 AAC 25.280 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown ❑ Perforate ✓❑ Waiver ❑ Other ❑ Alter casing ❑ Repair well ❑ Plug Perforations ❑ Stimulate ✓❑ Time Extension ❑ Change approved program ❑ Pull Tubing ❑ Perforate New Pool ❑ Re-enter Suspended Well ❑ 2. Operator Name: Marathon Oil Company 4. Current Well Class: 5. Permit to Drill Number: Development ❑ Exploratory ❑ Stratigraphic ❑ Service ❑ 2071490 ' 3. Address: 6. API Number: PO Box 1949, Kenai Alaska, 99611-1949 50-13320572-00-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes El No [:1KBU 14-6Y 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): XEID A-028142 87' (21' AGL) Kenai Gas Field - Beluga / Upper Tyonek 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Junk (measured): 7600' 7573' 7526' 7499' Casing Length Size MD TVD Burst Collapse Structural Conductor 99, 20" 120' 120' 3060 1500 Surface 1479' 13 3/8" 1500' 1500' 3450 1950 Surface Intermediate 5316' 9 5/8" 5337' 5312' 5750 3090 Production 7549' 3.5 7570' 7543' 10160 10550 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 5382'-7137' 5355'-7110' 3.5" L-80 Packers and SSSV Type: Packers and SSSV MD (ft): 13. Attachments: Description Summary of Proposal ❑✓ 14. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Development 0 Service ❑ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: January 8 -9th, 2008 Oil ❑ Gas Q Plugged ❑ Abandoned ❑ WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ 17. Verbal Approval: Date: Commission Representative: 18. 1 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 Phone 907-283-1372 Date December 18,2007 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOPTestD Mechanical Integrity Test ❑ Location Clearance ❑ Other: '? 4 ��'f- (,J'"; ?LOO$ Subsequent Form Required: a 4C I _ C. c%u." IL Sf(A (�lyt y Cr+U 'rF � i�rcj ►v 1� Cf I APPROVED BY Approved by: O ISSIONER THE COMMISSION Date: Form 10-403 Revised 06/2006 v� ORIGINAL Submiyin Duplicate KBU 14-6Y Fracture Stimulation Desription Summary of Proposal Kenai Beluga Unit 14-6Y was drilled and cased as a 3.5" Monobore Excape completion containing fifteen 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 15. 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 will 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 144 hours. However, due to the uncertainty of exactly how long KBU 14-6Y will be required to vent to atmosphere, this request is for a maximum vent period of 144 hours with a maximum vent volume during that period of 12 MMCF of methane 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. � V KBU 14-6Y Excape 15 module well AS RUN.xis Final Wellbore Diagram Final Wellbore Diagram- After Lowering Pipe (prior to cemer KS to GL 21.8 feet J THE EXPRO GROUP �M Casing: 3.5", 9.31t, L -80 EUE Module 15: 5382.45 - 5392.45 ( 10. feet of parts ) ( 13 Pins in Firing Head) Module 14: 5442.45 - 5452.45 ( 10. feet of parts ) ( 12 Pins In Firing Head) Module 13: 5808.45 - 5818.45 ( 10. feet of parts ) 1 11 Pins In Firing Head) Module 12: 6850.45 - 5860.45 ( 10. feet of parts ) ( 10 Pins in Firing Head) Module 11: 6027.45 - 6037.45 ( 10. feet of parts ) ( 9 Pins in Firing Head Module 10: 6192.45 - 6202.45 ( 10. feet of parts ) (8 Pins in Firing Head) Module 9: 6301.45 - 6311.45 ( 10. feet of parts 1 7 Pins In Firing Head) Module 8: 6421.55 - 6431.55 ( 10. feat of perfs ) 1 6 Pins In Firing Head) Module 7: 6580.45 - 6590.45 ( 10. feet of parts ) 1 13 Pins in Firing Head) Module 6: 6625.45 - 6635.45 ( 10. feet of parts ) 1 12 Pins in Firing Headl Module 5: 6733.45 - 6743.45 ( 10. feet of parts ) (11 Pins in Firing Head) Module 4: 6794.45 - 6804.45 ( 10. feet of Paris ) ( 10 Pins in Firing Head) Module 3: 6883.45 - 6893.45 ( 10. feet of parts ) (9 Pins in Firing Head) Module 2: 6994.45 - 7004.45 ( 10. feet of parts ) ( 8 Pins In Firing Heed) Module 1: 7127.49 - 7137.49 ( 10. feet of parts ) ( 6 Pins In Flying Head) Weatherford Float Collar 7533.39 ft shoe joint Weatherford Float Shoe 7570.74 ft Prepared by: Note: Pers are Open Hole Log Depths R/or to Cementing Note: Float Collar and TO depths are Running Tally Depths PLUS S 12/18/2007 1:08 PM 0 Regg, James B (DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, January 02, 2008 12:47 PM To: Skiba, Kevin J. Cc: Regg, James B (DOA) Subject: RE: KBU 14-6Y Status 0 Kevin, I won't be back in the office until Monday. I am still out of state. I don't remember if I processed the sundry prior to leaving. You might check with Jim Regg to see if that sundry has been finalized to return to you. Jim's phone number is 793-1236. Tom Maunder, PE AOGCC -----Original Message ----- From: Skiba, Kevin J. [mailto:kskiba@marathonoil.com] Sent: Wed 1/2/2008 11:14 AM To: Maunder, Thomas E (DOA) Cc: Rang, Craig L. Subject: KBU 14-6Y Status Tom, Hi, I know that you are just getting back from the holidays but wanted to follow up on KBU 14-6Y. The completion work for KBU 14-6Y has been pushed back a week. It is scheduled to begin on 1/16/08. The 10-403 Sundry, covering this work, was submitted on 12/18/07. Please let me know if you have any questions or need any additional information. I just want to make sure that I have all of the documentation in place before we get to close to the start date. Thanks again, Kevin Skiba Production Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 1 6 SARAH PAI GOVERNOR RQ O �"-"S 333 W 7th AVENUE, SUITE 100 •�.u� SSIO ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279 CON SE 6 -1433 Willard Tank FAX (907) 276-7542 Advanced Senior Drilling Engineer Marathon Oil Company 3201 C. Street Suite 800 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/ Upper Tyonek, KBU 14-6Y Marathon Oil Company Permit No: 207-149 Surface Location: 482' FSL, 1,121' FWL, SEC. 6, T4N, R11W, S. M. Bottomhole Location: 195' FSL, 1,137' FWL, SEC. 6, T4N R 11 W 0 - Dear 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 approvals have been issued. In addition, the Commission reseauthorize conducting drilling operations until all other required permits and withdraw the permit in the event it was erroneously issued. rves the right to 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 inspect at(9 ) 59-3607 (pager). K. DATED this !D day of November, 2007 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. 0 a Marathon Oil Company October 23, 2007 • RECENED OCT 2 4 2007 Alaska Oil & Gas Cons. Co{lillssion John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Kenai Gas Field Well: KBU 14-6Y Dear Mr. Norman Anchorage Worldwide Drilling North America P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713.499-6737 Enclosed please find the PERMIT TO DRILL application, along with the associated attachments. 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. Please note that the surface coordinates for this well and the directional plan are now utilizing North American Datum 1983 (NAD 83) as required in the latest BLM 43 CFR Part 3160, Onshore Order No. 1, dated March 7, 2007. Getting well and surface equipment coordinates on this GPS based standard (NAD 83) has been an effort that Marathon has been working on and will continue to progress. On the PERMIT TO DRILL we have included surface coordinates in NAD 27 in order to allow the commission to put the well in their database. All other attachments reference NAD 83. If you require further information, I can be reached at 713-296-3273 or by e-mail at wjtank@marathonoil.com. Sincerely, .fid&j �J� Willard J. Tank Advanced Senior Drilling Engineer Enclosures I vq EEIVE� 6t 1 STATE OF ALASKA ��� ALASKA OIL AND GAS CONSERVATION COMIASION 4 P Aw(5- QCT 2 4 2007 PERMIT TO DRILL ?n AAr 9- nor, 1a. Type of Work: Drill 0 Redrill ❑ Re-entry ❑ 1b. Current Well Class: Exploratory ❑ Development Oil ❑ Stratigraphic Test ❑ Service ❑ Development Gas ❑✓ Multiple Zone Single Zone ❑ -4 yul, . 1c. Specify if well is proposed foAnchoraaa Coalbed Methane ❑ Gas Hy2d ates ❑ Shale Gas ❑ 2. Operator Name: Marathon Oil Company 5. Bond: Blanket 0 Single Well ❑ Bond No. 5194234 11. Well Name and Number: KBU 14-6Y 3. Address: 3201 C. Street, Suite 800, Anchorage, AK 99503 6. Proposed Depth: MD: 7,782 TVD: 7,757 12. Field/Pool(s): Kenai Gas Field Beluga / Upper Tyonek Pool 4a. Location of Well (Governmental Section): Surface: 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Top of Productive Horizon: 195' FSL, 1,137' FWL, Sec. 6, T4N, RI 1W, S.M. Total Depth: 195' FSL, 1,137' FWL, Sec. 6, T4N, R1 IW, S.M. 7. Property Designation: A-028142 8. Land Use Permit: 13. Approximate Spud Date: November 23, 2007 9. Acres in Property: 2,560 14. Distance to Nearest Property: 1,086 ft 4b. Location of Well (State Base Plane Coordinates): NAD 27 Surface: x - 272,047.598 y - 2,362,530.423 Zone- 4 10. KB Elevation (Height above GL): (21' AGL) 87 feet 15. Distance to Nearest Well Within Pool: 1,120 ft KBU 24-6RD 16. Deviated wells: Kickoff depth: 1,100 feet Maximum Hole Angle: 8.4 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 4,276 Surface: 2,450 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 133 K-55 PE 99' 0' 0' 120' 120' 16" 13 3/8" 68 L-80 BTC 1,479' 0' 0' 1,500' 1,500' 463 sacks 12 1/4" 95/8" 40 L-80 BTC 5,316' 0' 0' 5,337' 5,312' 355 sacks 8 1/2" 3 1/2" 9.3 L-80 EUE 7,761' 0' 10' 7,782' 7,757' 1 1,124 sacks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Feer BOP Sketch Q Drilling Program ❑✓ Time v. Depth Plot ❑ Property Plat [] Diverter Sketch Q Seabed Report ❑ Drilling Fluid Program Q Shallow Hazard Analysis ❑ 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: 22. 1 hereby certify that the foregoing is true and correct. Printed Name Willard J. Tank Signature Date Contact Title Advanced Senior Drilling Engineer Phone 713-296-3273 Date October 23, 2007 Commission Use Only Permit to Drill Number: API Number: 50-%,�• pWIS',7� 67Qg90 Permit Ap al I Date: •.OT 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 met ne, gas hydrates, or gas contained in shales: Other: Samples req'd: YesNo Mud log req'd: Yes[ No❑ �OOO S, �O (� HZS measures: Ye: No V Dir Tonal svy req'd: Yes No Y ' DATE: APP VED BY THE COMMISSION (J COMMISSIONER Form 10-401 Revised 12/2005 ORIGINAL (,/ �_" Submit in Duplicate KBU 14-6Y Drilling Program Originator: Will Tank Reviewed by: Pete Berga Brian Roy MARATHON MARATHON OIL COMPANY DRILLING PROGRAM Kenai Gas Field KBU 14-6Y October 22, 2007 Date Date Date Marathon Oil Company Alaska 10/22/2007 CONFIDENTIAL MATERIAL Page 1 of 18 KBU 14-6Y Drilling Program TABLE OF CONTENTS • Marathon Oil Company Alaska 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. Internal 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 10/22/2007 CONFIDENTIAL MATERIAL Page 2 of 18 • KBU 14-6Y Marathon Oil Company Drilling Program Alaska Attachments Group Attachment Attached Commercial Information AFE Days/Cost vs. Depth Curves X Project Objectives and Scorecard RSO Coding Information X Requisitions Vendor List Bonus Program Drilling Contract Regulatory/ HES Information Emergency Evacuation Plan X H2S Contingency Plan n/a Regulatory Permits X Regulatory Rules and Regulations Risk Analysis Miscellaneous Programs(Vendors) Bit Proposal X Cement Proposal X Directional Plan X Fluids Program X Wellhead Equipment — Description/Drawings Drill String and BHA Summary Rig Mobil ization/Moorin Procedure n/a Geological Information Location Ma w/ offsets X Offset Data Proposed Formation Pore Pressure, Mud Wt & Fracture Gradient X Temperature Curves Geologic Structure Maps Geologic Cross Section Bath met Ma n/a Analysis Riser Analysis n/a Station Keeping Analysis — Mooring/DP n/a Stress Check Casing Design File X Maximum Allowable Overpull Miscellaneous Information Wellbore Diagram n/a Rig Elevations X Well Location Diagram X BOP Schematic X BOP Well Control Bridging Document Detailed Casing Specifications X Detailed Drill Pipe Specifications 10/22/2007 CONFIDENTIAL MATERIAL Page 3 of 18 KBU 14-6Y Drilling Program 1. Emergency Response Information 1.1 Directions to Location Marathon Oil Company Alaska Method Directions Air Latitude - 60°27'36.746"N Longitude - 151 °15'54.417'W NAD 83 907-283-6465 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 Inlet Drilling Tool Pusher Bridge Access Road 3.2 miles. Turn West on Kalifornsky Beach Road. Go West and then South, go approximately 5 miles, just Ground Marathon Supervisor 907-283-1312 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 Hospital Southeast 1 mile to pad 14-6. 1.2 Riq Contact Numbers Contact Office Cell Glacier Drilling Rig 1 907-283-6465 Kenai / Soldotna, Alaska Inlet Drilling Tool Pusher 907-283-1314 907-394-1321 Marathon Supervisor 907-283-1312 907-394-1317 1.3 Marathon Emergency Response Contacts Individual Postion Main Phone Altemative Kenai Gas Field Emergency Number 907-283-6465 Kenai / Soldotna, Alaska CERT 24 hrs Notification 1-800-MOC-CERT Ambulance CERT Crisis Center Houston 713-296-4230 713-296-4237 1.4 Outside Emernencv Response Best Practices: 1 Policy: Post emergency notification information on rig floor, company man's and tool pushers' office Comments: 10/22/2007 CONFIDENTIAL MATERIAL Page 4 of 18 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 907-2624453 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: 10/22/2007 CONFIDENTIAL MATERIAL Page 4 of 18 KBU 14-6Y Drilling Program 1.5 Marathon Contact List Marathon Oil Company Alaska 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 2. Regulatory Agency Contacts 2.1.1. Internal Regulatory Contact Contact I Title I Office Phone Cell Phone Home Phone Facsimile Chick Underwood I Regulatory Compliance 1 713-296-3254 979-830-7927 979-836-9390 713-499-6748 2.1.2. External Reaulatory Contact Contact Title Office Phone Facsimile 24 hr Emergency Pager AOGCC 1 907-793-1236 AOGCC North Slope Pager - 907-659-3607 BLM 1 907-267-1442 3. Regulatory Compliance Regulation Requirement 20 AAC 25.035 a 10 A BOP testing interval requirement is now 14 days. 20 AAC 25.035 a 10 F Requirement for a 24 hour notice to AOGCC prior to BOP test. Comments 10/22/2007 CONFIDENTIAL MATERIAL Page 5 of 18 KBU 14-6Y Marathon Oil Company Drilling Program Alaska 4. Drilling Program Summary 4.1 General Well Data Well Name KBU 14-6Y Lease / License Phone Surface Location 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S. M. WBS Code DD.07.16228.CAP.DRL Slot/Pad KGF Pad 14-6 Field Kenai Gas Field Spud Date 11/23/07 (est.) KB (above MSL) 88' County/Province Kenai Peninsula API No. Sandstone GL (above MSL) 67' State / Country Alaska Permit No. 5.8-8.6 Perm. Datum KB Total MD 7,782' Well Class Development Water Depth N/A Total TVD 7,757' Rig Contractor Glacier Drilling Water Protection Depth 5.8-10.6 Sandstone Rig Name Glacier Rig 1 Best Practices: Comments: 4.2 Workina Interest Owners Information Company Working Interest I Address Phone Facsimile Marathon 100% P.O. Box 196168 907-561-5311 907-565-3076 UTM East (x) 1,412,067.868' Anchorage, AK 99519-6168 Gas/Water Beluga 4.3 Geologic Program Summary 10/22/2007 CONFIDENTIAL MATERIAL Page 6 of 18 Surface Location Coordinates — NAD 83 From Lease/Block Lines 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. Latitude 60° 27'36.746" N Longitude 151 ° 15' 54.417" W UTM North (Y) 2,362,291.674' UTM East (x) 1,412,067.868' Tolerance Gas/Water 10/22/2007 CONFIDENTIAL MATERIAL Page 6 of 18 Formation MD - RKB (ft) TVD — RKB (ft) Pore Pore Pressure Pressure (psi) (ppg) Lithology Possible Fluid Content Sterling A-8 (Not a Prod Target) 3,549 3,537 0.8-6.5 Sandstone Gas/Water Beluga (Not a Prod Target) 4,711 4,687 1.5-7.3 Sandstone Gas Middle Beluga (Primary Target) 5,362 5,337 5.8-8.6 Sandstone Gas Lower Beluga (Primary Target) 6,077 6,052 5.8-10.6 Sandstone Gas Tyonek (Primary Target) 7,237 7,212 5.8-10.6 Sandstone Gas 10/22/2007 CONFIDENTIAL MATERIAL Page 6 of 18 0 KBU 14-6Y Drilling Program • Marathon Oil Company Alaska Target Depth (KB) Location Horizontal Displacement (ft) Tolerance (ft) MD (ft) TVD (ft) +N/ -S m +E1_W (X) Middle Beluga 5,362 5,337 195' FSL, 1,137' FWL, Sec. 6, T4N, R11W, S.M. -287 16 Circle 200' radius Lower Beluga 6,077 6,052 195' FSL, 1,137' FWL, Sec. 6, T4N, R11W, S.M. -287 16 Circle 200' radius Tyonek 7,237 7,212 195' FSL, 1,137' FWL, Sec. 6, T4N, R11W, S.M. -287 16 Circle 200' radius TD 7,782 7,757 195' FSL, 1,137' FWL, Sec. 6, T4N, R11W, S.M. -287 16 Circle 200' radius 4.4 Summary of Potential Drilling Hazards 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 +/- 3,549' MD (3,537' 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 Summary Interval Depth KB Electric Logs Mud Logs Hazard Event None None Precautions Intermediate 1,500'— 5,337' MD (TVD)Discussion None Basic with GCA, shale density, temperature in and out, sample collection (10' samples). 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 +/- 3,549' MD (3,537' 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 Summary Interval LWD Electric Logs Mud Logs Surface 0'— 1,500' MD None None None Intermediate 1,500'— 5,337' MD None None Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Production 5,337'— 7,782' 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: 10/22/2007 CONFIDENTIAL MATERIAL Page 7 of 18 0 KBU 14-6Y Drilling Program 4.6 Drillino Prooram Summary Drive Pipe: N/A Marathon Oil Company Alaska Conductor: 20" set to approximately 120', prior to drilling rig move. MIRU drilling rig. NU diverter. 1. RU crane and hammer. Drive 20" conductor to +/-120 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 +/- 1,500' set 13-3/8" casing. 1. Drill a 16" hole to 1,500' 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 +/- 5,337' 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 5,337' MD (5,312' 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. 10/22/2007 CONFIDENTIAL MATERIAL Page 8 of 18 KBU 14-6Y Marathon Oil Company Drilling Program Alaska Production: Drill 8 1/2" hole to +/- 7,782' 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 7,782' MD (7,757' TVD) as per the directional program, short tripping as required. 4. At TD circulate hole clean. Make wiper trip. TOOK 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: Best Practices: 1 Comments: Completion will be done without a rig. This will include activating the EXCAPE perforating modules via hydraulic pressure on the control lines and fracture stimulation of targeted zones. Wellbore clean out will likely include slickline and possibly nitrogen jetting. 10/22/2007 CONFIDENTIAL MATERIAL Page 9 of 18 KBU 14-6Y Drilling Program 4.7 Casina Prouram Summary Marathon Oil Company Alaska Casing Size (in) MD (ft) Weight ID Drift (lbs/ft) (in) (in) Grade Connection Hole Size (in) API Ratings Top Bottom O. D. Type (in) Makeup Torque (ft -lbs) m' g 0 .= U a o ,;, 9 133/8 0 1,500 68 12.415 12.259 K-55 BTC 14.375 N/A * 16 3,450 1,950 1,300 95/8 0 5,337 40 8.835 8.679 L-80 BTC 10.625 N/A * 121/4 5,750 3,090 979 31/2 0 7,782 9.3 2.992 2.867 L-80 8rd 4.5 3,200 81/2 10,160 10,530 207 Best Practices: 1 Have float 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: Overpull for the 3 1/2" string must be limited to 98,000 lbs. 4.8 Casino Desion 4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP) Setting Casing Shoe Depth Safety Factors Size TVD MAWP" Setting Mud/Gas (in) Maximum (psi) (psi) Percentage Casing 1,500 2,329 Depth Mud Wt Frac.C Form Surface 3,997 W a o Size Weight 6,668 TVD When Set Grad Press Pressure U) Q (in) (Ib/ft) Grade (ft) (Ib/gal) (Ib/gal (lb/gal) (psi) m' v 133/8 68 K-55 1,500 9.4 15.0 8.4 0 2.18 2.66 4.45 95/8 40 L-80 5,312 9.5 13.0 1.5 2,450 1.89 1.18 3.25 31/2 9.3 L-80 7,757 10.6 15.0 10.6 2,450 1.17 2.47 1.30 4.9 Calculation of Maximum Anticipated Pressures (MAWP and MASP) * 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 psilft 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 wellbore being completely evacuated with only a gas gradient remaining. 10/22/2007 CONFIDENTIAL MATERIAL Page 10 of 18 Setting Casing Depth Size TVD MAWP" MASP ** Mud/Gas (in) (ft) (psi) (psi) Percentage 133/8 1,500 2,329 0 30/70 95/8 5,312 3,997 2,450 30/70 31/2 1 7,757 6,668 2,450 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 psilft 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 wellbore being completely evacuated with only a gas gradient remaining. 10/22/2007 CONFIDENTIAL MATERIAL Page 10 of 18 KBU 14-6Y • • Drilling Program Surface casing: 13 3/8" (1.500' MD. 1.500' TVD) MASPfrac = ((Fracture gradient at shoe) x.052 x TVDshce) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg x .052 x 1,500') - (0.1 psi/ft x 1,500') MASPfrac = 1,170 psi - 150 psi MASPfrac= 1,020 psi. MASPbhP = BHPopen W, td — Hydrostatic pressure of mud portion — Hydrostatic pressure of gas portion MASPbhP = (1.50 ppg x.052 x 5,312') — (0.3 x 9.5 ppg x.052 x 5,312') — (0.7 x 0.1 psi/ft x 5,312') MASPbhP = 414 psi — 787 psi — 372 psi MASPbhP = 0 psi MASP = MASPbhP = 0 psi MAWP = (0.7 x Casing Burst) — (Mud Wt. — Backup Fluid Wt.) x.052 x TVD MAWP = (0.7 x 3,450) — (9.4 — 8.3) x.052 x 1,500' MAWP = 2,415 psi — 86 psi = 2,329 psi Intermediate casing: 95/8" (5.337' MD. 5.312' TVD) MASPfrac = ((Fracture gradient at shoe) x .052 x TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (13.0 ppg x .052 x 5,312') - (0.1 psi/ft x 5,312') MASPfrac = 3,591 psi - 531 psi MASPfrac = 3,060 psi. MASPbhP = BHPcPe„ hc,a td - Hydrostatic pressure of mud portion — Hydrostatic pressure of gas portion MASPbhP = (10.6 ppg x .052 x 7,757') — (0.3 x 10.6 ppg x .052 x 7,757') — (0.7 x 0.1 psi/ft x 7,757') MASPbhP = 4,276 psi — 1,283 psi — 543 psi MASPbhP = 2,450 psi MASP = MASPbhP = 2,450 psi MAWP = (0.7 x Casing Burst) — (Mud Wt. — Backup Fluid Wt.) x.052 x TVD MAWP = (0.7 x 5,750) — (9.5 — 9.4) x.052 x 5,312' MAWP = 4,025 psi — 28 psi = 3,997 psi Production casing: 3 1/2" (7.782' MD. 7.757' TVD) MASPfrac = ((Fracture gradient at shoe) x .052 x TVDshoe) - Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg x .052 x 7,757') - (0.1 psi/ft x 7,757') MASPfrac = 6,050 psi - 776 psi MASPfrac = 5,274 psi. MASPbhP = BHPcpen hcie td - Hydrostatic pressure of mud portion — Hydrostatic pressure of gas portion MASPbhP = (10.6 ppg x.052 x 7,757') — (0.3 x 10.6 ppg x.052 x 7,757') — (0.7 x 0.1 psi/ft x 7,757') MASPbhP = 4,276 psi — 1,283 psi — 543 psi MASPbhP = 2,450 psi MASP = MASPbhP = 2,450 psi MAWP = (0.7 x Casing Burst) — (Mud Wt. — Backup Fluid Wt.) x.052 x TVD MAWP = (0.7 x 10,160) — (10.6 — 9.5) x .052 x 7,757' MAWP = 7,112 psi — 444 psi = 6,668 psi Marathon Oil Company Alaska 10/22/2007 CONFIDENTIAL MATERIAL Page 11 of 18 KBU 14-6Y Drilling Program Best Practices: 1 Comments: 4.10 Casing 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. Testino and General Procedures BOP PROGRAM Casing Test Test Casing Pressure Test Fluid 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 Surface 133/8 2,329 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 3,997 2,450 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 6,668 2,450 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 Testina Function Regularly. 10/22/2007 CONFIDENTIAL MATERIAL Page 12 of 18 KBU 14-6Y Drilling Program 4.11.2. Pressure Testing 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 Summary 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, PR1 13 5/8" x 9 5/8" Fluted Dogleg ("/100') Inclination (deg) Mandrel Tubing Head 13-5/8" 3M Studded Bottom X 13-5/8" 5M Fig Top, W/ 2, 2-1/16" 5M Studded Outlets, 13 5/8" x 3 1/2" Manual +E/ -W (ft) U,AA,PSL1,PR1 Slip Adapter Flange 13-5/8" 5M X 3-1/16" 10M W/ Seal Pocket and 3" H BPV Threads 0 Best Practices: 1 Comments: Control lines and electric cable for the EXCAPE system will be routed through the adapter flange ports. 4.13 Directional Program Summary Sec. No. Description MD (ft) TVD (ft) Build Rate (°/100') Tum Rate (°/100') Dogleg ("/100') Inclination (deg) Azimuth (deg) Coordinates VS (ft) +N/ -S (ft) +E/ -W (ft) I Tie On 0 0 0 0 0 0 280.000 0 0 0 2 KOP 1100.00 1100.00 0 0 0 0 280.000 0 0 0 3 Build up Section 1.00 0 1.00 280.000 4 End of Build 1,850.00 1,847.86 1.00 0 1.00 7.50 280.000 8.51 -48.27 -11.17 5 Build and Turn Section 0.90 -3.16 1.00 6 End of Build and Turn 3,270.09 3,261.50 0.90 -3.16 1.00 8.40 153.435 -68.59 -93.38 63.31 7 Hold Section 0 0 0 8.40 153.435 8 End of Hold 4,521.82 4,499.79 0 0 0 8.40 1 153.435 -232.18 -11.58 231.18 9 Drop Section -1.00 0 1.00 153.435 10 End of Drop 5,362.03 5,337.00 -1.00 0 1.00 0 153.435 -287.19 15.92 287.63 11 TD 7,782.03 7,757.00 0 0 0 0 153.435 -287.19 15.92 287.63 10/22/2007 CONFIDENTIAL MATERIAL Page 13 of 18 KBU 14-6Y • Marathon Oil Company Drilling Program Alaska 0- Depth (MD) KBU 11-7 49.97 Surface KU 14X-6 68.88 690 KDU 1 102.96 3,058 KU 14-6RD 106.72 4,115 - [error ellipses intersect KBU 23-7 147.62 � _ 133/8" 301 Serious interference potential exists for KU 14-6RD. This well has inclination only surveys and no way to re -survey. See attached directional plan and anticollision analysis for more details. Best Practices: 1000 Comments: 4.14 Directional Surveying Summary � Other Survey Interval MD (ft) MWD Survey Magnetic Multishot Gyro Multishot Remarks KBU 146Y Middle Beluga KBU 14-6Y Lower Beluga KBU 146Y Tyone Tool .95/8'• Surface 0 — 1,500' X Intermediate 1,500' — 5,337' X Production 5,337'— 7,782' X 2000 Best Practices: 1 10/22/2007 CONFIDENTIAL MATERIAL Page 14 of 18 c _ 0 - 0 3000 o KBU 146Y TD t C) M v 4000 L KBU 146Y Tyonek U Z 5000 ~ 6000 U) 500 KBU 14-6Y Middle Beluga 7000 KBU 146Y Lower Beluga 8000 9000 -2000 -1000 -0 1000 0 500 2000 3000 4000 Vertical Section at 176.83° (2300 ft/in) West( -)/East(+) (300 ft/in) Comments: Vertical section calculated from a reference azimuth of 176.831 taken from surface location to bottom hole location Potential Well Interference: Well Distance (ft) Depth (MD) KBU 11-7 49.97 Surface KU 14X-6 68.88 690 KDU 1 102.96 3,058 KU 14-6RD 106.72 4,115 - [error ellipses intersect KBU 23-7 147.62 � _ 133/8" 301 Serious interference potential exists for KU 14-6RD. This well has inclination only surveys and no way to re -survey. See attached directional plan and anticollision analysis for more details. Best Practices: 1 Comments: 4.14 Directional Surveying Summary � Other Survey Interval MD (ft) MWD Survey Magnetic Multishot Gyro Multishot Remarks KBU 146Y Middle Beluga KBU 14-6Y Lower Beluga KBU 146Y Tyone Tool .95/8'• Surface 0 — 1,500' X Intermediate 1,500' — 5,337' X Production 5,337'— 7,782' X Best Practices: 1 Comments: Vertical section calculated from a reference azimuth of 176.831 taken from surface location to bottom hole location Potential Well Interference: Well Distance (ft) Depth (MD) KBU 11-7 49.97 Surface KU 14X-6 68.88 690 KDU 1 102.96 3,058 KU 14-6RD 106.72 4,115 - [error ellipses intersect KBU 23-7 147.62 1,273 KBU 22-6 150.04 301 Serious interference potential exists for KU 14-6RD. This well has inclination only surveys and no way to re -survey. See attached directional plan and anticollision analysis for more details. Best Practices: 1 Comments: 4.14 Directional Surveying Summary � Other Survey Interval MD (ft) MWD Survey Magnetic Multishot Gyro Multishot Remarks Tool Surface 0 — 1,500' X Intermediate 1,500' — 5,337' X Production 5,337'— 7,782' X Best Practices: 1 10/22/2007 CONFIDENTIAL MATERIAL Page 14 of 18 KBU 14-6Y Drilling Program Comments: is 4.15 Drillinfa Fluid Program Summary 0 Marathon Oil Company Alaska Interval — TVD Density LSRV Vis 1 min (seclgt) (Ib./100ft2) PV (cP) Minimum Inventory From To Gel From (ft) (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite NC -12 +/-9.5 <7.5 1,500 Gel, Gelex, Soda Ash, Caustic, Barite, Polypac 9.0-9.5 40,000+ 0 1,500 8.6-9.4 Gel / Gelex Spud Mud +/-5 5,312 7,757 9.4-10.6 30,000 + 10-16 Supreme UL, Sodium Meta Bisulfate +/- 9.5 Flo -Vis, PolyPac Supreme UL, KCI, SafeCarb 1,500 5,312 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, 5,312 7,757 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 Drillina Fluid Specifications Interval — TVD Density (Ib/gal) LSRV Vis 1 min (seclgt) (Ib./100ft2) PV (cP) YP (Ib/100 ttz) Fluid Loss (cc) pH Drill Solids (%) From (ft) To (ft) 0 1,500 8.6-9.4 60-100 N/A 25-35 NC -12 +/-9.5 <7.5 1,500 5,312 9.0-9.5 40,000+ 8-12 7-9 +/-9.5 +/-5 5,312 7,757 9.4-10.6 30,000 + 10-16 5-8 +/- 9.5 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 %" 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 CaCO3 (SafeCarb) will be used to control leakoff. 10/22/2007 CONFIDENTIAL MATERIAL Page 15 of 18 KBU 14-6Y Drilling Program 4.17 Solids Control Equipment Marathon Oil Company Alaska Item Equipment Specifications (quantity, design type, brand, model, flow capacity, etc) Shaker 2 — Swaco Mongoose PT Desander N/A Desilter C o m N/A Centrifuge 2 — MI/Swaco units Cuttings Dryer N/A d Marathon G&I Facility Z d vi m d rn � Nrn c rn p Y m U -r- co C3 0 2 U U U N Interval Interval Comments 0 — 7,782' 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: 10/22/2007 CONFIDENTIAL MATERIAL Page 16 of 18 KBU 14-6Y Drilling Program 4.18 Cement Program Summary 0 Marathon Oil Company Alaska Casing Size (in) Depth Cement Description Gauge Hole Size (in) Top of Cement Gauge Ann Vol To TOC (ft) Ann Vol With OH Excess (ft3) Slurry Density Lead/Tail (ppg) Open Hole Excess M Thickening Time (hrs) MD (ft) TVD (ft) MD (ft) TVD (ft) 20 120 120 Driven N/A 133/8 1,500 1,500 16 0 0 693 1,162 12.0 75 8 95/8 5,337 5,312 121/4 3,000 2,994 732 1,060 10.5 40 8 31/2 7,782 7,757 81/2 4,800 4,776 993 1,315 15.8 40 N/A Casing Size (in) Slurry Cement Description Density (Ib/gal) Qty (SX) Yield (ft3lsx) Slurry Vol (ft) TOC MD (ft) Mix Water WL (cc) FW (%) Compressive Strength (psi) 8 hr 24 hr Qty (gal/sx) Type 133/8 Tail Type I Cement 12.0 463 2.51 1,162 0 11.28 Fresh 812 0 196 818 95/8 Tail Class "G" 10.5 355 2.99 1,060 3,000 12.39 Fresh 24 0 145 1,441 31/2 Tail Class "G" 15.8 1,124 1.17 1,315 1 4,800 4.97 Fresh 1 24 1 0 1 226 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 Summary Interval — MD Size (in) Type Recommended Estimated From (ft) To (ft) Manufacturer Model No. IADC WOB (kips) RPM Expected Rotating Minimum ROP Hours (ft/hr) 0 1,500 16 Christensen MX -1 115 1 - 4 80-350 1,500 5,337 121/4 Christensen HCM 506Z M323 Up to 52 Motor 5,337 7,782 81/2 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'/4" hole a MX -C3 (IADC 137) should be used to finish this section. Back up bits for the 8 %" hole section will consist of mill tooth and TCI tricone bits. 10/22/2007 CONFIDENTIAL MATERIAL Page 17 of 18 KBU 14-6Y Drilling Program 4.20 Hydraulics Summary 0 Marathon Oil Company Alaska Qty Make Model Liner ID (in) Stroke (in) Max Press @ 90% WP (psi) Displacement @ 95% Vol. eff (gal/stroke) Max Rate @ 95% Vol. eff (spm/gpm) Hole Sections Used On 3 National Oil Well A60OPT 5 8 2,597 2.04 125/255 Surface 5 8 2,597 2.04 125/255 Intermediate 5 8 2,597 2.04 125/255 Production 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 W, and 8'/" holes were calculated using 5" drillpipe. 4.21 Formation Intearity Test Procedure Surface and Intermediate casing shoes will be tested to Leak -off. Prior to drilling out of casing strings, test BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak -off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Best Practices: 1 Comments: 10/22/2007 CONFIDENTIAL MATERIAL Page 18 of 18 Est. Hole Pump Standpipe Openhole Nozzle Depth -MD Size Rate Pressure Min AV MW ECD Size AP at bit (ft) (in) (gpm) (psi) (fpm) (ppg) (ppg) (32"s)(psi) Remarks (Drill string configuration) 0-1,500 16 650+ 1,400 69 9.3 2 — 18's Actual Data KBU 24-7X (@ 1,636' MD) 1-16 1,500 — 5,337 121/4 663 2,050 130 9.5 6 —13's Actual Data KBU 24-7X (@ 6,077' MD) 5,337 — 7,782 81/2 477 1,850 249 9.7 1 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 W, and 8'/" holes were calculated using 5" drillpipe. 4.21 Formation Intearity Test Procedure Surface and Intermediate casing shoes will be tested to Leak -off. Prior to drilling out of casing strings, test BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak -off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Best Practices: 1 Comments: 10/22/2007 CONFIDENTIAL MATERIAL Page 18 of 18 21 1/4" 2M Diverter ____10 Diverter Spool Marathon Oil Well KBU 14-6Y Diverter 16" Automatic Knife Valve 16" Diverter Line Marathon Oil Well KBU 14-6Y BOP Stack Flow Nipple 13 5/8" 5M Annular Preventer No 13 5/8" 5M Double Ram Preventer 2 1/16" 5M Check Valve 112 1/16" 5M Manually Operated Valves Illpllllllp1111IC 13 5/8" 5M x 13 5/8" 5M Drilling Spool Blind Ram Choke • 3 1/8" 5M Manually Operated Valve I r3 1/8" 5M Hydraulically Operated Valve Bottom of mud cross must be 24-45" from ground level for Glacier 1 rig placement. 13 5/8" 5M Tubing Head Flange Fo Gas Buster Marathon Oil Well KBU 14-6Y Choke Manifold To Blooey iine 0 Bleed off Line to Shakers From BOP Stack • 0 Surface Use Plan for Kenai Beluga Unit, well KBU 14-6Y Surface Location: 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. 1) Existing Roads Existing roads which will be used for access to KBU 14-6Y 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 14-6Y. 3) Location of existing wells Well KBU 14-6Y will be drilled on Kenai Gas Field (KGF) pad 14-6. A pad drawing is enclosed that shows existing wells and the proposed location of KBU 14-6Y. 4) Location of existing and/or proposed facilities The locations of existing production facilities on KGF pad 14-6 are shown on the enclosed pad drawing. A flowline will be installed from the KBU 14-6Y wellhead and tied into the existing production facilities. 5) Location of Water Supply A water supply well exists on the pad that KBU 14-6Y will be drilled from. 6) Construction Materials No major construction is planned on the pad at this time. Leveling of the pad for this work will be done with minimal materials needed. 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 24-7RD, 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 injected into approved disposal well Beaver Creek # 2 (Alaska Oil and Gas Conservation Commission Disposal Injection Order No. 4) or 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 0 • 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 ADEC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surface KBU 14-6Y will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of KBU 14-6Y and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from CIRI Native Corporation prior to any reclamation work beginning. 10) Surface ownership The surface owner of the land in the Kenai Beluga Unit is the Salamatof Native Association. Operator Certification Field: Kenai Gas Field Well: Kenai Beluga Unit, KBU 14-6Y Surface Location: 482' FSL, 1,121' FWL, Sec. 6, T4N, R11W, S.M. I hereby certify that I, or someone under my direct supervision, have inspected the drill site and access route proposed herein; that I am familiar with the conditions which currently exist; that I have full knowledge of state and Federal laws applicable to this operation; that the statements made in this APD package are, to the best of my knowledge, true and correct; and that the work associated with the operations proposed herein will be performed in conformity with this APD package and the terms and conditions under which it is approved. I also certify that I, or the company I represent, am responsible for the operations conducted under this application. These statements are subject to the provisions of 18 U.S.C. 1001 for the filing of false statements. Executed this 23 t day of October , 20 07 Name Willard J. Tank Position Title Advanced Senior Drilling Engineer Address P.O. Box 3128, Houston, TX 77253-3128 Telephone 713-296-3273 Field Representative Pete Berga (Drilling Superintendent) (if not above signature) Address _ 3201 C Street, Suite 800. Anchoraae Alaska 99503 (if different from above) Telephone 907-565-3032 (if different from above) E-mail w6tank6d1marathonoil.com (optional) • 0 SCALE 0 100 200 FEET 1. BASIS OF HORIZONTAL COORDINATES ARE ALASKA STATE PLANE NAD 83 ZONE 4 EPOCH 2003 DETERMINED BY AN NGS OPUS SOLUTION FROM CORS BASE STATIONS "KEN1 PID AF9548",'TSEA PID AI0952"AND'ZAN1 PID DE9153" OBSERVED AUGUST 23, 2007 ON MCI 11-1 KKPL 3" ALUM. CAP SET MP 10.9 KB RD N: 2367475.381 E: 1409643.183 2) BASIS OF VERTICAL DATUM IS MEAN SEA LEVEL. 3) SOUTHWEST CORNER SEC. 6 COORDINATES DETERMINED FROM DIRECT SURVEY TIE TO THE TO EXISTING BLM SECTION CORNER W.C. RECOVERED AND NOT THE PROTRACTED SECTION CORNER VALUES. 4 EDGE PAD FOOTPRINT PROPOSED PAD TOP OF BERM _ CONTROL PT. CP -3 TOP EDGE PAD \I KBU 14-6Y AS -STAKED I GRID N:2362291.674 UTOGATE GRID E:1412067.868 LATITUDE: 60°27'36.746"N 1121' FWL LONGITUDE: 151015'54.417"W J ELEV.: 65.5 FT. K.U. 21-7X rD N 2362277.93 \ A ' .� E 112279.36 +� 0 o e K.B.U. 11-7 K.B.U. 22-6 c\ N 2362281.83 N 2362291.62 E 1412218.27 K.T.U. 13-6 �o E 1412017.90 N 2362230.91 ° \ 0' ElK.U. 14X-6 E 1412232.97 N 2362226.74 K.D.U.-1 W; U3" E 1412090.92 IN IN N 2362219.39 0 K.B.U. 31-7 E 1411864.73 ® N 2362208.96 �41k 'E)K.U. 21-7 E 1412250.17 \I N 2362168.92 ^ E 1411956.82 oLD 'UMP .Ell ER BLDG. K.B.U. 23-7 .� K.U. 31-7X N 2362132.82 I W ' K.U. 14-6 RD K.B.U. 24-6 N 2362132.58 N 2362061.36 E 1412039.38 E 1412268.38 Z_ N 2362115.07 E 1411904.54 K.B.U. 23X-6 E 1412202.55 J ( 410 N 2362091.92 Z \ � 482' E 1412150.71 K.G.F. PAD 14-6 U B34 ELEVATION = 65.6' M.S.L. REBO Lu REBOIIER D TOP EDGE PAD '^ v' QK.U. 43-12 1y2 r- EDGE PAD FOOTPRINT 0 A.P.L.0 �^ RE -BOILER N 2361979.63 RESOILER BLDG CONTROL PT. BLDD, 4N 91C. T.B.M.EL.""" E 1411916.13 SPIKE IN P.P. I CP -2 METER _. S12 S7 BUILDING R12W R11W ELEV =65.67' O R PAV 1921 • I I a n I CONC. PAD W HEATER CONTRA _ .. - SBLDG LDG. G I WASTE SW COR ❑ WATER B DG. CENTAUR182 CBPRESSOR CNTACTOR PROPOSEDPAD " N 2361824.52 1 6 E 1410937.15 ' X. D 12 7 / / O.H. PAN SECTION LINE VALVE \ BLDG. / SATURN \ \ u, COMPRESSOR OFFlCESHOP / \ 3.4,85 BLDG. BLDG. \ / CONTACTOR SATURN VENT BLDG. SLOWDOWN 6 MMAT TONT 1 PROJECT REVISION: 1 DATE: 10/17/07 11��1 M OIL COWAW KBU 14-6Y WELL ON KGF PAD 14-6 DRAWN BYMSM ARATNON AUMXBOM AS -STAKED SURFACE LOCATION DIAGRAM SCALE: T"=l CansLL{Ln Inc ENGINEERING/MAPPING/SURVEYING/TESTING 9 P.O. BOX 488 SOLDOTNA AK 99889 VOICE: (907)283-4218 FAX: (907)2833285 PROJECT NO. 073140 BOOK NO. 07-24 LOCATION SHEET EMAIL SAMCLANEQMCLANECG.COM S6 T4N R11W SEWARD MERIDIAN, ALASKA 1 DF 1 NORTH .--' •��• 25 Pad 33-30 {{ oppy Lin• Yrl 32 Private, Road_ r 35 •fie r36 2 37000 "y FEET Pad 43-32 ' i+��+t: `•,I Pad 34-3 f :Gas Wens Tam _ • I ` KENAI GAS FIELD � •i I 1 �invN 6 5 ' Pits r t 4 3 Pad 14-8 Pad- 33-1 }, p -. Gas WeIs0Pad-41-7 _ .-. Pad 14-� f 4 t�lldgt� ' Project Location ,. ` Y •t, 12 I a 9 Private Road i• i Pad 41-18 0 { 1716„ •� r -� 14 " l COOK INLET Pt",4=18 � `y`` it • •� ..� 1��._„ Abandoned 1 Kenai Unit Boundary �{ •� �� 1 , • i asJ � , � - ��I' � (� G{ems 25 j 30 29 2 ._ 26` 1 1 < 36 31 ° 32 Ref cctwu 1 Lake K a8ilof River -vit =_�,. S a„1 us wet .r 2 ro -- _.i LandinP 1P �i St,,r Source Map: USGS, 1981 Kenai, Alaska 0-4, 1:83.380 — SCALE 1:63360 YNA 0 30011 --am _ 900D_ !^000 IN= IAOGI 00 TI0FEET S IWOYETERS Marathon Oil Company Kenai Gas Field U nugal:(3F.�rmMaQ.jpp Area Map Kenai Gas Field, Alaska Base Map 0.25 mi ? ? W N 3 2 KU 1 N 1I4---32 34-31 N � h 34/2 KU (0 1-6 KU 1 KBU 41-6 ID b -6U 0 5 KU 0 5 21-6X 0 � 8 7 0 6 KBU 22-6 6 5 5 U_42-6 6 KTU 43-6XR KBU 3 6 23X-9 69 5 KBU 4 6 33-6 6 KU KBU 7 43-6A KTU 0 -6X 5 13-5 A 5 5 6 KTU 6 6 6 24-6H 5 K 24-6R 3 q- 4? -6RD KDU 5 5 4 s 5 S S KU s U 24- 3 5 'l'l 4 24-5RD 2 N A 3 K U @ 'O 3 6 1 KBU 3 24-6 3IL 3 0 32 KBU 7 P ih 1-7 2 o- 22 FDU q , j W A h K 11 7 KBU -7X IQJ 5 A 1-7RD 1 1-8 6 3 v 3 0 KTU 3 2 A N 32-71-1 1 v 5 2-7 5 6 3 9 4 6 7 32 7 6 � 4 S 5 KBU 6 13-8 IDU 4RD O KBU 33-7 6 5 3-12 8 -7 6 7 B 4f 7 7 � 6 3-7X 6 S Marathon Oil Company KBU 24+ v KU KUH v 41-18 24-7 0 A 9 h 3 ' 3 h n 3 rn 11-17 a p N � 2 ,O a N A tN 17 Kenai Gas Field, Alaska Base Map 0.25 mi GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT 0 • I i I I--__-•�-- i 1 XTA 3406 i I 1 UwT 1 I 4' X IV 5N 9L 5V 9L 1 I I i I A"m PT A-600 PT I I I ! 1 1 i I I 73 FP 75 IP 75 kP 75 IP I xrA 3406 rmuoi, 6 x�3 n u• u u Ili�f I - 1 t 1 t } Fl q E I tiller MITI= 1IL i ;� J � t 1 1 1 1 1 i p ---A 1 ss I41t 1 40 WA FLL ru 0 • MARATHON MARATHON Oil Co?n'pany Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: slot #KBU 14-6Y Field: Kenai Gas Field (NAD83) Well: KBU1"Y Facili Pad 14 6 Wellbore: KB 14 6Y s m w O 0.A+KB ST: 0.00° Inc, O.00ft MD, 0.00ft TVD, 0.00ft VS Begin Build: 0.00° Inc, 1100.00ft MD, 1100.00ft TVD, 0.0 1.20° 3.201 L 13 3/8" Csg Surface: 5.20° 4.00` Inc, 1500.00ft MD, 1499.68ft TVD. -3.18ft VS 7.20' Begin Tum to Tgt: 7.50° Inc, 1850.00ft MD, 1847.86ft TVD,-11.17ft VS 6.06° 4.60° 3.69° 3.75° 1.00°/100ft 4.74° 6.23° 7.95° EOC : 8.40° Inc, 3270.098 MD, 3261.5011 TVD, 63.31ft 9800 KBU 14-6Y .0 7200 Revised ed 17 -Oct -07 17- a 0.00° Inc, 7237.03ft MD, 7212.0011 TVD, 287.631 a� TD: O TD Revised 17 -Oct -07 7 m 4200 'C Begin Angle Drop: 7.22* 8.40° Inc, 4521.82ft MD, 4499.79ft TVD, 231.18ft VS N L 4800 5.22° 1.00°/100ft 3.22° KBU14-6Y 12211 95/8" Csg Intermediate: L .25° Inc, 5337.03ft MD, 5312.0011 TVD, 287.58ft' 6400 Middle Beluga Revised 17 -Oct -07 End of Drop: 0.00' Inc, 5362.03ft MD, 5337.0011 TVD, 287.63 6000 Lower Beluga KBU Beluga Lower Beluga Tgt: Revised 17 -Oct -07 0.00° Inc, 6077.03ft MD, 6052.0011 TVD, 287.63 8400 -800 0 800 1200 1800 2400 Vertical Section (ft) sp I h- 1"ft Azimuth 176.83° with reference 0.00 N. 0.00 E from wellhead Sole 1 inch . , W ft Easting (ft) was BAILER HUGHES INTEQ EOC : 3261.50ft TVD,-68.59ft S,-93.38ft W C KBU 14-6Y Tyonek Tgt: 7200 Revised ed 17 -Oct -07 17- 0.00° Inc, 7237.03ft MD, 7212.0011 TVD, 287.631 KBU 14-6Y TD: 7800 TD Revised 17 -Oct -07 7 m 0.00° Inc, 7782.03ft MD, 7757.00ft TVD, 287.631 8400 -800 0 800 1200 1800 2400 Vertical Section (ft) sp I h- 1"ft Azimuth 176.83° with reference 0.00 N. 0.00 E from wellhead Sole 1 inch . , W ft Easting (ft) was BAILER HUGHES INTEQ EOC : 3261.50ft TVD,-68.59ft S,-93.38ft W C MARATHON Oil Company Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: slot #KBU 14-6Y Field: Kenai Gas Field (NAD83) Well: KBU14-6Y Facility: Pad 14-6 Wellbore: KBU14-6Y Maw M � Yt NU INTEQ Plot reference wellpath is KBU14-6Y Version #2 True vertical depths are referenced to Glacier #1 (RKB) Grid System: NAD83 / TM Alaska State Plane, Zone 4 (5004), US feet Measured depths are referenced to Glacier #1 (RKB) North Reference: True north Glacier #1 (RKB) to Mean Sea Level: 87 feet Scale: True distance Mean Sea Level to Mud line (Facility - Pad 14-6): 0 feet Depths are in feet Coordinates are in feet referenced to Slot Created by: jonethoh on 18 -Oct -07 Location Information Facility Name Grid East (USft) Grid North (USft) Latitude Longitude Pad 14-6 1410937.150 2361824.520 60° 27'31.931"N 151* 16' 16.783"W Slot Local N (ft) Local E (ft) Grid East (USft) Grid North (USft) Latitude Longitude slot #KBU 14-6Y 488.91 1121.54 1 1412067.870 1 2362291.670 60° 27'36.746"N 151 ° 15' 54.417"W Glacier #1 (RKB) to Mud line (Facility - Pad 14-6) 87ft Mean Sea Level to Mud line (Facility - Pad 14-6) Oft Glacier #1 (RKB) to Mean Sea Level 87ft Targets Name MD (ft) TVD (ft) Local N (ft) Local E (ft) Grid East (USft) Grid North (USft) Latitude Longitude KBU 14-6Y Middle Beluga Revised 17 -Oct -07 5362.03 5337.00 -287.19 15.92 1412078.27 2362004.24 60' 27'33.918"N 151" 15' 54.099'W KBU 14-6Y Lower Beluga Revised 17 -Oct -07 6077.03 6052.00 .287.19 15.92 1412078.27 2362004.24 60° 27' 33.918"N 151" 15' 54.099'W KBU 14-6Y Tyonek Revised 17 -Oct -07 7237.03 1 7212.00 1 -287.19 15.92 1412078.27 2362004.24 60' 27'33.918"N 151" 15'54.099'W KBU 14-6Y TD Revised 17 -Oct -07 7782.03 7757.00 -287.19 15.92 1412078.27 2362004.24 60' 27'33.918"N 151" 15' 54.099'W Well Profile Data Design Comment MD (ft) Inc (`) Az (') TVD (ft) Local N (ft) Local E (ft) DLS (°/100ft) VS (ft) RKB 87' 0.00 0.000 280.000 0.00 0.00 0.00 0.00 0.00 Begin Build 1100.00 0.000 280.000 1100.00 0.00 0.00 0.00 0.00 Begin Turn to Tgt 1850.00 7.500 1 280.000 1847.86 8.51 -48.27 1.00 -11,17 EOC 3270.09 8.402 153.435 3261.50 -68.59 -93.38 1.00 63.31 Begin Angle Drop 4521.82 8.402 153.435 4499.79 -232.18 -11.58 0.00 231.18 End of Drop 5362.03 0.000 153.435 5337.00 -287.19 15.92 1.00 287.63 Lower Beluga Tgt 6077.03 0.000 153.435 6052.00 -287.19 15.92 0.00 287.63 Tyonek Tgt 1 7237.03 0.000 153.435 7212.00 -287.19 15.92 0.00 287.63 TD 1 7782.03 0.000 153.435 7757.00 -287.19 15.92 0.00 287.63 0 Planned Wellpath Reportg =[g BAKER KBU14-6Y Version #2 HUGHES (MARATHON Page 1 of 6 INTEQ Planned Wellpath ReportF/RG BAKER KBU14-6Y Version #2 HUGHES MARATHON Page 2 of 6 ok INTEQ ELLPATH DATA (85 stations) t = inter olated/extra olated station NID [feet] Inclination ° A"0.000300.00 Vert Sect feet North feet East feet Grid East us surve feet Grid North [us surve feet DLS °/100ft Build Rate [°/100ft] Turn Rate [°/100ft Design Comments 0.00 0.000 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 87' 100.00t' 0.000 0 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 200.001 0.000 0 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 300.00 0.000 0 1 0.001 0.00 0.001 1412067.87 2362291.67 0.00 0.001 0.00 `400.00tj 0.000 0.000, 400.001 0.001 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 500.0011 0.000 0.000 500.00 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 600.00 j 0.000 0.000 600.00 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 700.001 0.000 0.000 700.00 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 800.00' 0.000 0.000 800.00 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 .., _ 0.000 0.000 900.00 0.00 0.00 „ ', 0.00 1412067.87 2362291.67 0.00 0:00 0.00 1000.001 0.000 0.000 1000.001 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 1100.00 0.000 280.000 1100.00 0.00 0.00 0.00 1412067.87 2362291.67 0.00 0.00 0.00 a in Build 1200.001 1.000 280.000 1199.99 -0.20 0.15 -0.86 1412067.01 2362291.84 1.00 1.00 0.00 1300.00' 2.000 280.000 1299.96 -0.80 0.61 -3.44 1412064.45 2362292.34 1.00 1.00 0.00 1466.06t 3.000 280.000 1399.86 -1.79 1.36 -7.73 1412060.17 2362293.18 1.00 �,.000 0.00 1500.001 4.000 280.000 1499.68 -3.18 2.42 -13.74 1412054.17 2362294.36 1.00 1.00 0.00 1600.001 5.000 280.000 1599.37 -4.97 3.79 -21.47 1412046.48 2362295.87 1.00 1.00 0.00 1700.001 6.000 280.000 1698.90 -7.15 5.45 -30.91 1412037.07 2362297.71 1.00 1.00 0.00 1800.001 7.000 280.000 1798.26 -9.73 7.42 -42.06 1412025.96 2362299.89 1.00 1.00 0.00 _ 1850.00 7.500 280.000 1847.86 -11.17 8.51 -48.27 1412019.77 2362301.11 1.00 1.00 0.00 Begin Tum to Tgt 1900.001 7.065 278.055 1897.46 -12.51 9.51 -54.53 1412013.53 2362302.22 1.00 -0.87 -3.89 2000.001 6.224 273.367 1996.78 -14.33 10.69 -66.03 1412002.06 2362303.63 1.00 -0.84 -4.69 2100.001 5.437 267.277 2096.27 -14.98 10.78 -76.18 1411991.92 2362303.91 1.00 -0.79 -6.09 2200.001 4.731 259.261 2195.87 -14.48 9.79 -84.96 1411983.12 1 2362303.09 1.00 -0.71 -8.02 ,., 4.1471 248.7341 2295.58 -12.81 7.71 -92,38 1411975.661 2362301.15 1.00 -0:58 -10.53 Planned Wellpath Report WGA2 p BAKER KBU14-6Y Version #2 HUGHES MARATHON Page 3 of 6 At INTEQ ELLPATH DATA (85 stations) t = interpolated/extrapolated station MD feet Inclination ° Azimuth ° TVD feet Vert Sect feet North feet East feet Grid East us survey feet Grid North us survey feet] DLS [0/100ft] Build Rate [°/100ft] Turn Rate [*/100ftl Design Comments 2400.001 3.743 235.389 2395.34 -9.99 4.54 -98.44 1411969.54 2362298.10 1.00 -0.40 -13.34 2500.001 3.581 219.890 2495.14 -6.00 0.29 -103.13 1411964.77 2362293.94 1.00 -0.16 -15.50 2600.001 3.693 204.173 2594.94 -0.86 -5.04 -106.45 1411961.35 2362288.67 1.00 0.11 -15.72 2700.00 1 4.055 190.3281 2694.71 5.44 -11.46 -108.40 1411959.27 2362282.30 1.00 0.36 -13.84 2800.00tj 4.609 179.272 2794.43 12.89 -18.95 -108.981 1411958.55 2362274.81 1.00 0.55 -11.06 2900.001 5.296 170.823 2894.06 21.50 -27.53 -108.20 1411959.17 2362266.23 1.00 0.69 -8.45 3000.001 6.070 164.413 2993.57 31.25 -37.18 -106.04 1411961.14 2362256.54 1.00 0.77 -6.41 3100.001 6.902 159.494 3092.93 42.15 -47.90 -102.51 1411964.46 2362245.75 1.00 0.83 -4.92 3200.001 7.774 155.650 3192.11 54.19 -59.69 -97.62 1411969.12 2362233.87 1.00 0.87 -3.84 3270.09 3300.001 8.402 1!15!3435 3291.09 67.33 -72.50 .n -91.42 1411973.20 1411975.08 2362224.89 2362220.95 1.00 0.00 0.90 0.00 -3.16 0.00 OC 3400.001 8.402 153.435 3390.01 80.74 -85.57 -84.89 1411981.36 2362207.75 0.00 0.00 0.00 3500.00' 8.402 153.435 3488.94 94.15 -98.64 -78.35 1411987.64 2362194.56 0.00 0.00 0.00 3600.00 8.402 153.435 3587.87 107.56 -111.71 -71.82 1411993.92 2362181.37 0.00 0.00 0.00 3700.001 8.402 153.435 3686.79 120.97 -124.78 -65.28 1412000.20 .2362168.18 0.00 0.00 0.00 3800.00 8.402 153.435 3785.72 134.38 -137.84 -58.75 1412006.49 2362154.99 0.00 0.00 0.00 3900.00 j 8.402 153.435 3884.65 147.79 -150.91 -52.21 1412012.77 2362141.79 0.00 0.00 0.00 4000.001' 8.402 153.435 3983.57 161.20 -163.98 -45.68 1412019.05 2362128.60 0.00 0.00 0.00 4100.001 8.402 153.435 4082.50 174.61 -177.05 -39.14 1412025.33 2362115.41 0.00 0.00 0.00 4200.00f 8.402 153.435 4181.43 188.03 -190.12 -32.61 1412031.62 2362102.22 0.00 0.00 O.OQ 4300.001' 8.402 153.435 4280.35 201.44 -203.19 -26.07 1412037.90 2362089.03 0.00 0.00 0.00 4400.001 8.4021 153.435 4379.28 214.85 -216.26 -19.54 1412044.18 2362075.83 0.00 0.00 0.00 4500.00tj 8.4021 153.4351 4478.21 228.26 -229.33 -13.01 1412050.46 2362062.64 1 0.001 0.00 0.00 4521.82 1 8.4021 153.4351 4499.791 231.18 -232.18 -11.581 1412051.83 2362059.76 1 0.001 0.001 0.00 egin Angle Drop 4577.211 241.19 -241.93 -6.711 1412056.52 2362049.93 1.00 -1.001 0.00 Planned Wellpath ReportriFla BAKER KBU14-6Y Version #2 HUGHES MARATHON Page 4 of 6 ok INTEQ ELLPATH DATA (85 stations) t = inter olated/eztra olated station MD feet Inclination Azimuth [° TVD feet 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 Design Comments 4700.00f 6.620 153.435 4676.44 252.56 -253.01 -1.16 1412061.85 2362038.74 1.00 -1.00 0.00 4800.001 5.620 153.435 4775.87 262.35 -262.55 3.60 1412066.43 2362029.11 1.00 -1.00 0.00 4900.00' 4.620 153.435 4875.47 270.54 -270.53 7.60 1412070.27 2362021.05 1.00 -1.00 0.00 5000.00f 3.620 153.435 4975.21 277.13 -276.96 10.81 1412073.36 2362014.57 1.00 -1.00 0.00 OQ _ 153.435 5075.06. 282.13 -281.$3 13.24 1412075.70 2362009.65 1_.00 -1.00: 5200.001 1.620 153.435 5174.99 285.52 -285.14 14.90 1412077.29 2362006.31 1.00 -1.00 0.00 5300.001 0.620 153.435 5274.97 287.32 -286.89 15.77 1412078.13 2362004.55 1.00 -1.00 0.00 5362.03 0.000 153.435 287.63 1412078.27 2362004.24 1.00 -1.00 0.00 ndofDrop 5400.00' 0.000 0.000 5374.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 y 5474,97 x$7.63287.19 5.92 1412078.27 2362004.24 0.00 0.00 5600.00 j 0.000 0.000 5574.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 5700.00' 0.000 0.000 5674.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 5800.001 0.000 0.000 5774.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 5900.00t 0.000 0.000 5874.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 $974.97 2 -2$719 ..'" 1412078:27 .24 0.00 0.00 6077.03 0.000 153.435 287.63 1412078.27 2362004.24 0.00 0.00 0.00 Lower Beluga Tgt 6100.001 0.000 0.000 6074.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 6200.00' 0.000 0.000 6174.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 6300.001 0.000 0.000 6274.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 .9 1374. 7; 287 b3 X87:19 15.92 1412078.27 2362004.24 ;; 4 `QQ. O liE 6500.00 1 0.000 0.000 6474.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 6600.00 1 0.000 0.000 6574.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 6700.0011 0.000 0.000 6674.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 6800.00ti 0.000 0.000 6774.97 287.63 -287.191 15.92 1412078.27 2362004.24 0.00 0.00 0.00 4 : O:QQf1 087071',"-":- x -- 21.13 2$ �..9' 15.92 1412078,27 2362004 24 _. 0.00 0.00'., I Planned Wellpath Report IGA2 p BAKER KBU14-6Y Version #2 HUGHES MARATHON Page 5 of 6 A INTEQ ELLPATH DATA (85 stations) t= inter olated/extrapolated station String/Diameter Start MD [feet] Ad MD feet Inclination ° Azimuth ° TVD [feet] Vert Sect [feet] North [feet] East feet Grid East us surveyfeet Grid North us surveyfeet] DLS [°/100ft Build Rate °/100ft Turn Rate Design °/100ftComments 7000.001 0.000 0.000 6974.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 7100.001 0.000 0.000 7074.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 7200.00' 0.000 0.000 7174.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 7237.03 0.000 153.435 5312.00 287.63 -287.14 15.90 1412078.27 2362004.24 0.00 0.00 0.00 Tyonek Tgt 7300.06fi ' 0.000 0:000 7274.971'287.63 0.00 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 7400.001 0.000 0.000 7374.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 7500.00t 0.000 0.000 7474.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 7600.00t. 0.000 0.000 7574.97 287.63 -287.19 15.92 1412078.27 2362004.24 0.00 0.00 0.00 7700.00ti 0.000 0.0001 7674.97 287.63 -287.191 15.92 1412078.27 2362004.24 0.00 0.00 0.00 7782.03 0.000 153.43 287.631412078.27 2362004.24 0.00 0.00 0.00ID HOLE & CASING SECTIONS Ref Wellbore: KBU14-6Y Ref Wellpath: KBU14-6Y Version #2 String/Diameter Start MD [feet] End MD [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W [feet] End N/S [feet] End E/W [feet] 16in Open Hole 0.00 1500.00 1500.00 0.00 1499.68 0.00 0.00 2.42 -13. 13.375in Casing Surface 0.00 1500.00 1500.00 0.00 1499.68 0.00 0.00 2.42 -13.74 12.25in Open Hole 1500.00 5337.03 3837.03 1499.68 5312.00 2.42 -13.74 -287.14 15.90 9.625in Casing Intermediate 0.00 5337.03 5337.03 0.00 5312.00 0.00 0.00 -287.14 15.90 8.5in Open Hole 5337.03 7782.04 2445.00 5312.00 NA -287.14 15.90 NA NA 3.5in Casing Production 0.00 7782.04 7782.04 0.00 NA 0.00 0.00 NA NA 0 M I RATHON Planned Wellpath Report KBU14-6Y Version #2 Page 6 of 6 FNA .a BAKER HUGHES INTEQ TARGETS Name MD TVD North East Grid East Grid North Latitude Longitude Shape [feet] [feet] [feet] [feet] [us survey feet] [us survey feet] [°] [°] 1) KBU 14-6Y Middle Beluga Revised 17- 5362.03 circle Oct -07 2) KBU 14-6Y Lower Beluga Revised 17- 6077.03 circle Oct -07 7237.03 IIIIIIIIJUcircle 3) KBU 14-6Y Tyonek Revised 17 -Oct -07 7782. 03 circle 4) KBU 14-6Y TD Revised 17 -Oct -07 SURVEY PROGRAM Ref Wellbore: KBU14-6Y Ref Wellpath: KBU14-6Y Version #2 Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore feet [feet] 0.00 1500.00 NaviTrak (Standard) U14 -6Y 1500.00 5337.04 NaviTrak (Standard) U14 -6Y 5337.04 7782.03 NaviTrak (Standard) U14 -6Y 0 ws Well P ath Design A P Approval Report BAKER Wellpath: KBU14- lYpVersion #2 HUGHES MARATHON Pagel of 3 Ok jNTEQ WEF12 Wellpath Design Approval Report BAKER Wellpath: KBU14-6Y Version #2 HUGHES AtMARATHON Page 2 of 3 INTEQ ELLPATH DATA (9 stations) MD Inclination [feet] N Ref Wellbore: KBU14-6Y Azimuth [°] TVD North [feet] [feet] East [feet] Design Comments 0.00 0.000 280.000 0.00 0.00 0.00 RKB 87' End TVD [feet] 1100.00 0.000 280.000 1100.00 0.00 0.00 Begin Build 1850.00 7.500 280.000 1847.86 8.51 -48.27 Begin Turn to Tgt 0.00 3270.09 8.402 153.435 3261.50 -68.59 -93.38 EOC 0.00 1500.00 8.402 153.435 4499.79 -232.18 _ -11.58 Begin An-Sle Drop 2.42 5362.03 0.000 153.43569mamma. 5337.0011 -287.19 15.92 End of Drop 5312.00 6077.03 0.000 153.435 6052.00 -287.19 15.92 Lower Beluga Tgt 5337.03 7237.03 0.000 153.435 7212.003 -287.19 15.92 yonek Tgt 15.90 7782.03 0.0001 153.435 7757.004 -287.19 15.92 D -287.14 HOLE & CASING SECTIONS Ref Wellbore: KBU14-6Y Ref Wellpath: KBU14-6Y Version #2 String/Diameter Start MD [feet] End MD [feet] Interval [feet] Start TVD [feet] End TVD [feet] Start N/S [feet] Start E/W [feet] End N/S [feet] End E/W [feet] l6in Open Hole 0.00 1500.00 1500.00 0.00 1499.68 0.00 0.00 2.42 -13.74 13.375in Casing Surface 0.00 1500.00 1500.00 0.00 1499.68 0.00 0.00 2.42 -13.74 12.25in Open Hole 1500.00 5337.03 3837.03 1499.68 5312.00 2.42 -13.74 -287.14 15. 9.625in Casing Intermediate 0.00 5337.03 5337.03 0.00 5312.00 0.00 0.00 -287.14 15.90 8.5in Open Hole 5337.03 7782.04 2445.00 5312.00 NA -287.14 15.90 NA NA 3.5in Casing Production 0.00 7782.04 7782.04 0.00 NA 0.00 0.00 NA NA Wellpath Design A P Approval Report BAKER • Wellpath: KBU14- IY�Version #2 HUGHES MARATHON Page 3 of 3 INTEQ TARGETS Prepared by Name MD TVD North East Grid East Grid North Latitude Longitude Shap [feet] [feet] [feet] [feet] [us survey feet] [us survey feet] [ol [o] 1) KBU 14-6Y Middle Beluga Revised 17- 5362.03 circle Oct -07 Date 2) KBU 14-6Y Lower Beluga Revised 17 -Oct- 6077.03 circle 07 Position 7237.03 circle 3) KBU 14-6Y Tyonek Revised 17 -Oct -07 7782.03 circle 4) KBU 14-6Y TD Revised 17 -Oct -07 SURVEY PROGRAM Ref Wellbore: KBU14-6Y Ref Wellpath: KBU14-6Y Version #2 1 Start MD l End MD I Positional Uncertainty Model Log Name/Comment Wellbore 0.001 1500.00(javiTrak (Standard) JK2U14-6Y 1500.001 5337.04 aviTrak (Standard) U14 -6Y 5337 r APPROVAL INTEQ Representatives Prepared by Reviewed by Signature Signature Position Position Date Date MARATHON Oil Company Representative Approved by Position Signature Date m t 0 0 Z M MARATHON MAR THON Oil Co pany Location: Cook Inlet, Alaska (Kenai Penninsula) Slot: slot #KBU 14-6Y Field: Kenai Gas Field (NAD83) Well: KBU14-6Y Facility Pad 14-6 Wellbore: Ki14-6Y Easting (ft) MAP its BAKER HUGHES INTEQ --LW -1fo -1bu -PLb -1w -/6 -b0 -2b u Zb bu to Juu TCb slot #KU 43-12 ��V G 50 325 � J 50 b10 Y /50. 25 1900 25 2100 5900 900 230 190 0 2500 500 300 1po slot #KBU 14-6Y -2nn -775 0 0 25 Slot Ki 11-7 2700 700 570 25 2900 2100 79-25 55 900 -50 3100 -50 slot #KU 14X-6 (Originally KDU 8) slot #KTU 5300 1100 500 1900 '75 900 3300 2300-75 5300 slot #KDU 1 1100 0O 4500 01 5900 ss 0 0 6� 0 KU14X-6 00 1900 100 slot #KU 21-7 '125 500 3700 -125 700 1300 Slot #KBU 23-7 150 1300 21 tmo '150 3900 1500 6� 3 500 700 1700 11 1 *BV14 15100 KU14-6 170 .175 1 1700 ,��yoo�o�� -175 13500 4100 1300 100,0 Slot #K13U 24-6 \\�'( QN 11300 12700 1500 200 0�79G� 10300 1500 slot #KBU 23X-6 -200 ,Ays`d S Jt�O� 1300 300 g3pp On 5100 43001100 1 1900 Oti n 5500 225 3500 -225 11 4500 17 slot #KU 14-6Rd 250 -250 4700 2100 1900 275 4900 1700 275 5100 7700 , 2100 300 �< slot #KU 43-12 325 350 /50. 1900 375 -2nn -775 Ann -12fi Ann -75 din -25 0 25 .-.-=-I Easting (ft) 2300 Clearance Report Closest Approach KBU14-6Y Version #2 Page 1 of 54 rupro. BAKER HUGHES INTEQ `POSITIONAL .UNCERTAINTY CALCULATION SETTINGS Ellipse Confidence Limit 3.00 Std De v Ellipse Start Depth —[19--00-East 0.00 feet Surface Position Uncertainty lincluded Declination of TN Dip Angle 73.370 Magnetic Field Strength 55408 nT M MARATHON Clearance Report Closest Approach KBU14-6Y Version #2 Page 2 of 54 err BAKER HUGHES INTEQ sANTI-COLLISION RULE ]Rule Name E -type Closest Approach w/Hole&Csg Limit:0 StdDev:3.00 w/Surface Uncert Rule Based On 1EHipsoid Separation Plane of Rule Closest Approach Threshold Value 0.00 feet Subtract Casing & Hole Size 1yes Apply Cone of Safety Ino 'HOLE & CASING SECTIONS Ref Wellbore: KBU14-6Y Ref Wellpath: KBU14-6Y Version #2 String/Diameter Start MD [feet] End MD Interval [feet] [feet] Start TVD [feet] End TVD [feet] Start N/S Start E/W [feet] [feet] End N/S [feet] End E/W [feet] 16in Open Hole 0.00 1500.00 1500.00 0.00 1499.68 0.00 0.00 2.42 -13.74 13.375in Casing Surface 0.00 1500.00 1500.00 0.00 1499.68 0.00 0.00 2.42 -13.74 12.25in Open Hole 1500.00 5337.03 3837.03 1499.68 5312.00 2.42 -13.74 -287.14 15.90 9.625in Casing Intermediate 0.00 5337.03 5337.03 0.00 5312.00 0.00 0.00 -287.14 15.90 8.5in Open Hole 5337.03 7782.04 2445.00 5312.00 NA' -287.14 15.90 NA NA 3.5in Casing Production 0.00 7782.04 7782.04 0.00 NA 0.00 0.00 NA NA ;SURVEY PROGRAM Ref Wellbore: KBU14-6Y Ref Wellpath: KBU14-6Y Version ##2 Start MD End MD feet feet Positional Uncertainty Model Log Name/Comment Wellbore 0.00 1500.00 NaviTrak (Standard) U14 -6Y 1500.00 5337.04 NaviTrak (Standard) U14 -6Y 5337.041 7782.03 aviTrak (Standard) U14 -6Y M IATHON Clearance Report Closest Approach KBU14-6Y Version #2 Page 3 of 54 EAF.■ BAKER HUGHES INTEQ CALCULATION RANGE & CUTOFF 11111lu 1 E To: 7782.03 MD C -C Cutoff (none) i OFFSET WELL CLEARANCE SUMMARY (17 Offset Wellpaths selected) Offset Offset Offset Offset Offset Facility Slot Well Wellbore Wellpath Ref MD [feet] Min C -C Clear Dist [feet] Diverging from MD [feet] Ref MD of Min C -C Min C -C Ell Sep Ell Sep [feet] [feet] Min C -C ACR Ell Sep Status Dvrg from [feet] Pad 14-6 Slot#KBU 11-7 KBU 11-7 KBU 11-7 MWD <0-7900> 0.00 49.97 7600.00 0.00 36.47 7600.00 PASS Pad 14-6 Slot #KBU 22-6 KBU22-6 KBU22-6 MWD <0-8855> 301.06 150.04 7782.03 309.19 136.72 7782.03 PASS Pad 14-6 Slot #KBU 23-7 KBU 23-7 KBU 23-7 MWD <0-9320> 1272.63 147.62 1272.63 1284.89 132.15 1284.89 PASS Pad 14-6 Slot #KBU 24-6 KBU24-6 KBU24-6 MWD <0-7500> 1281.39 206.63 7237.03 1281.39 191.98 7237.03 PASS ad 14-6 Slot #KBU 24-6 KBU24-6Rd KBU24-6Rd MWD <3964-7830> 1281.391 206.63 7600.00 1281.391 191.98 7600.00 PASS Pad 14-6 Slot #KU 21-7X KU21-7X KU21-7X MWD <193-5032> 1163.51 201.82 4800.00 1174.64 186.97 4800.00 PASS Pad 14-6 slot #KBU 23X-6 KBU23X-6 KBU23X-6 GMS <0-6950> 1906.80 196.59 1906.80 1935.87 178.43 1935.87 PASS Pad 14-6 slot #KBU 31-7 KBU31-7 KBU31-7 GMS <0-7375> 895.97 193.37 895.97 905.67 177.43 905.67 PAS Pad 14-6 slot #KBU 31-7 KBU31-7 KBU31-7Rd MWD <5814-7575> 895.97 193.37 895.97 905.67 177.43 905.67 PASS Pad 14-6 slot #KDU 1 KDU-1 KDU-1 MSS <0-9895> 3058.12 102.96 5600.00 2974.64 77.78 5800.00 PASS Pad 14-6 slot #KTU 13-6 (Originally KU 13-6) KU13-6 KU13-6 MSS <0-5500> 1078.62 115.66 1078.62 1097.36 97.95 1097.36 PASS Pad 14-6 slot #KU 14-6Rd KU14-6 KU14-6 Totco Incl. Surveys <200-150475 4114.74 106.72 7782.03 7782.03 -154.41 7782.03 FAIL Pad 14-6 slot #KU 14-6Rd KU14-6 KU14-6 Sidetrack Totco Incl Survey<4800 - 54035 4114.74 106.72 5400.00 4246.73 -51.50 5400.00 FAIL Pad 14-6 slot #KU 14X-6 (Originally KDU 8) KU14X-6 KU14X-6 GMS <0-10000> MSS <10194-10225> 690.31 68.88 6200.00 1108.96 54.24 6200.00 PASS Pad 14-6 slot #KU 21-7 KU21-7 KU21-7 MSS<0-4453> 4.00 165.54 1000.00 12.10 152.31 1000.00 PASS Pad 14-6 slot #KU 31-7X (Originally KU31-7) KU 31-7 KU 31-7 MWD <0-5790> 0.00 255.97 0.00 0.00 242.74 0.00 PASS Pad 14-6 1 slot #KU 43-12 KU43-12 KU43-12 MSS <0-6530> 0.001 346.991 0.001 0.19 333.771 0.19 1 PASS MARATHON Clearance Report Closest Approach KBU14-6Y Version #2 Page 37 of 54 FISFIG BAKER HUGHES INTEQ CLEARANCE DATA - Offset Wellbore: KU14-6 Offset Wellpath: Totco Incl. Surveys <200-150471> facility: Pad 14-6 Slot: slot #KU 14-6Rd Well: KU14-6 Threshold Value=0.00 feet t = interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C -C Clear Dist Ellipse Sep [feet] [feet] [feet] [feet] feet [feet] [feet] [feet] [°] [feet] [feet] ACR MASD [feet] ACR Status 0.00 0.001 0.00 0.00 5.30 0.00 -233.42 -158.88 214.24 282.36 269.10 13.26 PASS 200.00f 200.00 0.00 0.00 205.30 200.00 -233.42 -158.88 214.24 282.36 267.62 14.74 PASS 400.00f 400.00 0.00 0.00 405.64 400.34 -233.38 -158.81 214.24 282.29 263.18 19.11 PASS 600.00t 600.00 0.00 0.00 606.58 601.28 -233.12 -158.31 214.18 281.80 255.87 25.93 PASS 86,QW, .00 0.90 0.00 808.22 .802.91 -232.32 -156.80 214.02 280.30 246.89 33.41 PASS 1000.001 1000.00 0.00 0.00 1007.27 1001.95 -231.31 -154.88 213.81 278.38 237.39 41.00 PASS 1100.00 1100.00 0.00 0.00 1106.49 1101.17 -231.01 -154.32 213.74 277.82 233.00 44.82 PASS 1200.001 1199.99 0.15 -0.86 1206.52 1201.20 -230.80 -153.91 213.53 277.06 228.33 48.73 PASS 1400.00t 1399.86 1.36 -7.73 1406.67 1401.35 -230.28 -152.92 212.08 273.38 216.76 56.62 PASS 1600.00t 1599.37 3.79 -21.47 1606.40 1601.07 -229.63 -151.69 209.16 267.29 203.23 64.06 PASS 1800.00t 1798.26 7.42 42.06 1805.44 1800.10 -228.86 -150.23 204.60 259.87 188.65 71.22 PASS 1850.00 1847.86 8.51 -48.27 1855.06 1849.71 -228.65 -149.84 203.18 258.00 184.87 73.14 PASS 2000.00t 1996.78 10.69 -66.03 2003.98 1998.63 -227.98 -148.55 199.07 252.54 173.61 78.93 PASS 2200.00t 2195.87 9.79 -84.96 2202.69 2197.33 -227.11 -146.90 194.65 244.86 158.13 86.73 PASS 2400.00f 2395.34 4.54 -98.44 2401.841 2396.48 -226.35 -145.45 191.51 235.63 141.07 2600.00t 2594.94 -5.04 -106.45 2601.22 2595.86 -225.68 -144.19 189.71 223.85 121.51 102.34 PASS 2800.00t 2794.43 -18.95 -108.98 2800.55 2795.18 -225.10 -143.07 189.39 208.94 98.89 110.05 PASS 3000.00t 2993.57 -37.18 -106.04 2999.55 2994.17 -224.58 -142.10 190.89 190.84 73.18 117.66 PASS 3200.00t 3192.11 -59.69 -97.62 3197.99 3192.62 -224.15 -141.27 194.86 170.15 44.96 125.19 PASS 3270.09 3261.30 -68.59 -93.38 3267.43 3262.05 -224.00 -140.99 197.03 162.54 34.73 127.821 PASS 3400.00t 3390.01 -85.57 -84.89 3396.01 3390.62 -223.70 -140.41 201.90 148.87 16.17 132.70 PASS 3600.00t 3587.87 -111.71 -71.82 3593.96 3588.58 -223.15 -139.38 211.23 130.33 -10.08 140.411 FAIL 3800.00f 3785.72 -137.84 -58.75 3791.91 3786.54 -222.52 -138.18 223.17 116.10 -32.39 148.50 FAIL 4000.001 3983.57 -163.98 -45.68 3989.79 3984.40 -221.83 -136.87 237.61 108.00 -49.05 157.05 FAIL 4114.741 4097.08 -178.98 -38.1$ 4103.29 4097.89 -221.42 -136.10 246.56 106.72 -55.37 162.10 FAIL 4200.00t 4181.43 -190.12 -32.61 4187.661 4182.26 -221.12 -135.51 253.24 107.47 -58.38 165.85 FAIL 4400.00f 4379.28 -216.26 -19.54 4385.53 4380.12 -220.38 -134.11 267.94 114.64 -59.86 174.51 FAIL 4521.82 4499.79 -232.18 -11.58 4506.05 4500.64 -219.91 -133.23 275.76 122.27 -57.34 179.611 FAIL 4600.00t 4577.21 -241.93 -6.71 4583.48 4578.06 -219.61 -132.65 280.051 127.91 -54.91 182.821 FAIL 4800.00t 4775.87 -262.55 3.60 4782.15 4776.73 -218.82 -131.141 287.981 141.67 -49.22 190.89 FAIL Clearance Report Closest Approach KBU14-6Y Version #2 Page 38 of 54 Eris BAKER HUGHES INTEQ CLEARANCE DATA - Offset Wellbore: KU14-6 Offset Wellpath: Totco Incl. Surveys <200-150471> [Facility: Pad 14-6 Slot: slot #KU 14-611d Well: KU14-6 Threshold Value=0.00 feet t = interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C -C Clear Dist Ellipse Sep ACR MASD ACR [feetl ]feetl ]feetl jfeetl [feet] [feetl [feet] ]feet] 101 [feet] [feet] [feet] Status 5000.00tj 4975.21 -276.96 10.81 4980.94 4975.52 -218.27 -130.10 292.61 152.64 -46.22 198.86IFAIL L 5200.00f 5174.99 -285.14 14.90 5180.49 5175.07 -218.16 -129.90 294.82 159.53 -47.29 206.83L 5362.03 5337.00 -287.19 15.92 5342.60 5337.18 -218.06 -129.71 295.39 161.20 -52.03 213.23 5400.00t 5374.97 -287.19 15.92 5380.59 5375.17 -218.03 -129.64 295.41 161.16 -53.51 214.66 5600.001 5574.97 -287.19! 15.92 5580.72 5575.29 -217.77 -129.15 295.57 160.83 -61.39 222.22; 5800.001 5774.97 -287.19 15.92 5780.84 5775.42 -217.39 -128.42 295.81 160.34 -69.45 229.79 6000.00 5974.97 -287.19 15.92 5980.94 5975.51 -216.90 -127.50 296.11 159.72 -77.66 237.38 6077.03 6052.00 -287.19 15.92 6058.01 6052.58 -216.68 -127.09 296.24 159.45 -80.87 240.31 6200.001 6174.97 -287.19 15.92 6181.03 6175.60 -216.31 -126.38 296.48 158.98 -86.02 245.00L 6400.001 6374.97 -287.19 15.92 6381.13 6375.68 -215.62 -125.08 296.91 158.12 -94.51 252.63L6600.001 6574.97 -287.19 15.92 6581.19 6575.75 -214.84 -123.58 297.41 157.15 -103.13 260.286800.00[ 6774.97 -287.19 15.92 6781.19 6775.74 -214.03 -122.04 297.94 156.16 -111.79 267.95L:7000.001 6974.97 -287.19 15.92 6981.18 6975.72 -213.21 -120.49 298.47 155.18 -120.46 275.64L7200.00f 7174.97 -287.19 15.92 7181.17 7175.71 -212.40 -118.95 299.01 154.22 -129.13 283.35 7237.03 7212.00 -287.191 15.92 7218.21 7212.74 -212.25 -118.66 299.11 154.04 -130.74 284.78 F 7400.001 7374.97 -287.19 15.92 7381.16 7375.68 -211.59 -117.411 299.551 153.27 -137.811 291.09 FAIL 7600.00f 7574.97 -287.19 15.92 7581.16 7575.68 -210.77 -115.86 300.11 152.34 -146.50 298.84 FAIL 7782.03 7757.00 -287.19 15.92 7763.18 7757.70 -210.04 -114.46 300.621 151.50 -154.411 305.91 FAIL M MARATHON Clearance Report Closest Approach KBU14-6Y Version #2 Page 39 of 54 PAP.0 BAKER HUGHES INTEQ OWELLPATH COMPOSITION Offset Wellbore: KU14-6 Offset Wellpath: Totco Incl. Surveys <200-150471> I Start MD I End MD I Positional Uncertainty Model I Log Name/Comment Wellbore 0.001, 15137.001 Custom Drift Indicator (1.4 Maximum Inclination) Totco Incl. Surveys <200-150475 KU 14-6 OFFSET WELLPATH MD REFERENCE - Offset Wellbore: KU14-6 Offset Wellpath: Totco Incl. Surveys <200-150471> MD Reference: Actual Datum (RKB) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) 0 MARATHON Clearance Report Closest Approach KBU14-6Y Version #2 Page 40 of 54 I CA Fag BAKER HUGHES INTEQ FREFERENCE-WELLPATH ACR MASD [feet] Operator MARATHON Oil Company Slot slot #KBU 14-6Y Area Cook Inlet, Alaska (Kenai Penninsula) Well KBU14-6Y Field Kenai Gas Field (NAD83) Wellbore KBU14-6Y Facility Pad 14-6 ;.CLEARANCE DATA - Offset Wellbore: KU14-6 Sidetrack Offset Wellpath: Totco Incl Survey<4800 - 5403'> jFacility: Pad 14-6 Slot: slot #KU 14-611d Well: KU14-6 Threshold Value=0.00 feet f = interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C -C Clear Dist Ellipse Sep [feet] [feet] [feet] feet feet [feet] [feet] feet °] [feet] [feet] ACR MASD [feet] ACR Status 0.00 0.00 0.00 0.00 5.30 0.00 -233.42 -158.88 214.24 282.36 269.10 13.26 PASS 200.00t 200.00 0.00 0.00 205.30 200.00 -233.42 -158.88 214.24 282.36 267.62 14.74 PASS 400.00f 400.00 0.00 0.00 405.64 400.34 -233.38 -158.81 214.24 282.29 263.18 19.11 PASS 600.00t 600.00 0.00 0.00 606.58 601.28 -233.12 -158.31 214.18 281.80 255.87 25.93 PASS 800.00t 800.00 0.00 0.00 808.22 802.91 -232.32 -156.80 214.02 280.30 246.89 33.41 PASS 1000.0Ot 1000.001 0.00 0.00 1007.27 1001.95 -231.31 -154.88 213.81 278.38 237.39 41.00 PASS 1100.00 1100.00 0.00 0.00 1106.49 1101.17 -231.01 -154.32 213.74 277.82 233.00 44.82 PASS 1200.00f 1199.99 0.15 -0.86 1206.52 1201.20 -230.80 -153.91 213.53 277.06 228.33 48.73 PASS 1400.00t 1399.86 1.36 -7.73 1406.67 1401.35 -230.28 -152.92 212.08 273.38 216.76 56.62 PASS 1600.00t 1599.37 3.79 -21.47 1606.40 1601.07 -229.63 -151.69 209.16 267.29 203.23 64.06 PASS 1800.00t 1798.26 7.42 -42.06 1805.441 1800.10 -228.86 -150.231 204.60 259.87 188.65 71.22 PASS 1850.00 1847.861 8.51 48.27 1855.06 1849.71 -228.65 -149.84 203.18 258.00 184.87 73.14 PASS 2000.00t 1996.78 10.69 -66.03 2003.98 1998.63 -227.98 -148.55 199.07 252.54 173.61 78.93 PASS 2200.00t 2195.87 9.79 -84.96 2202.69 2197.33 -227.11 -146.90 194.65 244.86 158.13 86.73 PASS 2400.00f 2395.34 4.54 -98.44 2401.84 2396.48 -226.35 -145.45 191.51 235.63 141.07 94.55 R 2600.00t 2594.94 -5.04 -106.451 2601.22 2595.86 -225.68 -144.19 189.71 223.85 121.51 102.34 PASS 2800.00t 2794.43 -18.95 -108.98 2800.55 2795.18 -225.10 -143.07 189.39 208.94 98.89 110.05 PASS 3000.00t 2993.57 -37.18 -106.04 2999.55 2994.17 -224.58 -142.10 190.89 190.84 73.18 117.66 PASS 3200.00 3400.00ti 3192.11 3390.01 -59.69 -85.57 -97.62 -84.89 3197.99 67.43 3396.01 3192.62 3262.05 3390.62 -224.15 -224.00 -223.70 -141.27 -140.99 -140.41 194.86 197.03 201.90 170.15 162.54 148.87 44.96 34.73 16.17 125.19 127.82 132.70 PASS PASS,. PASS 3600.00tj 3587.87 -111.71 -71.82 3593.961 3588.58 -223.15 -139.381 211.23 130.33 -10.08 140.411 FAIL 3800.00ti 3785.72 -137.84 -58.75 3791.91 3786.54 -222.52 -138.18 223.17 116.10 -32.31 148.411 FAIL 4000.00tj 3983.57 -163.98 -45.68 3989.79 3984.40 -221.83 -136.87 237.61 108.00 -45.46 153.46 FAIL 7.08 -178.98 -38.18 4103.29 4097.89 -221.42 -136.10 246.56 106.72 49.77 156.501 FAIL 4200.00t 4181.43 -190.12 -32.61 4187.66 4182.26 -221.12 -135.51 253.24 107.47 -51.28 158.75 FAIL 4246.731 4227.65 -196.23 -29.56 4233.89 4228.49 -220.95 -135.19 256.83 108.49 -51.50 159.99 FAIL 4400.001 4379.28 -216.26 -19.54 4385.53 4380.12 -220.38 -134.11 267.94 114.64 -49.26 163.911 FAIL 4521.82 4499.79 -232.18 -11.58 4506.05 4500.64 -219.91 -133.23 275.76 122.27 166.881 FAIL 4600.00t 4577.21 -241.93 -6.71 4583.48 4578.06 -219.61 -132.65 280.05 127.91 _-44.61 -40.81 168.721 FAIL Clearance Report Closest Approach KBU14-6Y Version #2 Page 41 of 54 E.. BAKER HUGHES INTEQ CLEARANCE DATA - Offset Wellbore: KU14-6 Sidetrack Offset Wellpath: Totco Incl Survey<4800 - 54031> Facility: Pad 14-6 Slot: slot #KU 14-6Rd Well: KU14-6 Threshold Value=0.00 feet t = interpolated/extrapolated station Ref MD Ref TVD Ref North Ref East Offset MD Offset TVD Offset North Offset East Horiz Bearing C -C Clear Dist Ellipse Sep [feet] [feet] [feet] [feet] [feet] feet [feet] [feet] [°] [feet] [feet] ACR MASD [feet] ACR Status 4800.00t 4775.87 -262.55 3.60 4782.471 4777.05 -218.81 -131.14 287.98 141.67 -31.58 173.25 FAIL 5000.00t 4975.21 -276.96 10.81 4986.91 4980.99 -212.33 -118.81 296.50 144.96 -30.82 175.77 FAIL 5200.00t 5174.99 -285.14 14.90 5184.17 5178.02 -208.01 -110.61 301.57 147.34 -34.99 182.33 FAIL 5362.03 5337.00 -287.19 15.92 5347.32 5341.02 -204.46 -103.86 304.63 145.63 -44.41 190.04 FAIL 5400.00t 5374.97 -287.19 15.92 5383.26 5376.91 -203.72 -102.45 305.19 144.86 -47.24 192.10 FAIL 5600.00t 5574.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 229.62 104.34 125.28 PASS 5800.00t 5774.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 405.04 327.93 77.12 PASS 6000.00t 5974.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 596.15 538.31 57.83 PASS 6077.03 6052.00 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 671.14 617.68 53.46 PASS 6200.00t 6174.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 791.66 743.30 48.36 PASS 6400.00t 6374.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 988.97 945.90 43.07 PASS 6600.00t 6574.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 1187.18 1147.27 39.90 PASS 6800.00t 6774.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 1385.90 1347.95 37.95 PASS 7000.00t 6974.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.34 1584.95 1548.19 36.76 PASS 7200.00t 7174.97 -287.191 15.92 5403.00 4096.63 -203.52 -102.081 305.341 1784.21 1748.15 36.05 PAS 7237.03 7212.00 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.341 1821.12 1785.161 35.961 PASS 7400.00t 7374.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.341 1983.61 1947.921 PASS 7600.00tj 7574.97 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.341 2183.13 2147.56 35.571 PASS 7782.03 1 7757.00 -287.19 15.92 5403.00 5396.63 -203.52 -102.08 305.341 2364.79 2329.171 35.621 PASS M MARATHON Clearance Report Closest Approach KBU14-6Y Version #2 Page 42 of 54 INAFAS BAKER HUGHES INTEQ r_ ELLPATH COMPOSITION Offset Wellbore: K64-6 Sidetrack Offset Wellpath: Totco Incl Survey<4800 - 5403'> j Start MD I End MD I Positional Uncertainty Model I Log Name/Comment Wellbore 1 0.001 4781.00 1 Custom Drift Indicator (1.4 Maximum Inclination) Totco Incl. Surveys <200-15047'> 1 KU14-6 4781.001 5403.00 1 Custom Drift Indicator (5°Maximum Inclination ) Totco Survevs <4800 - 5403'> 1 KU14-6 Sidetrack OFFSET WELLPATH MD REFERENCE -Offset Wellbore: KU14-6 Sidetrack Offset Wellpath: Totco Incl Survey<4800 - 54031> MD Reference: Actual Datum (RKB) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) 0 I� IF • • Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PROJECT PLAN m� sws�cc Prepared For: MARATHON OIL COMPANY Well KBU 14-6Y Kenai Peninsula, Alaska Prepared by: Jim Dwyer Reviewed by: Hal Martens Presented to: Will Tank 1 1 � October 18, 2007 • IFE Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: • Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Enclosed is the recommended drilling fluid program for the KBU 14-6Y Well to be drilled in November / December 2007. The following is a brief synopsis of the program. Overview: KBU 14-6Y is a development well targeting the Tyonek formation at the Kenai Gas Field. Flo -Pro fluid will be used for the intermediate and production intervals. After logging the production interval, the well will be completed with a 3-1/2" excape system cemented in place. 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 program calls for the standard SafeCarb bridging material, Mix II should be added to the mud system prior to drilling the Sterling A8 sand (+/- 4565' MD). Gseal will be on Iocation for contingency if SafeCarb and Mix II do not stop excessive losses. This sand 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 weights above 10.0 PPG may 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 Senior Project Engineer Reference Wells: KBU 22-6; KBU 11-8Y; KBU 41-6; KBU 11-7 NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties required. LLQ IFE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. EXECUTIVE SUMMARY Our overall goal is no spills and no incidents while providing fluids and solids control services to Marathon Oil Company. Our goal for KBU 14-SY Is to remove drill solids from the mud system at a cost of less than $0.31 per pound. With the revised fluid formulation (utilizing the Intermediate interval fluid for the production interval), we expect to drill this well for a product cost of less than $31.59 per foot. We estimate the use of less that 5733 barrels to complete this well, not withstanding any excessive 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 FE$1,250,000. With continued usage of our equipment, we expect to provide more savings to you during future operations. In addition, the installation 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. IFE i IFE • Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Interval Benchmarks and Targets Drilling Intervals Depth Benchmark 1 Benchmark 2 Benchmark 3 Benchmark 4 Interval (ft) Fluid cost per Volume Usage Solids Removal foot 0 —1500' < $5.20 ft < 1950 bbls 1500 — 5324' <$49.50 < 3132 bbls 5324— 7765' < $16.75 ft < 651 bbls Total Project Avg. Max. Targets for < $31.59 ft <5733 bbls < $0.31 Ib No Spills from Drilling Centrifuge Van Interval Operation IFE IFE • 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth ND Mud Mud Sum Interval Size Size Program System Weight Days Mud Cost (in) (in) (it) (ft) Solids Control (ppg) w/ Engineer 13-3/8" 16" 1500' 1500' Gel/Gelex Spud Mud 8.6-9.4 6 $14,280 Screens 165/175 mesh Desilter Centrifuge Van 9-5/8" 12-1/4" 5337' 5312' Flo -Pro w/SafeCarb 9.0— 7 $204,153 Screens 200 mesh < 9.5 Desilter Centrifuge Van 3-1/2" 8-1/2" 7782' 7757' Flo -Pro w/SafeCarb 9.4— 6 $47,360 Screens 200 - 230 10.6+/ - mesh Desilter Completion Centrifuge Van 3 1/2" 8-1/2" 7782' 7757' 6% KCl 8.6 4 $11,144 ➢ 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 2% Lubetex concentration in intermediate and production interval. IFE n IFE 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Estimated Product Usage Summary M -I Bar 0 313 260 0 573 1.86 M -I Gel 378 0 0 0 378 1.75 Gelex 24 0 0 0 24 0.18 Soda Ash 9 16 7 032 0.25 Caustic Soda 9 47 13 0 80 1.28 Conqor 404 0 9 3 0 14 6.39 Sodium Meta Bisulfate 19 31 13 2 65 1.86 Bicarb 0 16 7 0 25 0.17 Conqor 303 0 0 0 4 4 0.72 F1oVis 0 219 39 0 258 23.22 Desco CF 8 0 0 0 8 0.16 Polypac UL 9 110 23 0 133 9.67 KCl 0 1315 273 42 1630 13.00 Safecarb 0 1409 195 0 1604 13.37 Lubetex 0 50 10 0 60 19.13 Mix II 0 251 0 0 251 1.39 Gseal** 0 100 0 0 100 4.20 SteelLube 0 0 4 0 4 1.27 Citric Acid 0 0 13 0 13 0.57 Defoam X 0 7 4 0 11 0.42 Engineer Service 6 7 6 4 23 ** Gseal as contingency product for excessive losses in Sterling sands IFE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Offset Well Information 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 Drig ahead 1680 9.2 14 20 7.8 Drlg to casing point, run surface casing 12.25 3453 9.3 8 11 9.2 Drlg out, displace to FloPro, Run LOT, drlg ahead 4649 9.4 12 14 8.8 Drlg ahead 5338 9.2 14 18 5.8 Lost partial returns @ 4929' spot 50 bbl LCM pill, regain returns 6032 9.3 14 16 5.4 Lost partial returns @ 5840', add LCM to mud 6535 9.6 17 19 5.2 Reduce ppg, pump LCM pills, run casing, cement same 8.5 7095 9.85 17 21 5.8 Drig out cmt, LOT, drlg ahead 8136 9.85 17 23 5 Drlg ahead, short trip OK, drig ahead 8855 10.3 19 21 5.2 Drlg to csg point, short trip, some tight spots, POH for logs 8855 10.45 19 22 5.8 Logging well 8855 10.65 19 20 5.2 RIH, weight up to 10.6 PPG, condition mud, POH 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 Drig 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 Drlg to csg point, add 3% Lubetex (torque), POH 5820 9.55 19 22 5.8 Log well, wiper trip, 5820 9.7 20 26 5.4 Run csg, cement same, lost partial returns 8.5 5840 9.3 14 18 6.2 Drlg out, LOT, drlg ahead, add EMI -920 and Lubetex for torque 7574 9.75 17 27 5 Drlg ahead 8220 10 16 27 5.4 Drlg to TD, increase PPG to 10.0 for gas 8220 10.5 17 28 5.8 POH, wireline well, increase PPG to 10.5 for gas 8220 10.8 17 26 5.2 Run and cement excape string, disp to brine IFE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Offset Well Information 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 Drlg to casing point, run surface casing 1862 9.3 12 14 7.2 Cement surface casing 12.25 3431 9.3 12 16 8 Drig out, displace to FloPro, Run LOT, drlg ahead 5044 9.2 13 17 8.4 Drlg to 4206', wiper trip OK, drig ahead, pump sweeps every 500 ft 6289 9.2 13 19 7.4 Drlg to 5278' lost returns, stopped with LCM, drig ahead 7105 9.3 14 23 7.6 Drlg to 6897', wiper trip OK, drig 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, drig 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 Drlg ahead, increase Lubetex to 4% 9733 10.3 16 19 4.6 TD well, 9733 10.6 15 18 4.4 Wiper trip, inc PPG to 10.6 for gas, POH for logs 9733 10.8 15 20 5.2 Log well, wiper trip, treat for running coals, POH 9733 10.8 14 21 5.6 Run and cement excape string, disp to brine KBU 11-7 16 187 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, drig ahead 4460 9.1 11 18 7.8 Drlg ahead with miminal losses 5080 9.3 11 15 8.6 Short trip, OK, drig 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 for RFT tool 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, drig ahead 6940 9.9 21 23 5.8 Drlg ahead, weight up for gas, wiper trip, backreaming needed 7770 10.3 26 27 6 RIH, drig ahead, weight up for stability, add asphasol for coals 7900 10.5 27 29 5.8 TD well, wiper trip, extensive backreaming, POH for logs 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 'FE IFE 1 • Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Plans & Procedures => COMMUNICATION — The Field Mud Engineer will communicate daily with the In -Town Project Engineer. The Project Engineer will then communicate daily with the rig Drilling Engineer. Communications should be about, but not limited to, fluid properties, hole difficulties, possible changes to the mud program, and proposals to use products not included in the mud program. => Whole Mud Losses to the Stering 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 sufficient 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. MIXING CONDITIONS — Whenever possible all treatments to the mud system should be made as pre -mix additions. Polymers and KCI should first be mixed in fresh water in that order and then blended into the active system over one or two circulations as needed. CORROSION — Congor 404 additions should be made daily when drilling with FloPro fluid in order to maintain a Conqor 404 concentration of +/- 2000 PPM. => CORRISION - Sodium MetaBisulfate 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 — All increases in mud weight should be accomplished with barite additions. In the production interval, insure chloride concentration is maintained at 30,000 to minimize the need for barite additions. IFE IFE 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Interval Summary —16" hole 0 -1500' Drilling Fluid System Gel/Gelex Spud Mud Key Products MI Gel / Gelex / Soda Ash / Caustic Soda / MI Bar / PolyPac Supreme UL / Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens — 165 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, hole cleaning. Interval Drilling Fluid Properties Depth Mud Funnel Yield API Drill Interval Weight Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec./qt) (lb./100ftz) (ml/30min) ("/o) 0 - 1500' 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 Meta 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 — 1892 barrels. ➢ Estimated haul off volume — 2984 barrels. IFE IFE • 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Hole Cleaning Index rA Sjft _ 01995-2006 M-1 L. .C. 'Mark of M-1 L.L.C. VIRTUAL NYDRAULIC�RDR" MD:1500 ft TVD1500 ft Bit Size16 in Date10/19/2007 OperatorMarathon Well Narn&BU 14-6Y LocationKenai Peninsula StateAlaska Hole Cleaning 1.00 Marathon KBU 14-6Y - — ROP 50 ft/h _ — ROP 125 ft/ ir — ROP 200 ft/ ir 0011! Qffl— mi - 0.75 x m -a - ole. C e c 0.50 a� U Good HoeCea n 0 0.25 Very o d H le Cleaning 00 500 600 700 800 900 Flow Rate Inal/minl IFE 0 IFE 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Interval Summary—12-1/4" hole 1500 —5337' Drilling Fluid System Flo -Pro Fluid Key Products Flo -Vis / PolyPac Supreme UL / KCl / SafeCarb 10, 40, 250 / Interval Weight Viscosity Mix II /MI Bar / Caustic Soda / Congor 404 / Sodium Meta Bisulfate MBT Lubetex / GSeal Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens — 200 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight < 7.5 hole conditions Interval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (ppg) (cp.) (cps) (ml/30min) (%) 1500 - 5337' 9.0 — < 9.5 8-12 40,000+ 7 - 9 < 7.5 ➢ 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 possible. ➢ After drilling out surface casing, displace hole to Flo -Pro fluid prior to running leak off test ➢ As mud heats up, increase F1oVis concentration to 2 PPB as needed. ➢ NOTE. Be prepared for whole mud losses in the Sterling A8 sands (+/- 4465' MD). ➢ If torque or sliding problems occur, add 1 — 3% Lubetex. ➢ NOTE: This fluid will be used in the production interval It is inherent to maintain proper fluid properties for that purpose. ➢ Estimated volume usage for interval — 3715 barrels. ➢ Estimated haul off volume — 4033 barrels. ➢ Condition mud prior to running 9-5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. IFE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Fluid Formula -12-1/4" Interval 12-1/4" Interval from 1500 - 5337' In id Deacf'i torr KBU 14-6Y NU I t: Pre -heat makeup water with steam hoses as much as possible. Output -1 bbl Mud Weight 9.0-9.5 PMbydrated Get No ftghtl Material Code SafeCarb Preh rated Gel Cont. IMMM W ht Material SG 2.8 6 IFE NU I t: Pre -heat makeup water with steam hoses as much as possible. Output -1 bbl Order of Products " Conc rdration Volume Product Addition Fief lb Lab Field bbl Lab ml U 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 Viscosity 4 Polypac Supreme UL 2.00 2.00 0.004 1.25 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 pH Control 6 Potassium Chloride 19.07 19.07 0.023 7.98 Inhibition 7a SafeCarb 10 4.00 4.00 0.040 1.44 Bridging Agent 7b SafeCarb 40 1 12.00 12.00 0.012 4.32 Bridging Agent 7c SafeCarb 250 4.00 4.00 0.004 1.44 Bridging Agent 8 KlaGard 4.00 4.00 0.008 2.25 Inhibition Plan on adding 2.5 - 5 PPB Mix II to the muds stem prior to drilling into the Sterling A8 sand +/- 4565' MD 9 Mix II 5.00 5.00 0.010 3.12 LCM If torque becomes a problem, or sliding is difficult add 1 - 3% of the followin : 10 Lubetex 1 14.00 1 14.00 1 0.041 14.43 Lubricity If bit ballina becomes a Problem add the followin : 11 D -D CWT 1.00 1.00 0.003 1.00 Reduce BHA Balling TOW 1 399 399 1.000 350 'C ut ft " l TotaitCttforwa - 9.500 pro d"v 29600 3715 Barrels IFE IFE 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Hole Cleaning Index M� $� 01995-2006 M-1 L. L. C. •Mark MD:5337 ft Operator:Marathon of M-1 L.L.C. TVD:5337 ft Well NameKBU 14-6Y VIRTUAL RYURAULICSIRUR' Bit Size12.25 Date:10/19/2007 in LocationKenai Peninsula State:Alaska 1.00 - Hole Cleaning Marathon KBU 14-6Y — ROP 25 ft/hr — ROP 55 ft/hr — ROP 85 ft/hr — ROP 115 ft/ r — ROP 145 ft/1- r- 0.75-- ROP 175 ft/ X d v c — rn � c .E 0.50 d U m 0 = Good Hole Cleaning f 4- 0.25 V90 God ole Cleaning 440 460 480 500 520 540 560 580 600 620 640 660 Flow Rate (gal/min) In all cases where hole cleaning is rated as either "Fair" , "Fair to Poor", or "Poor" extra precautions must be made to keep the wellbore clean. 1. Extra time spent should be spent on circulation prior to connections and trips. 2. Adjust rheology if possible to help with hole cleaning. 3. Weighted high viscosity sweeps may help but should not be used as a primary cleaning strategy. 4. Maximized rpm while drilling and circulating will generally aid with hole cleaning. 5. Monitor PWD data (if available) closely. 6. Observe and chart pickup and slack off weights during each connection. IFE IFE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. 12.25" VH SNAPSHOT 11/Ij $ ©1995-2006 M -I L.L.C. 3axaM-iLLC. MD: 5337 tt TVD: 5337 ft Operator: Marathon ell Name: KBU-6Y VIRTUAL HYDRAULICS' $nau$hote Bit Size: 12.25 in t 10N9/2007 Location: Kenai Peninsula Count : Alaska l�tlh Geometry MDITVD ag ODIID 4500 5500 Va (tUmin) Hole Clean Index Pnssu (// wribution Bit =22.6 Ann =3.3 DS=7 Drilling Fluid Water -Based Mud Mud Weight 9.5 Ib/gal System Data Rate 550 Penetration Rate 100 ft/hr Rotary Speed 80 rpm Weight on Bit 10 1000 Ib' Bit Nozzles 0.902in' Pressure Losses Modified Power Law Drill String 1080 psi MWD 322 psi Motor 251 psi Bit329 psi Bit On/Off 100 psi Annulus 48 psi Surface Equip 23 psi U -Tube Effect 62 psi Total S stem2214 si ESD ECD +Cut Csg Shoe 9.61 9.75 9.97 IN - Vewlon 3.1 Fann 35 -KBe 146YADS 'FE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Bridging Formula -12-1/4" hole MiSVI/ACO COPTIBRIDGEOperator. Marathon Max Permeability : 1000 mDarcy Well Name: KBU %6Y Sand Control Device: 11 Location: Kenai Gas Field M-IL.L.C.-gllRlghlaRssarved COnlments: Optimum Blend Optimum Bridging Agent Blend 1.0 0.9 - Target Blend 0.8 0.7---- 0.6--- 0.6- 0.4--- 0.3 .70.60.50.40.3 0.2 - 0.7 1x10'2 1x101 1x10° 1x101 1x10 1Y4n3 �..� Particle Size (microns) 1FE �/ D10 - D60 - D90 D 10 Ta rget 18 iend: 1.3 / 1.7 microns D50Target/Blend: 31.6 / 29.8 microns D90Target /Bland: 102.5 / 144.2 microns Optimum Blend for 0 to 100 % CPS Rang Brand Name Brid In A en Ib/ 1 ° A=Safe-Cart 2 (VF) 0.1 0.34 B= Safe -Cart 10 (F) 0.0 0.00 C=Safe-Cart 20 12.0 47.81 D=Safe-Cart 40 (M) 13.0 51.85 E=Safe-Cart 250 (C) 0.0 0.00 A 0.3% C 47.8% D 41051.9% Simulation Accuracy Calcium Carbonate added : 25 Ib/bb Avg Error 0 - 100 % CPS Range : 1.63 % Max Error 0 - 100 %CPS Range : 11.48 % 0 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Interval Summary — 8-1/2" hole 5337 - 7782' Drilling Fluid System Flo -Pro Fluid Key Products Flo -Vis / Polypac Supreme UL / KCl / SafeCarb / MI Bar / Caustic Soda / Congor 404 / Sodium Meta Bisulfate / SteelLube / Lubetex Solids Control Shale Shakers / Desilter / Centrifuge Van Recommended shaker screens — 200 - 230 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions Interval Drilling Fluid Properties Depth Interval (ft) Mud Weight (p g) Plastic Viscosity (cp-) LSRV 1 min (cps) API Fluid Loss MBT (mV30min) Drill Solids (%) 5324 —7200' 9.4+/- 10-14 30,000+ 6 - 8 < 7.5 +/-5% 7200 — 7782' 10.0 —10.6 12 —16 30,000+ 5-7 < 7.5 +/-5% ➢ 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. ➢ NOTE: Plan on increasing the mud weights to 10.0 — 10.6 PPG to control pressures in the Tvonek formation (+/- 7400' MD). However, mud weight increases should not be needed while drilling the lower Beluga formation. ➢ NOTE: If metal -to -metal torque is a problem after drilling out the 9-5/8" casing then add 0.5 — 1% SteelLube prior to adding Lubetex ➢ If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. ➢ Estimated additional volume for interval — 651 barrels. ➢ Estimated haul off volume — 2301 barrels. ➢ Condition mud prior to running 3-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. IFE • 0 IFE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Dilution Formula - 8-1/2" Interval 8412" Interval from 5324 - 7782' i.,....E p2 cri tion KBU 14-6Y Mud Weight 9.4 -10.6+ 113rehydrated Gel Weight Ma#erlal`2g ft !No MI BaR IPre rated Oel Conc. Weight Material SG 4.2 KCI Wt% 6 1 Water 325.19 325.19 0.929 325.19 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 FloVis Plus 2.00 2.00 0.005 1.34 Viscosity 4 Pol pac Supreme UL 2.00 2.00 0.004 1.33 Fluid Loss Control 5a SafeCarb 20 15.00 22.50 0.017 5.67 Tridging BridgingAgent 5b I SafeCarb 40 5.00 7.50 0.006 1.89 Bridging Agent 6 Potassium Chloride 20.76 20.76 0.025 8.68 Inhibition 7 CONQOR 404 2.00 2.00 0.004 1.43 Corrosion Control 8 Caustic Soda 0.50 0.50 0.001 0.23 pH Control 9 Sodium Meta Bisulfate 0.50 0.25 0.001 0.25 Oxygen Scaven er If high torque in incured while drilling out the 9-5/8" casing add 0.5 -1.0 % SteelLube 10 ISteelLube 3.50 3.50 1.500 3.50 Metal to Metal Lub If sliding or high torque becomes a problem add 1 - 3% of the following 11 Lubetex 7.00 7.00 0.021 7.00 Lubricity 12 If sloughing coals become a As hasol Supreme r problem add 2 - 4 ppb of the followin 2.00 2.00 1 0.004 1.33 Wellbore Stability Mix fluid in the order listed above. 380.1 1 380.1 9.050 1FE r AFE 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Interval Summary — Completion Procedures Corrosion Control Additive in Casing x Tubing Annulus Well KBU 14-6Y Volumes: Tubing Volume 3-1/2" Tubing 67.70 barrels Annular Volume Casing x Tubing 327.32 barrels 3.50 x 2.992 x 7782 ft 9.625 x 8.681 @ 5337 ft MD 8.500 x 3.50 @ 7782 ft MD Open Hole x Tbg 120.23 barrels Total Annular Volume 447.56 Tubing Volume 67.70 Total Hole Volume 515.26 Treatment Procedures. 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. IFE 0 0 IFE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. HSE Issues HANDLING OF DRILLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. 2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. 3. PPE must be in good working order and be utilized as recommended by the PPE charts. 4. Product additions should be made with the intent to use complete unit amounts of products (sacks, drums, cans) as much as possible in order to minimize inventory of partial units. 5. Insure all MSDS sheets are up to date and readily available for workers to access for information. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all hoses and connections between the van and the rig are secure. IFE 0 0 Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Flammability Re PPE M-1 BAR Weighting Agent *1 0 0 E M-1 GEL Viscosity control *1 1 0 E GELEX Bentonite Extender 1 1 0 E FLOVIS Viscosifier 1 1 0 E DUAL-FLO Modified Starch 1 1 0 E POLYPAC Fluid Loss Reducer *1 1 0 E HEC Loss Circulation Material 1 1 0 E Safe-Carb 10,40,250 Bridging and weighting agent *1 0 0 E Nut Plug Loss Circulation Material *1 1 E M-1 Seal F, M, C Loss circulation Material *1 1 0 ' , E Mix II F,M,C Loss circulation Material *1 1 E E DESCO CF Dispersant 1 1 SALT (Solar) Densifier 1 0 E POTASSIUM CHLORIDE Shale Inhibitor 1 0 E CAUSTIC SODA Alkalinity control 3 0 X BORAX Inorganic Borate 1 0 E SAPP Sodium Pyrophosphate *1 0 E SODA ASH Alkalinity control 1 1 0, - E SODIUM BICARBONATE Alkalinity control 1 0 E CITRIC ACID pH Adjuster 1 0 E BIOBAN BP -PLUS Biocide *2 0 J GREEN CIDE 25G - Biocide 3 0 J DEFOAM X - Defoamer 1 1 J G -SEAL Sized graphite LCM 1 1 E SteelLube Lubricant 1 1 J LUBE TEX Lubricant 1 1 0 J D -D CWT Detergent 2 1 0 J Concor 404 Corrosion Inhibitor 1 1 0 ;# J SAFEKLEEN Drilling fluid additive 1 1 0 J Asphasol Supreme Shale Inhibitor 1 1 0 J Sodium Meta Bisulfate Oxygen Scavenger 1 1 0 J IFE IFE Marathon Oil Company Well Name: KBU 14-6Y Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 - Severe hazard 3 - Serious hazard 2 - Moderate hazard 1 - Slight hazard 0 - Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A - Safety Glasses B - Safety Glasses, Gloves C - Safety Glasses, Gloves, Synthetic Apron D - Face Shield, Gloves, Synthetic Apron E - Safety Glasses, Gloves, Dust Respirator F - Safety Glasses, Gloves, Synthetic Apron, Dust Respirator G - Safety Glasses, Gloves, Vapor Respirator H - Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator I - Safety Glasses, Gloves, Dust and Vapor Respirator J - Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator K - Air Line Hood or Mask, Gloves, Full Suit, Boots X - Consult your supervisor for special handling directions 0 IFE Contacts 0 Marathon Oil Company Well Name: KBU 14-6Y 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 Tony Tykalsky Project Engineer tykalsky@miswaco.com 907 274-5011 907 227-2412 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 Irooneyl@alaska.net 907 235-0598 907 398-9474 MI SWACO (home) John Nicholson / Dan Drilling Foremen alaska_drilling@marathon 907 283-1312 Byrd oil.com Marathon Responsibilities ➢ MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M -I field engineers. ➢ Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. ➢ Field Engineers will monitor and supervise product inventory to include re -palletizing any products for shipment to other locations at the end of the well. ➢ Field Engineers will communicate with office personnel (Marathon & MI 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. IF% TRANSMITTAL LETTER CHECKLIST WELL NAME PTD# Development Service Exploratory Stratigraphic Test Non -Conventional Well Circle Appropriate Letter / Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS TEXT FOR APPROVAL LETTER WHAT (OPTIONS) APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well Permit No. , API No. 50- - - (If last two digits in API number are between 60-69) Production should continue to be reported as a function of the original APT number stated above. PILOT HOLE In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well name ( PH) and API number (50- - -�) from records, data and logs acquired for well SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to perforate and produce / inject is contingent upon issuance of a conservation order approving a spacing exception. , assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: Non -Conventional production or production testing of coal bed methane is not allowed Well for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Comaanv Name) must contact the Commission to obtain advance approval of such water well testing program. Rev: 7/13/2007 W Field & Pool KENAI, UP TYONEK BELUGA GAS - 448571 –Well Name: KENAI BELUGA UNIT 14-6Y Program DEV Well bore seg PTD#: 2071490 Company BP EXPLORATION (ALASKA I) NC _ Initial Class/Type DEV/PEND GeoArea 820 Unit 51120 On/Off Shore On _ Annular Disposal Administration 1 Permit_fee attached- - - - - - - - - - - - - - - --- ------------- NA ------------- 2 Lease number appropriate_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - --------------------------------- 3 Unique well _name and number - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - yes 4 Well located in_a_defined -pool _ - - _ _ ------ - - -- ---- -Yes------- --------------- 5 Welllocatedproperdistancefromdrillingunitboundary - - - - - - - - - - - - - - - - - - - - - - - - Yes- - - - - - - - - - - - - - - . 6 Well located proper distance from other wells_ - - - - - - - - - - - - - - - - - - - Yes ------- 7 Sufficient acreage -available in -drilling unit- . - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - - - - _ _ _ - - - - - - - - - - - - - - - - - - - - - - - -------------- 8 If_ deviated, is wellbore plat -included ----- - ----------------------------- Yes_-_-__-------- ------------------------------------------------------------ 9 Operator only affected party - - - - - - - - - - - - - - - - - - _ - - - ----- _ _ _ _ - _ _ _ _ _ - _ _ Yes - - - - - - - - - - - - - - - - _ ------------------------- 10 Operator has -appropriate bond in force _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ _ _ _ _ - Blanket Bond #5194234 ------------------------------------------- 11 Permit can be issued without conservation order_ - - - - - - - - - - - - - - - - - - - - - - - - Yes Appr Date 12 Permit can be issued -without administrative -approval _ - - - - Yes - - - - - - - - ACS 10/29/2007 13 Can permit be approved before 15 -day wait Yes 14 Well located within area and_strata authorized by Injection Order # (put 10# in -comments) - (For_ NA_ - - - - - - - - - - - 15 All wells_within 1/4_mile area_of review identified (For service well only)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA _ _ _ _ _ _ _ _ _ _ _ - - - - - - - _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ - _ - _ - - - - - - _ ----------------------------- 16 Pre -produced injector; duration -of pre -production less than 3 months (For service well only) _ - NA_ ------------------------------ 17 Nonconven. gas conforms to AS31.05.030(j.1_.A),G..2.A-D) - - - - - - - - - - - - - - - - - - NA_ ----------------------------- Engineering 18 Conductor string_p_rovided- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes- - - - - - - - 19 Surface casing_ protects all -known- USDWs - - - - - - - Yes - - - - . Surface casing planned at 1500' tvd. All aquifers exempted- bel_ow_1300' tvd,_40 CFR_ 147.102(b0M(iii)- - - - - - - 20 _C_MTv_oladequatetocirculate o_n-conductor & surf _csg- - - - - - - - - - - - - - - - - - - - - - - - Yes- - - - - - - 21 CMT_v_ol_ adequate to tie -in -long string to—surf csg- - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ - - - - ------------- 22 _C_MT_will coverall known_productive horizons- - Yes -- ----- - - - - -- -- -------- 123 Casing designs adequate for C,_T, B_& permafrost- - - - - - - - - - -- - - - - - - - - - - - Yes _ - - - 124 Adequate tankage -or reserve pit - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - --------------------------------------------- - - - - - - Rig equipped with steel pits. No reserve pit planned._ All waste to approved disposal well(s). 125 If_a_ re -drill, has_a 10-403 for abandonment been approved - - - - - - - - - - - - - - - -NA ---------------------------------------- - ---- 26 Adequate wellbore separation -proposed- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - _ _ _ - Proximity_ analysis performed. Traveling cylinder path calculated, _ _ _ - - - - - - - - - - - - - - - - - _ - - _ _ _ _ _ 27 If_diverter required, does it meet regulations - - - - - - - - - - - - - - - - - - - - - - - - Yes - --------------- -------------- Appr Date 28 Drilling fluid- program ram schematicui _& a list -adequate- - - - - - - - - - - 9 9 equip - - - - - - - - - - - - - Yes - - - - - um - Maximexpected formation pressure -10:6 EMW._ {;ammed_mud_weight 1.0.6 ppg or as needed. - - - - - - - - - - TEM 11/5/2007 29 gOPEs,_dothey meet regulation - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - - - - - Yes- - - - - - - - - - - ---- �A ry�� 30 _B_O_PE_press rating appropriate; test to_(put psig in comments)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Y_es _ ------ ----- _ _ _ _ - MASP 2450_psi w/30% mud, 70%°gas. -3500 psi gas_only. 3000_psi_appropriat - _ _ _ _ _ _ _ _ _ _ _ _ _ _ 31 Choke manifold complies w/API_ RP -53 (May 84)_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes _ - - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ -------------------------------- 132 Work will occur without operation shutdown_ - - - - - - - - - - - - - - - - Yes - - - - - - - �'33 is presence of H2S gas probable_ - - - - - - - - - - - - - - - - - - - - - - - NA _ - _ - - H2S has not been reported in dry gas production._ 34 Mechanical -condition of wells within AOR verified (For service well only) , _ _ _ _ NA_ --- - -- - - - - -- Geology 35 Permit- can be issued w/o hydrogen sulfide measures - - - - - - - - - - - - - - - - - - - - - - - - -Y_es ---- — — 36 _Data- presented on potential overpressure zones_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ NA - - - - ACS Date 37 Seismic -analysis of shallow gas_zones_ - ---- - - NA_ ACS 10/29/2007 38 - Seabed condition survey_(if off_ -shore) - - „ _ _ _ _ - - - - --- NA_ ----------------------- -- - --- I 139 _C_o- - - name/phone for weekly -progress reports- [exploratory only] - - - - - - - - - Yes Willard Tank -7.13-296-3273 - - - - - - Geologic Engineering i Commissioner: Date: Commissioner: Date C mi ner Date ,PT,5 I, '41 1 W
