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Home My WebLink About205-091David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt and return one copy of this transmittal or FAX to 907 564-4424 Received By: Date: Hilcorp North Slope, LLC Date: 06/22/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL FTP Folder Contents: Log Print Files and LAS Data Files: Well API # PTD # Date Log Type Logging Company KBU 11-08Y 50133205520000 205091 1/28/2021 SET PLUG Yellowjacket KBU 23-7 50133205320000 203217 12/20/2020 JET CUT Yellowjacket KBU 23-7 50133205320000 203217 1/4/2021 PERF GAMMA RAY Yellowjacket KBU 41-6 50133205550000 205141 2/8/2021 SET PLUG Yellowjacket KBU 43-07Y 50133206250000 214019 1/22/2021 PERF GAMMA RAY Yellowjacket KBU 44-06 50133204980000 200179 2/22/2021 SET PLUG - JET CUT Yellowjacket KBU 42-07RD 50133204880100 208052 5/31/2020 PERF GAMMA RAY/GPT Yellowjacket KBU 42-07RD 50133204880100 208052 6/2/2020 PERF GAMMA RAY/GPT Yellowjacket KBU 42-07RD 50133204880100 208052 6/7/2020 PERF GAMMA RAY/GPT Yellowjacket KDU 09 50133205780000 208106 11/25/2020 JET CUT Yellowjacket KDU 09 50133205780000 208106 5/17/2021 PERF / GPT Yellowjacket KTU 13-05 50133203700000 184108 1/12/2021 SET PLUG Yellowjacket KTU 24-06H 50133204900000 199073 6/19/2020 PERF Yellowjacket KTU 24-06H 50133204900000 199073 6/20/2020 GPT Yellowjacket KU 44-08 50133206940000 220068 1/15/2021 SET PLUG Yellowjacket KU 44-08 50133206940000 220068 2/4/2021 PERF GAMMA RAY/GPT Yellowjacket KU 44-08 50133206940000 220068 4/6/2021 PERF GAMMA RAY / GPT Yellowjacket Please include current contact information if different from above. 06/28/2021 Received By: 37' (6HW By Abby Bell at 12:23 pm, Jun 28, 2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 05/04/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 11-08Y (PTD 205-091) CBL Cement Bond Log 02/08/2021 Please include current contact information if different from above. PTD: 2050910 E-Set: 35081 Received by the AOGCC 05/04/2021 05/04/2021 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, N2, Cement Pkr 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:4,120; 4,330; 4,603; 4,715; 5,050; 5,300; Total Depth measured 8,220 feet 5,487 & 5,710 feet true vertical 7,753 feet N/A feet Effective Depth measured 4,120 feet N/A feet true vertical 3,744 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)N/A N/A N/A N/A Packers and SSSV (type, measured and true vertical depth)N/A; N/A N/A; N/A 12. Stimulation or cement squeeze summary: 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 134' 1,485' 5,750psi 3,450psi Collapse 1,500psi 1,950psi 3,090psi 10,540psi Casing Structural 20" 13-3/8" 9-5/8" Length 113' 1,515' 5,791' 8,176' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 0 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. 321-034 0 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 205-091 50-133-20552-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 00 Kenai Beluga Unit (KBU) 11-08Y N/A FEDA 028142 5,812' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field - Sterling Gas Pool (s) 4, 3N/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 3-1/2'8,197' 5,346' 7,730' WINJ WAG 0 Water-Bbl MD 134' 1,536' 0 t Fra O O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 3:01 pm, Mar 10, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.03.10 14:47:41 -09'00' Taylor Wellman (2143) DSR-3/10/21 SFD 3/16/2021BJM 4/26/21 RBDMS HEW 3/10/2021 Rig Start Date End Date 1/28/21 3/1/21 01/30/2021 - Saturday PTW/JSA. Pump fresh water down tubing taking returns to the IA. After 80 bbls pumped swap pump lines. Reverse out drilling mudd. Pump down IA and return up production tubing. Circulate at 3.5 bbls/min for a total of 418 bbls pumped. Well is cleaned up ready for cement job. 01/29/2021 - Friday PSM/PTW. Rig up hot oil truck Pump down tubing taking returns up the IA. Pressure up to 3,500 psi. Pressure slowly bleeding down. Keep working pump and pressure to get drilling mudd moving. Flow rate slowly increasing each time. Circulating has increased, circulate 200 bbls. Shut down swap hoses. Attempt to reverse circulate. No luck. Drilling mudd plugging off at the tubing cut. Swap pump lines back the long way. Continue to circulate wellbore pumping down tubing and returns up the IA. 408 total bbls pumped. Manifest fluids for G&I. Freeze protect well and truck. SDFN. 01/28/2021 - Thursday PTW, JSA. Production plow snow from around wellhead. MIRU Yellow jacket E-line. Make up 3.5" (2.75" OD) CIBP. Stab on well. PT stack 250/3,500 psi. RIH and correlate depth to AK E-line CBL. Set CIBP at 4,603', CCL depth 4,588.5'. POOH tag up at surface. Pop off well and break down setting tool. Make up 2.75" dump bailer x 40' . Mix up cement. RIH with run 1 of 2 and dump cement on top of CIBP at 4,603'. POOH to surface. Mix up cement and load in dump bailer. RIH with run 2 of 2 and dump cement on CIBP at 4603'. 35' of cement placed above CIBP. TOC is 4,568'. POOH to surface. Break down bailer. Make up Jet cutter. RIH fluid level found around 800' from surface. Rig up Hot oil truck to E-line pump in sub. Calculated 8 bbls to fluid pack well. Online at 2 bbls/min with lease water for 6 bbls. Swap to 60/40 methanol water mix. Continue to pump 3 bbls to pressure up to 2,500 psi. IA gauge on wellhead showing 0 psi. Attempt to confirm gate valve is open. Not able to access valve. Jet cut 3.5" tubing at 4,520' with 2,500 psi on tubing. Pressure on tubing dropping. No indication of pressure change on IA. POOH to surface. Close master and swab. 300 psi WHP SITP. Rig down hot oil truck and YJES. Wellsite secure. SDFN. 02/04/2021 - Thursday HES arrive on location. PTW/JSA. 3.5" tubing, IA, OA all showing 0 psi.,Spot in Halliburton cement equipment. Cruz Vac Tanker, and cruz dirty vac truck. RIg up HES 1502 iron to wellhead tubing adapter/pump in sub. Hold pre cement job safety meeting.,Online down 3.5" tubing taking returns up IA to return tank. Confirmed circulation with tubing cut at 4520' RKB. Perform rate checks. 2 bbl/min 550 psi, 3 bbls/min 900 psi, 4 bbls/min 1400 psi. Circulated 12 bbls of water ahead. Perform low PT 250 psi. High pt 3500 psi for 5 minutes. Good test.,Cement wet 13:32 hrs. Mix and pump 590 SKS@15.3 PPG, 1.234Y, 5.58 GPS @ 4 bbl/min 900 psi. 129 bbls pumped.,Shut down after 129 bbls pumped. Swap valves on high pressure manifold. Launch foam ball. Follow foam ball with 39.8 bbls of displacement pumped at 4.5 bbls/min. Displacement pumped. Shut in swab and upper master valve. Confirmed wing valve closed. Post cement job SITP 750 psi. IA 0 psi, OA 0 psi.,Wash up HES pump truck. Manifest return fluids to G&I facility. Rig down HES equipment and depart 16:00,RIg down HAK 1502 iron from IA valve to rain for rent tank. Remove pump in sub and install night cap on 3.5" wellhead adapter. Wellsite secure. Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 11-08Y 50-133-20552-00-00 205-091 Jet cut 3.5" tubing at 4,520' Mix and pump 590 SKS@15.3 PPG, 1.234Y, 5.58 GPS @ 4 bbl/min 900 psi. Set CIBP at 4,603', Continue to pump 3 bbls to pressure up to 2,500 psi. TOC is 4,568' 129 bbls pumped., Launch foam ball. Follow foam ball with 39.8 bbls of displacement pumped at 4.5 bbls/min. Displacement pumped. S Rig Start Date End Date 1/28/21 3/1/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 11-08Y 50-133-20552-00-00 205-091 Sign in. Mobe to location.Pressure up well with gas to 822 psi and pressure broke over. Rig up lubricator PT to 250 low and 3,000 psi high. Pressure up well with field gas. RIH w/ 2.75" OD CIBP and tie into Plug correlation log. Send correlation log to town. Get ok to set top of plug at 4,330'. Spot and set plug with 706 psi. Lost 150 lbs line tension when plug set. Waited 5 min and pick up 30' then back down and tag plug. POOH. Good set.Had to put 35' of cement on top of plug. Went to shop and pick up cement & tools. RIH w/2.5"x30' Cement Dump Bailer with 17 ppg of cement in it (18') and tag plug at 4,330'. Pick up 17' and dump 18' of cement on top of plug. Lost 175 lbs of line wt. when cement was dumped. POOH. Good dump. Dumped at 1435 hrs. RIH w/2.5"x30' Cement Dump Bailer #2 with 17 ppg of cement in it (18')and stop at 4,312'. Dump 18' of cement on top of first dump. Lost 155 lbs of line wt. when cement was dumped. POOH. Good dump. Dumped at1700 hrs. Est TOC 4,294'.CIP at 1700 hrs. RIH w/ 2-3/8" x 10' HC, 5 spf, 60 deg phase and tie into Perf log. Run correlation log and send to town. Get ok to perf from town to perf from 4,181' to 4,191' with 500 psi. Spot and fire gun. After 5 min -492 psi, 10 min- 481 psi and after 15 min 470 psi. POOH. Fired gun at 1915 hrs. All shots fired/gun was dry. Rig down off of well for the night. Turn well over to field. Will be back in am. 02/12/2021- Friday Sign in. mobe to location. PTW, spot equipment and rig up lubricator. PT to 250 psi low and 3000 psi high. RIH w/ 2-1/2" x 10' Spiral Strip, 4 spf, 45 deg and tie into GPT log dated 12-2-20. Sent correlation log to town. At 4,410' had some weird Gama Ray. Re-ran correlation log and send to town. Town said it was better and on depth. We bled well to 511 psi before running log. Spotted and fired gun from 4,373' to 4,383'. After 5 min - 514 psi, 10 min - 520 psi and 15 min - 523 psi. POOH and found out we had lost our tools. When we. fired guns, we lost 230 lb of line tension. We were about 130 lbs light coming out of hole. We have slickline coming to fish tools. Wait on Pollard Slickline. (1-1/2 hr) ARRIVE ON LOCATION JSA PERMIT. WO Pollard SL (1-1/2 hrs). ARRIVE ON LOCATION JSA PERMIT. Rig up lubricator, PT to 250 psi low and 3,000 psi high. RIH W/ 1-7/16'' OVER SHOT BAITED W/ 3-1/2'' GR TAG FLUID 775'KB CONT. TO 4,414'KB SIT W/T LATCH FISH 1 JAR LICK 400# OVER-HOLDING WENT DOWN TO RE SET JARS TOOLS FALLING TO 4,475'KB PULL UP TOOLS FREE 130# OVER P/U WEIGHT POOH W/ FISH. Rig down lubricator and all of E-Line fish that was in hole. Will shoot a fluid level to deteremine next step. Be back at 0700 hrs in the am. 02/13/2021 - Saturday RU AK E-Line (Joe Dalebout). Log CBL from TD to Surface post IA cement job. PBTD 4,510'. RDMO. 02/09/2021 - Tuesday Est TOC 4,294' Rig down lubricator and all of E-Line fish that found out we had lost our tools. Spot and fire gun. fired gun from 4,373' to 4,383' RIH w/ 2.75" OD CIBP p 30' then back down and tag plug. P Log CBL from TD to Surface post IA cement job. Had to put 35' of cement on top of plug. W p of plug at 4,330'. Spot and set p o perf from 4,181' to 4,191' Rig Start Date End Date 1/28/21 3/1/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 11-08Y 50-133-20552-00-00 205-091 02/28/2021 - Sunday RU Pollard SL. RIH W/ 2.5” X 9' DD BAILER TO 3,953'KB W/T TO 3,963'KB POOH FULL SOUPY MUD. Bail soupy mud to 4,036' KB. SDFN. 03/01/2021 -Monday RU Slickline. RIH w 2.5" pump bailer to 3,996'. Bail mud to 4,026'. RDMO. 02/14/2021 - Sunday Sign in. PTW and JSA. Rig up lubricator PT to 250 psi low and 3,000 psi high. Push fluid into perfs. RIH w/2.75" OD CIBP and tie into perf log. Run correlation log and send to town. Get ok to set at 4,120' with 458.6 psi. Spot and set plug. Lost 115 lbs of line tension when plug set. Wait 5 min and pickup 30' and go back down and tag plug. POOH. Setting tool look good. Good set. RIH w/ 2-1/2" x 10' Spiral strip Gun, 4 spf, 45 deg and tie into perf log. Run correlation log and send to town. Got ok to perforate from 4,019' to 4,029' with 450 psi. Spotted and fired gun. After 5min - 312 psi, 10 min - 254 psi and 15 min - 229 psi. Lost 150 lbs of line tension when gun fired and blew gun up about 15' where wire kinked, All shots fired/gun dry. Rig down equipment, secure well and turn over to field. ok to set at 4,120' t ok to perforate from 4,019' to 4,029' with 450 psi. Spotted and fired gun. RIH w/2.75" OD CIBP Excape control lines bled down and observed for pressure build-up after perforating. No sign of pressure build-up 3/19/21. go back down and tag plug. Spot and set plug. Lease: State:Alaska Country:USA 3/3/2021 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL ~ 3º / 100' @ 450' Revised by:Jake Flora Last Revison Date: Completion Fluid: Well Name & Number: County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls 15.8 ppg) IA cement job pumped 2/5/21 (129 bbls 15.3ppg) Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 -6,118' Module 8 -6,296' Module 7 -6,552' Module 6 -6,663' Module 5 -7,038' Module 4 -7,591' Module 3 -7,742' Module 2 -8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 4,120' MD 3,744' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A - 028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 PA #: Perforation Detail Sands Top (MD) Btm (MD) Gun Sz SPF Status Date A8 4019' - 4029' 2-1/2" 4 Open 02-14-21 A11 4181' - 4191' 2-1/2" 4 Isolated 02-14-21 B2A 4373' - 4383' 2-1/2" 4 Isolated 02-13-21 B5A 4,618' 4,623' 2-3/8" 6 Isolated 10-17-20 B5A 4,693' 4,698' 2-3/8" 6 Isolated 01-29-21 B5A 4,700' 4,710' 2-1/8" 6 Isolated 01-29-21 UB-1X 5,205' 5,215' 2-3/8" 4 Isolated 08-26-17 UB-2 5,319' 5,337' 2-3/8" 5 Isolated 06-12-17UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15UB-5B 5,578' 5,590' 2-3/8" 5 Isolated 01-28-16 SCHEMATIC CIBP 4715' (12-02-20) CIBP 5087' w 37' cmt top (10-17-20) CIBP 5300' (8-26-17) CIBP 5487' (6-08-17) Bridge Plug 5710' Tree cxn = 4-3/4" Otis 3-1/2 x 9-5/8 TOC @ 2396' (2-8-21 CBL) 9-5/8" x OH TOC @ 3760' (temp log) Owen Permanent Patch ID 2.375" 4616' - 4627' 12-03-20 Top of mud fill @ 4026' (3/1/21 slickline) CIBP @ 4120' (2-14-21) CIBP @ 4330' w 35' cmt (2-13-21) Jet cut tbg @ 4520' CIBP 4603' w 35' cmt (12-02-20) A8 4019' -4029' 2-1/2" 4 Open 02-14-21 A11 4181' - 4191' 2-1/2" 4 Isolated 02-14-21 B2A 4373' - 4383' 2-1/2" 4 Isolated 02-13-21 () () A8 4019' 4029'21/2" 4 O 02 14 21 MITIA passed Notes:MIT tubing and IA to 1500. Tubing 10 minutes IA for 30 minutes. Customer:Hilcorp Customer Contact:Cole Bartlewski LSD: Job #: Date: Fluid Pumped: KBU 11-08Y 50/50 methanol 2021-02-09 10:41 Ticket #: Phone #: Operator: MIT tubing and IA 1500 psi COLE BARTLEWSKI 907-690-2854 Total Fluid Pumped:142.8 USG Date Comment Feb 9, 2021 - 09:34:23 AM P2 DIS PRESS: 1635 PSI, Pressure test tubing to 1500 psi. Start PT at 0934 hrs 1635 psi Feb 9, 2021 - 09:46:59 AM P2 DIS PRESS: 1620 PSI, Finished tubing MIT End pressure 1620 psi. Feb 9, 2021 - 09:59:00 AM P2 DIS PRESS: 1613 PSI, Start MIT on IA 1500 psi for 30 minutes Feb 9, 2021 - 10:34:54 AM P2 DIS PRESS: 1542 PSI, IA MIT finished. ending pressure 1542 psi. 34 minute test. Final Readings (2021-02-09 10:39): B1 TOTAL: 0 USG PUMP TOTAL: 142.8 USG Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE : 03/05/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 11-08Y (PTD 205-091) Plug & PERFORATING RECORD 02/14/2021 Please include current contact information if different from above. PTD: 2050910 E-Set: 34747 Received by the AOGCC 03/08/2021 03/09/2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 02/01/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 11-08Y (PTD 205-091) CBL Cement Bond Log 01/14/2021 Please include current contact information if different from above. PTD: 2050910 E-Set: 34638 Received by the AOGCC 02/02/2021 Abby Bell 02/02/2021 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 Cement IA, 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? 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: 5087', 4715' Junk (MD): 8,220'N/A Casing Collapse Structural Conductor 1,500psi Surface 2,260psi Intermediate 3,090psi Production 10,540psi 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 jake.flora@hilcorp.com 7,753'5,700'5,234'1392 psi 5710', 5487', 5300', N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 028142 205-091 50-133-20552-00-00 Kenai Beluga Unit (KBU) 11-08Y Kenai Gas Field - Sterling Gas Pool(s) 4, 3 Length Size C.O. 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY NA TVD Burst NA 10,160psi MD 5,750psi 3,060psi 5,020psi 134' 1,485' 5,346' 134' 1,536' 7,730'3-1/2" 20" 13-3/8" 113' 9-5/8"5,791' 1,515' 8,197' Perforation Depth MD (ft): 5,812' See Attached Schematic 8,176' 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: January 30, 2021 NA Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. S By Samantha Carlisle at 9:17 am, Jan 19, 2021 321-034 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.19 08:36:05 -09'00' Taylor Wellman 10-404 * CBL and MIT-IA to 1500 psi cement packer X DLB 01/19/2021 DSR-1/19/21gls 1/21/21 Comm. 1/22/21 dts 1/22/2021 JLC 1/22/2021 RBDMS HEW 1/27/2020 Well Prognosis Well: KBU 11-08Y Date: 01-15-2021 Well Name:KBU 11-08Y API Number:50-133-20552-00 Current Status:Shut in Gas well Leg:N/A Estimated Start Date:1/30/21 Rig:E-line Reg. Approval Req’d?Yes Date Reg. Approval Rec’vd: Regulatory Contact:Donna Ambruz 777-8305 Permit to Drill Number:205-091 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: 1789 psi @ 3976’ TVD (Based on 0.45 gradient) Max. Potential Surface Pressure:1392 psi (Based on expected BHP minus gas gradient to surface (0.10psi/ft) Well Status SI Gas Producer. Brief Well Summary KBU 11-08Y drilled and completed in 2005 targeting the Beluga formation and completed as an Excape completion. The well came online 1.5 MMCFD with little to no water production. Stayed fairly flat on rate until it died in early 2009. Multiple attempts to get it back with no success. In late 2015, a program kicked off by isolating the modules and perforating several Beluga sands. The well did not perform very well, never making any more than about 350 mcfd. The well finally went offline in 2018 due to low inflow. In October 2020, the Sterling B4A was perfed, built pressure from 600 psi to 750 psi after 15 min. Guns came out wet and brought the well online and would not sustain flow. In December 2020, a patch was set over the B4 sand and the B5 was perforated and again came in wet. Fluid level determined to be at 1950’ MD. The well has cum’d just under 1.8 BCF and 3.9 Mbbls of water to date. Currently, KBU 11-08Y is shut-in. Notes Regarding Wellbore Condition x MITIA PASSED 1/13/21 x Max deviation of 30.2 degrees at 3576’ MD / 3273’ TVD. x 3-1/2” x 9-5/8” TOC: 1/14/21 CBL confirms TOC @ 4575’ x 9-5/8” annulus TOC: A temperature survey ran after cementing showed a good cement top at 3760’, and scattered cement from 3470’ to 3350’. E-Line Procedure (with pump truck) 1. MIRU e-line and pressure control equipment. PT lubricator to 3,000 psi High. 2. Set CIBP at 4615’, dump bail 35 ft cement on top of plug. 3. Pressure up tubing to 2000 psi. 4. Jet Cut 3.5” tubing at 4520’, look for communication with IA, attempt to circulate well. 5. If well will not circulate at 3000 psi tubing pressure discuss with OE, it may be necessary to cut again further up-hole to achieve circulation. If it will circulate RD E-line, continue circulating to clean up for IA cement job. IA Cementing Procedure 6. RU cement truck, PT lines. 7. Mix and pump 127 bbls 15.3# cement down tubing, with returns from IA. Planned TOC in IA is 2500ft. Currently, KBU 11-08Y is shut- TOC planned at 2500 ft . Well Prognosis Well: KBU 11-08Y Date: 01-15-2021 8. Displace 3.5” tubing to the jet cut depth (~39.3 bbls) 9. SI master valve, hold pressure. Discuss freeze protecting with Operator. WOC 3 days. Slickline / E-Line Procedure / CTU Contingency 10. MIRU Slick-Line, PT Lubricator. Log memory CBL from TD to surface. Send log to AOGCC. Coil Tubing Milling Contingency (if cement is left too high in 3.5” tubing) I. MIRU CTU, 24hr notice for BOP test II. Conduct BOP test 250psi low, 3000psi high III. RIH w milling BHA, mill out cement to ~10’ above jet cut depth IV. Blow down well with nitrogen, trap pressure for perforating, RDMO CTU. 11. Swab well down. 12. Pressure up well with well gas or Nitrogen. 13. RU E-Line, PT Lubricator. Perforate below zones from the bottom up: a. Discuss wellhead pressure with OE. If necessary RU Nitrogen to pressure well prior to perforating. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Trudi Hallett 907.301.6657 Geologist Ben Siks 907.229.0865 d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. e. Pool 4 sands will need to be isolated with a CIBP and 35ft cement prior to perforating Pool 3 sands. 14. POOH. 15. RD E-Line. Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom PA Pool CO Plan to shoot Order to Shoot Estimated Reservoir Pressure P3_A8 ±4,019' ±4,036' 17' ±3,656' ±3,673' Sterling KENAI, STERLING 3 GAS CO 510A Top 10' 5 800 PSI P3_A10 ±4,072' ±4,085' 13' ±3,702' ±3,715' Sterling KENAI, STERLING 3 GAS CO 510A Top 10' 4 315 PSI P3_A11 ±4,181' ±4,221' 40' ±3,797' ±3,837' Sterling KENAI, STERLING 3 GAS CO 510A Top 10' 3 415 PSI P4_B1A ±4,259' ±4,306' 47' ±3,865' ±3,912' Sterling KENAI, STERLING 4 GAS CO 510A Top 20' 2 265 PSI P4_B2A ±4,369' ±4,383' 14' ±3,962' ±3,976' Sterling KENAI, STERLING 4 GAS CO 510A All 1 600 PSI Note: after perforating verify that Escape control lines are not compromised.(Pressure test lines to 1500psi ... if leaking contact AOGCC. 10a. Perform MIT-IA to 1500 psi /min (review Nitrogen SOP with all crews before commencing displacement) 4520 x .0087 bpf= 39 bbls KENAI , P3_A8 ±4,019'±4,036'17'±3,656'±3,673'Sterling CO 510A Top 10'5 800 PSISTERLING 3 GAS KENAI , P3_A10 ±4,072'±4,085'13'±3,702'±3,715'Sterling CO 510A Top 10'4 315 PSISTERLING 3 GAS KENAI , P3_A11 ±4,181'±4,221'40'±3,797'±3,837'Sterling CO 510A Top 10'3 415 PSISTERLING 3 GAS KENAI , P4_B1A ±4,259'±4,306'47'±3,865'±3,912'Sterling CO 510A Top 20'2 265 PSISTERLING 4 GAS KENAI , P4_B2A ±4,369'±4,383'14'±3,962'±3,976'Sterling CO 510A All 1 600 PSTERLING 4 GAS 53 CBL post cementing Well Prognosis Well: KBU 11-08Y Date: 01-15-2021 16. Turn well over to production.(Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Nitrogen (Contingency) 1. If Nitrogen is required to pressure up well prior to perforating: 2. MIRU Nitrogen Unit, review Nitrogen SOP, pressure well to desired perforating pressure. E-line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 3. RIH and set 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: Current Well Schematic Proposed Well Schematic Standard Well Procedure – N2 Operations CTU BOP Schematic Lease: State:Alaska Country:USA Last Revison Date: Completion Fluid: Well Name & Number: County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º 12/22/2020 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL ~ 3º / 100' @ 450' Revised by:Donna Ambruz Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485'Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppgfollowed by Tail of 248 sks of class G, 13.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 ppg Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated Excape System Details: - Ceramic flapper valves below each module as follows: - 8 Conventional flappers - No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 4,715' MD 4,281' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A - 028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: UB-5B Perforation Detail Sands Top (MD) Btm (MD) Gun Sz SPF Status Date B5A 4,618' 4,623' 2-3/8" 6 Isolated 10-17-20 B5A 4,693' 4,698' 2-3/8" 6 Open 12-03-20 B5A 4,700' 4,710' 2-1/8" 6 Open 12-04-20 UB-1X 5,205' 5,215' 2-3/8" 4 Isolated 08-26-17 UB-2 5,319' 5,337' 2-3/8" 5 Isolated 06-12-17UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15UB-5B 5,578' 5,590' 2-3/8" 5 Isolated 01-28-16 SCHEMATIC UB-5A UB-5 UB-1X UB-2 CIBP 4715' (12-02-20) TOC @ 5050'CIBP 5087' (10-17-20) CIBP 5300' (8-26-17) CIBP 5487' (6-08-17) Bridge Plug 5710' Tree cxn = 4-3/4" Otis B4A B5A 9-5/8" x OH TOC 3760' (temp log) 3-1/2" x 9-5/8" TOC 4574' (CBL) Owen Permanent Patch ID 2.375" over B4A perfs 4616' - 4627' 12-03-20 1536' MD passed MIT-IA Sterling Perforations Lease: State:Alask a Country:USA Last Revison Date: Completion Fluid: Well Name & Number: County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º 1/8/2021 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL ~ 3º / 100' @ 450' Revised by:T.Hallett Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134'TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppgfollowed by Tail of 248 sks of class G,,, 13.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 ppg Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 4,715' MD 4,281' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A -028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 PA #: Perforation Detail Sands Top (MD) Btm (MD) Gun Sz SPF Status Date New Sterling Sands ±4,019' -±4,383' Proposed TBD B5A 4,618' 4,623' 2-3/8" 6 Isolated 10-17-20 B5A 4,693' 4,698' 2-3/8" 6 Open 12-03-20 B5A 4,700' 4,710' 2-1/8" 6 Open 12-04-20 UB-1X 5,205' 5,215' 2-3/8" 4 Isolated 08-26-17 UB-2 5,319' 5,337' 2-3/8" 5 Isolated 06-12-17UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16,,,, UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15 PROPOSED 1/15/21 CIBP 4715' (12-02-20) TOC @ 5050'CIBP 5087' (10-17-20)@@ CIBP 5300' (8-26-17) CIBP 5487' (6-08-17) Bridge Plug 5710' Tree cxn = 4-3/4" Otis 9-5/8" x OH TOC 3760' (temp log) 3-1/2" x 9-5/8" TOC ±4575' 1/14/21 CBL Owen Permanent Patch ID 2.375" over B4A perfs 4616' -4627' 12-03-20 1. Dump Bail 35' CMT under patch 2. Set CIBP above patch @ 4600' 3. Jet Cut tbg @ 4520', circ IA 4. Cement IA 4019-4383' approx 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. 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hͲϱ 3HUIRUDWLRQ'HWDLO 6DQGV7RS0'%WP0'*XQ6]63)6WDWXV'DWH %$ ,VRODWHG %$ 2SHQ %$ 2SHQ 8%; ,VRODWHG 8% ,VRODWHG8% ,VRODWHG 8%$ ,VRODWHG8%% ,VRODWHG ^,Dd/ hͲϱ hͲϱ hͲϭy hͲϮ /WϰϳϭϱΖ;ϭϮͲϬϮͲϮϬͿ dKΛϱϬϱϬΖ/WϱϬϴϳΖ;ϭϬͲϭϳͲϮϬͿ /WϱϯϬϬΖ;ϴͲϮϲͲϭϳͿ /WϱϰϴϳΖ;ϲͲϬϴͲϭϳͿ ƌŝĚŐĞWůƵŐϱϳϭϬΖ 7UHHF[Q 2WLV ϰ ϱ ϵͲϱͬϴΗǆK,dKϯϳϲϬΖ;ƚĞŵƉůŽŐͿ ϯͲϭͬϮΗǆϵͲϱͬϴΗdKϰϱϳϰΖ;>Ϳ KǁĞŶWĞƌŵĂŶĞŶƚWĂƚĐŚ/Ϯ͘ϯϳϱΗŽǀĞƌ ϰƉĞƌĨƐ ϰϲϭϲΖͲ ϰϲϮϳΖϭϮͲϬϯͲϮϬ ϱ /WϰϳϭϱΖ;ϭϮͲϬϮͲϮϬͿ (New perfs) KǁĞŶWĞƌŵĂŶĞŶƚWĂƚĐŚ/Ϯ͘ϯϳϱΗŽǀĞƌ ϰƉĞƌĨƐ ϰϲϭϲΖͲϰϲϮϳΖϭϮͲϬϯͲϮϬ %$ %$ ,VRODWH 2SHQ %$ %$ 8% 2SHQ 2SHQ OW 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? 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): 5,300; Junk (MD): 8,220'N/A Casing Collapse Structural Conductor 1,500psi Surface 2,260psi Intermediate 3,090psi Production 10,540psi 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 jake.flora@hilcorp.com 7,753'5,700'5,234'1274 psi 5,487 & 5,700 N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 028142 205-091 50-133-20552-00-00 Kenai Beluga Unit (KBU) 11-08Y Kenai Gas Field - Sterling 5.2 Gas Pool Length Size C.O. 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY NA TVD Burst NA 10,160psi MD 5,750psi 3,060psi 5,020psi 134' 1,485' 5,346' 134' 1,536' 7,730'3-1/2" 20" 13-3/8" 113' 9-5/8"5,791' 1,515' 8,197' Perforation Depth MD (ft): 5,812' See Attached Schematic 8,176' 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: December 10, 2020 NA Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 2:33 pm, Nov 23, 2020 320-497 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.23 11:04:08 -09'00' Taylor Wellman DLB11/23/2020 10-404 DSR-11/23/2020gls 11/24/20 Plug Perforations X Perforate New Pool Comm 11/24/2020 dts 11/24/2020 JLC 11/24/2020 RBDMS HEW 11/25/2020 Well Prognosis Well: KBU 11-08Y Date: 11-19-2020 Well Name: KBU 11-08Y API Number: 50-133-20552-00 Current Status: Shut in Gas well Leg: N/A Estimated Start Date: 12/10/2020 Rig: E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-091 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: 1700 psi @ 4,260’ TVD (Based on offset well BHP data) Max. Potential Surface Pressure: 1274 psi @ (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KBU 11-08Y is an “escape completion” well drilled by Marathon in 2005. Hilcorp perforated the Beluga UB-5A in 2015, the UB-5 and UB-5B in 2016, and the UB-1X in 2017. In October 2020 the Sterling B4A was perforated and did not flow. Well has been shut in since September 2018. The Sterling B5A sand has drawn more interest after recent successful testing across the field. The purpose of this sundry is to permanently abandon the isolated Beluga sands by dumping cement on the existing CIBP at 5155’, add perforations the Lower Sterling B5A sand, and isolate the B4A sand behind a permanent patch. The existing Sterling perfs are in the Sterling 5.1 pool with the proposed perfs lying in the Sterling 5.2 pool. The top of the permanent patch will be ~ 4615 ft which is 78 ft above the proposed B5A perforations. Future plugging of the B5A sand will require dump bailing cement thru the patch to the planned CIBP at 4715’. Notes Regarding Wellbore Condition x 3-1/2” (2.75” OD) CIBP set at 5300’ WLM on 8/26/2017. x Max deviation of 30.2 degrees at 3576’ MD / 3273’ TVD. x 3-1/2” x 9-5/8” TOC: CBL dated 9/9/2005 indicates a top of cement at 4574’ MD/4152’ TVD. x 9-5/8” annulus TOC: A temperature survey ran after cementing showed a good cement top at 3760’, and scattered cement from 3470’ to 3350’. E-Line Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 3,000 psi High. 2. Dump bail 25’ of cement on existing CIBP at 5155’. 3. Set CIBP at 4715’. (this will provide a bottom for future cement bailing to abandon B5A perfs) 4. Perforate the top 5’ of the Sterling B5A sand from 4693’ – 4698’. Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom P5_B5A ±4,693' ±4,720' 5’ (Top of 27’ sand) ±4,260' ±4,285' a) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. Perforate New Pool New perfs P5_B5A ±4,693' ±4,720' 5’ (Top of 27’ sand) ±4,260' ±4,285' Well Prognosis Well: KBU 11-08Y Date: 11-19-2020 b) Use Gamma/CCL to correlate. c) 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. d) The listed Sands are governed by Conservation Order 510a. 5. Set 10 ft permanent patch over B4A perfs with packers at 4615’ – 4625’. 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) Attachments: 1. Current Well Schematic 2. Proposed Well Schematic (ID = 2.375") Lease: State:Alask a Country:USA Jake Flora Completion Fluid: Well Name & Number: County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º Last Revison Date:10/22/2020 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL ~ 3º / 100' @ 450' Revised by: Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134'TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppgfollowed by Tail of 248 sks of class G,,, 13.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 ppg Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 5,700' MD 5,234' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A -028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: UB-5B Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status B4A 4,618' 4,623' 2-3/8" 6 Open UB-1X 5,205' 5,215' 2-3/8" 4 Isotated UB-2 5,319' 5,337' 2-3/8" 5 Isolated UB-5 5,531' 5,548' 2-,,,,3/8" 5 Isolated UB-5A 5,552' 5,565' 2-3/8" 5 Isolated UB-5B 5,578' 5,590' 2-3/8" 5 Isolated SCHEMATIC UB-5A UB-5 UB-1X UB-2 Sterling B4A CIBP 5155' (10-17-20) CIBP 5300' (8-26-17) CIBP 5487' (6-08-17) Bridge Plug 5710' 9-5/8" x OH TOC 3760' (temp log) 3-1/2" x 9-5/8" TOC 4574' (CBL) Tree cxn = 4-3/4" Otis Lease: State:Alask a Country:USA Last Revison Date: Completion Fluid: Well Name & Number: County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º 11/23/2020 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL ~ 3º / 100' @ 450' Revised by:Jake Flora Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134'TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppgfollowed by Tail of 248 sks of class G,,, 13.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 ppg Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 5,700' MD 5,234' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A -028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: UB-5B Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status B5A 4693' 4698' 2-3/8" 6 planned B4A 4,618' 4,623' 2-3/8" 6 Open UB-1X 5,205' 5,215' 2-3/8" 4 Isotated UB-2 5,319' 5,337' 2-3/8" 5 Isolated UB-5 5,531' 5,548' 2-,,,,3/8" 5 Isolated UB-5A 5,552' 5,565' 2-3/8" 5 Isolated UB-5B 5,578' 5,590' 2-3/8" 5 Isolated Proposed WBD 11-23-20 UB-5A UB-5 UB-1X UB-2 Sterling B4A B5A 4693' -4698' CIBP 4715' CIBP 5155' (10-17-20) CIBP 5300' (8-26-17) CIBP 5487' (6-08-17) Bridge Plug 5710' Patch B4A perfs Tree cxn = 4-3/4" Otis 9-5/8" x OH TOC 3760' (temp log) 3-1/2" x 9-5/8" TOC 4574' (CBL) (ID of patch =2.375") 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: 5,155; Total Depth measured 8,220 feet 5,300 & 5,700 feet true vertical 7,753 feet N/A feet Effective Depth measured 5,710 feet N/A feet true vertical 5,244 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 8,197' MD 7,730' TVD Packers and SSSV (type, measured and true vertical depth)N/A; N/A N/A; N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Ted Kramer Authorized Title:Operations Manager Contact Email: Contact Phone:777-8420 WINJ WAG 0 Water-Bbl MD 134' 1,536' 0 Oil-Bbl measured true vertical Packer 3-1/2'8,197' 5,346' 7,730' measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field - Sterling 5.1 Gas PoolN/A measured TVD Tubing Pressure 500 Kenai Beluga Unit (KBU) 11-08Y N/A FEDA 028142 5,812' Plugs Junk STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 205-091 50-133-20552-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 320-399 0 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 0 Authorized Signature with date: Authorized Name: 100 Casing Pressure Liner 0 0 Representative Daily Average Production or Injection Data 113' 1,515' 5,791' 8,176' Conductor Surface Intermediate Production 10,540psi Casing Structural 20" 13-3/8" 9-5/8" Length 5,750psi 3,450psi Collapse 1,500psi 1,950psi 3,090psi tkramer@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 3,060psi 10,160psi 134' 1,485' 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 3:28 pm, Nov 09, 2020 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.11.09 15:21:36 -09'00' Taylor Wellman gls 12/10/20 RBDMS HEW 11/9/2020 DSR-11/10/2020 Perforate New Pool SFD 11/6/2020 Plug Perforations Rig Start Date End Date E-Line 10/17/20 10/17/20 10/17/2020 - Saturday Sign in, Mobe to location. PTW and JSA. Spot equipment and rig uplubricator. PT to 250 psi low and 2,500 psi high. TP - 1,000 psi (pressured up overnight from another well. RIH w/GPT and tied into HLB GPT log. Tagged obstruction at 5,318' KB. Run correlation log and send to town. Told to add 21' and set plug at 5,155'. Set plug at 5,155', pick up 20' and go back and tag plug. POOH. Setting tool look ok. Looks like good set. RIH w/ 2-3/8" x 5' HC Razor, 6 spf, 60 deg phase and tie into GPT tool. Run strip and send to town. Told to subtract 35' and re-send. Subtract 35' and send log to town. Log was ok. Spotted and fired perf gun from 4 618' to to 4 623' with 600 psi on tubing. After 5 min - 650 psi, 10 min - 700 psi and 10 min - 750 psi. POOH all shots fired/gun was wet. Rig down equipment and turn well over to field. Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 11-08Y 50-133-20552-00 205-091 Lease: State:Alaska Country:USA 10/22/2020 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL ~ 3º / 100' @ 450' County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º Revised by:Donna Ambruz Last Revison Date: Completion Fluid: Well Name & Number: Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485'Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppgfollowed by Tail of 248 sks of class G, 13.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 ppg Tree cxn = 4-3/4" Otis Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated Top of Cement Bond Log @ 4,574' MD Excape System Details: - Ceramic flapper valves below each module as follows: - 8 Conventional flappers - No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 5,700' MD 5,234' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A - 028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: UB-5B Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date B4A 4,618' 4,623' 2-3/8" 6 Open 10-17-20 UB-1X 5,205' 5,215' 2-3/8" 4 Isotated 08-26-17 UB-2 5,319' 5,337' 2-3/8" 5 Isolated 06-12-17UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15 UB-5B 5,578' 5,590' 2-3/8" 5 Isolated 01-28-16 Bridge Plug with 10 ft. of cement @ 5,710' SCHEMATIC UB-5A UB-5 UB-1X CIBP @ 5,155' 10-17-20 Plug @ 5,487' 06-08-17 UB-2 Sterling B4A CIBP @ 5,300' 08-26-17 B4A 4,618' 4,623' 2-3/8" 6 Open 10-17-20 B4A Sterling CIBP @ 5,155' 10-17-20BBCIBCIB 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: Run new completion 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): 5,300; Junk (MD): 8,200'N/A Casing Collapse Structural Conductor 1,500psi Surface 2,260psi Intermediate 3,090psi Production 10,540psi 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: Mike Quick 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 mquick@hilcorp.com 7,753'5,700'5,234'500 psi 5,487 & 5,700 N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 028142 205-091 50-133-20552-00-00 Kenai Beluga Unit (KBU) 11-08Y Kenai Gas Field - Sterling 3 and Sterling 4 Gas Pool Length Size C.O. 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 9.3# / L-80 TVD Burst 8,197' 10,160psi MD 5,750psi 3,060psi 5,020psi 134' 1,485' 5,346' 134' 1,536' 7,730'3-1/2" 20" 13-3/8" 113' 9-5/8"5,791' 1,515' 8,197' Perforation Depth MD (ft): 5,812' See Attached Schematic 8,176' 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: Oct. 12, 2020 3-1/2" Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 8:57 am, Sep 30, 2020 320-408 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.25 21:51:52 -08'00' Taylor Wellman *CBL over 9 5/8" casing required. GAS gls 10/8/20 10-404 Pulll Tubing 401 SFD 9/30/2020 SFD 9/30/2020 Run new completion Perforate New Pool * 2500 psi BOPE test (2000 psi annular test ) DSR-10/1/2020 X 8,220 Plug Perforations q Yes C 10/8/2020 dts 10/08/2020 JLC 10/8/2020 RBDMS HEW 11/2/2020 Well Prognosis Well: KBU 11-08Y Date: 9-24-2020 Well Name: KBU 11-08Y API Number: 50-133-20552-00 Current Status: Shut in Gas well Leg: N/A Estimated Start Date: 10/12/2020 Rig: 401 / N2 / E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-091 First Call Engineer: Michael Quick (907) 777-8442 (O) (907) 317-2969 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: 500 psi @ 3,905’ TVD (Based on offset well BHP data) Max. Potential Surface Pressure: 110 psi @ 3,905’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KBU 11-08Y is an “escape completion” well drilled by Marathon in 2005. Hilcorp perforated the Beluga UB-5A in 2015, the UB-5 and UB-5B in 2016, and the UB-1X in 2017. Well has been shut in since September 2018. The purpose of this sundry is to return this well to production by working the well over to be able to perforate the Sterling sand intervals. Work scope includes setting a 3-1/2” CIBP in the tubing above the UB-1X perforations, cutting and pulling the existing 3-1/2” tubing above the top of cement, running 3-1/2” tubing and a packer above the planned Sterling production intervals. This completion will allow perforating the listed Sterling sands, one at a time, to test productivity. Notes Regarding Wellbore Condition x Current shut in tubing pressure = 100 psi. x 3-1/2” (2.75” OD) CIBP set at 5300’ WLM on 8/26/2017. x Open perforations from 5205’ to 5215’. x Max deviation of 30.2 degrees at 3576’ MD / 3273’ TVD. x CBL dated 9/9/2005 indicates a top of cement in the 3-1/2” by 9-5/8” annulus at 4574’ MD/4152’ TVD, and free pipe likely above 4550’. x Due to losses during the primary cement job for the 9-5/8” casing, a temperature survey was ran after pumping the cement and showed a good cement top at 3760’, and scattered cement from 3470’ to 3350’. Neither Hilcorp nor the AOGCC have a copy of this temperature survey. x This escape well has two control lines running to surface that were used to activate the escape module system. Control lines were 0.25” 316L stainless steel lines with 0.049” wall thickness. x All escape wells ran a 0.5” OD braided cable along with the control lines, to act as a protective barrier providing standoff protection to the control lines. Marathon used any 3/8” to ½” braided cable with no technical specs, they utilized lower cost cable that was easily obtained, including used E-line cable a few times. x All escape wells used stainless bands to hold the control lines and braided cable, three bands per joint, one band at each connection and a band in the middle of each joint. x Each joint of tubing also used a slip on centralizer that was held in place with set screws. x This well is listed as using a utilized a special tubing connector that was 5.25” OD with machined slots in the OD to protect the control lines. Due to losses during the primary cement job for the 9-5/8” casing, a temperature survey was ran after pumping the cement and showed a good cement top at 3760’, and scattered cement from 3470’ to 3350’. Neither Hilcorp nor the AOGCC have a copy of this temperature survey. CBL dated 9/9/2005 indicates a top of cement in the 3-1/2” by 9-5/8” annulus at 4574’ MD/4152’ TVD, and free pipe likely above 4550’. this wellwork is pending results of sundry 320-399 (perf sundry for B4A zone) TOC @ 4574 ft TOC @ 3760 ft Well Prognosis Well: KBU 11-08Y Date: 9-24-2020 Example photo of banded control lines and ½” braided cable Well Objectives 1. Isolate the tubing below the top of cement in the 3-1/2” x 9-5/8” annulus (TOC 4574’ MD). 2. Perform a rig workover to cut and pull the 3-1/2” tubing above the top of cement in the 3-1/2” x 9-5/8” annulus (TOC 4574’ MD). a. It is imperative that the 3-1/2” tubing, two control lines, and ½” braided cable are severed before pulling the 3-1/2” tubing. 3. Run 3-1/2” tubing and packer, set packer above top Sterling zone of interest. a. This will allow the well to be produced starting at the bottom zone, and isolating any sand with an expandable plug and cement, as needed to move up hole. Pre-Sundry Work 1. Pressure test (MIT-IA) 3-1/2” x 9-5/8” annulus to 1500 psi for 30 minutes. (TOC at 4152’ TVD x 0.25 psi/ft = 1038 psi pressure test, 1500 psi is minimum test pressure). Chart test. Pre-Rig Work 1. MIRU E-line. Pressure test Lubricator to 3,000 psi. 2. Set 3-1/2” CIBP in tubing at 4674’, +/-100’ below TOC of 4574’ from CBL. 3. Load tubing with 8.4 ppg produced water. 4. Pressure test plug to 1500 psi for 30 minutes. 5. Pressure tubing to 525 psi. Tubing punch 3-1/2” tubing at 4362’, establish circulation/connection to annulus. a. Tubing punch with top shot 2 ft below coupling per CCL (Correlate to CBL dated 9-9-05). NOTE: Collar signature is wide due to collar and centralizer installed directly below collar on every joint. b. Annulus has 10.7 ppg mud, well will be 525 psi out of balance when punching tubing if tubing pressure is not applied to the 8.4 ppg fluid in the tubing. c. It may be necessary to pump both directions (down tubing or down annulus) to establish connectivity. d. Have flow back tank and pump available to allow well to balance out. It is imperative that the 3-1/2” tubing, two control lines, and ½” braided cable are severed before pulling the 3-1/2” tubing. May be perfs open from sundry 320-399 (B4A zone) Well Prognosis Well: KBU 11-08Y Date: 9-24-2020 e. Fill tubing and/or backside with 8.4 ppg produced water to balance out u-tube of well if needed. f. Stop here if circulation cannot be established. Consult with OE for plan forward options. i. Bottom planned perforation is at 4289’. There might be room to shorten the perforation interval, a final attempt at getting circulation could be made near 4289’. 6. RIH and Space out 2.5” OD jet cutter at 4362’ (or depth circulation was achieved), 2 ft below coupling per CCL (Correlate to CBL dated 9-9-05), and fire jet cutter. Attempt to confirm pipe cut / pipe separation with CCL by dropping back down across cut. POOH. a. Spacing out cutter as close to known banding location will increase the success of cutting the cable and control lines. b. Run eline spang jars. 7. Contingency: If CCL cannot confirm pipe cut in step 6, RIH with the CCL on the bottom of the tool string, log to confirm tubing is cut. 8. RIH, correlate CCL and Fire second jet cutter at same spot as first cut, to ensure control lines and braided cable are severed. POOH. a. The objective of the double cut is to ensure the pipe and control lines/braided cable are severed prior to attempting to pull the tubing. b. Run eline spang jars. 9. Run tubing caliper log (STOP log 100’ above tubing cut) to determine condition of tubing, determine if the tubing condition is good to re-run. POOH. 10. Rig down E-line. Secure well. Rig 401 1. MIRU workover rig 401. 2. Notify AOGCC 24 hours in advance for witness of BOP test. 3. Fill tubing and/or annulus with 8.4 ppg produced water to balance out u-tube of well if needed. Monitor well for static conditions. a. Well maybe out of balance, with 8.4 ppg produced fluid in tubing and 10.7 ppg drilling mud in annulus. i. The well was displaced to corrosion inhibited 10.7 ppg 6% KCL Flo-Pro drilling mud prior to cementing the escape completion in 2005. b. Verify reports to ensure there is a pressure tested plug in the tubing, isolating the open perforations. Plug was installed during pre-rig work above. 4. Set back pressure valve. 5. ND tree, confirm measurement down to top of tubing below pack off, for spear run in step 7. 6. NU 13-5/8” BOP stack and test to 250 psi low & 2,500 psi high, annular to 250 psi low & 2,000 psi high. Record accumulator pre-charge pressures and chart tests. a. Pull BPV, set TWC for testing. b. Perform BOP Testing. c. Test VBR rams on 3-1/2” and 2-7/8” test joints. d. Pull TWC. e. Submit completed form 10-424 to AOGCC within 5 days of BOPE test. 7. PU and RIH with Spear set with grapple for 2.992” tubing ID. RIH and spear tubing, pick up to release slips and pick up tubing adapter hanger/pack off with tubing. a. Ensure Spear is engaged in tubing (not packoff) with measurement from step 5. 2500 psi BOPE test Cut tubing and cables Well Prognosis Well: KBU 11-08Y Date: 9-24-2020 b. Packoff and tubing must be pulled together due to the control lines. c. YellowJacket has model 9412 3-1/2” tubing spears with grapple sizes from 2.990” to 3.001”. 8. Displace well to 8.4 ppg produced water brine. a. Wellbore volume 305 bbl: i. 3-1/2” tubing to 4362’ = 38 bbl ii. 3-1/2” x 9-5/8” annulus = 267 bbl 9. POOH with cut 3-1/2” tubing. Cut and remove control lines and cable each joint, along with the banding, and remove the centralizers that are held on with set screws. a. Determine, based on visual inspection and the tubing caliper log information, if the tubing is in satisfactory condition to reuse in this well. If tubing is good, plan to rack it back. 10. Pick up 2-7/8” workstring with flat/concave bottom 8.625” mill and 9-5/8” casing scraper and RIH to tubing cut depth at +/- 4360’ WLM. 11. Circulate wellbore clean. 12. POOH, L/D workstring. 13. MIRU E-line. Plan to run a line wiper (no pressure control equipment). 14. Run CBL log to determine TOC behind 9-5/8” casing. Log from 4,300’ to 1,500’ MD or top of cement. a. Stop point if TOC is not above 4000’ on the CBL. i. Remedial cement work could be required to move forward based on actual TOC. TOC must be above 4019’ MD. 15. RIH and set 9-5/8” CIBP ~10’ above tubing stub, set CIBP at +/-4,350’ MD. RD E-line. 16. Pressure test casing and CIBP to 1500 psi for 30 minutes. (AOGCC regulation 20 AAC 25.112 (g) (2). the minimum pressure of 1500 psi, based on the required 0.25 psi/ft multiplied by the true vertical depth pressure test requirement) 17. RIH with 3-1/2” tubing, packer and jewelry per the following: a. Gas lift mandrel at +/- 3820’ (full joint above packer), with dummy valve installed. b. Packer setting depth at +/- 3850’ (use full joints to space out) c. XN profile a full joint below packer at +/- 3880’. d. Plan space out to have WLEG at +/- 3910’, but no deeper than 3950’. e. 3-1/2” 9.3# L-80 EUE 8 round Mod tubing: i. API recommended torque: 18. Add corrosion inhibitor to 8.4 ppg fluid and displace tubing and annulus to corrosion inhibited fluid prior to setting packer. 19. Land tubing hanger. 20. Set packer per manufacturer’s recommendation. a. For a hydraulic set packer, drop ball and rod to set the packer with pressure. Note: Slickline will be needed to pull ball and rod after packer is set. b. The packer setting pressure will serve as the tubing pressure test. 21. Pressure test IA / MIT IA (3-1/2” tubing by 9-5/8” casing) to 1500 psi for 30 minutes. 22. N/D BOP stack. 23. Install TWC and N/U tree. Test tree to 5,000 psi. 24. Pull TWC. 25. RDMO Rig 401. Minimum Torque Optimum Torque Maximum Torque 2,270 ft-lb 3,030 ft-lb 3,790 ft-lb 9 5/8" CIBP @4350' (chart) 95/8"CBL Send CBL log to AGOCC for review by email. (pdf ) Remedial cement work could be required to move forward based on actual TOC. TOC must be above 4019’ MD. Well Prognosis Well: KBU 11-08Y Date: 9-24-2020 Slickline Procedure 1. MIRU Slickline. 2. RIH and pull ball and rod used to set packer from XN profile at +/-3880’. 3. Pull dummy valve from gas lift mandrel at +/-3820’. 4. Run 1” orifice valve and set in gas lift mandrel at +/-3820’. 5. RDMO Slickline. 6. Use field gas or nitrogen to lift well dry from gas lift mandrel at +/-3820’ prior to perforating. a. Fluid in well is 8.4 ppg produced water i. 3-1/2” tubing to 3820’ = 33 bbl ii. 3-1/2” x 9-5/8” annulus = 234 bbl Contingency: If gas lift will not lift the fluid to achieve dry tubing: b. MIRU Coil tubing unit. Pressure test BOP to 4,000 psi high, 250 psi low. c. RU Nitrogen. RIH W/ Coil and blow well dry with Nitrogen leaving 500 psi on well head. RDMO Nitrogen and CTU. Safety Concerns for N2 x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (if venting Nitrogen during this job). x Ensure all crews are aware of stop work authority. E-Line Procedure 1. MIRU e-line and pressure control equipment. PT lubricator to 3,000 psi High. 2. PU and RIH with perforation gun. Perforate each interval, one at a time, starting at the bottom interval, with 2-3/8” Perforating guns, 6 to 12 SPF, 60 degree phasing. 3. Proposed Perforation Intervals: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Reservoir Pressure P3_A8 ±4,019' ±4,036' 17' ±3,655' ±3,672' 250 psi P3_A10 ±4,072' ±4,085' 13' ±3,702' ±3,715' 250 psi P3_A11 ±4,163' ±4,206' 43' ±3,782' ±3,825' 500 psi P4_B1 ±4,237' ±4,289' 52' ±3,853' ±3,905' 500 psi a) Proposed perforations are also shown on the proposed schematic in red font. b) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. c) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d) Use Gamma/CCL to correlate. e) 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. f) The listed Sands are governed by Conservation Order 510a. Comingling of Sterling pool 3 and Sterling pool 4 is not allowed. An isolation Expandable plug with 25’ of cement will be set above the top Pool 4 sand (P4_B1) prior to perforating Pool 3 (P4_A11) sands. g) If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. -------------------- Conservation Order 510a. tion concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank pool 4 Comingling of Sterlinggy pool 3 and Sterling pool 4 is not allowed. Ensure all crews are aware of stop work authority. Discuss nitrogen asphyxiat pool 3 current weather forecast (if venting Nitrogen k placement based on wind direction and c NOTE---> Well Prognosis Well: KBU 11-08Y Date: 9-24-2020 4. If fluid is suspected in the well after perforating, run GPT tool to confirm fluid level. 5. Rig up Nitrogen and push fluid away to open perforations, set expandable plug and dump bail 10’ of cement above open perforations. a) NOTE: An expandable plug with 25’ of cement will be set above the top Pool 4 sand (P4_B1) prior to perforating Pool 3 (P4_A11 or higher) sands. Contingency: If nitrogen cannot push fluid away: b) MIRU Coil tubing unit. Pressure test BOP to 4,000 psi high, 250 psi low. c) RU Nitrogen. RIH W/ Coil and blow well dry with Nitrogen leaving 500 psi on well head. RDMO Nitrogen and CTU. 6. Shoot next perforation interval per step 3 above. a) Note that the well is pressurized with nitrogen. b) If necessary, bleed pressure down as requested by the OE to establish a drawdown on the formation. 7. POOH. 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 #1 3. Proposed Well Schematic #2 with Pool 3 and Pool 4 Isolation 4. BOP Diagram 5. Coil BOP Diagram 6. Current Wellhead Diagram 7. Standard Well Procedure – N2 Operations 8. RWO Sundry Revision Change Form Lease: State:Alaska Country:USA (TVD): 9/13/2017 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL 4,747' - 7,685' Well Name & Number: ~ 3º / 100' @ 450' Perforations (MD): County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º Revised by:Donna Ambruz Last Revison Date: Completion Fluid: 5,205' - 8,152' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppg followed by Tail of 248 sks of class G, 13.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 ppg Tree cxn = 4-3/4" Otis Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated Top of Cement Bond Log @ 4,574' MD Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 5,700' MD 5,234' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A -028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: UB-5B Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-1X 5,205' 5,215' 2-3/8" 4 Open 08-26-17 UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15 UB-5B 5,578' 5,590' 2-3/8" 5 Isolated 01-28-16 Bridge Plug with 10 ft. of cement @ 5,710' SCHEMATIC UB-5A UB-5 UB-1X CIBP @ 5,300' 08-26-17 95/8" 5205-15' 13 3/8" 10.7 ppg CBL over 95/8" cut tbg Lease: State:Alaska Country:USA (TVD): 9/23/2020 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL 4,747' - 7,685' Well Name & Number: ~ 3º / 100' @ 450' Perforations (MD): County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º Revised by:M. Quick Last Revison Date: Completion Fluid: 5,205' - 8,152' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppg followed by Tail of 248 sks of class G, 13.5 ppg Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Mod Top Bottom MD 0' 3,910' WLEG TVD 0' 3,595' 3-1/2" L-80 9.3 ppf EUE 8rd Mod Top Bottom MD 4362' 8,197' TVD 3980' 7,730' Tree cxn = 4-3/4" Otis Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Top of Cement 3-1/2" x 9-5/8" Bond Log @ 4,574' MD Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 5,700' MD 5,234' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A -028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date A8 +/-4019' +/-4036' A10 +/-4072' +/-4085' A11 +/-4163' +/-4206' B1 +/-4237' +/-4289' UB-1X 5,205' 5,215' 2-3/8" 4 Isolated UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15 Bridge Plug with 10 ft. of cement @ 5,710' PROPOSED SCHEMATIC #1 UB-5 UB-5A UB-5B UB-1X CIBP @ 5,300' 08-26-17 9-5/8" CIBP @ 4,350' Tubing cut @ 4,362' 3-1/2" CIBP @ 4,674' B1 9-5/8" TOC @ 3760'Packer @ 3850' GLM @ 3820' XN 8.4 ppg brine sterling sands Lease: State:Alaska Country:USA (TVD): 9/23/2020 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL 4,747' - 7,685' Well Name & Number: ~ 3º / 100' @ 450' Perforations (MD): County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º Revised by:M. Quick Last Revison Date: Completion Fluid: 5,205' - 8,152' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppg followed by Tail of 248 sks of class G, 13.5 ppg Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Mod Top Bottom MD 0' 3,910' WLEG TVD 0' 3,595' 3-1/2" L-80 9.3 ppf EUE 8rd Mod Top Bottom MD 4362' 8,197' TVD 3980' 7,730' Tree cxn = 4-3/4" Otis Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Top of Cement 3-1/2" x 9-5/8" Bond Log @ 4,574' MD Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 5,700' MD 5,234' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A -028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date A8 +/-4019' +/-4036' A10 +/-4072' +/-4085' A11 +/-4163' +/-4206' B1 +/-4237' +/-4289' UB-1X 5,205' 5,215' 2-3/8" 4 Isolated UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15 UB-5B 5,578' 5,590' 2-3/8" 5 Isolated 01-28-16 Bridge Plug with 10 ft. of cement @ 5,710' PROPOSED SCHEMATIC #2 Isolated Pool 3 & 4 UB-5 UB-5A UB-5B UB-1X CIBP @ 5,300' 08-26-17 9-5/8" CIBP @ 4,350' Tubing cut @ 4,362' 3-1/2" CIBP @ 4,674' 9-5/8" TOC @ 3760' Packer @ 3850' GLM @ 3820' A8 A10 A11 B1 XN The picture can't be displayed.The picture can't be displayed.The picture can't be displayed.The picture can't be displayed. 13-5/8"Spherical Annular Height: 46" Weight: 12,806 13-5/8"LWS Double BOP Height: 37" Width: 93" Weight 9,900 lbs. TOP RAMS 2-7/8" TO 5-1/2" MULTI- RAMS BOTTOM RAMS BLIND RAMS 13-5/8"Mud Cross W/ 4- 1/16" outlets Height:28.5" Width 31" Dual 4-1/16" Manual Gate valves W/ DSA to 2-1/16" 4-1/16" Manual Gate valve & 4-1/16" HCR W/ DSA to 2-1/16" Full Mud Cross Assy. width w/ valves installed Width: 98.5" Weight: 2200 lbs. Kill side Choke side Height Addition for Ring Gaskets: 0" BOP Total Height: 111.5" BOP Total weight: 24,906 lbs. 13-5/8" 5m BOP Package W/ 4-1/16" Valves Kenai Gas Field KBU 11-08Y Current 07/09/2015 Valve, Upper Master, VG 300, 3 1/16 10M FE, HWO, DD trim Valve, Swab, VG-300, 3 1/16 10M FE, HWO, DD trim Valve, Wing, VG-300, 3 1/16 10M FE, HWO, DD trimValve, VG-200, 3 1/8 5M FE, w/ Axelson MHA operator, EE trimDSA, 3 1/16 10M X 3 1/8 5MTree cap, Otis, 3 1/16 10M FE X 6 ½ Otis Quick Union 20'’ 13 3/8'’ 9.625'’ 3.5'’ Starting head, Vetco MB-196, 13 5/8 3M X 13 3/8 VG-Loc bottom, w/ 2- 2'’ LPO Multibowl, Vetco MB-196, 13 5/8 3M stdd bottom X 13 5/8 5M FE top, w/ 2- 2 1/16 5M SSO Adapter, Vetco, 13 5/8 5M stdd X 3 1/16 10M stdd top, prepped f/ 6 ½’’ extended neck Valve, VG-200, 2 1/16 5M FE, HWO, AA trim Valve, Master, VG-300, 3 1/16 10M FE, HWO, DD trim Kenai Gas Field KBU 11-08Y 20 X 13 3/8 X 9 5/8 X 3 ½ False hanger neck, Vetco Gray MB-196, 13 5/8 5M x 3'’ CIW Type H BPV profile, No Lift Threads Excape lines x 2 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. Hilcorp Alaska, LLC Hilcorp Alaska, LLC Changes to Approved Rig Work Over Sundry Procedure Subject: Changes to Approved Sundry Procedure for Well KBU 11-08Y (PTD 205-091) Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Sec Page Date Procedure Change New 403 Required? Y / N HAK Prepared By (Initials) HAK Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date 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? 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): 5,300; Junk (MD): 8,200'N/A Casing Collapse Structural Conductor 1,500psi Surface 2,260psi Intermediate 3,090psi Production 10,540psi 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: Mike Quick 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 mquick@hilcorp.com 7,753'5,700'5,234'1030 psi 5,487 & 5,700 N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 028142 205-091 50-133-20552-00-00 Kenai Beluga Unit (KBU) 11-08Y Kenai Gas Field - Sterling 5 Gas Pool Length Size C.O. 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 9.3# / L-80 TVD Burst 8,197' 10,160psi MD 5,750psi 3,060psi 5,020psi 134' 1,485' 5,346' 134' 1,536' 7,730'3-1/2" 20" 13-3/8" 113' 9-5/8"5,791' 1,515' 8,197' Perforation Depth MD (ft): 5,812' See Attached Schematic 8,176' 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: Oct. 9, 2020 3-1/2" Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:23 am, Sep 28, 2020 320-399 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.25 15:49:26 -08'00' Taylor Wellman Perforations Perforate New Pool N2 10-404 * *MIT-IA before and after perforations added to 1500 psi 8,220 SFD 9/28/2020 gls 10/6/20 Sterling 5.1 Gas Pool DSR-9/28/2020 SFD 9/28/2020 SFD 9/28/2020 C.O. 510A Comm 10/6/2020 dts 10/06/2020 JLC 10/6/2020 RBDMS HEW 11/2/2020 Well Prognosis Well: KBU 11-08Y Date: 9-24-2020 Well Name: KBU 11-08Y API Number: 50-133-20552-00 Current Status: Shut in Gas well Leg: N/A Estimated Start Date: 10/9/2020 Rig: N2 / E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-091 First Call Engineer: Michael Quick (907) 777-8442 (O) (907) 317-2969 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: 1450 psi @ 4,198’ TVD (Based on offset well BHP data) Max. Potential Surface Pressure: 1030 psi @ 4,198’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KBU 11-08Y is an “escape completion” well drilled by Marathon in 2005. Hilcorp perforated the Beluga UB-5A in 2015, the UB-5 and UB-5B in 2016, and the UB-1X in 2017. Well has been shut in since September 2018. The purpose of this sundry is to return this well to production by adding perforations the Lower Sterling sand intervals. Work scope includes setting a 3-1/2” CIBP in the tubing above the UB-1X perforations, and perforating the Sterling B4A sand. Notes Regarding Wellbore Condition x Current shut in tubing pressure = 100 psi. x 3-1/2” (2.75” OD) CIBP set at 5300’ WLM on 8/26/2017. x Open perforations from 5205’ to 5215’. x Max deviation of 30.2 degrees at 3576’ MD / 3273’ TVD. x CBL dated 9/9/2005 indicates a top of cement in the 3-1/2” by 9-5/8” annulus at 4574’ MD/4152’ TVD. x A temperature survey ran after cementing showed a good cement top at 3760’, and scattered cement from 3470’ to 3350’, for the 9-5/8” casing. Pre-Sundry Work 1. Pressure test (MIT-IA) 3-1/2” x 9-5/8” annulus to 1500 psi for 30 minutes. (TOC at 4152’ TVD x 0.25 psi/ft = 1038 psi pressure test, 1500 psi is minimum test pressure). Chart test. E-Line Procedure 1. MIRU E-line and pressure control equipment. PT lubricator to 3,000 psi High. 2. RIH with GPT tool to confirm fluid level. 3. Rig up field gas or Nitrogen and push fluid away to open perforations, push fluid level below 5155’ 4. PU and RIH with 3-1/2” tubing CIBP and set at +/-5155’. Leave 875 psi on the well. Contingency: If nitrogen cannot push fluid away: a) MIRU Coil tubing unit. Pressure test BOP to 4,000 psi high, 250 psi low. b) RU Nitrogen. RIH W/ Coil and blow well dry with Nitrogen leaving 500 psi on well head. RDMO Nitrogen and CTU. MIT-IA CIBP @ 5155FT CBL TOC 4574 FT Well Prognosis Well: KBU 11-08Y Date: 9-24-2020 5. PU and RIH with 2-3/8” Perforating gun, 6 to 12 SPF, 60 degree phasing. Proposed Perforation Intervals: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Reservoir Pressure P5_B4A ±4,597' ±4,626' 29' ±4,169' ±4,198' 1450 psi a) Proposed perforations are also shown on the proposed schematic in red font. b) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. c) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d) Use Gamma/CCL to correlate. e) 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. f) The listed Sands are governed by Conservation Order 510a. 6. POOH. 7. RD E-line. 8. Pressure test (MIT-IA) 3-1/2” x 9-5/8” annulus to 1500 psi for 30 minutes. Chart test. 9. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Safety Concerns for N2 x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (if venting Nitrogen during this job). x Ensure all crews are aware of stop work authority. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil Tubing BOP 4. Standard Well Procedure – N2 Operations 1450 psiP5_B4A ±4,597' ±4,626' 29' ±4,169' ±4,198' POST PERF MIT-IA Lease: State:Alaska Country:USA (TVD): 9/13/2017 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL 4,747' - 7,685' Well Name & Number: ~ 3º / 100' @ 450' Perforations (MD): County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º Revised by:Donna Ambruz Last Revison Date: Completion Fluid: 5,205' - 8,152' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppg followed by Tail of 248 sks of class G, 13.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 ppg Tree cxn = 4-3/4" Otis Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated Top of Cement Bond Log @ 4,574' MD Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 5,700' MD 5,234' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A -028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: UB-5B Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date UB-1X 5,205' 5,215' 2-3/8" 4 Open 08-26-17 UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15 UB-5B 5,578' 5,590' 2-3/8" 5 Isolated 01-28-16 Bridge Plug with 10 ft. of cement @ 5,710' SCHEMATIC UB-5A UB-5 UB-1X CIBP @ 5,300' 08-26-17 9-5/8" TOC 3350' Lease: State:Alaska Country:USA (TVD): 9/25/2020 Dated Completed:9/20/2005 Angle @ KOP and Depth:Angle/Perfs: 6% KCL 4,747' - 7,685' Well Name & Number: ~ 3º / 100' @ 450' Perforations (MD): County or Parish: Kenai Gas FieldKenai Beluga Unit 11-8Y Kenai Peninsula Borough ~ 0.6º Revised by:M. Quick Last Revison Date: Completion Fluid: 5,205' - 8,152' Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' TVD 0' 134' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppg followed by Tail of 248 sks of class G, 13.5 ppg Production Casing 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 ppg Tree cxn = 4-3/4" Otis Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Isolated Module 8 - 6,277' - 6,287' (Beluga) Isolated Module 7 - 6,533' - 6,543' (Beluga) Isolated Module 6 - 6,644' - 6,654' (Beluga) Isolated Module 5 - 7,019' - 7,029' (Beluga) Isolated Module 4 - 7,572' - 7,582' (Beluga) Isolated Module 3 - 7,723' - 7,733' (Tyonek) Isolated Module 2 - 8,035' - 8,045' (Tyonek) Isolated Module 1 - 8,142' - 8,152' (Tyonek) Isolated 3-1/2" Top of Cement Bond Log @ 4,574' MD Excape System Details: -Ceramic flapper valves below each module as follows: -8 Conventional flappers -No flapper at Module-1 Flappers MD (RKB): Module 9 - 6,118' Module 8 - 6,296' Module 7 - 6,552' Module 6 - 6,663' Module 5 - 7,038' Module 4 - 7,591' Module 3 - 7,742' Module 2 - 8,054' Module 1 - NA KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. TD 8,220' MD 7,753' TVD PBTD 5,700' MD 5,234' TVD Permit #:205-091 API #:50-133-20552-00-00 Prop. Des:A -028142 KB elevation:87' (21' AGL) Latitude:60°27' 35.16" N Longitude:151°14' 43.28" W Spud:7/2/2005 TD:7/14/2005 Rig Released:7/21/05 12:00hrs PA #: UB-5B Perforation Detail Sands Top (MD) Btm (MD) Gun Size SPF Status Date B4A 4,597' 4,626' 2-3/8" UB-1X 5,205' 5,215' 2-3/8" 4 Open 08-26-17 UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15 UB-5B 5,578' 5,590' 2-3/8" 5 Isolated 01-28-16 Bridge Plug with 10 ft. of cement @ 5,710' PROPOSED SCHEMATIC UB-5A UB-5 UB-1X CIBP @ 5,300' 08-26-17 B4A Pre/post perf MIT-IA TOC 4575' CIBP 5155 ft 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. 205 -oq \ !ph Nolan Hilcorp Alaska, LL GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 u ^` Tele: 907 777-8308 Hae„rp,tL,Mku,1.1A: Fax: 907 777-8510 NOV 1 3 2017 E-mail: snolan@hilcorp.com AOGCC DATA LOGGED \\M4/2011 DATE 11/10/2017 K BENDER To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 11-08Y SCANNED FEB 0 12018 Prints: FLUID LEVEL LOG PRESSURE/TEMP CD1: digital data KBU_11-08Y PRESS-TEMP_30AUG 17.1as 10/4/2017 3:27 PM LAS File 224 KB KBU_11-08Y PRESS-TEMP_30AUG 17.pdf 10/4/2017 3:27 PM Adobe Acrobat Doc... 574KB KBU_11-08Y PRESS-TEMP 30AUG 17_img.tif 10/4/2017 3:27 PM TIF File 1,886 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Received By:MALtd-toLd1) /l"'j Date: REPCM • STATE OF ALASKA • ALASKA OIL AND GAS CONSERVATION COMMISSION OCT 1 (J 201? V-E7r- -- REPORT OF SUNDRY WELL OPERATIONSIN �.,{�,,,ee� 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing U Operations shutdown U Performed: Suspend Cl Perforate ❑� Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ srforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ 205-091 3.Address: 3800 Centerpoint Dr,Suite 1400 Anchorage, Stratigraphic❑ Service ❑ 6.API Number: AK 99503 50-133-20552-00 7. Property Designation(Lease Number): 8.Well Name and Number: A-028142 Kenai Beluga Unit(KBU)11-08Y 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Gas Field-Beluga/Upper Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 8,220 feet Plugs measured 5,300&5,700 feet true vertical 7,753 feet Junk measured N/A feet Effective Depth measured 5,700 feet Packer measured N/A feet true vertical 5,234 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 113' 20" 134' 134' 3,060 psi 1,500 psi Surface 1,515' 13-3/8" 1,536' 1,485' 5,020 psi 2,260 psi Intermediate 5,791' 9-5/8" 5,812' 5,346' 5,750 psi 3,090 psi Production 8,176' 3-1/2" 8,197' 7,730' 10,160 psi 10,540 psi Liner Perforation depth Measured depth See Attached Schematic /AN chematici nE -F2,7 True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3#/L-80 8,197'MD 7,730'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: 0 141 2 0 67 Subsequent to operation: 0 114 0 0 63 14.Attachments(required per 20 AAc 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations 0 Exploratory❑ Development s Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 317-216 Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: ,��Operations Manager Contact Email: tkrameraahilcorp.com Authorized Signature: (�,�,"L n Date: `Ill S/I 7 Contact Phone: 777-8420 Form 10-404 Revised 4/2017 ,,,e///5,7 1//6 17 Ri .-) v�/ C ,; i i cu" Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 11-08Y SL/ E-Line 50-133-20552-00 205-091 6/8/17 8/26/17 Daily Operations: 06/08/2017-Thursday PTW/JSA. Mobe to location and rig up lubricator. PT to 250 psi low and 3,000 psi high. Pressure up tubing to 420 psi and pressure broke over. Kept pressure flowing in well for 1 hr to push fluid away. RIH w/2.76" G-ring to 5,593' KB tag w/tool would not pass. POOH. RIH w/3-1/2" GS w/AD-2 stop to 5,489' KB w/tool set shear off. POOH. RIH w/3-1/2" GS w/ Weatherford packoff to 5,487' KB, sit w/tool shear off. POOH. Plug set tubing pressure 180psi. RIH w/3-1/2" GS w/AA stop to 5,200' KB sit down w/tool would not fall. POOH, check tool. GS sheared AA stop left in hole discuss w/ Billy—production, have production put 200psi on tubing. RIH w/3-1/2" GS to 5,184' KB, sit latch AA stop. POOH w/stop RIH w/2.7" lib to 4535'KB sit hit 3 times POOH w/impression of plug-fluid level 4460'. RIH w/equalizing prong to 3,755' KB, sit w/tool pressure climbing slow. POOH. RIH w/3-1/2" GS to 3,755' KB, sit latch w/tool. POOH w/packoff, redress have production pressure up tubing to 800psi. RIH w/3-1/2" GS w/Weatherford packoff to 5,487' KB, sit w/tool shear off. POOH. Plug set tubing pressure 600psi. RIH w/3-1/2" GS w/AA stop to 5,486' KB, sit w/tool. POOH, AA stop set, stand by for pressure test 1,500psi 20 min. Good test. RIH w/2-1/2" x 13' dump bailer to 5,485' KB, sit w/tool dump sand. POOH. Rig down, turn in permit, sign out. 06/12/2017 - Monday PTW and JSA. Mobe equip to location. Rig up lubricator, pressure test to 250 psi and 3,000 psi high. Arm gun. RIH slow w/2- 3/8" x 18' Connex HC, 5 spf, 60 degree phase, tie into digital log sent from town and pick up 50' every 500' to season brand new wireline and tag at 5,455'. Ran correlation log and send to town.Adjusted 8' up and resend. Get ok to perf from 5,319' to 5,337' with 1,627 psi on Scada (1,600 tree gauge). Fired gun and pressure went to 1,629' and stayed there. POOH to 42' and line started pulling tight. Worked tools and decided to close wireline valve. It was leaking by so we brought well down from 1,600 psi to 1,000 psi. Worked tools a little stronger and tools jumped and came free. Pulled out of hole and all shots fired. No tools or wire left in hole. Seems like pressure is trying to build but slow at 1,000 psi. Found nothing that had us hung up. Rope socket was web a little. Rig down lubricator and wireline. Turn well over to field. 08/18/2017- Friday PTW and JSA. Mobe equip to location. Rig up lubricator, pressure test to 250 psi and 3,000 psi high. RIH w/GPT tool and tie into Perf log dated 6-12-17. Found fluid level at 4,460' with 1,600 psi on tubing.Tagged at 5,419'. Send log to town. POOH. Had trouble correlating log. Run in hole with 2-3/8" x 18' Geo HC, 5 spf, 0 phase and tie into OHL. Ran correlation log and send to town. Got ok to re-perf from 5,319' to 5,337'. Spotted shot and fired gun with 1,631 psi on well, after 5 min TP was down to 1,637 psi. POOH. All shots fired. Rig down lubricator and turn well over to field. TP- 1,627 psi. 08/21/2017- Monday JSA/TGSM rig up PT 2,500 psi (good). RIH w/2" DD bailer to 5,422' KB.Tag fill, pooh. RIH w/survey, see stop sheet. OOH w/ good data, rig down. 08/25/2017- Friday Mobe to location. PTW and JSA. Pressure test to 250 psi low and 3,000 psi high. RIH w/GPT tool and 2.74" OD plug and tie into log perf log. Saw FL at 4,980' with 1,459 psi on well. Send log to town. Town called back and said we need to push fluid below proposed perf zone at 5,216'. POOH. Field will push fluid away tonight and Pollard E-line will be back in am. Rig down lubricator and turn well over to field. S • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 11-08Y SL/ E-Line 50-133-20552-00 205-091 6/8/17 8/26/17 Daily Operations: 08/26/2017 -Saturday Mobe to location. PTW and JSA. Rig back up lubricator, pressure test to 250 psi low and 3,500 psi high. RIH w/GPT tool and 2.75" CIBP and tie into log sent from town. Injecting gas to keep fluid pushed away at 1,714 psi. Ran correlation log and send to town. Adjusted log 2' and spotted plug at 5,300'. Turn gas off and set plug with 1,714 psi on well. Lost 30 lb when plug set. Picked up 30' and went back down and tag plug. POOH. No FL. RIH w/2-3/8" x 10 HC, 4 spf, 0 deg phase and tie into plug correlation log. Run correlation log and send to town. Got ok to perf from 5,205' to 5,215' Bleed well to 1,600 psi. Spot shot and fired gun with 1,608.6 psi.After 2-1/2 min - 1,528.9 psi and after 5 min - 1,489.1 psi. Fired gun at 1340 hrs. Rig down lubricator and turn well over to production. All shots fired. Gun was dry. • • KB 11 -8Y Pad 41-7 SCHEMATIC Hilcorp Alaska 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. Conductor Permit#: 205-091 20" K-55 133 ppf API #: 50-133-20552-00-00 Top Bottom Prop. Des: A-028142 - "t„ MD 0' 134' 1 � TVD 0' 134' KB elevation: 87' (21'AGL) R" 1./14' ,.hrLatitude: 60°27'35.16" N �fi ' ', Longitude: 151° 14'43.28"W ''¢ ;.« • Surface Casing 13-3/8" J-55 68 ppf BTC Spud: 7/2/2005 t''' r,, * ' Top Bottom TD: 7/14/2005 "�-' MD 0' 1,536' Rig Released: 7/21/05 12:O0hrs 4k1 ek TVD 0' 1,485' a. Cmt w/494 sks of Type 1, 12 ppg 0,40 * 1 t Intermediate Casing �' UB-1X 9-5/8" L-80 40 ppf BTC � r o* Top Bottom MD 0' 5,812' Tree cxn=4-3/4"Otist NI TVD 0' 5,346' ,� Lead Cmt wl 323 sks of class G,12.5 ppg followed by Tail of 248 sks of class G, Top of Cement UB 5 13.5 ppg Bond Log @ 4,574'MD UB-5A -._.'___.1_.- UB-5B Production Casing 3-1/2" L-80 9.3 ppf EUE CIBP @ 5,300' 08-26-17Tp Bottom 8rd CI '.11111 MD 0' 8,197' `' TVD 0' 7,730' ij Cmt w/1,112 sks(230 bbls)of class G, i 11 #1 15.8 ppg ' l Excape System Details: - 9 Excape modules placed Bridge Plug with 10 ft. of cement .`` ! Red contol line firestop 8 modules @ 5,710' `" '''l -Green control line fires bottom module ;i -Ceramic flapper valves below each module except for module 1 ' Perfs MD(RKB): ' 'A Module 9- 6,099'-6,109' (Beluga)Isolated Module 8- 6,277'-6,287' (Beluga) Isolated Excape System Details: I I I Module 7- 6,533'-6,543' (Beluga) Isolated -Ceramic flapper valves below 4 Module 6- 6,644'-6,654' (Beluga) Isolated each module as follows: I1 Module 5- 7,019'-7,029' (Beluga) Isolated -8 Conventional flappers I Module 4- 7,572'-7,582' (Beluga) Isolated -No flapper at Module-1 ; f Module 3- 7,723'-7,733' (Tyonek)Isolated I Module 2- 8,035'-8,045' (Tyonek)Isolated Flappers MD(RKB): Module 1 - 8,142'-8,152' (Tyonek)Isolated Module 9- 6,118' I Module 8- 6,296' c Perforation Detail Module 7- 6,552' III '. Sands Top(MD) Btm(MD) Gun Size SPF Status Date Module 6- 6,663' ' UB-1X 5,205' 5,215' 2-3/8" 4 Open 08-26-17 Module 5- 7,038' II '? UB-5 5,531' 5,548' 2-3/8" 5 Isolated 01-28-16 UB-5A 5,552' 5,565' 2-3/8" 5 Isolated 08-18-15 Module 4- 7,591' UB-5B 5,578' 5,590' 2-3/8" 5 Isolated 01-28-16 Module 3- 7,742' , Module 2- 8,054' Module 1 - NA « 1 - 1" TD PBTD 8,220'MD 5,700'MD 7,753'TVD 5,234'TVD Well Name&Number: Kenai Beluga Unit 11-8Y _ Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 5,205'-8,152' (TVD): 4,747'-7,685' Angle/Perfs: -0.6° Angle @ KOP and Depth: -3°/100' @ 450' Dated Completed: 9/20/2005 Completion Fluid: 6%KCL • Revised by: Donna Ambruz Last Revison Date: 9/13/2017 • • • w\� � Tit THE STATE 9 Alaska Oil and Gas hs�� , oALAsKA Conservation Commission 333 West Seventh Avenue C GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 L;5�� Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager SCANNED J U , 0 5 rt '", Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KBU 11-08Y Permit to Drill Number: 205-091 Sundry Number: 317-216 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this I day of June, 2017. RBDMS L 'JUN - 2 2017 • • RECEIVED STATE OF ALASKA MAY 2 6 2017 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS AOGCC 20 AAC 25.280 1.Type of Request: Abandon 0 Plug Perforations❑ Fracture Stimulate 0 Repair Well ❑ Operations shutdown 0 Suspend ❑ Perforate ❑✓ ' Other Stimulate ❑ Pull Tubing 0 Change Approved Program 0 Plug for Redrill 0 Perforate New Pool ❑ Re-enter Susp Well El Alter Casing 0 Other: El 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory 0 Development Q . 205-091 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20552-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? C.O.510A • ❑ Kenai Beluga Unit(KBU)11-08Y • Will planned perforations require a spacing exception? Yes ❑ No • 9.Property Designation(Lease Number): 10.Field/Pool(s): A-028142 ' Kenai Gas Field-Beluga/Upper Tyonek Gas Pool ' 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): $,200' - •17 7,753' 8,160' 7,693' -1,643 psi N/A N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 113' 20" 134" 134' 3,060 psi 1,500 psi Surface 1,515' 13-3/8" 1,536' 1,485' 5,020 psi 2,260 psi Intermediate 5,791' 9-5/8" 5,812' 5,346' 5,750 psi 3,090 psi Production 8,176' 3-1/2" 8,197' 7,730' 10,160 psi 10,540 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 8,197 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary ❑✓ Wellbore schematic ❑✓ 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory 0 Stratigraphic 0 Development❑✓ Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: June 15,2017 OIL 0 WINJ ❑ WDSPL ❑ Suspended 0 16.Verbal Approval: Date: GAS ❑✓ WAG ❑ GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown 0 Abandoned ❑ 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: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramer hilcorp.com /,'J Contact Phone: 777-8420 Authorized Signature: / (/f Date: 5/Z4//7 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 3t`1- 2•k Le Plug Integrity El BOP Test ❑ Mechanical Integrity Test 0 Location Clearance ❑ .145 c Co/41-4 Other: Post Initial Injection MIT Req'd? Yes ❑ No 0 RBDMS L/ JUN - 2 2C:/ Spacing Exception Required? Yes ❑ No M/ Subsequent Form Required: /CA.`-`i b 0 *- APPROVED BY I Approved by: COMMISSIONER THE COMMISSION Date: / 7 5'-3/—/7 Submit Form and Form 10-403 Revised 4/2017 dpt c is valid or 12 months from the date of approval. ttachments in Duplicate O I V m47 ,,/' S- 6'17 • • Well Prognosis Well: KBU 11-08Y Ilileorp Alaska,LLQ Date: 5/25/2016 Well Name: KBU 11-08Y API Number: 50-133-20552-00 Current Status: Flowing Leg: Estimated Start Date: June 15, 2017 Rig: Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-091 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (C) Second Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) AFE Number: Estimated Bottom Hole Pressure: —2,131 psi at 4,875' TVD (Assumed 0.437 psi/ft gradient) Max. Potential Surface Pressure: —1,643 psi (0.10 psi/ft gas gradient) Brief Well Summary KBU 11-08Y is a well that was plugged back and recompleted in the Upper Beluga UB-5 sands in January 2016. The well was originally completed as an EXCAPE well and consists of 13-3/8" surface casing and 9-5/8" intermediate casing with 3-1/2" cemented tubing. ✓ Via. The purpose of this work/sundry is to add perforations in the Upper Beluga 1X, 1, 2, sands. Notes Regarding Wellbore Condition • Well is currently flowing 180 MSCFD at 64 psi and making about 1.5 BWPD. • Cement Bond Log (9/9/05) indicates competent cement to 4,574' between the 3-1/2" and 9-5/8" • Slickline Operations will be performed prior to perforating include: -- rb>'' t ' o Make slickline drift and tag run prior to performing this work. o Setting a retrievable tubing plug at 5,480' (+/-) to isolate low pressure perforations. E-line Procedure: 1. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. a. Tree connection is 4.75" OTIS. 2. PU perforating guns. 3. Consult the Operations Engineer to determine the amount of pressure to place on well prior to perfing. Place pressure to desired underbalance.. 4. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT SPF Upper Beluga UB-1X 5,206' 5,216' 10' S Upper Beluga UB-1 5,244' 5,254' 10' 5 Upper Beluga UB-2 5,319 5,337' 18' 5 a. Use Gamma/CCL/to correlate. Correlate using CBL Log dated 9/9/05 (Bond Log Tie-in log). b. Record tubing pressures before and after each perforating run. 5. POOH and RD E-line. 6. Turn well over to production. • Well Prognosis Well: KBU 11-08Y Iiilcorp Alaska,LL Date:5/25/2016 7. Note: If a sand is wet,then the zone will be plugged back with a tubing patch. Attachments: 1. Actual and Proposed Schematic H KB 11 -8Y Pad41-7 SCHEMATIC Hilcorp Alaska 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. Permit#: 205-091 API #: 50-133-20552-00-00 Conductor Prop. Des: A-028142 `�` 20" K-55 133 ppf ,rs.;; l .4 Top Bottom KB elevation: 87' (21'AGL) `, _ y MD 0' 134' Latitude: 60°27' 35.16" N !,'"I' • . - TVD 0' 134' Longitude: 151° 14'43.28"W Spud: 7/2/2005 '''`y "4 '° Surface Casing TD: 7/14/2005 'j"' 13-3/8" J-55 68 ppf BTC Rig Released: 7/21/05 12:00hrs 4 Ir Top Bottom PA#: .' MD 0' 1,536' ' 1; TVD 0' 1,485' "I,'i '` '0 Cmt w/494 sks of Type 1, 12 ppg '- Intermediate Casing #I 9-5/8" L-80 40 ppf BTC Tree cxn=4-3/4"Otis �,. 4 Top Bottom +, UB-5 MD 0' 5,812' UB 5A TVD 0' 5,346' Top of Cement ' Lead Cmt w/ 323 sks of class G,12.5 ppg Bond Log @ 4,574'MD ,r` �: '' followed by Tail of 248 sks of class G, 1r y: 7 UB-5B 13.5 ppg . e. ati t L," Production Casing 'ttw° a 3-1/2" L-80 9.3 ppf EUE '- Top Bottom 8rd MD 0' 8,197' r 14.iv TVD 0' 7,730' ; � Cmt w/1,112 sks(230 bbls)of class G, !, 15.8 ppg Bridge Plug with 10 ft.of cement ' @ 5,710' Excape System Details: - 9 Excape modules placed " -Red contol line firestop 8 modules ;: -Green control line fires bottom module I l -Ceramic flapper valves below each module except for module 1 Excape System Details: " ' Perfs MD(RKB): -Ceramic flapper valves below s " " each module as follows. I Module 9- 6,099'-6,109' (Beluga)Isolated -8 Conventional flappers , 1 Module 8- 6,277'-6,287' (Beluga)Isolated -No flapper at Module-1 .r Module 7- 6,533' 6,543' (Beluga)Isolated Module 6- 6,644'-6,654' (Beluga)Isolated II. Module 5- 7,019'-7,029' (Beluga)Isolated Flappers MD(RKB): Module 9- 6,118' 4* Module 4- 7,572'-7,582' (Beluga)Isolated Module 8- 6,296' #r I Module 3- 7,723'-7,733' (Tyonek) Isolated Module 7- 6,552' t Module 2- 8,035'-8,045' (Tyonek) Isolated Module 6 6,663' a t Module 1 - 8,142'-8,152' (Tyonek) Isolated Module 5- 7,038' II Module 4- 7,591' Perforation Detail Module 3- 7,742' /x Sands Top(MD) Btm(MD) Gun Size SPF Status Date Module 2- 8,054' f .'k UB-5 5,531' 5,548' 2-3/8" 5 Open 01-28-16 Module 1 - NA ( UB-5A 5,552' 5,565' 2-3/8" 5 Open 08-18-15 i2 UB-5B 5,578' 5,590' 2-3/8" 5 Open 01-28-16 TD PBTD 8,220'MD 8,161'MD 7,753'TVD 7,694'TVD Well Name&Number: Kenai Beluga Unit 11-8Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,099'-8,152' (TVD): 5,633'-7,685' Angle/Perfs: -0.6° Angle @ KOP and Depth: -3°1100' @ 450' Dated Completed: 9/20/2005 Completion Fluid. 6%KCL Revised by: Donna Ambruz Last Revison Date: 2/4/2016 11 KBU 11 -8Y PROPOSED Pad 41-7 SCHEMATIC Hilcorp Alaska 89' FSL, 705' FEL, Sec. 6, T4N, R11 W, S.M. Conductor Permit#: 205-091 20" K-55 133 ppf API #: 50-133-20552-00-00 Top Bottom Prop. Des: A-028142 MD 0' 134' ®e TVD 0' 134' KB elevation: 87' (21'AGL) ,, Latitude: 60°27' 35.16" N • Surface Casinq Longitude: 151° 14'43.28"W13-3/8" J-55 68 ppf BTC Spud: 7/2/2005 +{ 'r - Top Bottom TD: 7/14/2005MD o' 1,536' Rig Released: 7/21/05 12:00hrs ..* a- .. ' TVD 0' 1,485' P Cmt w/494 sks of Type 1, 12 ppg PA#: ,(v f FO I,y r'/07 ��" Intermediate Casinq ' A r' re 9-5/8" L-80 40 ppf BTC UB-1X =�>f - Top Bottom UB-B1 MD 0' 5,812' Tree cxn=4-3/4"Otis ' - tom^ UB_B2 TVD 0' 5,346' t eR Lead Cmt w/ 323 sks of class G,12.5 ppg ., followed by Tail of 248 sks of class G, Top of Cement - - UB-5 13.5 ppg Bond Log @ 4,574'MD - , . • UB-5A ► ,) UB-5B Production Casinq 3-1/2" L-80 9.3 ppf EUE RBP @±5,480' ✓ k ..iii Top Bottom 8rd MD 0' 8,197' L TVD 0' 7,730' T '�Pe ; i Cmt w/1,112 sks(230 bbls)of class G, r ►* $* L 15.8 ppg -'10 Excape System Details: t t - 9 Excape modules placed Bridge Plug with 10 ft.of cement . ' - contol line firestop 8 modules @ 5,710' `A1 - control line fires bottom module -Ceramic flapper valves below each ' ° module except for module 1 M s Perfs MD(RKB): ILI Module 9- 6,099'-6,109' (Beluga)Isolated - + Module 8- 6,277'-6,287' (Beluga)Isolated Excape System Details: ' V1 Module 7- 6,533'-6,543' (Beluga)Isolated -Ceramic flapper valves below Module 6- 6,644'-6,654' (Beluga)Isolated each module as follows: Mt Ell Module 5- 7,019'-7,029' (Beluga)Isolated -8 Conventional flappers ,; Module 4- 7,572'-7,582' (Beluga)Isolated -No flapper at Module-14 Module 3- 7,723'-7,733' (Tyonek)Isolated It 'P Module 2- 8,035'-8,045' (Tyonek)Isolated Flappers MD(RKB): Module 1 - 8,142'-8,152' (Tyonek)Isolated Module 9- 6,118' V. I 1 .5 Module 8- 6,296' Perforation Detail Module 7- 6,552' ,tcI« ( Sands Top(MD) Btm(MD) Gun Size SPF Status Date Module 6- 6,663' 1 UB-1X 5,205' 5,216 Proposed TBD Module 5- 7,038' II 1 UB-1 5,244' 5,254' Proposed TBD Module 4- 7,591' 414. UB-2 5,319' 5,337' Proposed TBn HI UB -5 5,531' 5,548' 2-3/8" 5 Open 01-28-16 Module 3- 7,742' r' ' UB-5A 5,552' 5,565' 2-3/8" 5 Open 08-18-15 Module 2- 8,054' Ak# UB-5B 5,578' 5,590' 2-3/8" 5 Open 01-28-16 Module 1 - NA ,* TD PBTD 8,220'MD 8,161'MD 7,753'TVD 7,694'TVD Well Name&Number: Kenai Beluga Unit 11-8Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,099'-8,152' (TVD): 5,633'-7,685' Angle/Perfs: -0.6° Angle @ KOP and Depth: -3°/100' @ 450' Dated Completed: 9/20/2005 Completion Fluid: 6%KCL Revised by: Donna Ambruz Last Revison Date: 5/25/2017 • 2.-CA'101 eth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Tele: 907 777-8308 Hilrnrp Alaska.i.L(. Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATA LOGGED 3/9/201 Co M.K.BENDER DATE 03/04/2016 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II 333 W 7th Ave Ste 100 Anchorage, AK MAR 0 2016 99501 -- AOGCC DATA TRANSMITTAL KBU 11-08 Perforation Record print and data BONNE° MAR 1 5 2016 Prints: Perforation Record CD1: digital data KBU_11-8Y_PERF_28JAN16 2/12/20163:13 PM PDF Document 673 KB KBU 11-8Y PERF 28JAN16 1ST GUN COR.,. 2/12120163:13 PM LAS File 91 KB KBU_11-8Y_PERF_28JAN16_1ST GUN PERF 2/'12/20163:13 PM LAS File 47 KB KBU_11-8Y_PERF_28JAN16_2ND GUN CO... 2'12/20163:13 PM LAS File 100 KB KBU_11-8Y_PERF_28JAN16_2ND GUN PERF 2112/20163:13 PM LAS File 57 KB KBU 11-8Y_PERF_28JAN16_irng 2/12/2016 3:13 PM TIFF File 2,.113 KB Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Date: Received)vaiza `��`LQ DD��// V STATE OF ALASKA • • AKA OIL AND GAS CONSERVATION COMMISSION MAR 01 201b REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon Li Plug Perforations Li Fracture Stimulate U Pull Tubing U Operations shutdown U Performed: Suspend ❑ Perforate 0 Other Stimulate ❑ Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ 3rforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ 205-091 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20552-00 7.Property Designation(Lease Number): 8.Well Name and Number: A-028142 Kenai Beluga Unit(KBU)11-08Y 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Gas Field/Beluga/Upper Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 8,200 feet Plugs measured 5,710 feet true vertical 7,753 feet Junk measured N/A feet Effective Depth measured 8,160 feet Packer measured N/A feet true vertical 7,693 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 113' 20" 134' 134' 3,060 psi 1,500 psi Surface 1,515' 13-3/8" 1,536' 1,485' 5,020 psi 2,260 psi Intermediate 5,791' 9-5/8" 5,812' 5,346' 5,750 psi 3,090 psi Production 8,176' 3-1/2" 8,197' 7,730' 10,160 psi 10,540 psi Liner Perforation depth Measured depth See Attached Schematic SCANNED True Vertical depth See Attached Schematic Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3#/L-80 8,197'MD 7,730'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: 0 275 2 55 62 Subsequent to operation: 0 275 0 50 62 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations ❑✓ Exploratory Development El Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas El WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-010 Contact Taylor Nasse-777-8354 Email tnassetu'�.hilcorp.com Printed Name Chad Helgeson Title Operations Manager Signature ,, :lr/ - Phone 907-777-8405 Date 3/1/ lc Form 10-404 Revised 5/2015 '4, 3-1//a l B MS LI, _Q 2 20'6 Submit Original Only ?A4O • • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 11-08Y E-Line 50-133-20552-00 205-091 1/28/16 1/28/16 Daily Operations: 01/27/2016-Wednesday PTW and JSA.Tried to rig up but wind was blowing too hard. Checked again at 1500 hrs and still too much wind. Decided to perf in the morning. 01/28/2016-Thursday PTW and JSA. Rig back up lubricator and PT to 250 psi low and 3,000 psi high. RIH w/2-3/8" x 12' Connex, 5 spf, 60 deg phase and tie into CBL log. Run correlation log and send to town. Get ok to perf from 5,578'to 5,590'._Fired gun with 389.2 psi, went to 390.1 psi and was still there after 5 min. POOH.All shots fired. Gun was dry. RIH w/2-3/8" x 17' Connex, 5 spf, 60 deg phase and tie into CBL log. Run correlation log and send to town. Get ok toperf from 5,531'to 5,548'. Fired gun with 389.2 psi, went to 392.4 psi and was still there after 5 min. POOH. All shots fired. Gun was dry. Rig down lubricator and turn ;well over to field. • KB U 11 -8Y Pad 41-7 41. SCHEMATIC Hilearp Alaska 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. Permit#: 205-091 API#: 50-133-20552-00-00 Conductor Prop. Des: A-028142 20" K-55 133 ppf KB elevation: 87' (21'AGL) MD T0'p 6134om Latitude: 60°27'35.16"N TVD 0' 134' Longitude: 151° 14'43.28"W Spud:, 7/2/2005 , Surface Casing TD: 7/14/2005 13-3/8" J-55 68 ppf BTC Rig Released: 7/21/05 12:00hrs Top Bottom PA#' MD 0' 1,536' ND 0' 1,485' Cmt w/494 sks of Type 1, 12 ppg Intermediate Casing Tree cxn=4-3/4"Otis 9-5/8" L-80 40 ppf BTC . UB-5 Top Bottom MD 0' 5,812' ND 0' 5346' Top of Cement i UB-5A Lead Cmt w/ 323 sks of,class G,12.5 ppg Bond Log @ 4,574'MD followed by Tail of 248 sks of class G, UB-5B 13.5 ppg II Production Casing 3-1/2" L-80 9.3 ppf EUE is Top Bottom 8rd k'' MD 0' 8,197' «,%. ND 0' 7,730' Cmt w/1,112 sks(230 bbls)of class G, 15.8 ppg Bridge Plug with 10 ft. of cement @ 5,710' Excape System Details: - 9 Excape modules placed -Red contol line firestop 8 modules -Green control line fires bottom module -I -Ceramic flapper valves below each , W module except for module 1 Excape System Details: i Perfs MD(RKB): -Ceramic flapper valves below each module as follows: ,i l Module 9- 6,099'-6,109' (Beluga)Isolated 8 Conventional flappers ' ,of Module 8- 6,277'-6,287' (Beluga)Isolated No flapper at Module-1 If Module 6- 6,644'-6,654' (Beluga)Isolated II .' Module 5- 7,019'-7,029' (Beluga)Isolated Flappers MD(RKB): ' Module 4- 7,572'-7,582' (Beluga)Isolated Module 9- 6,118' Ell '1,4 Module 8- 6,296' E '' Module 3- 7,723'-7,733' (Tyonek)Isolated Module 7- 6,552' I Module 2- 8,035' 8,045' (Tyonek)Isolated Module 6- 6,663' Module 1 - 8,142'-8,152' (Tyonek)Isolated Module 5- 7,038' ii Module 4- 7,591' 4 Perforation Detail Module 3- 7,742' , , t„,„ Sands Top(MD) Btm(MD) Gun Size SPF Status Date Module 2- 8,054' lc t 1 UB-5 5,531' 5,548' 2-3/8" 5 Open 01-28-16 Module 1 - NA 1 UB-5A 5,552' 5,565' 2-3/8" 5 Open 08-18-15 id UB-5B 5,578' 5,590' 2-3/8" 5 Open 01-28-16 - F 1( 11 Fir 1,t. TD PBTD 8,220'MD 8,161'MD 7,753'TVD 7,694'TVD Well Name&Number: Kenai Beluga Unit 11-8Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,099'-8,152' (TVD): 5,633'-7,685' Angle/Perfs: -0.6° Angle @ KOP and Depth: -3°/100' @ 450' Dated Completed: 9/20/2005 Completion Fluid: 6%KCL Revised by: Donna Ambruz Last Revison Date: 2/4/2016 •of 7„,t, • THE STATE Alaska Oil and Gas of Conservation Commission LAsKA St _— 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 O4`'ALAS*P Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson r. Operations Manager SCANNED F '` ' 2 6 20113 Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KBU 11-08Y Permit to Drill Number: 205-091 Sundry Number: 316-010 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P oerster Chair DATED this (/day of January, 2016. �pN ,�110 101)16 • • RECEIVED STATE OF ALASKA JAN ) 6 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION I f 6' APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate 0 ' Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number: Exploratory ❑ Development ❑✓ • 205-091 • 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20552-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? C.O.510A ' Kenai Beluga Unit(KBU)11-08Y , Will planned perforations require a spacing exception? Yes ❑ No 0 • 9.Property Designation(Lease Number): 10.Field/Pool(s): A-028142 • Kenai Gas Field-Beluga/Upper Tyonek Gas Pool 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 8,200' ' 7,753' • 8,160' 7,693' 1,690psi WA N/A Casing Length Size MD TVD Burst Collapse Structural Conductor 113' 20" 134" 134' 3,060 psi 1,500 psi Surface 1,515' 13-3/8" 1,536' 1,485' 5,020 psi 2,260 psi Intermediate 5,791' 9-5/8" 5,812' 5,346' 5,750 psi 3,090 psi Production 8,176' 3-1/2" 8,197' 7,730' 10,160 psi 10,540 psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 8,197 Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary 0 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: CommencingOperations: January 20,2016 OIL P ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS Q WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasseethilcorD.com Printed Name Chad Helgeson Title Operations Manager Signature Ci�L�ld Phone 907-777-8405 Date 1 /6 ii 6, COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. 3Ilo • 0/0 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Igo \1 1,0 Post Initial Injection MIT Req'd? Yes ❑ No ❑ D�■� Spacing Exception Required? Yes ❑ No d Subsequent Form Required: /b ,. -1 o q R� �1�1 APPROVED BY i� Approved by:Al- . COMMISSIONER THE COMMISSION Date: ///—(6, Fo 10-403 Revised 2015 o[ 1'piIiA ir for 12 months from the date of approv /../, Attach ents in Duplicate • Well Prognosis Well: KBU 11-08Y Hilcorp Alaska,LLQ Date: 1/5/2016 Well Name: KBU 11-08Y API Number: 50-133-20552-00 Current Status: Flowing Leg: Estimated Start Date: January 20, 2016 Rig: Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-091 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824 (C) AFE Number: Estimated Bottom Hole Pressure: —2,203 psi at 5,124' TVD (Assumed 0.43 psi/ft gradient) Max. Potential Surface Pressure: —1,690 psi (0.10 psi/ft gas gradient) Brief Well Summary KBU 11-08Y is a well that was plugged back and recompleted in the Upper Beluga UB-5A sand in August 2015. The well was originally completed as an EXCAPE well and consists of 13-3/8" surface casing and 9-5/8" intermediate casing with 3-1/2" cemented tubing. The purpose of this work/sundry is to add perforations in the Upper Beluga 5 sands. Notes Regarding Wellbore Condition • Well is currently flowing 330 MSCFD at 63 psi and making about 22 BWPD. • Cement Bond Log (9/9/05) indicates competent cement to 4,574' between the 3-1/2" and 9-5/8" • Make slickline drift and tag run prior to performing this work. E-line Procedure: 1. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. a. Tree connection is 4.75" OTIS. 2. RU 2-3/8" 5 SPF perforating guns. 3. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT SPF Upper Beluga UB-5 5,531' 5,548' 17' 5 Upper Beluga UB-5B 5,578' 5,590' 12' 5 a. Shut in well 5 minutes before perforating. b. Use Gamma/CCL/to correlate. Correlate using CBL Log dated 9/9/05 (Bond Log Tie-in log). c. Record tubing pressures before and after each perforating run. 4. POOH and RD E-line. 5. Turn well over to production. 6. Note: If a sand is wet,then the zone will be plugged back with a tubing patch. Attachments: 1. Actual and Proposed Schematic • 41111 Permit#: 205-091 KB U 11 -8Y API#: 50-133-20552-00-00 Pad 41-7 Prop. Des: A-028142 89' FSL, 705' FEL, KB elevation: 87' (21'AGL) HIiCor ��.� ska Sec. 6, T4N, R11 W, S.M. Latitude: 60°27'35.16"N Longitude: 151° 14'43.28"W Conductor Spud: 7/2/2005 20" K-55 133 ppf TO: 7/14/2005 MD Top Bottom 0' 134' Rig Released: 7/21/05 12:00hrs -:4= ND 0' 134' PA#: I' + Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' " ND 0' 1,485' Cmt w/494 sks of Type 1, 12 ppg a Tree cxn=4-3/4"Otis , Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom Top of Cement MD 0' 5,812' ND 0' 5,346' Bond Log @ 4,574'MD Lead Cmt w/ 323 sks of class G,12.5 ppg ' followed by Tail of 248 sks of class G, UB-5A 13.5 ppg • Production Casing ' 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197 ND 0' 7,730' Cmt w/1,112 sks(230 bbls)of class G, 15.8 ppg Bridge Plug with 10 ft. of cement @ 5,710' Excape System Details: - 9 Excape modules placed Li - contol line firestop 8 modules - control line fires bottom module 1,,,. i 1 -Ceramic flapper valves below each ) module except for module 1 Excape System Details: * i -Ceramic flapper valves below 1 Pe odrfs MD(- 6,09 each module as follows: l Module 9 6,099'-6,109' (Beluga)Isolated Module 8 6,277'-6,287' (Beluga)Isolated 8 Conventional flappers ) Module 7- 6,533'-6,543' (Beluga)Isolated -No flapper at Module-1 , Module 6- 6,644'-6,654' (Beluga)Isolated ° H Module 5- 7,019'-7,029' (Belulga)Isolated Flappers MD(RKB): Module 4- 7,572'-7,582' (Beluga)Isolated Module 9- 6,118' II Module 8- 6,296' Module 3- 7,723'-7,733' (Tyonek)Isolated Module 2- 8,035'-8,045 (Tyonek)Isolated Module 7- 6,552' I Module 1 - 8,142'-8,152' (Tyonek)Isolated Module 6- 6,663' Module 5- 7,038' s4 I _ Module 4- 7,591' Perforation Detail Module 3- 7,742' 1,0 Sands Top(MD) Btm(MD) Gun Size SPF Status Date Module 2- 8,054' ti i 5,552' 5,565' 2-3/8" 5 Open 08-18-15 Module 1 - NA ' J t _ 1001 `$ TD PBTD 8,220'MD 8,161'MD 7,753'TVD 7,694'TVD Well Name&Number: Kenai Beluga Unit 11-8Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,099'-8,152' (TVD): 5,633'-7,685' Angle/Perfs: -0.6° Angle @ KOP and Depth: -3°/100' @ 450' Dated Completed: 9/20/2005 _ Completion Fluid: 6%KCL Revised by: Taylor Nasse Last Revison Date: 1/6/2016 PROPOSED SCHEMATIC 411 Permit#: 205-091 K B U 11 -8Y API #: 50-133-20552-00-00 Pad 41-7 Prop. Des: A-028142 i89' FSL, 705' FEL, u•1 KB elevation: 8T (21'AGL) a Sec. 6, T4N, R11W, S.M. 11i1corp itlaska Latitude: 60°27'35.16"N Longitude: 151° 14'43.28"W Conductor Spud: 7/2/2005 20" K-55 133 ppf TD: 7/14/2005li. ' I Top Bottom Rig Released: 7/21/05 12:00hrs MD o' 13a' ND 0' 134' PA#: rl Surface Casing 13-3/8" J-55 68 ppf BTC ;_ Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/494 sks of Type 1, 12 ppg Tree cxn=4-3/4"Otis rs- Intermediate Casing 9-5/8" L-80 40 ppf BTC • UB- Top Bottom 81Top of Cement �_ TVD 0' 5,33466MD 0' 5, ' ' UB-5A Bond Log @ 4,574'MD � Lead Cmt w/ 323 sks of class G,12.5 ppg th. followed by Tail of 248 sks of class G, Li '- -■ '17UB-5B 13.5 ppg I. Production Casing '' 016 3-1/2" L-80 9.3 ppf EUE M" Top Bottom 8rd MD 0' 8,197' �. TVD 0' 7,730' Cmt w/1,112 sks(230 bbls)of class G, 15.8 ppg Bridge Plug with 10 ft.of cement @ 5,710' Excape System Details: - 9 Excape modules placed + - contol line firestop 8 modules control line fires bottom module it -Ceramic flapper valves below each module except for module 1 Excape System Details: tx IL Perfs MD(RKB): Ceramic flapper valves below ll Module 9- 6,099'-6,109' (Beluga)Isolated each module as follows: Module 8- 6,277'-6,287' (Beluga)Isolated 8 Conventional flappers w � Module 7- 6,533'-6,543' (Beluga)Isolated No flapper at Module-1 Module 6- 6,644'-6,654' (Beluga)Isolated II Module 5- 7,019'-7,029' (Beluga)Isolated Flappers MD(RKB): ` ' Module 4- 7,572'-7,582' (Beluga)Isolated Module 9- 6,118' ►rI Module 8- 6,296' V"; ap I Module 3- 7,723'-7,733' (Tyonek)Isolated Module 7- 6,552' ' Module 2- 8,035'-8,045' (Tyonek)Isolated Module 6 6,663' Module 1 - 8,142'-8,152' (Tyonek)Isolated Module 5- 7,038' I Module 4- 7,591' r,.� J� Perforation Detail Module 3- 7,742' !� G Sands Top(MD) Btm(MD) Gun Size SPF Status Date Module 2- 8,054' `� UB-5 5,531' 5,548' 2-3/8" 5 Proposed TBD Module 1 - NA * UB-5A 5,552' 5,565' 2-3/8" 5 Open 08-18-15 • ,, UB-5B 5,578' 5,590' 2-3/8" 5 Proposed TBD ry TD PBTD 8,220'MD 8,161'MD 7,753'TVD 7,694'TVD Well Name&Number: Kenai Beluga Unit 11-8Y Lease: Kenai Gas Field • County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,099'-8,152' (TVD): 5,633'-7,685' Angle/Perfs: -0.6° Angle @ KOP and Depth: -3°/100' @ 450' Dated Completed: 9/20/2005 Completion Fluid: 6%KCL Revised by: Taylor Nasse Last Revison Date: 1/6/2015 RECEIVED STATE OF ALASKA SEP 8 2015 A OIL AND GAS CONSERVATION COM ION *' REPORT OF SUNDRY WELL OPERATIONS AOGCC 1.Operations Abandon Li Plug Perforations U Fracture Stimulate Li Pull Tubing❑ Operations shutdown U Performed: Suspend ❑ Perforate Q Other Stimulate ❑, Alter Casing❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: _❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ 205-091 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20552-00 7.Property Designation(Lease Number): 8.Well Name and Number: A028142 Kenai Beluga Unit(KBU)11-08Y 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Gas Field/Beluga/Upper Tyonek Gas Pool 11.Present Well Condition Summary: Total Depth measured 8,200 feet Plugs measured 5,710 feet true vertical 7,753 feet Junk measured N/A feet Effective Depth measured 8,160 feet Packer measured N/A feet true vertical 7,693 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 113' 20" 134' 134' 3,060 psi 1,500 psi Surface 1,515' 13-3/8" 1,536' 1,485' 5,020 psi 2,260 psi Intermediate 5,791' 9-5/8" 5,812' 5,346' 5,750 psi 3,090 psi Production 8,176' 3-1/2" 8,197' 7,730' 10,160 psi 10,540 psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic r., p N il0\ix620j5 Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3#/L-80 8,197'MD 7,730'ND Packers and SSSV(type,measured and true vertical depth) N/A N/A N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 67 Subsequent to operation: 0 220 15 0 53 14.Attachments(required per 20 MC 25.070;25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations El Exploratory El Development Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas ❑ WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 315-420 Contact Taylor Nasse Email tnassena,hilcorp.com Printed Name Taylor Nasse Title Operations Engineer Signature ir'' '''--`----.— - Phone 907-777-8354 Date q//V//LY ?z_ _3/5---l2 o RBDM SEP 2 2 201 Form 10-404 Revised 5/2015 /y -- Submit Original Only • • Hilcorp Alaska, LLC Well Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 11-08Y 50-133-20552-00 205-091 8/12/15 8/18/15 Daily Operations: 08/12/2015-Wednesday Meet at office. Mobe to location. PTW and JSA. Rig up lubricator and PT to 250 psi low and 3,000 psi high TP-63 psi. RIH w/ 2.80" GR x 2.70" Cent x braided line brush. Hit tight spot at 5,550' KB. Work from 5,600'to 5,500' until tight spot cleaned up. Went down hole and tagged at 5,787' KB. POOH.That was the only tight spot that was found. Rig down lubricator and move equipment to CLU 11. 08/13/2015-Thursday Meet at office. Mobe to location and spot equipment. Rig up lubricator, pressure test to 250 psi low and 3,000 psi high. RIH w/2.75" OD CIBP,tie into Expro CBL dated Sept 9, 2005 and tag obstruction at 5,727'. Run correlation log and send to town. Get ok to set plug at 5,720'. Set plug and lost 100 lbs line wt when set. Picked up 30' and went back and tagged plug lightly. POOH.TP-60 psi. RIH w/2.5" x 20' dump bailer filled with cement and dumped cement on top of plug at 5,720'. Est TOC is 5,710'. Cement in place at 1230 hrs. Rig down lubricator and turn well over to field. 08/18/2015-Tuesday Meet at office. Mobe to location. PTW and JSA. Rig up lubricator, pressure test to 250 psi low and 3,000 psi high. RIH w/2- 3/8" x 13' HC Razor, 5 spf, 60 deg phase perf gun and tie into Pollard Plug log dated 8/13/15. Run correlation log and send to town. Get ok to perf from 5,552' to 5,565' (changed 4' per Jacob Dunston).Spot shot and fired gun with 250 psi on tubing. Saw no pressure change for 5 min. POOH. Gun was oozing gray mud out of perf holes. Rig down lubricator and turn well over to field.TP was 400 psi. • • KB U 11 -8Y Permit#: 205-091 API#: 50-133-20552-00-00 Pad 41-7 Prop. Des: A-028142 89' FSL, 705' FEL, , KB elevation: 8T (21'AGL) Sec. 6, T4N, R11W, S.M. E�I�Cf)1'�) Alaska Latitude: 60°27'35.16"N Longitude: 151° 14'43.28"W Conductor Spud: 7/2/2005 20" K-55 133 ppf TD: 7/14/2005 Top Bottom Rig Released: 7/21/05 12:00hrs :il TVD o' 13a' PA#: Surface Casing 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/494 sks of Type 1, 12 ppg Tree cxn=4-3/4°Otis Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' Top of Cement TVD 0' 5,346' (est.) @ 4,574'MD Lead Cmt w/ 323 sks of class G 12.5 ppg followed by Tail of 248 sks of ciass G, UB-5A 13.5 ppg 111 Production Casing 4 3-1/2" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' fTVD 0' 7,730' N. Bridge Plug with 10 ft. of cement Cmt w/1,112 sks(230 bbls)of class G, @ 5,710' 15.8 ppg, Excape System Details: - 9 Excape modules placed Tagged fill -Red contol line firestop 8 modules @ 5,738'with 2.5"LIB on (7/3/15) -Green control line fires bottom module -Ceramic flapper valves below each -Excape System Details: 1module except for module 1 -Excape System Details: 1 Ceramic flapper valves below Perfs MD(RKB): each module as follows: Module 9- 6,099'-6,109' (Beluga) Module 8- 6,277'-6,287' (Beluga) -8 Conventional flappers -No flapper at Module-1 Module 7- 6,533'-6,543' (Beluga) Module 6- 6,644'-6,654' (Beluga) -Di 5- 7,019'-7,029' (Belulga) Flappers MD(RKB): ? Module 9- 6,118' Module 4- 7,572'-7,582' (Beluga) Module 8- 6,296' Module 3- 7,723'-7,733' (Tyonek) Module 7- 6,552' Module 2- 8,035'-8,045' (Tyonek) -Di I Module 6- 6,663' ?r Module 1 - 8,142'-8,152' (Tyonek) Module 5- 7,038' Module 4- 7,591' - �� Perforation Detail Module 3- 7,742' ° Sands Top(MD) Btm(MD) Gun Size SPF Status Date Module 2- 8,054' UB-5A 5,552' 5,565' 2-3/8" 5 Open 08-18-15 Module 1 - NA 1*l 4101 ' TD PBTD 8,220'MD 8,161'MD 7,753'TVD 7,694'TVD Well Name&Number: Kenai Beluga Unit 11-8Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,099'-8,152' (TVD): 5,633'-7,685' Angle/Perfs: -0.6° Angle @ KOP and Depth: -3°/100' @ 450' Dated Completed: 9/20/2005 Completion Fluid: 6%KCL Revised by: Donna Ambruz Last Revison Date: 9/18/2015 OF Thr • ��j�,sv THE STATE Alaska Oil and Gas ofA LAsKA Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Alaska 99501-3572 Q 2 .(�'\„h Main: 907.279.1433 ALASY'� -`�C� ,\\j._ " Fax: 907 276 7542 S ®'�"y G www aogcc alaska gov Taylor Nasse Operations Engineer Qsos‘- D� I Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KBU 11-08Y Sundry Number: 315-420 Dear Mr. Nasse: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathy P. Foerster Chair DATED this 1 ay of July, 2015 Encl. • STATE OF ALASKA 1 ' ' t ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS , r 20 MC 25.280 1.Type of Request: Abandon❑ Plug Perforations IY( Fracture Stimulate ❑ Pull Tubing ❑ Operations shutdown ❑ Suspend❑ Perforate 0 • Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other. ,' .,1G I [ 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number. Hilcorp Alaska,LLC Exploratory ❑ Development ❑ • 205-091 • 1 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,AK 99503 50-133-20552-00 • 7.If perforating: // l �- 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? (,. ,6), /L/, I - ,/ , Kenai Beluga Unit(KBU)11-08Y • Will planned perforations require a spacing exception? Yes ❑ No ❑, ��n� 9.Property Designation(Lease Number): 10.Field/Pool(s): A028142 - Kenai Gas Field-Beluga/Upper Tyonek Gas Pool • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth ND(ft): Plugs(measured): Junk(measured): 8 b L l5 7,753 1 8,160 • 7,693 ' N/A N/A Caking AVtc.'Length Size MD TVD Burst Collapse Structural Conductor 113' 20" 134" 134' 3,060 psi 1,500 psi Surface 1,515' 13-3/8" 1,536' 1,485' 5,020 psi 2,260 psi Intermediate 5,791' 9-5/8" 5,812' 5,346' 5,750 psi 3,090 psi Production 8,176' 3-1/2" 8,197' 7,730' 10,160 psi 10,540 psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" 9.3#/L-80 8,197' Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A N/A 12.Attachments: Description Summary of Proposal Q 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development E • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: 7/23/2015 Commencing Operations: OIL WINJ ID ❑ Suspended ❑ 16 Verbal Approval: Date: GAS 2 • WAG ❑ GSTOR ❑ SPLUG 0 Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Taylor Nasse Email tnasse@hilcorp.com Printed NameTaylor Nasse Title Operations Engineer 1 T.,,v„r- ___.. Phone 907-777-8354 Date f> 9/ IS Signature COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31 5^11L0 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Spacing Exception Required? Yes 1:1 No /Subsequent Form Required: /6-- 4/044 APPROVED BY !/J _ Approved by: dsgt7 •�y�— COMMISSIONER THE COMMISSION Date: 7�T. . 1 4 '/5//�� ^- Submit Form and Form 10-403 Revised 5/ 15 if)* ipeikmAdiL:.7 12 months fro tile date of approval. Attachments in upiicate V ' ` RBDMSJ tC JUL 1 7 20154-,. 7 w. K Well Prognosis Well: KBU 11-08Y Hilcorp Alaska,LU Date:7/9/2015 Well Name: KBU 11-08Y API Number: 50-133-20552-00 Current Status: Shut In Leg: Estimated Start Date: July 23, 2015 Rig: Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-091 First Call Engineer: Taylor Nasse (907)777-8354 (0) (907) 903-0341 (C) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(C) AFE Number: Estimated Bottom Hole Pressure: —2,254 psi at 5,243' ND (Assumed 0.43 psi/ft gradient) Max. Anticipated Surface Pressure: 1,730 psi (0.10 psi/ft gas gradient) Brief Well Summary KBU 11-08Y is a well that is completed in the Tyonek and Beluga sands but is currently shut in. The well was originally completed as an Excape well and consists of 13-3/8" surface casing and 9-5/8" intermediate casing with 3-1/2" monobore. The purpose of this work/sundry is to plug back the existing Beluga and Tyonek intervals and add perforations • in the Upper Beluga. Notes Regarding Wellbore Condition • Well is currently shut in. • Tagged fill at 5,738' MD on 7/3/15. • PT survey on 7/3/15 indicated fluid level at±230' MD. • Cement Bond Log(9/9/05) indicates competent cement to 4,574' between the 3-1/2" and 9-5/8" (see attached log interval) Slickline/Eline Procedure: 1. MIRU Slickline/e-line, PT Lubricator to 3,000 psi Hi 250 Low. 2. RIH and set bridge plug at 5,720'. y 3. Dump bail 10' of cement on top of bridge plug. 4. Wait on cement for 24 hours. 5. RU bailer and tag top of cement. a. Dump additional cement if cement top is below 5,710'. 6. Fill well with lease water. Pressure test plug to 1,500 psi for 30 min. 7. Swab well down to the top of the plug (approximately 50 bbls). Bail water out if necessary to get fluid level below 5,570. Coiled Tubing Contingency Procedure (If bailing doesn't remove all water): 8. MIRU Coiled Tubing, PT BOPE to 4,500 psi Hi 250 Low. 9. RIH w/1.75" coil to 5,710' MD and tag top of cement. 10. Displace well fluids with Nitrogen. Well Prognosis Well: KBU 11-08Y Hi!carp Alaska,LLt Date:7/9/2015 a. Estimated volume of displaced produced water is 50 bbl. 11. Leave well with 750 psi Nitrogen SITP. 12. POOH w/coil. 13. RD Coiled Tubing. E-line Procedure: 14. MIRU E-line, PT lubricator to 3,000 psi Hi 250 Low. a. Tree connection is 4.75"OTIS. b. SITP will be 750 psi (Nitrogen Pressure). c. If coil is not used, pressure well with 750 psi of natural gas from jumper on HP gas system. 15. RU 2-1/2" 3 SPF perforating guns. Interval is planned for 6 SPF so it will be shot twice. 16. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT SPF Upper Beluga UB-5A 5,556' 5,569' 13' 6 a. Verify tubing pressure desired by Reservoir Engineer prior to perforating(bleed down if necessary). b. Proposed perfs shown on the proposed schematic in red font. c. Correlate using CBL Log dated 9/9/05 (Bond Log Tie-in log). d. Use Gamma/CCL/to correlate. e. Record tubing pressures before and after each perforating run. 17. RD E-line. 18. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Coil BOPE Schematic 4. Expro CBL dated 9/9/05 • n Permit#: 205-091 KB U 11 -8Y API#: 50-133-20552-00-00 Pad 41-7 Prop. Des: A-028142 89' FSL, 705' FEL, f h I Icor ) Alaska KB elevation: 87' (21'AGL) Sec. 6, T4N, R11 W, S.M. Latitude: 60°27'35.16" N Conductor Longitude: 151° 14'43.28"W - 20" K-55 133 ppf Spud: 7/2/2005 Top Bottom TD: 7/14/2005 MD o' 134' Rig Released: 7/21/05 12:00hrs TVD 0' 134' PA#: r � Surface Casing - 13-3/8" J-55 68 ppf BTC . Top Bottom MD 0' 1,536' TVD 0' 1,485' Cmt w/494 sks of Type 1, 12 ppg Tree cxn=4-3/4"Otis • {s' Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' Top of Cement ND 0' 5,346' (est.) @ 4,574'MD Lead Cmt wl 323 sks of class G,12.5 ppg followed by Tail of 248 sks of class G, 13.5 ppg t Production Casing 3-1/2" L-80 9.3 ppf EUE ''dTop Bottom 8rd MD 0' 8,197' 1•* ND 0' 7,730' Cmt w/1,112 sks(230 bbls)of class G, ' 15,8 ppg Excape System Details: - 9 Excape modules placed Unable to get past top module -Red contol line firestop 8 modules @ 6,100'with 1.75"LIB on (1/12/09) -Green control line fires bottom module II -Ceramic flapper valves below each module except for module 1 Excape System Details: ;:4 I I -Ceramic flapper valves below 10 Perfs MD(RKB): each module as follows: ' si Module 9- 6,099'-6,109' (Beluga) -8 Conventional flappers Module 8- 6,277'-6,287' (Beluga) No flapper at Module-1 ) Module 7- 6,533'-6,543' (Beluga) Module 6- 6,644'-6,654' (Beluga) LI tModule 5- 7,019'-7,029' (Belulga) Flappers MD(RKB): ..4% Module 9 6,118' i:; I Module 4- 7,572'-7,582' (Beluga) Module 8 6,296' %. Module 3- 7,723'-7,733' (Tyonek) Module 7- 6,552' ii►9 Module 2- 8,035'-8,045' (Tyonek) Module 6- 6,663' II Module 1 - 8,142'-8,152' (Tyonek) Module 5- 7,038' II Module 4- 7,591' DI f Module 3- 7,742' --i. 7 Module 2- 8,054' 10 Module 1 - NA '4* • S,+ TD PBTD 8,220'MD 8,161'MD 7,753'TVD 7,694'TVD Well Name&Number: Kenai Beluga Unit 11-8Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,099'-8,152' (TVD): 5,633'-7,685' Angle/Perfs:_ -0.6° Angle @ KOP and Depth: -3°/100' @ 450' Dated Completed: 9/20/2005 Completion Fluid: 6%KCL Revised by: Craig Rang Last Revison Date: 3/18/2010 PROPOSED SCHEMATIC KB U 1 1 -8 i la Permit#: 205-091 - API#: 50-133-20552-00-00Pad 41-7 Prop. Des: A-028142 89' FSL, 705' FEL, KB elevation: 8T (21'AGL) Sec. 6, T4N, R11W, S.M. t Iilcorp r�I�ska Latitude: 60°27'35.16" N Longitude: 151° 14'43.28"W Conductor Spud: 7/2/2005 20" K-55 133 ppf TD: 7/14/2005 • Top Bottom Rig Released: 7/21/05 12:00hrs MD o' 134' 4? ND 0' 134' PA#: A 4 , ., ; Surface Casing 13-318" J-55 68 ppf BTC Top Bottom MD 0' 1,536' ND 0' 1,485' �' .3 Cmt w/494 sks of Type 1, 12 ppg Tree cxn=4-3/4"Otis ',o i ,« Intermediate Casing 9-5/8" L-80 40 ppf BTC 4:..a ---`Nry., Top Bottom Top of Cement \ MD 0' 5,812' (est.) @ 4,574'MD -1 TVD 0' 5,346' C SS ' Lead Cmt w/ 323 sks of class G,12.5 ppg followed by Tail of 248 sks of class G, UB-5A 13.5 ppg -- i' IL------- Production Casing 3-1/2" L-80 9.3 ppf EUE i Top Bottom 8rd ,� MD 0' 8,197' - ' ND 0' 7,730' Bridge Plug with 10 ft. of cementcmt w/1,112 sks(230 bbls)of class G, @ 5,710' il' 15.8 ppg '4, 11.14:C 'rp� Excape System Details: - 9Excape modules placed Tagged fill PC- - contol line firestop 8 modules @ 5,738'with 2.5"LIB on (7/3/15) - ,;r n control line fires bottom module 11 ., -Ceramic flapper valves below each 3 module except for module 1 Excape System Details: 11 Perfs MD(RKB): -Ceramic flapper valves below each module as follows: I) Module 9- 6,099'-6,109' (Beluga) 8 Conventional flappers Module 8- 6,277'-6,287' (Beluga) - No flapper at Module-1 II • Module 7- 6,533'-6,543' (Beluga) Module 6- 6,644'-6,654' (Beluga) Flappers MD(RKB): II Module 5- 7,019'-7,029' (Belulga) Module 9- 6,118' DI fi . Module 4- 7,572'-7,582' (Beluga) Module 8- 6,296' 3 '" Module 3- 7,723'-7,733' (Tyonek) Module 7- 6,552' DI t M41 Module 2- 8,035'-8,045' (Tyonek) Module 6 6,663' a Module 1 - 8,142'-8,152' (Tyonek) Module 5- 7,038' u}I ' Module 4- 7,591' -n Perforation Detail Module 3- 7,742' L7f , Sands Top(MD) Btm(MD) Gun Size SPF Status Date c Module 2- 8,054' ' UB-5A 5,556' 5,569' 2-1/2" 6 Proposed , Module 1 - NA Iii- ' TD PBTD 8,220'MD 8,161'MD 7,753'TVD 7,694'TVD Well Name&Number: Kenai Beluga Unit 11-8Y Lease. Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,099'-8,152' (TVD): 5,633'-7,685' Angle/Perfs: -0.6° Angle @ KOP and Depth: -3°/100' @ 450' Dated Completed: 9/20/2005 Completion Fluid: 6%KCL Revised by: Craig Rang Last Revison Date: 3/18/2010 Kenai Gas Field KBU 11-08Y 7/9/2015 Flileorj, %144,1.III. Kenai Beluga Unit 11-08Y 13 3/8 X 9 5/8 x 3 1/2 Coil Tubing BOP Lubricator to injection head f cr—• 1.75"Tandem Stripper 1 T C•',I,I Blind/Shea 41/1610N'- Blind/Shear 111.1 il •',I.Blind/Shear Blind/Shear II ' '--- * `.',I, Slip =0 Slip ,I.'• I •',L. Pipe Pipe ___� L_ Y 1 Mud Cross u1 u1 •• - 4 1/1610M X41/16 10M oil i��i( ��.I�Iiii *oho��I�� w/2-201/1610Mfull • opening FMC valves Manual Manual 11.1 Manual Manual 21/1610M 21/1610M � 21/161OM 21/161OM Crossover spool 4 1/16 10M X 3 1/16 10M ,y, 44\4, Valve,Swab, l "AL �o.' moi- Ja*�0 ct2' VG-300,3 1/16 10M FE, �e' y �i y0 y� pQ HWO, DD trim 0 •, 1ao3o00 y�yG X0p. 0�,j,. , 11411...... /� 3 0 JOS �Qeio 1 ul_ O H. I jj. LL. 1It ' l Oo AM, _ Valve,upper master, 4 VG-300,3 1/16 10M FE, 0 y. HWO, DD trim 'illiU ' .le 1114- Valve,master, 11( t>11° VG-300,3 1/16 10M FE, �. O HWO, DD trim 1,. © •�t vuV.66.. 77 17.1777 U U - - -.................-...... --- i .7, I 1: . 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' I !Al L .f .1, . . •:, :1 • ' f • - me _ 'Y--- ... . i'el • I 5000 1,. -• • 7'• "%.• -.-• - ..- --: -- -- -•-• 1 i • _ ...,, • • T I 1.,......-....--...-/ • i" . 1 L. • ••• ±III > 7 • 'i''i '''' / •S . , •,f, <-- 1 ' ... 4j---- ..:---. .,- . ! _..........-_______.-.--. ..•.;P 3 I - .. lit _ _ .x1 _ _._ i:-.: _ 0 ,.....„ , i;•[ i- _ Itil _:- -:-. _.: - ,,_ , i f V --i--..: --- .:,'I 1 -41 WWII MEM 1 i -. , 1.1 'ill ... 4: ) , • s') • I''t,o'qi i IV I =Mi. __ ......... . i_ — Ilt __ __ _ _. '..;•-•1 :4—.. '. .. --—7.-- '.•6-'. =MI •• ' .1.- a,' •. ) i imierssa •-• - i!.- — 1-4 , 0 . __ ___ _ . . 11,1 .. ... :.____________. 1 i ' • • 17- -t-- 4 . „ • - -ii,,,.1 v. , .,IA.1. ;.., ,,- , . : . • S...t. 1 , —Era - .- ,........___,___,......A , N" • ,.____ — mEianNllniiIMrneN10.11.Sm,.11..1I 1y11111111111111M1'__—.._ _._..._M. IMI- lt ' . ,-1 ---: 1 .' b - . ' • 1 • • Marathon Alaska Production LLC Alaska Asset Team Marathon P.O. Box 1949 MARATHON Alaska Production LLC Kenai,AK 99611 ® Telephone 907/283-1371 Fax 907/283-1350 July 12, 2011 Guy Schwartz Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Field: Kenai Gas Field SCANNED :JNI 0 9 %'0 l' Dear Mr. Schwartz, Submitted for your records is the Wellview cementing and frac information for KBU 11-8x well. Also included are Cement Bond Logs for: • KBU 11-7 • KBU 11-8x KBU 11-8Y 205'010 • KBU 22-6 • KBU 24-7x Please contact me at (907)283 -1371 if you have any questions or need additional information. Sincerely, .PAuv"� Kevin J. Skiba Regulatory Compliance Representative Enclosures: Wellview Reports cc: Houston Well File 5 CBL logs Kenai Well File (2) KJS • 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. a~,5- ~ ~' ~ Well History File Identifier Organizing (aone> ^ Two-sided III II~IIIII III II III ^ Rescan Needed III II~III II II III III RE CAN DIGITAL DATA OVERSIZED (Scannable) C for Items: ^ Diskettes, No. ^ Maps: Greyscale Items: ^ Other, No/Type: ^ Other Items Scannable by a Large Scanner ^ Poor Quality Originals: OVERSIZED (Non-Scannable) ^ Other: ^ Logs of various kinds: NOTES: BY: Maria Date: ~. (~ ^ Other:: /s/ 1 Project Proofing II(II'III VIII II III BY: Maria Date: ~ /s/ Scanning Preparation _~ x 30 = + = TOTAL PAGES-- ~~~ (Count d oes not include cover sheet) BY: Maria Date: I I' 7 QI (~ /7 /sl ~M Production Scanning Stage ~ Page Count from Scanned File: (count does include cover sheet) Page Count Matches Number in Scanning Preparation: ~ YES NO BY: Maria Date: ~ ~ ~ `~q ~ ~ '7 /s/ +~ ~ rVI 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 f) II I II II I I III ReScanned BY: Maria Date: /s/ Comments about this file: o~„,.~~e~kea uiimiuiiiuuii P P 10/6/2005 well History File Cover Page.doc • M Marathon MARATHON Oil Company January 21, 2009 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 11-8Y Dear Mr. Maunder: • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~~-- ~ ~ 1 r ._ Al SAN "~ ~ ~:' ; ., `~~~ Oil ~ ~ ,.,;. ~rf,. ,. Attached for your records is the Report of Sundry Well Operations, 10-404, for KBU 11-8Y well. Marathon intended to install a Capillary String and was granted permission under Sundry #308-432. Preliminary work revealed that solids had infiltrated the wellbore. Efforts to remove this material were unsuccessful. A strategy is being developed to determine future work over activities on KBU 11-8Y and a number of the other Kenai wells that are experiencing solids infiltration. Strategy development will require investigative research including data collection before a viable plan can be developed. Marathon is closing out this sundry, without installing the Capillary String, since the exact corrective actions and time frame for completing the work is unknown. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~~~ F'.. ~~.~ ~. ~ t, `~ fj y~CVf'. ~f r ~./ ~ I:~ i. wii.a~ ~ ~ 7 . _, tom. b.: ~, 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 - C"5, G~..r Ls 1 N L V STATE OF ALASKA A~ ~ ~ ~~~~ /J j ~ ALAS~OIL AND GAS CONSERVATION COMMON ~~ REPORT OF SUNDRY WELL OH46G~Aff1®6~ Cof~s. Commission 1 ~nci~o~ ~~;> 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Attempted to y Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver^ Time Extension ^ install Capillary Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ String 2. Operator Marathon Oil Company N 4. Well Class Before Work: 5. Permit to Drill Number: ame: Development 0 Exploratory^ 205-091 3. Address: PO Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20552-00-00 " 7. KB Elevation (ft): 9. Well Name and Number: 87' (21' AGL) ' Kenai Belu a Unit 11-8Y 8. Property Designation: 10. Field/Pool(s): A - 028142 - Kenai Gas Field /Beluga 8~ Upper Tyonek Pools 11. Present Well Condition Summary: Total Depth measured 8,220' - feet Plugs (measured) NA true vertical 7,753' - feet Junk (measured) NA Effective Depth measured 8,160' - feet true vertical 7,693' - feet Casing Length Size MD TVD Burst Collapse Structural Conductor 113' 20" 134' 134' 3,060 psi 1,500 psi Surface 1,515' 13-3/8" 1,536' 1,485' 5,020 psi 2,260 psi Intermediate 5,791' 9-5/8" 5,812' 5,346' 5,750 psi 3,090 psi Production 8,176' 3-1/2" 8,197' 7,730' 10,160 psi 10,540 psi Liner Perforation depth: Measured depth: 6,099' - 8,152' True Vertical depth: 5,633' - 7,685' Tubing: (size, grade, and MD) 3-1/2" L-80 8,197' Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): Attempted to clean fill out of wellbore, in prepartion for Capillary String installation, without success. Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 100 1 57 Subsequent to operation: 0 0 - 1 59 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ^~ - Service ^ Daily Report of Well Operations X 16. Well Status after work: Oil ^ Gas ^/ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 308-432 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technician Signature ,.• ~ Phone (907) 283-1371 Date January 21, 2009 Form 10-404 Revised 04/2006 ~' > ,. Submit Original Only it #: 205-091 50-133-20552-00-00 -Des: A - 028142 evation: 87' (21' AGL) Ide: 60° 27' 35.16" N itude: 151 ° 14' 43.28" W _ 7/2/2005 7/14/2005 eleased: 7/21 /05 12:OOhrs KBl1 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. Tree cxn = 4-3/4" Otis Top of Cement 3-1/2" x 9-5/8" Casing (est.) @ 4,574' MD • MARATHON Conductor 20" K-55 133 ppf Top Bottom MD 0' 134' ND 0' 134' Surface Casino 13-3/8" J-55 68 ppf BTC Top Bottom MD 0' 1,536' ND 0' 1,485' Cmt w/ 494 sks of Type 1, 12 ppg 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 5,812' TVD 0' 5,346' Lead Cmt w/ 323 sks of class G, 12.5 ppg followed by Tail of 248 sks of class G, 13.5 ppg 3-112" L-80 9.3 ppf EUE Top Bottom 8rd MD 0' 8,197' TVD 0' 7,730' Cmt w/ 1,112 sks (230 bbls) of class G, 15.8 PP9 Unable to get past top module @ 6,100' with 1.75" LIB on 1/12/09 Excape Svstem Details -Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 9 - 6,116' Module 8 - 6,294' Module 7 - 6,551' Module 6 - 6,662' Module 5 - 7,038' Module 4 - 7,590' Module 3 - 7,741' Module 2 - 8,053' Module 1 - NA TD PBTD 8,220' MD 8,161' MD 7,753' TVD 7,694' TVD Excape Svstem Details - 9 Excape modules placed - Red contol line firestop 8 modules - ~:+ - .control line fires bottom module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099' - 6,109' (Beluga) Module 8 - 6,277' - 6,287' (Beluga) Module 7 - 6,533' - 6,543' (Beluga) Module 6 - 6,644' - 6,654' (Beluga) Module 5 - 7,019' - 7,029' (Belulga) Module 4 - 7,572' - 7,582' (Beluga) Module 3 - 7,723' - 7,733' (Tyonek) Module 2 - 8,035' - 8,045' (Tyonek) Module 1 - 8,142' - 8,152' (Tyonek) Well Name & Number: KBU 11-8Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,099' - 8,152' (TVD): 5,633' - 7,685' Angle/Perfs: - 0.6° Angle @ KOP and Depth: - 3° / 100' @ 450' Dated Completed: 9/20/2005 Completion Fluid: 6% KCL Revised by: Kevin Skiba Last Revison Date: 1/21/2009 ~^ ~~~~ Gperations Summary Report '~ ,~,,,!, ~~~~Cornp~~Y Well Name: KENAI BELUGA UNIT 11-SY Daily Operations Report Date: 72C31C1008 Job Category: R&M MAINTENANCE 2i H r Semmary Having problems with cold weather, spot equip. and shut down operation. opa StartTtne ErtlTlne Der 0 Cotle P,C'W Cotle Stada Tro~bk otle Camme~t 07:00 16:00 9.00 RURD COIL Moving in coil unit, having problems with starting units in -20 degree weather.Get equip. moving, move in storage and displacement tanks,spot coil a ui .shut down for cold weather.Turn in work ermits. Report Date: 1l70f2009 Job Category: R&M MAINTENANCE 21 H r S~mmary~ Rig up coil, attempt to test bop, damage shear rams function test.send to shop overnight for repairs. shut down. Ops StartTh~e E~dTlnc Dir 0 COGe Putt Co4e Stairs TroebkCOtle Comment 07:00 10:00 3.00 RURD COIL arm up and start equip., 10:DD 11:00 1 .00 SAFETY MTG Safety meeting with ASRC, and BJ serv. 11:00 13:30 2.50 RURD COIL Finish rigging up coil, hook up hyd. lines, pump lines and suction Iines.Hook u control lines. 13:30 14:00 0.50 TEST ROPE Function test ROPE. Dama ed shear rams durin test.Send to sho to be repaired. Mike stop job to check ROPE. 14:00 17:00 3.00 RURD COIL Shut down rigging up coil.Prep location for night crew.Renew permits, change crews. Report Date: 7M1f2009 Job Category: R&M MAINTENANCE 2l H r Srmmary Finish nipple up, Test ROPE, prep equip. shut down. ops S~rtTme ErtlTme Drr o Cote Pmt1r Co0e S1ada Tro~DkCOtle Comment 07:00 08:00 1 .00 SAFETY MTG Arive on well site, have JSA, Pre-job with BJ services, ASRC, Check equip. 08:00 10:00 2.00 NUND ROPE Nipple up BOP and test. Witness waived by Jim Regg X1500 hrs. 1 P912009.Function test BOPE.Visual ins ection. 10:00 10:30 0.50 SAFETY DRIL Coil tubing operator initiated stop the job, weather conditions -20 degrees, brought in serv. hands to warm up. 10:30 12:45 2.25 TEST ROPE Prime pump with methanal, set up for ROPE test, break circ. thru iron, Start est low press. blind ram and body test, 250 psi low, 4200 psi high, test slip and tubing rams 250 psi low, 4500 psi high, Press. test for N2 valves 350 psi low, 5000 psi high, End ROPE test remove test bar. 12:45 15:00 2.25 RURD COIL Finish prep. coil for clean out, check dimple on connector, replace stripping element, prep location to shut down for night. Flow line runnig to wellhead lu ed steam on wheels to thaw out. Shut down turn in ermits. www.peloton.com Report Printed: 1f20t2009 ~^ ~~~~ +~perations Summary Report ,~,,,~, LO~~CornP~nY Well Name: KENAI BELUGA UNIT 11~Y Daily Operations Report Date: 7M22009 Job Category: R&M MAINTENANCE Zl N r SYmmary Body test, load coli wl brine, RIH, tag at 6109', couldn't get past 6110', clear coil w1 N2, POOH shut down. S~rtTlnc EYdTme OYr 0 COG! FYC1U COGe Ops Stalls TroYbkCOGe CanmeYt 07:00 08:00 1 .00 SAFETY MTG Safety Meeting and JSA with BJ services and ASRC Crane operator. 08:00 09:00 1 .00 RURD COIL Pick up injector hd, check 2" nozzle and 3' bar. double flapper. 09:00 12:00 3.00 AITON OTHR Steam on wheels heatin brine from 32 de rees to 54 de rees. 12:00 12:30 0.50 CIRC CFLD Circ. and fill coil with 27.5 bbls. 696 KCL. 12:30 13:00 0.50 TEST ROPE Shell test BOP w/ 300psi low, 2100psi high. 13:00 13:30 0.50 RUNPUL COIL I w coil pumping .44 BPM KCL and prime N2 while running in hole. 30 psi on WH, Fluid level at 250'.Pull test at 3850', 12,000# Up. Wt., 290psi CTU, 10psi VvNP 13:30 14:00 0.50 RUNPUL COIL RIH F13850' Start N2 at 350 scfm. 14:00 14:15 0.25 RUNPUL COIL Pull test at 5400', Up wt =14,000#, Dn. wt.= 980#, 281 bbls.in supply tank, 68 bbls. in return tank. 14:15 14:30 0.25 RUNPUL COIL Pull test at 6000', Up wt =16,000#, Dn. wt.=980# Start pumping at 1.75 bpm RIH 14:30 14:45 0.25 RUNPUL COIL Ta ell u at 6109'tr to work coil ast 6109' returns have some formation sand and soap, Parked and washing at 6110', 14:45 15:15 0.50 RUNPUL COIL Trying to work past 6110', Pump=1.75 BPM, N2=350scfm. Not able to get ast 6110'. 3630psi CTU, 315psi WHP. 15:15 16:15 1 .00 RUNPUL COIL POOH, Pump N2 to displace coi1,150 bbls. in storage tank, 200 bbls.in return ank.Vac. truck takin returns to G81 lam. 16:15 16:30 0.25 PUMP N2 Shut down N2, Bleed down coil. 16:30 17:30 1.00 RURD COIL Rig down injector hd.,Pump methanol across tree and choke manifold. 17:30 18:00 0.50 RURD COIL Secure well and location, leave location,turn in permits. Report Date: 1M32009 Job Category: R&M MAINTENA NCE 2l h r SImRi3n~ R!iJ ~;liclir~e, F~~tJ ~.?0" LIB, could not get down, stopped at 6070"VVLM,PN 1 314 bailer, Stopped same place, PIU 1 314"LIB stopped same place.Rig down a'grtTlne EYOTme DYr 0 COGe AYC111 Cotle Ofa Stalls TroYbkCatle Comment 09:00 10:00 1 .00 SAFETY MTG Safety meeting JSA with Pollard and Steam on wheels for sim ops. Spot equip. 10:00 10:30 0.50 RURD SLIK Finish ri in u ands attin a ui . 10:30 11:00 G.50 RURD SLIK Pick up lubricator, BOP and tools, test lubricator to 2000 psi no leaks. 11:00 12:00 1 .00 RUNPUL SLIK RIH wl , RS,Stem,Stem, OJ,SJ, 2.70" LIB, 6010' WLM, tag twice, POOH, small amount shaved on one side of LIB. 12:00 13:15 1 .25 RUNPUL SLIK RIH wl RS,Stem, Stem, OJ, SJ,1 314" DD Bailer, to 6070' WLM, work bailer, could not get down, ,POOH, Marks on side of bailer em 13:15 14:00 0.?5 RUNPUL SLIK RIH wI RS, Stem, Stem, OJ, SJ, 1 314" LIB, to 6070' VvLM, tag down three imes, tools hung up, hit spang jars several times did not come loose, set down load jars, hit jars one time and came Ioose.POOH, 1 3I4" LIB had definite marks on side of LIB. 14:00 15:00 1 .00 RURD SLIK Rig down slicline unit and move to KBU22-6. Report Date: 1M~2009 Job Category: R&M MAINTENA NCE ~l NrSYmman;~ RIH and N2 lift vaell.'vv'ell did not kick off. SgrtTlne EYOTtne DYr 0 Cotle RCtll CoG! Opc StatYa TroYbkCoGe CanmeYt 07:00 07:45 0.75 SAFETY MTG AF Hold PJSM. Discuss BJ JSA and assign tasks. Issue permit. 07:45 08:45 1.00 RURD COIL AF RU injector and stab on well. 08:45 09:00 0.25 TEST EQIP AF Shell test to 1000 si. 09:00 11:00 2.00 RUNPUL COIL AF RIH pumping N2 at 500 SCFRnin. Pump ressure 1200 VvNP = 240 11:00 11:30 0.50 RUNPUL COIL AF SD pump and observe well. 11:30 12:00 0.50 PUMP N2 AF Restart N2 at 500 SCFRnin. No significant pressure increase from 11:00 SD. (580 psi to 740 or an influx of 3 Bbls) 12:00 12:30 0.50 RUNPUL COIL AF POH while pumping N2. 12:30 13:00 0.50 RUNPUL COIL AF SD N2 at 4200'. Pump pressure at 500 and WHP at 50 psai. Finish POH. 13:00 18:00 5.00 RURD COIL AF RD coiled tubing to move to KU 22-6X. Release Ct at 1800. Close permit and leave location. www.peloton.com Report Printed: 120/2009 ALASS-A OIL A1~TD GA5 CONSER'1TATIOI~T COMl-IIS51Oi1T Kevin Skiba Engineering Technician Marathon Oil Company PO Box 1949 Kenai AK 99611-1949 SARAH PALIN, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 a~~~ Re: Kenai Gas Field, Beluga & Upper Tyonek Gas Pools, KBU 11-8Y Sundry Number: 308-432 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 Comrrussion 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 December, 2008 Encl. M Marathon MARATHON Oil Company November 24, 2008 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: Kenai Beluga Unit 11-8Y Dear Mr. Maunder: • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 -~, ~, f' Marathon proposes to run a 3/8" capillary string in KBU 11-8Y to mitigate water loading. Setting depth of the capillary string should be approximately 8,142' MD. Please call me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~~'~~ Kevin J. Skiba Engineering Technician Enclosures: 10-403 Application for Sundry Approvals cc: AOGCC Current Well Schematic Houston Well File Detailed Operations Program Kenai Well File KJS ~~ STATE OF ALASKA `.L.2 ALA OIL AND GAS CONSERVATION COMIv~OfV APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 /o?~~ ~Iv a ~~ti a, ~N 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown^ Perf~+fate Q Waiver ^ Other ^ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Install _ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ Capil;lary String 2. Operator Name: Marathon Oil Company 4. Current Well Class: 5. Permit to Drill Number: Development ^ , Exploratory ^ 205-091 3. Address: p0 Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20552-00-00 ' 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: S ^ ^~ Kenai Beluga Unit 11-8Y pacing Exception Required? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): (~,.5 A- 028142 87' (21' AGL) Kenai Gas Field /Beluga & Upper Tyonek Pools 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 8,220' - 7,753' 8,160' - 7,693' - NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 113' 20" 134' 134' 3,060 psi 1,500 psi Surface 1,515' 13-3/8" 1,536' 1,485' 5,020 psi 2,260 psi Intermediate 5,791' 9-5/8" 5,812' 5,346' 5,750 psi 3,090 psi. Production 8,176' 3-1 /2" 8,197' 7,730' 10,160 psi 10,540 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6,099' - 8,152' 5,633' - 7,685' 3-1/2" L-80 8,197' 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: Commencin O erations: December 9, 2008 g p ^ Gas Q i Plugged ^ Abandoned ^ Oil 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technician Signature ~' ' (907) 283-1371 Date November 24, 2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~ . '~~a Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: Subsequent Form Required: L~D~ APPROVED BY Approved by: . COMMISSIONER THE COMMISSION Date: Form 10-403 Revised 06/2006 Submit in Duplicate -GL: 21.00' -TH F: 21.70' cxn = 4-3/4" Otis KBU 11-8Y Pad 41-7 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M TOC (est.) - 4574' MD 3-1/2" x 9- :eramic flapper valves below each module as follows: Module 9 - 6,116' Module 8 - 6,294' Module 7 - 6,551' Module 6 - 6,662' Module 5 - 7,038' Module 4 - 7,590' Module 3 - 7,741' Module 2 - 8,053' Module 1 - NA I `~~. . ,~ , •.. • M MARATHON Drive Pipe: 20", 133 ppf, K-55 to 134' Surface Casino: 13-3/8", 68 ppf, J-55, BTC @ 1536' Cmt w/ 494 sx. of Type 1 at 12 PP9• Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 5812' Cmt w/ lead of 323 sx of class G @ 12.5 ppg followed by tail of 248 sxs class G @ 13.5 ppg Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 8197' Cmt w/ 1112 sx of class G at 15.8 ppg Excape Svstem Details - 9 Excape modules placed - Red contol line firestop 8 modules - Gr:•~r. control line fires bottom module - Ceramic flapper valves below each module except for module 1 Perfs MD (RKB): Module 9 - 6,099'- 6,109' (Beluga) Module 8 - 6,277'- 6,287' (Beluga) Module 7 - 6,533'- 6,543' (Beluga) Module 6 - 6,644'- 6,654' (Beluga) Module 5 - 7,019'- 7,029' (Belulga) Module 4 - 7,572'- 7,582' (Beluga) Module 3 - 7,723'- 7,733' (Tyonek) Module 2 - 8,035'- 8,045' (Tyonek) Module 1 - 8,142'- 8,152' (Tyonek) Well Name & Number: KBU 11-8Y Lease: Kenai Gas Field County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): (TVD): Angle/Perfs: Angle @ KOP and Depth: Dated Completed: 9/20/2005 Completion Fluid: 6% KCL Prepared By: Kevin Skiba Last Revison Date: 7/31/2008 TD - 8,220' PBTD - 8,160' ^ 2008 Capillary String Installation KBU 11-8Y Capillary String Install Pad 41-7 WBS: Requested Obiective Install capillary string (3/8" 2205 0.049" WT) into well for delivering foamer to alleviate liquid loading. Procedure Capstring Set Depth: 8142' TVD at Set Depth: 7675' Tag: CT cleanout is planned before capstring Installation Procedure: Disconnect power to wellhouse (call electrician) MI crane, manlift. Remove wellhouse. On site: 8250' spool, Well Head Adapter (WHA), Sundry, Work Permit, Well Control Standards Sheet. Install Capillary Strin (g~JSA): 1. MIRU BJ Dyna-Coil unit. Place liner around wellhead and truck. 2. Shut swab valve, pull tree-cap flange, remove OTIS blanking plug. 3. Replace plug with WHA (note o-ring). MU flange. Pressure test 1.Sx SITP. 4. P/LJ Dyna-Coil injector with crane, run 3/8" string through injector. 5. Set Fluid Control Valve pressure = (Setting TVD 7675')(0.433 psi/ft H20)(1.036 foamer SG) = 3442 + 458 psi = 3900 psi 6. MU BHA; run the 3/8" string through pack-off; attach BHA. 7. Perform "pull test" on BHA. 8. Thread pack-off assembly into 2-7/8" female connection (a wrench or chain tongs maybe needed to hold the adapter from turning). Wrap wellhead with absorbents to catch drips. 9. Configure tubing to pump foamer downhole while running in, or cap tubing end. 10. Set Rattiguns to running tightness, and pump up pressure on pack-off. 11. Open swab valve. 12. Adjust Rattiguns and pressure on pack-off as needed to minimize leaks. 13. RIH to setting depth of 8142'. 14. Set slips. Set Rattiguns; leave 1.5 times SITP on hydraulic pack-off. 15. Pull tubing excess through injector. 16. Cap tubing with a Swagelok cap and valve, pressure gauge, and filter. 17. Lockout Swab, Upper Master, and Lower Master as per Capstring Lockout Procedure. 18. Hookup injection line to CICM. NOTE: Start foamer at 1 gpd. 19. RDMO. Cleanup site. Sign-out. 20. Replace well house NOTE: When replacing well house, be careful of the tubing "bend" as it goes back inside if it extends through the roof. KBU 11-8Y Coil Tubing clean-out Sundry Requirements Page 1 of 1 Maunder, Thomas E (DOA) From: Maunder, Thomas E (DOA) Sent: Friday, November 21, 2008 11:34 AM To: 'Skiba, Kevin J.' Cc: Walsh, Ken Subject: RE: KBU 11-8Y (205-091) Coil Tubing clean-out Sundry Requirements Kevin and Ken, You are correct. I will place a copy of this message in the well file. Tom Maunder, PE AOGCC From: Skiba, Kevin J. [mailto:kskiba@marathonoil.com] Sent: Friday, November 21, 2008 11:10 AM To: Maunder, Thomas E (DOA) Cc: Walsh, Ken; Skiba, Kevin Subject: KBU 11-8Y Coil Tubing clean-out Sundry Requirements Tom, This email is to conirirm the sundry requirements for the coil tubing clean out of KBU 11-8Y wetl. As per our telephone conversation: * No 10-403 Sundry is required to perform the coil tubing clean-out * Documentation of this work will be provided on a 10-404 Sundry Please confirm or correct this interpretation. Thanks, >, °' ~~~~ Kevin Skiba Engineering Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 11/21/2008 F:1LaserFiche\CvrPgs~InsertslMierofilm Marker.doc ~~ DATA SUBMITTAL COMPLIANCE REPORT 7/19/2007 Permit to Drill 2050910 Well Name/No. KENAI BELUGA UNIT 11-8Y Operator MARATHON OIL CO API No. 50-133-20552-00-00 MD 8220 TVD 7753 Completion Date 7/20/2005 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Samples No DATA INFORMATION Types Electric or Other Logs Run: SP/GR-EL-Density/Neutron-Sonic-Single Arm Caliper. MFTs Well Log Information: Log! Electr Data Digital Dataset Log Log Run Ty~ Med/Frmt Number Name Scale Media No QED C Las 15207 Induction/Resistivity Well Cores/Samples Information: Directional Survey Yes (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments 1451 8257 Open 6/14(2007 Precision Energy Services GR, Neutron, Density, Sonic, Induction Sample Interval Set Name Start Stop Sent Received Number Comments ADDITIONAL INFORMAxTION /~ Well Cored? Y / N1 Daily History Received? '/\;ay, N Chips Received? ~-F~P~1-` Formation Tops ~/ N Analysis Y~l~ Received? Comments: Compliance Reviewed By: _ _ Date: 3 ~ ~~? M Marathon MARATHON Oil Company June 13, 2007 Alaska Oil & Gas Conservation Commission Attn: Howard Okland 333 W. 7~' Avenue, Suite 100 Anchorage, AK 99501 RE: Marathon KBU #11-8Y -API 50-133-20552-00 CONFIDENTIAL Dear Mr. Okland: Alaska Asset Team Northern Business Unit P.O. Box 3128 Houston, TX 77253 Telephone 713-296-3597 Fax 713-499-4469 FEDERAL EXPRESS Enclosed is the replacement CD you requested containing confidential digital well data for the above referenced well, as described on the attached CD Contents document. Please indicate your receipt of this data by signing below and returning one copy to my attention at the letterhead address or fax to 713-499-4469. ~~ Thank you, Courtney McElmoyl Received by: Date: ! ~ C nn,-~._ ~.1.~-~1 Enclosures ~OS ~~l Operations Summary: Name KBU_I 1-SY_Operations_Summary. xls Directional Data: Name EOWR KBUII-8Y INTEQ.pdf " ~kbull-8y dir_sur,dat ~.--~ KBUI1-8Y Survey.txt Wireline Data: Name ~FINAL_Marathon KBU11-8V_Run 2 MFT complete,dpk FINAL Marathon KBU11-8Y_Runl_complete,dpk ~~~FINAL Marathon KBU11-8Y_Run l~lotted,dpk LJ KBU11 8Y_MAINDEPTH.Ias FINAL Marathon KBU11.8Y Run 2_complete.dpk ~FINAL_Marathon KBU11-8Y_Run 2~lokked.dpk `~kbull 8y r2 MAINDEPTH.Ias Mudlog Data: Name U KBU 11-BY.las ~KBUll-8Y_DD.pdF -KBU11-$V_ML_MD.pdF ~` i;BUll-8Y_ML TVD.pdF KBUl l 8Y.dbP ®KBUll-8Y SCL,DBF KBU11-8Y TVD.DBF kbu l l -8yr. dbf ®khu i l-8y. hdr KBUll-8Y.mdx • KBU11-8Y SCL.MDX KBUf1-8Y TVD.mdx ®kbull-8yr.mdx "~ Well Report KBU 11-8Y,doc ~KUB 11-8Y Remarks dot -KBU11-8Y DD.pdF _ , ~` Y,BU11-8Y ML_MD.pdF ~- k:BU11-8Y ML TVD,pdF KBU 11-8Y API 50-133-20552-00 CD CONTENTS Confidential As-built Plat in PDF format. • M Marathon MARATHON Oil Company February 9, 2006 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West 7`h Ave., Suite 100 Anchorage, Alaska 99501 Reference: Completion Report 10-407 for permit 205-054 Field: Kenai Gas Field /Beluga / Tyonek Well: KBU 11-8Y Dear Mr. Aubert: Alaska Business Unit Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 Enclosed please find the Well Completion Report with associated attachments for Kenai Beluga Unit Well No. 11-8Y. This well has been completed cased hole with a 3.5" Excape monobore production string to surface. I apologize for the delay in getting this completion notice to you. Should you require further information, I can be reached at 713-232-9347 or 713-296-2730 or by email at JRThompson C~3 MarathonOil.com. Sincerely, James R. Thompson Sr. Completions Engineer Enclosures: Completion Report Directional Survey Wellbore Diagram Well Summary Report STATE OF ALASKA ~E~E~ v ~~ ALASK~L AND GAS CONSERVATION COMMIS~I FEB 1 3 2006 WELL COMPLETION OR RECOMPLETION REPORT ND. G 1a. Well Status: Oil Gas ~ Plugged Abandoned^ Suspended^ WAG 1b. Well CI 2aAACZS.ios zoAAC2s.iio Development Q ~~S1~I~tS~'^ GINJ ^ WINJ ^ WDSPL^ No. of Completions Other Service ^ Stratigraphic Test^ 2. Operator Name: 5. Dat Co Susp., or 12. Permit to Drill Number: Marathon Oil Company Aband.: 205-091 3. Address: 6. Date Spudded: 13. API Number: P. O. Box 3128, Houston, TX 77253 July 2, 2005 50-133-20552 4a. Location of Well (Governmental Section): 7. Date TD Reached: 14. Well Name and Number: Surface: 89' FSL, 705' FEL of Sec 6, T4N, R11W, S.M. July 14, 2005 Kenai Beluga Unit 11-8Y Top of Productive Horizon: 8. KB Elevation (ft): 15. Field/Pool(s): 865' FNL, 1087' FWL, Sec 8, T4N, R11 W, S.M. 87' Kenai Gas Field Total Depth: 9. Plug Back Depth(MD+TVD): Beluga/Upper Tyonek Pool 865' FNL, 1087' FWL, Sec 8, T4N, R11 W, S.M. 8160' / 7693' 4b. Location of Well (State Base Plane Coordinates): 10. Total Depth (MD + TVD 16. P operty Designation: ~ Surface: x- 275,205.83 y- 2,362,098.81 Zone- 4 8220' ~ ~,~ ~ -028142 TPI: x- 276,979.15 y- 2,361,107.05 Zone- 4 11. Depth Where SSSV Set: 17. Land Use Permit: Total Depth: x- 276978.68 y- 2361094.46 Zone- 4 N/A 18. Directional Survey: Yes Q No 19. Water Depth, if Offshore: 20. Thickness of Permafrost: N/A feet MSL NA 21. Logs Run: SP/GR-EL-Density/Neutron-Sonic-Single Arm Caliper. MFTs 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT ~ TOP BOTTOM TOP BOTTOM PULLED 20" 133 K-55 0 134' 0 134' Driven NA NA 13 3/8 68 L-80 0 1536' 0 1485' 16" 494 sacks NA 9 5/8 40 L-80 0 5812' 0 5346' 12-1/4" 571 sacks NA 3 1/2 9.3 L-80 0 8197' 0 7730' 8 1/2" 1112 sacks 85000 23. Perforations open to Production (MD +TVD of Top and Bottom 24. TUBING RECORD Interval, Size and Number; if none, state "none"): SIZE DEPTH SET (MD) PACKER SET (MD) MD (RKB) TVD (RKB) 3 1/2" 8197' N/A Module 1:8142-8152 7675-7685 Module 2: 8035-8044 7568-7578 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Module 3: 7723-7733 7256-7266 DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Module 4: 7572-7582 7150-7115 Module 1:8142-8152 BJ Lightning, 21497 Ibs prop Ottawa & Sand Module 5: 7019-7029 6552-6562 Module 2: 8035-8044 BJ Lightning, 21542 Ibs prop Ottawa & Sand Module 6: 6644-6654 6177-6187 Module 3: 7723-7733 BJ Lightning, 21914 Ibs prop Ottawa & Sand Module 7: 6533-6543 6066-6076 Module 4: 7572-7582 BJ Lightning, 24136 Ibs prop Ottawa & Sand Module 8: 6277-6287 5810-5820 Module 5: 7019-7029 BJ Lightning, 20550 Ibs prop Ottawa & Sand Module 9: 6099-6108 5633-5643 Module 6: 6644-6654 BJ Lightning, 24174 Ibs prop Ottawa & Sand Continued on back 26. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): September 21, 2006 FIOWIn Date of Test: Hours Tested: Production for Oil-Bbl: Gas-MCF: Water-Bbl: Choke Size: Gas-Oil Ratio: 10/1/2006 24 Test Period NA 1300 170 128/64th NA Flow Tubing Casing Press: Calculated Oil-Bbl: Gas-MCF: Water-Bb1: Oil Gravity -API (corr): Press. 210 0 24-Hour Rate ~ NA 1300 170 NA 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary). Spbmlt core chips; if none, state "none". None ~ ~ ~~~ ~ ~ ~~~~ ~ ~.:~' ~~ Y Alaseka_Cmpl 10-407.x1s Q ~ ~ ~ ~ ~~ ~ LCONTINUED ON REVERSE 2/9/2006 3:26 PM 28. GEOLOGIC MARKERS 29. FORMATION TESTS NAME M TVD Include and briefly summ est results. List intervals tested, and attach detailed supporting data as ecessary. If no tests were conducted, state "None". Beluga 5209 4751 Zone Top MD Top TVD Pressure Tyonek 7785 7318 M4 6097 5630 2437 M8 6275 5809 1837 M14 6532 6065 L2 6643 6176 2511 L9 7019 6552 2406 L17 7571 7104 72-8 7722 7259 1447/2052 73-1 8034 7567 73-1 8141 7674 30. List of Attachments: Directional Survey, Wellbore Diagram, Well Operations Summary 31. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: Printed Name: James R. Thompson Title: Senior Production Engineer Signature: Phone: 713-296-2730 Date: 2/9/2006 V 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 1 a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one poo! with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 13: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: True vertical thickness. Item 22: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 23: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 26: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 27: It no cores taken, indicate "none". Item 29: List all test information. If none, state "None". 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Module 7: 6533-6543 BJ Lightning_V_1600, 22701 Ibs prop (20/40 Ottawa & 12/20 Flex Sand) Module 8: 6277-6287 BJ Lightning_V_1600, 26525 Ibs prop (20!40 Ottawa & 12!20 Fiex Sand} Module 9: 6099-6109 BJ Lightning_V_1600, 27129 Ibs prop (20!40 Ottawa & 12/20 Flex Sand) Form 10-407 Revised 12/2003 KBU 11-8Y Alaska_Cmpl_10-407.x1s 2/9/2006 3:25 PM SURVEY LISTING Page 1 Wellbore: KBU 11-8Y ~~„~~ Wellpath: MWD <0-8220> - - Date Printed: 14-Ju1-2005 iV~'[~f~ Wellbore Name Created Last Revised KBU 11-SY 6-Jul-2005 14-Jul-2005 WeII _ ___ _ _ ~ Slot Name Grid Northin Grid Eastin Latitude Lon itude North East slot# KBU11-8Y 2362098.8100 275205.8300 N60 27 35.1615 W151 14 43.2779 117.50N 4288.53E Installation Name Eastin Northin Coord S stem Name North Ali nment Pad 41-7 270916.0101 2362063.9749 AK-4 on NORTH AMERICAN DATUM 1927 datum True Field Created_ By ___ ____ Comments _ All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 87.8ft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 118.04 degrees Bottom hole distance is 2037.66 Feet on azimuth 118.45 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~1 LJ SURVEY LISTING Page 2 Wellbore: KBU 11-8Y Wellpath: MWD <0-8220> Date Printed: 14-Ju1-2005 _.._-__ BAIC~R'. l~~G~lEI~ __..~ _ _ 1 ~ "I~ [~; t,~ Well ath Grid Re ort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg de /100ft Vertical Section ft Easting Northing 0.00 0.00 0.00 0.00 O.OON 0.00E 0.00 0.00 275205.83 2362098.81 196.00 0.80 222.40 195.99 1.01S 0.92W 0.41 -0.34 275204.89 2362097.82 257.00 0.70 219.20 256.99 1.61 S 1.45W 0.18 -0.52 275204.35 2362097.22 317.00 0.90 226.30 316.98 2.22S 2.02W 0.37 -0.74 275203.77 2362096.63 377.00 1.00 231.50 376.97 2.88S 2.77W 0.22 -1.09 275203.01 2362095.99 437.00 0.90 186.50 436.97 3.67S 3.23W 1.22 -1.13 275202.53 2362095.20 498.00 1.70 156.30 497.95 4.97S 2.92W 1.68 -0.24 275202.81 2362093.89 559.00 2.60 147.30 558.91 6.97S 1.81 W 1.57 1.68 275203.89 2362091.88 621.00 3.70 134.90 620.81 9.56S 0.37E 2.08 4.82 275206.02 2362089.24 680.00 4.80 130.60 679.65 12.51S 3.59E 1.94 9.05 275209.18 2362086.23 741.00 6.70 128.10 740.34 16.37S 8.33E 3.14 15.04 275213.85 2362082.29 803.00 8.70 124.30 801.78 21.24S 15.05E 3.33 23.27 275220.47 2362077.29 867.00 10.80 120.60 864.85 27.02S 24.21E 3.42 34.07 275229.52 2362071.33 929.00 12.50 120.10 925.57 33.35S 35.02E 2.75 46.58 275240.21 2362064.81 993.00 15.20 117.90 987.71 40.75S 48.42E 4.30 61.89 275253.47 2362057.16 1056.00 17.70 117.40 1048.12 49.02S 64.23E 3.97 79.73 275269.12 2362048.59 1119.00 19.50 118.40 1107.83 58.43S 81.98E 2.90 99.83 275286.69 2362038.84 1182.00 21.00 116.80 1166.93 68.52S 101.31E 2.54 121.63 275305.82 2362028.39 1245.00 22.30 116.60 1225.49 78.96S 122.07E 2.07 144.86 275326.38 2362017.56 1308.00 24.10 118.30 1283.39 90.42S 144.09E 3.05 169.68 275348.18 2362005.69 1371.00 27.30 116.60 1340.16 102.99S 168.34E 5.21 196.99 275372.18 2361992.66 1434.00 29.10 115.50 1395.68 116.05S 195.09E 2.97 226.74 275398.68 2361979.10 1493.00 29.50 115.90 1447.13 128.57S 221.10E 0.75 255.59 275424.45 2361966.09 1561.00 29.00 117.30 1506.46 143.45S 250.81E 1.25 288.80 275453.87 2361950.65 1624.00 28.40 118.40 1561.72 157.58S 277.56E 1.27 319.06 275480.35 2361936.02 1687.00 28.30 115.50 1617.16 171.13S 304.22E 2.19 348.96 275506.75 2361921.96 1748.00 28.20 114.60 1670.90 183.36S 330.38E 0.72 377.79 275532.67 2361909.25 1811.00 27.80 115.00 1726.52 195.76S 357.23E 0.70 407.32 275559.27 2361896.34 1938.00 28.60 117.60 1838.45 222.36S 411.01E 1.15 467.29 275612.54 2361868.73 2064.00 28.60 117.60 1949.08 250.31 S 464.46E 0.00 527.61 275665.45 2361839.78 2191.00 28.10 116.60 2060.85 277.78S 518.14E 0.54 587.90 275718.60 2361811.29 2317.00 28.00 115.90 2172.05 303.99S 571.28E 0.27 647.12 275771.23 2361784.09 2440.00 29.60 118.70 2279.84 331.19S 623.90E 1.70 706.36 275823.33 2361755.90 2566.00 29.40 117.80 2389.50 360.56S 678.56E 0.39 768.40 275877.42 2361725.50 2692.00 29.10 118.50 2499.43 389.60S 732.84E 0.36 829.97 275931.14 2361695.44 2818.00 29.20 118.00 2609.48 418.65S 786.90E 0.21 891.34 275984.64 2361665.37 2945.00 29.10 118.00 2720.39 447.69S 841.52E 0.08 953.20 276038.70 2361635.30 3072.00 28.90 118.80 2831.47 476.98S 895.68E 0.34 1014.77 276092.30 2361605.00 3197.00 28.80 118.40 2940.95 505.85S 948.64E 0.17 1075.08 276144.69 2361575.14 3324.00 28.60 119.40 3052.35 535.32S 1002.03E 0.41 1136.06 276197.52 2361544.66 3450.00 28.40 119.00 3163.08 564.65S 1054.51E 0.22 1196.17 276249.43 2361514.34 3576.00 30.20 118.40 3272.96 594.25S 1108.60E 1.45 1257.83 276302.95 2361483.73 3701.00 30.20 118.00 3380.99 623.97S 1164.02E 0.16 1320.70 276357.79 2361452.97 3826.00 29.80 118.90 3489.25 653.74S 1218.97E 0.48 1383.20 276412.16 2361422.17 3952.00 29.90 118.90 3598.53 684.05S 1273.87E 0.08 1445.91 276466.48 2361390.83 4077.00 29.40 118.60 3707.17 713.79S 1328.09E 0.42 1507.74 276520.12 2361360.07 4204.00 29.30 118.70 3817.86 743.64S 1382.71E 0.09 1569.98 276574.17 2361329.19 4329.00 29.00 117.90 3927.03 772.50S 1436.32E 0.39 1630.87 276627.22 2361299.32 4393.00 27.40 118.80 3983.43 786.86S 1462.94E 2.59 1661.11 276653.56 2361284.47 4456.00 25.30 118.10 4039.89 800.18S 1487.52E 3.37 1689.07 276677.89 2361270.68 4519.00 22.90 118.90 4097.39 812.45S 1510.13E 3.84 1714.79 276700.26 2361257.99 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 87.8ft above. mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 118.04 degrees Bottom hole distance is 2037.66 Feet on azimuth 118.45 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated r~ I. J SURVEY LISTING Page 3 Wellbore: KBU 11-8Y Wellpath: MWD <0-8220> Date Printed: 14-Ju1-2005 B ~~~5 We ll ath G rid Re ort MD[ft] Inc[deg] Azi(deg] TVD[ft] North[ft] East[ft] Dogleg de /100ft Vertical Section ft Easting Northing 4580. 00 21.20 117 .50 4153. 93 823 .28S 1530 .30E 2.92 1737. 69 276720. 22 2361246. 78 4644. 00 20.00 117 .40 4213. 83 833 .66S 1550 .29E 1.88 1760. 20 276740. 00 2361236. 02 4707. 00 19.70 117 .30 4273. 09 843 .49S 1569 .29E 0.48 1781. 60 276758. 82 2361225. 84 4770. 00 19.20 117 .90 4332 .49 853 .21 S 1587 .88E 0.85 1802. 57 276777. 22 2361215. 77 4832. 00 18.70 117 .40 4391. 13 862 .55S 1605 .71E 0.85 1822. 71 276794. 87 2361206. 09 4896. 00 18.50 118 .00 4451. 79 872 .04S 1623 .79E 0.43 1843. 12 276812. 76 2361196. 26 4959. 00 18.50 117 .10 4511. 53 881 .28S 1641 .51E 0.45 1863. 11 276830. 31 2361186. 68 5022. 00 18.10 116 .80 4571 .35 890 .25S 1659 .14E 0.65 1882. 89 276847. 77 2361177. 39 5085. 00 17.30 117 .20 4631. 37 898 .94S 1676 .21E 1.28 1902. 04 276864. 66 2361168. 37 5149. 00 15.80 117 .00 4692. 71 907 .25S 1692 .43E 2.35 1920. 26 276880. 73 2361159. 76 5212. 00 14.60 115 .80 4753 .51 914 .60S 1707 .23E 1.97 1936. 77 276895. 38 2361152. 13 5275. 00 13.40 117 .10 4814 .64 921 .38S 1720 .87E 1.97 1952. 01 276908. 90 2361145. 09 5338. 00 12.10 116 .50 4876 .08 927 .65S 1733 .28E 2.07 1965. 91 276921. 18 2361138. 59 5401. 00 10.90 116 .10 4937 .81 933 .22S 1744 .54E 1.91 1978. 46 276932. 34 2361132 .81 5464. 00 10.00 115 .60 4999 .77 938 .20S 1754 .82E 1.44 1989. 88 276942. 52 2361127. 63 5527. 00 8.90 117 .10 5061 .91 942 .79S 1764 .10E 1.79 2000. 22 276951. 70 2361122. 88 5589. 00 7.40 117 .30 5123. 29 946 .80S 1771 .91E 2.42 2009. 01 276959. 44 2361118 .71 5652. 00 5.20 119 .20 5185 .90 950 .06S 1778 .01E 3.51 2015. 92 276965. 48 2361115 .34 5762. 00 2.10 116 .60 5295 .67 953 .39S 1784 .17E 2.82 2022. 92 276971. 57 2361111. 89 5820. 00 1.70 117 .50 5353 .63 954.27S 1785 .88E 0.69 2024. 84 276973. 27 2361110. 99 5945 .00 1.60 124 .80 5478 .58 956 .12S 1788 .96E 0.19 2028. 43 276976. 31 2361109 .08 6070. 00 1.60 123 .90 5603 .53 958 .09S 1791 .84E 0.02 2031. 90 276979. 15 2361107 .05 6195. 00 0.90 136 .80 5728 .50 959 .78S 1793 .96E 0.60 2034. 56 276981. 24 2361105. 33 6321 .00 0.70 139 .30 5854 .49 961 .OBS 1795 .14E 0.16 2036. 22 276982. 39 2361104 .00 6448. 00 0.70 138 .20 5981 .48 962 .25S 1796 .16E 0.01 2037. 67 276983. 40 2361102 .81 6574. 00 0.60 143 .80 6107 .47 963 .35S 1797 .06E 0.09 2038. 98 276984. 28 2361101. 69 6700. 00 0.40 150 .60 6233 .47 964 .27S 1797 .67E 0.17 2039. 95 276984. 86 2361100 .76 6825 .00 0.40 137 .00 6358 .47 964 .97S 1798 .18E 0.08 2040. 73 276985. 36 2361100 .05 6951. 00 0.30 136 .50 6484 .46 965 .53S 1798 .71E 0.08 2041. 46 276985. 88 2361099 .48 7077. 00 0.20 174 .00 6610 .46 965 .99S 1798 .96E 0.15 2041. 89 276986. 12 2361099. 02 7204 .00 0.20 211 .30 6737 .46 966 .40S 1798 .87E 0.10 2042. 01 276986. 02 2361098 .61 7330 .00 0.30 190 .90 6863 .46 966 .91S 1798 .69E 0.11 2042. 09 276985. 83 2361098 .11 7456. 00 0.30 227 .00 6989 .46 967 .46S 1798 .39E 0.15 2042. 08 276985. 52 2361097. 56 7582 .00 0.30 236 .00 7115 .46 967 .87S 1797 .87E 0.04 2041. 82 276985. 00 2361097 .16 7708 .00 0.40 262 .60 7241 .45 968 .11S 1797 .16E 0.15 2041. 31 276984. 28 2361096 .93 7833. 00 0.40 243 .70 7366 .45 968 .36S 1796 .34E 0.11 2040. 70 276983. 46 2361096 .70 7960. 00 0.80 240 .80 7493 .44 968 .99S 1795 .17E 0.32 2039. 96 276982. 27 2361096. 09 8114 .00 0.90 246 .90 7647 .43 969 .99S 1793 .12E 0.09 2038. 62 276980. 20 2361095 .13 8167. 00 0.90 244 .60 7700 .42 970 .33S 1792 .36E 0.07 2038. 11 276979. 44 2361094. 81 8220. 00 0.90 244 .60 7753 .41 970 .68S 1791 .61E 0.00 2037. 61 276978. 68 2361094. 46 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Glacier 1 87.Sft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 118.04 degrees Bottom hole distance is 2037.66 Feet on azimuth 118.45 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated L~ SURVEY LISTING Page 4 Wellbore: KBU 11-8Y Wellpath: MWD <0-8220> Date Printed: 14-Ju1-2005 I'~"CI'~ Comments MD ft TVD ft North ft East ft Comment 8220.00 7753.41 970.68S 1791.61E - _ Pr~ction to TD _ All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Glacier 1 87.8ft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 118.04 degrees Bottom hole distance is 2037.66 Feet on azimuth 118.45 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated • RT-GL: 21.00' RT-THF: 21.70' 89' FSL, 705' FEL, Sec. 6, T4N, R11 W, S.M. Tree cxn = 4-3/4" Otis ~, Drive Piae: 20", 133 ppf, K-55 to 134' ~' _ ~ ~ '~ Surface Casino: 13-3/8", 68 ppf, J-55, BTC '~ ~ 1536' Cmt w/ 494 sx. of Type 1 at 12 ~ PPg• ~'', ~ Int. Casina: 9-5/8", 40 ppf, L-80, BTC ~ TOC (est.) - 4574' MD 3-1/2" x 9-5/8" ~,~ ~ 5812' Cmt w/ lead of 323 sx of class G ~ ~ ~ 12.5 ppg followed by tail of 248 sxs class G a.' ~ 13.5 PP9 ' ~ ", Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 8197' -~' Cmt w/ 1112 sx of class G at 15.8 ppg i f i r Excape System Details - Ceramic flapper valves below each module as follows: Module 1 - NA Module 2 - 8053' Module 3 - 7741' Module 4 - 7590' Module 5 - 7038' Module 6 - 6662' Module 7 - 6551' Module 8 - 6294' Module 9 - 6116' ~~~ . I~ ~~~ ~~ K ~'~ f~~ ~~ .: - "'~! ~)~ '~ fj f' ~~ IM ~t TD - 8220' PBTD - 8160' Excape System Details - 9 Excape modules placed -Green control line fires bottom module -Red contol line firestop 8 modules - Ceramic flapper valves below each module except for module 1 Module 1 - 8142-8152' (Tyonek) Module 2 - 8035-8045' (Tyonek) Module 3 - 7723-7733' (Tyonek) Module 4 - 7572-7582' (Beluga) Module 5 - 7019-7029' (Belulga) Module 6 - 6644-6654' (Beluga) Module 7 - 6533-6543' (Beluga) Module 8 - 6277-6287' (Beluga) Module 9 - 6099-6109' (Beluga) Well Name & Number: KBU 11-8Y Lease: Kenai Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) See Above (TVD) Angle/Perfs Angle G KOP and Depth BHP: BHT: Completi on Fluid: 6% KCL Dated Completed: 9/20/2005 Prepared By: J. R. Thompson Last Revison Date: 9/15/2005 Marathon Oil Company Operations Summary Report -Per Well Legal Weil Name: Common Well Name Event Date Event Report Date From - To Page 1 of 8 KENAI BELUGA UNIT 11-8Y KENAI BELUGA UNIT 11-8Y Spud Date: 7/1/2005 -_- - Hours Code Sub Phase Event Type --/-- Objective Gode SideTrack- --/-- Description of Operations 6/29/2005 Event 7/1/2005 12:00 - 00:00 12.00 RURD RIG_ MIRU 00:00 - 06:00 6.00 RURD_ RIG_ MIRU '2/2005 06:00 - 12:00 6.00 RURD_ RIG_ MIRU 12:00 - 13:00 1.00 SAFETY MTG_ MIRU 13:00 - 18:30 5.50 RURD_ RIG_ MIRU 18:30 - 20:30 2.00 NUND BOPE MIRU 20:30 - 00:00 3.50 RURD_ RIG_ MIRU 00:00 - 04:00 4.00 RURD_ RIG_ MIRU 04:00 - 06:00 2.00 NUND BOPE SURDRL 7/3/2005 06:00 - 10:30 4.50 NUND BOPE SURDRL 10:30 - 12:00 1.50 TEST BOPE SURDRL 12:00 - 15:00 3.00 REPAIR RIG_ SURDRL ~ 15:00 - 17:00 2.00 PULD_ DP_ SURDRL 17:00 - 18:30 ~ 1.50 PULD_ BHA_ SURDRL 18:30 - 06:00 11.50 DRILL_ ROT_ SURDRL 7!4/2005 06:00 - 12:30 6.50 DRILL ROT SURDRL 12:30 - 13:30 1.00 CIRC MUD_ SURDRL 13:30 - 15:00 1.50 _ TRIP_ WIPR SURDRL 15:00 - 15:30 0.50 SERVIC RIG_ SURDRL 15:30 - 16:30 1.00 TRIP_ WIPR SURDRL 16:30 - 17:30 1.00 CIRC_ MUD_ SURDRL 17:30 - 19:00 1.50 TRIP_ DP_ SURDRL 19:00 - 20:30 1.50 PULD_ BHA_ SURDRL 20:30 - 21:00 0.50 CLEAN_ RIG_ SURCSG 21:00 - 23:30 2.50 RURD_ CSG_ SURCSG 23:30 - 00:00 0.50 RUN_ CSG_ SURCSG 00:00 - 00:30 0.50 SAFETY MTG_ SURCSG 00:30 - 03:30 3.00 RUN_ CSG_ SURCSG 03:30 - 05:00 1.50 RURD_ CSG_ SURCSG 05:00 - 05:30 0.50 RURD_ EOIP SURCSG 05:30 - 06:00 0.50 TRIP_ EOIP SURCSG 7/5/2005 06:00 - 07:00 1.00 TRIP_ TOOL SURCSG 07:00 - 08:00 1.00 CIRC_ MUD_ SURCSG 08:00 - 09:30 ~ 1.50 PUMP_ CMT_ SURCSG ORIGINAL DRILLING --/-- Development-Gas OH --/-- PJSM: Move sub, pits, pump room, carrier, boiler house, water tank, hanson tank, Generator, All camp trailers, Set in sub and jack up, Set mud pits, and carrier, and hook up same. PJSM:Change out safety lines on angle lift antifall device on derrick climber, stabbing board and pull wires, PJSM: with crane operator set in outriggers and set doghouse and choke manifold house. OH --/-- PJSM:Rig pits, stairs to doghouse, Set in trip tank, Scope up top section of derrick. Safety meeting with both crews PJSM: R/U beaver slide, catwalk, set in pump #3, General R/U PJSM:Make final cut on 20" and install starter head and test to 1200 psi. for 10 min. PJSM: R/U floor, Torque tube, fill pits and mix spud mud, PJSM: R/U top drive and rig floor and mix spud mud, accept rig at 00:00 hrs. 7/2/2005 PJSM: Nipple up diverter. No accidents, No injuries OH --/-- PJSM: N/U Diverter system PJSM: Function test diverter system and koomey test. Chuck Sheve with AOGC waived test, and Tim Lawlor W/ BLM PJSM: Rig safety audit ,Trouble shoot Denison, Repair derrick finger and turnbucklle pad with welder. PJSM: P/U M/U and stand back 25 stds 5" DP PJSM: P/U and make up Bha while cleaning out conductor to 134' PJSM: Dir drill and survey F/ 134' to1000' (ART=2.4hrs. AST=2.8 hrs) OH --/-- PJSM: Dir drill and survey F/1000' to 1550' (AST= 2.5hrs. ART=1.1 hrs) Circ Hi-Vis sweep around at 640 gpm, 1500 psi. PJSM:FIow Check, POOH to 130' (No drag, gain, loss, torque) PJSM:Service rig PJSM: TIH to 1550' (No noticeable fill) Circ Hi-Vis sweep @ 640 gpm, 1500 psi. with Safe Garb 250 to determine washout 17% by volume. PJSM:FIow Check, POOH to Bha. PJSM: UD Bha #1 PJSM: Clean floor in prep for csg job. PJSM: Rig up weatherford 13 3/8" csg running tools. M/U Jts. 1 and 2 and float equipment and check floats. Hold safety meeting at crew change Run a total of 35 jts. 13 3/8" 68# J55 BTC CSG. to 1536' PJSM: R/D Weatherford csg tools PJSM: R/U Drill pipe tongs elevators bails and elevators. PJSM: M/U Stab in tools and RIH with same on 5" DP OH --/-- PJSM: RIH with stab in tool and locate in stab in collar @ 1489' PJSM: Circ @ 400 gpm, 500 psi. PJSM: Pump 40 bbl. mud clean 11 preflush w/ rig turn to BJ pump 2 bbls water, test lines to 2000 psi. Mix and pump 494 sxs Type 1 cement with 22 % LW 6,20%MPA 1, 1 %A-2, .3%CD 32, 2% CaCl12, 1 ghs FP6L, At 12.0 ppg, (218 bbl. slurry) Displace With 2 bbl. water and 19.4 bbl. mud cut displacement short by 5 bbl. Had good cement returns to surface at 11 bbls away during displacement. Check floats OK. Cement in place @ 0930 hrs. Printed: 2/9/2006 4:20:47 PM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Name: 'Event Dat~Event ,Report Date From - To 08:00 - 09:30 09:30 - 13:30 13:30 - 17:30 17:30 - 19:30 19:30 - 00:00 KENAI BELUGA UNIT 11-8Y KENAI BELUGA UNIT 11-8Y Hours ~~, Code Code Phase 1.50 PUMP_ CMT_ SURCSG 4.00 CIRC_ MUD_ SURCSG 4.00 WAITON CMT_ SURCSG 2.00 NUND ROPE SURCSG 4.50 NUND BOPE SURCSG 00:00 - 06:00 ' 6.00 NUND BOPE SURCSG 7/6/2005 06:00 - 11:30 5.50 TEST BOPE SURCSG 11:30 - 12:00 0.501 RUNPUL WBSH SURCSG 12:00 - 12:30 0.50 TEST_ CSG_ SURCSG 12:30 - 18:30 6.00 PULD_ DP_ SURCSG 18:30 - 21:00 2.50 PULD_ BHA_ SURCSG 21:00 - 22:00 1.00 TRIP_ DP_ SURCSG 22:00 - 23:00 1.00 DRILL_ CMT_ SURCSG 23:00 - 00:00 1.00 CIRC_ MUD_ SURCSG 00:00 - 00:30 0.50 CIRC_ MUD_ SURCSG 00:30 - 01:30 1.00 TEST_ LOT_ SURCSG 01:30 - 06:00 4.50 DRILL ROT IN1 DRL 7/7/2005 06:00 - 00:00 18.00 DRILL ROT INIDRL 00:00 - 01:30 1.50 CIRC_ MUD_ IN1 DRL 01:30 - 03:30 2.00 TRIP_ WIPR IN1DRL M 03:30 - 04:30 1.00 SERVIC RIG_ IN1DRL 04:30 - 05:30 1.00 TRIP_ WIPR IN1DRL 05:30 - 06:00 0.50 DRILL_ ROT_ IN1 DRL 7/8/2005 06:00 - 06:00 24.00 DRILL_ ROT_ IN1DRL 7/9/2005 06:00 - 16:00 10.00 DRILL_ ROT_ IN1DRL 16:00 - 17:30 1.50 CIRC_ MUD_ IN1EVL 17:30-18:30 1.00 DRILL_ ROT_ IN1DRL 18:30 - 20:30 2.00 CIRC_ MUD_ IN1DRL 20:30 - 01:00 4.50 TRIP_ WIPR IN1DRL 01:00 - 01:30 0.50 SERVIC RIG_ IN1 DRL 01:30 - 04:30 3.00 TRIP_ WIPR IN1DRL 04:30 - 06:00 1.50 CIRC MUD IN1 DRL 7/10/2005 06:00 - 07:30 1.50 CIRC_ MUD_ IN1DRL 07:30 - 13:00 5.50 TRIP_ DP_ IN1DRL 13:00 - 15:00 2.00 PULD BHA IN1DRL Event Type --/-- Objective SideTrack- --/-- Description of Operations Page 2 of 8 Spud Date: 7/1/2005 7/4/2005, Tim Lawlor with BLM waived cement job. PJSM: Pull 2- stds and circ cement out of 13 3/8", POOH 5" DP WOC, and prep diverter for N/D, Clean pits PJSM: P/U Diverter and Rough cut 13 3/8" and N/D Diverter PJSM: Remove 20" starting head, Cut 20" and make final cut on 13 3/8" install 13 3/8" vetco gray Multi Bowl head and test to 1500 psi. for 15 min good test. PJSM: Nipple up BOP stack and related equipment. OH --/-- PJSM: R/U test equipment and presurre test BOP stack and all related equipment. 250/2000 psi. Test waived by Chuck Sheve w/AOGC and Tim Lawlor with BLM PJSM: Run and set wear Bushing PJSM: Test csg to 2000 psi. for 30 min. OK PJSM: P/U and stand back in derrick 5" DP PJSM: M/U BHA #2 PJSM: TIH with Bha #2 to 1425' tag cmt stringer PJSM:Drill Cmt and Float collar and shoe and 20' new hole - F/1550' to 1570' (ART=.25 hrs) PJSM: Circ Bottoms Up PJSM: Displace wellbore with Flo-Pro mud 9.1 ppg. PJSM: Run LOT (9.1 ppg. MW, Pressure 492, TVD 1497' =15.4 ppg.) PJSM:Dir drill and survey F/1570' to 1932' (ART=2.5hrs. AST=0.4 hrs) No loss, gain ,torque, drag, no accidents, no incidents. OH --/-- Dir drill and survey 12 1/4" hole F/1932' to 3885'. (ART=10.6hrs AST=0.7hrs) No loss, gain, torque, drag PJSM: Circ Hi-Vis sweep ,Flow check well pump slug. PJSM: Wiper TOH to csg shoe @ 1536' (No excessive torque, drag, gain, loss Service rig. (while servicing crown notice keeps in turnbuckles need to be tightened and did so) PJSM: Wiper TIH, tag ledge @ 3805' wash from 3805' - 3885' (No noticeable fill) PJSM: Dir drill and survey 12 1/4" hole F/3885' to 3933' (ART= .3hrs) OH --/-- Dir drill and survey F/3933' to 5282' (ART=9.7hrs. AST=6.0 hrs) OH --/-- Dir drill and survey F/5282' to 5750' (ART=3.6hrs. AST=2.8 hrs) Circ for samples @ 5750' MD. 5284' TVD. Dir drill and survey F/5750' to 5820' (ART=.9hrs) Pump Hi-Vis sweep ,@ 633 gpm, 2050 psi. Circ clean, Flow check, pump dry job. PJSM: Wiper POOH to shoe @ 1536' (Tight hole 3950' to 3884'). Bback ream with top drive through this area rest of hole in good shape on way out. Service rig PJSM:Wiper TIH, Tight @ 4632'-4740', 5700-5720', Wash do F/ 5700' to 5820' (No noticeable fill. ) Circ Hi-Vis sweep and work pipe (633 gpm, 2050 psi) Returns on sweep very high percentage increase of sand ,coal, clay type material recovered. no loss, gain, drag ,torque, normal. Max gas unit on bottoms up 300 units. OH --/-- Circ Hi-Vis sweep @ 633 gpm, 2050 psi.Flow check, pump dry job. PJSM:POOH, SLM drill pipe, tight spot @ 5410' PJSM: UD Bha #2 Printed: 2/9/2006 4:20:47 PM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Name: Event Date Event Report Date From - To 7/11 /2005 7/12/2005 15:00 - 16:30 16:30 - 17:00 17:00 - 18:30 18:30 - 20:30 20:30 - 22:30 22:30 - 23:00 23:00 - 02:00 02:00 - 03:00 03:00 - 04:00 04:00 - 06:00 06:00 - 06:30 06:30 - 07:00 07:00 - 09:30 09:30 - 13:00 13:00 - 13:30 13:30 - 14:30 14:30 - 15:00 KENAI BELUGA UNIT 11-8Y KENAI BELUGA UNIT 11-8Y ___- ~ Hours Code Code Phase 1.50 ELEC IN1EVL 0.50 ELEC IN1EVL 1.50 ELEC IN1EVL 2.00 ~OH_ IN1EVL 2.00 ELEC IN1EVL 0.50 ELEC IN1EVL 3.00 OH_ IN1EVL 1.00 ELEC IN1EVL 1.00 BHA_ IN1CSG 2.00 DP_ IN1CSG 0.50 DP_ IN1CSG 0.50 WASH FILL IN1CSG 2.50 MUD_ IN1CSG 3.50 DP_ IN1CSG 0.50 BOPE IN1CSG 1.00 ~BOPE IN1CSG 0.50 _ ~EQIP IN1CSG Event Type --/-- Objective SideTrack- --/-- Description of Operations Page 3 of 8 Spud Date: 7/1/2005 PJSM: R/U Schlumberger and rih with DSI to 5760' tag. (electrical short developed) PJSM: POOH, with DSI tool PJSM: Chg out DSI logging tool RIH with DSI tool and log F/5761' to1536' POH,R/D Schlumberger PJSM: R/U Precision logging quad combo logging tool RIH with quad combo logging tool to 5761' PJSM: POOH with Quad combo logging tool log F/5762' to 1536' PJSM: R/D precission logging tools PJSM: M/U Bha # 3 for clean out run PJSM: TIH with Bha #3 OH --/-- TIH to 5760' tag bridge Wash through bridge and continue to wash to 5812' Circ Hi-Vis sweep, check flow, pump dry job. PJSM: POOH PJSM: Change variable bore rams to 9 5/8" csg rams and pull wear bushing. PJSM: Set test plug and test bop doors to 250/2000 psi pull test plug and rig down test equipment. PJSM: M/U 13 9/16" X 9 5/8" hanger assy to 9 5/8" landing joint .Make test run and verify hanger landed. L/D hanger assy. 15:00 - 18:00 3.00 RURD_ CSG_ IN1CSG PJSM:R/U 9 5/8" Csg. running tools. 18:00 - 18:30 0.50 SAFETY MTG_ IN1CSG Safety meeting with all parties involved in running 9 5/8" csg. 18:30 - 19:30 1.00 RUN_ CSG_ IN1CSG M/U Jts. 1-2-3 of 9 5/8" shoe track/ thread lock same and check floats. 19:30 - 01:30 6.00 RUN_ CSG_ IN1 CSG Run a total of 138 jts. 9 5/8" 40# L80 BTC Csg. M/U Landing Jt and hanger. Shoe set @ 5812' 01:30 - 02:30 1.00 CIRC_ MUD_ IN1CSG Pump 50 bbl. Icm sweep and circ @ 307 gpm 500 psi. 02:30 - 05:30 3.00 PUMP_ CMT_ IN1 CSG PJSM:Pump 5 water test lines to 4000 psi, pump 30 bbI.MCS-40 + 0.6 Ibs/bbl MCS-D + +621bs/bbl barite- sack+23.1 Ibs/bbl. bentonite- sack @ 10 ppg.+ 121 bbl. lead cmt. 323 sxs. "G" +0.2% bwoc CD-32+0.5% bwoc FL-52+1gals/100 sack FP-6L+2.2% bwoc sodium Metasilicate +105.9% fresh water. mixed @ 12.5 ppg. Pump 84 bbls. 248sxs. "G" +15% bwoc BA-90+2% bwoc Calcium Chloride+2.5% bwoc BA-56+ 0.5% bwoc EC-1+ 0.1 %bwoc ASA -301+1 gals/100sack FP-6L+0.5% bwoc Sodium Metasilicate+ 84.8% Fresh Water mixed @ 13.5 ppg. Displace with 5 bbl. water + 430 bbl. mud.slowed rate last 10 bbl. to 2.5 bpm 700 psi burned plug to 1400 psi. released floats held. bleed back 2.3 bbl. had low percentage of returns to full returns throughout job CIP@ 0530 hrs. 7/11/2005 (Job waived by Tim Lawlor with BLM) Lost app 478 bbl. througout job .Ended up with 630 psi of cement hydrostatic at end of job. 05:30 - 06:00 0.50 PULD EOIP INICSG UD Landing Joint and wash out stack. 06:00 - 08:00 2.00 RURD_ CMT_ IN1 CSG OH --/-- PJSM: R/D BJ cementing equipmenUD landing jt and wash out stack 08:00 - 09:00 1.00 TEST_ EOIP IN1CSG PJSM: Install 9 5/8" packoff and test to 5000 psi. F/15 min.(OK) 09:00 - 10:30 1.50 RURD_ EQIP IN1CSG PJSM: R/U drill pipe handling equipment 10:30 - 13:00 ~ 2.50 TEST_ BOPE IN1CSG PJSM: Set test plug, M/U test equipment and pressure test all BOP equipment to 250/2000 psi. perform koomey test; (Test waived by Jim Regg W/ AOGC) 13:00 - 13:30 0.50 SETREL PLUG IN1CSG PJSM: Pull test plug and set wear bushing. 13:30 - 14:00 0.50 SERVIC RIG_ IN1CSG PJSM: Service rig 14:00 - 16:30 2.50 LOG_ OTHR IN1CSG PJSM:R/U Expro E-line and run temperature survey determine possible scattered cmt 3350' to 3470' good cmt top @ 3760' R/D Expro RURD_ RUNPUL RURD_ LOG_ RURD_ RUNPU LOG_ RURD_ PULD_ TRIP_ TRIP CIRC_ TRIP_ NUND TEST_ RURD Printed: 2/9/2006 4:20:47 PM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Name: Event Date Event (Report pate ~~ From - To 16:30 - 17:30 17:30 - 19:00 19:00 - 21:30 21:30 - 23:30 23:30 - 00:00 00:00 - 01:00 01:00 - 01:30 01:30 - 06:00 7/13/2005 06:00 - 06:00 7/14/2005 ~ 06:00 - 12:00 12:00 - 15:00 15:00 - 21:00 21:00 - 21:30 21:30 - 23:00 23:00 - 03:30 KENAI BELUGA UNIT 11-8Y KENAI BELUGA UNIT 11-8Y Hours ~ Code Code Phase 1.00 TEST_ CSG_ INICSG 1.50 PULD_ BHA_ IN1CSG 2.50 TRIP_ DP_ IN1CSG 2.00 DRILL_ CMT_ IN1CSG 0.50 DRILL_ ROT_ IN1CSG 1.00 CIRC_ MUD_ IN1CSG 0.50 TEST_ LOT_ IN1CSG 4.50 DRILL_ ROT_ PR1DRL 24.00 DRILL_ ROT_ PR1DRL 6.00 DRILL ROT PR1DRL 3.00 CIRC MUD PR1DRL 6.00 TRIP_ WIPR PR1DRL 0.50 SERVIC RIG_ PR1DRL 1.50 TRIP_ WIPR PRIDRL 4.50 CIRC MUD PR1DRL 03:30 - 06:00 2.50 TRIP DP ~ PR1 DRL 7/15/2005 06:00 - 09:30 3.50 TRIP_ DP_ PR1 DRL 09:30 - 10:30 1.00 TRIP_ BHA_ PR1 DRL ' 10:30 - 12:00 1.50 RURD_ ELEC PR1 EVL 12:00 - 16:30 4.50 LOG_ OH_ PR1 EVL 16:30 - 17:00 0.50 RURD_ ELEC PR1 EVL 17:00 - 17:30 0.50 PULD_ BHA_ PR1 EVL 17:30- 19:00 1.50 PULD_ BHA_ PR1EVL 19:00 - 21:30 2.50 TRIP_ DP_ PR1EVL 21:30 - 02:00 4.50 CIRC MUD PR1 EVL 02:00 - 03:00 1.00 TRIP_ DP_ PR1 EVL 03:00 - 04:00 1.00 RURD_ ELEC PR1 EVL 04:00 - 06:00 2.00 LOG_ OH_ PR1 EVL 7/16/2005 06:00 - 11:00 5.00 LOG_ OH_ PR1 EVL 11:00 - 12:00 1.00 LOG_ OH_ PR1 EVL 12:00 - 12:30 0.50 TRIP_ DP_ PR1 EVL 12:30 - 19:30 7.00 LOG_ OH_ PR1 EVL 19:30 - 20:00 0.50 RURD_ ELEC PR1EVL 20:00 - 20:30 0.50 TRIP DP PR1 EVL Event Type --/-- Objective SideTrack- --/-- Description of Operations Page 4 of 8 Spud Date: 7/1/2005 PJSM: Test csg to 2000 psi. (good test) PJSM: M/U Bha #4 PJSM: TIH to 5727' Float collar ,Picking up 70 jts. dp from catwalk. PJSM: Drill shoe tract and clean out rat hole.F/5727' to 5820' Dir drill and survey F/5820' to 5840' (ART=.25) Circ wellbore clean and condition mud for LOT. Perform LOT(9.3 ppg mud+1550 psi.leak off psi@ 5345' TVD =14.88 ppg. EMW) Dir drill and survey F/5840' to 6220" (ART=2.85hrs AST=0.6hrs) OH --/-- Dir drill and survey F/6220' to 7887" (ART= 18.3hrs) OH --/-- Drill ahead 8 1/2 hole dretnl 7887 - 8220 ft. TD well 8220 ft as per MOC Geo Dept. No connection drag /torque /gain /loss. ART = 4hrs Circ /cond drlg fluids, background gas steady increase to 600 - 800 units. Raise mud wt to 9.9 ppg. Background decrease to 50 - 150 units. PJSM, flow check, POH wiper trip to shoe at 5812 ft. 15 - 25K over pull to 7259 ft, backream 7259 - 5812 ft. Large particles coal /clays / at shaker. No gain /loss. Service rig PJSM, flow check, RIH wiper trip, precaution wash 8180 - 8220 ft, 30 - 40 ft fill. Circ /cond fluids, gas peaks immediately 500 - 1800 units. 2800 units with increase in flowline flow at 3000 strokes. Shut in, cont Circ through choke 100 SPM / 810 PSI. Btms up gas decreasing slightly to 1800 - 2100 units. Raise mud wt to 10.1 ppg, linear decrease to 150 - 300 units and stable. 240 SPM / 1850 PSI. Note large particles coals /silt sand at shaker. Cont circ wellbore clean, no gain /loss. Pump hi vis sweep (shaker clean), wt pill. PJSM, flow check, POH 5" DP for E-logs. 5100 ft at 0600 hrs. No swab /gain /loss. Slight overpull 15000 K at 7119 ft, remainder good cond. OH --/-- Cont POH 5" DP for E-logs, no gain /loss /drag Flow check, Handle BHA #4, lay do dretnl assy / bit #4. PJSM, place E-log equip rig floor, RU same Flow check, commence RIH E-logs (Quad Combo). Open hole E-logs 8210 - 5800. Tag btm 8220 ft, 9 5/8 shoe 5810 ft. Rig do E-log equip, clear rig floor. RIH 5" HWDP POH laying do 5" HWDP Note slight flow /gas at flow check, RIH 5" DP to 8220 ft for mud wt. increase. Wt up surface volume to 10.5 ppg, displace /circ 10.5 ppg drlg fluid through choke holding differential for balance. 200 spm (550 psi initial, 675 psi final) Flow check, fluid column static. POH 5" DP to 6867 ft, no drag /gain /loss R/U E-log equip for RFT RIH wireline, commence E-logs (RFT) from 8159 ft OH --/-- Cont E-logs 7743 - 6967 with MFT Flow check, POH wireline, rig do sheaves. PJSM, POH 5" DP to 5820 ft. for E-logs E-logs 6831 - 5924 with MFT POH wireline, rig dn, lay out all equip, clear floor release unit. PJSM, flow check, RIH 5" DP to 8220 ft for gas circ, no do drag /fill Printed: 2/9/2006 4:20:47 PM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: _Common Well Name: Event Date Event Report Date From - To 20:00 - 20:30 20:30 - 22:00 7/17/2005 7/17/2005 22:00 - 00:00 00:00 - 01:00 01:00 - 04:00 04:00 - 05:00 05:00 - 06:00 06:00 - 07:00 07:00 - 07:30 07:30 - 08:00 08:00 - 09:00 09:00 - 19:00 19:00 - 20:00 Event 20:00 - 23:00 KENAI BELUGA UNIT 11-8Y KENAI BELUGA UNIT 11-8Y Hours Code Code Phase 0.50 TRIP_ DP_ PR1EVL 1.50 CIRC MUD PR1EVL 2.00 TRIP_ DP_ PR1EVL 1.00 SLPCUT DLIN PR1EVL 3.00 TRIP_ DP_ PRIEVL 1.00 RURD ELEC PR1EVL 1.00 LOG_ OH_ PR1 EVL 1.00 LOG_ OH_ PR1 EVL 0.50 LOG_ OH_ PR1 EVL 0.50 PULD_ LOG_ PR1 EVL 1.00 PULD_ LOG_ PR1EVL 10.00 LOG OH PR1 EVL 1.00 _ PULD _ i LOG PR1 EVL 3.00 ~ TRIP_ DP_ PR1CSG 23:00 - 01:00 2.00 CIRC_ MUD_ PR1CSG 01:00 - 06:00 5.00 PULD_ DP_ PR1CSG 7/18/2005 06:00 - 09:30 3.50 PULD_ DP_ PR1CSG 09:30 - 10:00 0.50 CLEAN_ RIG_ PR1CSG 10:00 - 10:30 0.50 RUNPUL WBSH PR1CSG 10:30 - 12:00 1.50 CHANG EOIP PR1CSG 12:00 - 14:00 2.00 RURD_ CSG_ PR1CSG ~ 14:00 - 21:30 7.50 RUN_ CSG_ PR1 CSG 21:30 - 22:00 0.50 CIRC_ MUD_ PR1CSG 22:00 - 00:00 2.00 RUN_ CSG_ PR1CSG 00:00 - 03:00 3.00 RUN_ CSG_ PR1 CSG 03:00 - 04:00 1.00 CIRC_ MUD_ PR1CSG 04:00 - 06:00 2.00 RUN_ CSG_ PR1 CSG 7/19/2005 06:00 - 07:00 1.00 CIRC_ MUD_ PR1CSG 07:00 - 09:00 2.00 RUN CSG PR1CSG 09:00 - 10:30 1.50 CIRC_ MUD_ PR1CSG 10:30 - 12:00 1.50 RURD_ ELEC PR1CSG 12:00 - 13:30 1.50 LOG_ CSG_ PR1CSG 13:30 - 14:30 1.00 LOG_ CSG_ PR1CSG 14:30-15:00 0.50 CIRC_ CFLD PR1CSG 15:00 - 16:00 1.00 RURD_ CMT_ PR1CSG 16:00 - 19:00 3.00 PUMP CMT PRICSG _- _ -- Event Type --/-- Objective SideTrack- --/-- Description of Operations Spud Date: 7/1/2005 Page 5 of 8 Circ /displace well with 10.7 ppg drlg fluids. Max gas 2328 units with no increase flowline flow. Initial 200 spm / 875 psi, final 200 spm / 930 psi (30 units) Flow check, fluid column static. PJSM, POH 5" DP to shoe at 5800 ft, no drag /gain /loss Slip / cut drlg line Flow check, PJSM, POH 5" DP to surface for E-logs PJSM, RU Schlum for E-logs RIH wireline, commence DSL 8220 - 7000 ft at 0600 hrs OH --/-- Cont E-logs (DSL), 7000 - 5800 ft POH wireline /DSL Flow check, lay do E-log equip PJSM, M/U CSAT log tools, surface test same. RIH CSAT, log 8220 -surface. Lay out all Schlum equip, clear floor, release unit. Begin completion phase. ORIGINAL COMPLETION --/-- Development -Gas PJSM, MU 8 1/2 clean out assy, RIH 5" DP to btm 8220 ft. no do drag /fill /gain /loss Flow check, circ / cond drlg fluids, btms up gas 480 units. No gain /loss Flow check, PJSM, POH laying do 5" DP. No swab /gain /loss. Correct hole fill. 5200 ft at 0600 hrs OH --/-- Lay Down D.P. & B.H.A. Clean Out Mousehole & Rig Floor Pull Wear Bushing R/D Rig Tongs, Spinners & UD All 5" D.P. Handling Tools C/O Bails& Elevators. R/U Circ.Line. R/U Weatherford Tongs. Hang Sheaves For Control Lines To Modules PJSM. M/U Shoe Track & Ck. Floats RIH W/ 3 1/2 EUE Excape Completion Completion system, 9 Modules & 53 Jts. 3 1/2 8 R/D Pipe T/ 2147 Circ. & Ck. Modules 200 spm. 1250 psi 3100 stks. RIH F/ 2147 T/ 3307 W/ 3 1/2 Excape Completion Run 3 1/2 Excape Completion F/ 3307 T/ 5812 Circ At 5812 9 5/8 Shoe 190 spm.= 1850 psi Gas Peak 180 Units. No Gain/ Loss, Correct Hole Fill. Run 3 1/2 Excape Completion Csg. To 6850' OH --/-- Circ. Btms. Up At 7000' 180 spm= 1900 psi/ 345 Units Gas at 12000 Stks, No Gain/ Loss. Flow Ck./ Cont. Rih W/ Excape Completion Csg. F-7000 To 8208. No Fill. Float Collar At 8160.70 Shoe At 8197.39. 9 modules total, 2 control lines, 1 sacrificial / line. Circ/ Cond. At 8208' 180 spm= 1775 psi / 620 Units. Gas at 14600 Stks. Shakers clean PJSM. & R/U To Run Expro Correlation Log. Rih w/ Gamma Ray and Correlation Log. No Correction to Shoe Depth. Pooh w/ Logging Tools PJSM/ Circ. And Spot Corrosion Inhibitor Lay Down 10ft Pup And M/U 5ft Pup R/U Cmt. Head/ Tee. wash Dn. LineTo Lower Cmt. Head To Floor. Commence Cement 3 1/2 Excape Completion; PJSM, pump 5 BBI Water, Test Lines 3500 psi. Mix And Pump 50 BBIs spacer. Mix And Pump 1112 Sx. Class G Cement Printed: 2/9/2006 4:20:47 PM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Name: Event Date Event Report Date From - To Page 6 of 8 KENAI BELUGA UNIT 11-8Y KENAI BELUGA UNIT 11-8Y Spud Date: 7/1/2005 Hours Code Sub phase Event Type --/-- Objective Code SideTrack- --/-- Description of Operations 16:00 - 19:00 ~ 3.00 PUMP_ CMT_ PR1 CSG 19:00 - 03:30 8.50 NUND BOPE PR1CSG 03:30 - 06:00 2.50 CUT_ CSG_ PR1CSG 06:00 - 06:30 0.50 NUND BOPE PR1CSG 06:30 - 07:30 1.00 NUND TREE PR1CSG 07:30 - 09:30 2.00 NUND TREE PR1CSG 09:30-11:00 1.50 SAFETY MTG_ PR1CSG 11:00 - 12:00 1.00 TEST TREE PR1CSG 12:00 - 12:30 0.50 TEST_ TREE PR1CSG 12:30 - 18:00 5.50 RURD RIG RDMO 18:00 - 00:00 6.00 RURD RIG RDMO 00:00 - 06:00 6.00 RURD_ R1G_ , RDMO 7/21/2005 106:00 - 12:00 I 6.001 RURD I RIG I RDMO 8/10/2005 ~ Event 8/10/2005 09:00 - 09:30 0.50 SAFETY MTG_ PR1CSG 09:30 - 09:45 0.25 SAFETY MTG_ PR1CSG ' 09:45 - 10:15 0.50 RURD_ ELEC PR1CSG 10:15 - 12:00 1.75 RUNPUL ELEC PRICSG 12:00 - 14:30 2.50 LOG_ CSG_ PR1CSG 14:30 - 15:10 0.67 RUNPUL ELEC PR1CSG 15:10 - 15:45 0.58 RURD_ ELEC PR1CSG 8/14/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM 8/15/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM 8/16/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM 8/17/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM 8/18/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM 8/19/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM 8/20/2005 ~ -06:00 - 18:00 12.00 RURD STIM CMPSTM 18:00 - 22:00 ~ 4.00 ~ PERF_ ~ CSG_ ~ CMPSTM 15.8 PPg /Yield 1.161, Total Slurry 230 BBIs. Drop Plug, Confirm Plug Drop W/ 5 BBIs Water. Displace Cement W/ 66.3 BBLs KCL Brine. Bump Plug Correct Dislacement W/ 2500 psi. Hold 2500 / 5 Min. For Csg. Test. Bleed/ Floats Holding. 100% Returns, ICP= 618 PSI, FCP= 1327 PSI No Gain/ Loss. Plug Bumped, Cement In Place At 1849 Hrs. PJSM /Nipple Down BOP Stack Cut Off 3 1!2 Csg. Final Prep For tree OH --/-- N/D BOP, Set Slips, Cut Csg. 16.44' Removed. Install Pack Off Test To 5000 psi F/ 5 Min. Terminate control lines, test same. Install 2 way Ck Nipple up Tree Standdown, MOC drug meeting. Test Tree 500/ 5000 Test Tubing Hanger Void to 5000 psi. Hold For 15 Min. Pre- Tour Mtg. ,Pull Two Way Ck. Valve And Set Back psi Valve Rig Down; Pits, Degasser, Blow Down Choke Manifold. R/d Service Lines,From Pits And #3 Mud Pump. Clean Sand Out Of Rig Water Tank R/D Same. Pump Out Fuel Tank Continue R/d; Top Drive, Monkey Board, Elect And Geronamo lines. R/D Cuttings Tank. R/D Steam, Water, Mud And Air Lines For Move. Remove Turnbuckles From Top Drive Torque tube. RID Torque Tube, Load Out Epoch Unit. R/D Floor, Snub Posts, Mud Manifold And Cylinder Tarps. Remove Carrier Exhaust. Remove Choke And Doghouse Lights. Scope Down Derrick OH --/-- PJSM, cont rig do on KBU 11-8Y, prepare for move. All loads /modules broken do /readied for move CLU-10. Glacier rig 1 released this date 7/21/05 1200 hrs to CLU-10 ORIGINAL COMPLETION --/-- Development -Gas OH --/-- Arrive at office, sign in, issue work permit, safety/procedure meeting. Well sight safety meeting, fill out TOOL location assessment RU E-line unit with packoff RIH w! bond tool Run CBL logging up pass. TOC--3465'. Finish logging, POOH. RD E-line OH --/-- Lay down liner and spot Sand Kings and Frac Tanks. RU frac tank manifold. Berm up liner. OH --/-- Started hauling water and filling frac tanks. Continued laying liner and berming same OH --/-- Finished hauling water and filling frac tanks. Finished laying out liner. OH --/-- RU flowback iron and equipment. Spotted CT unit and equipment. Started spotting well test equipment. OH --/-- Mixed 6% KCL in all frac tanks. OH --l-- Pressure test flowback and CT lines and equipment 250 Lo / 4500 High. OH --/-- Finished RU of all frac lines and trucks. Pressure test frac trucks and lines to 9500 psig. Perform site survey and check entire frac layout. RU expro firing lines to wellhead terminations. PT firing line to 10000 psig. Open green line valve and attempt to pressure up and fire module 1. Leak at 1/2" needle valve. Break out valve and inspectg threads. Threads damaged. Change out both red and green line valves and PT same. Pressure up on green line to 4000 psig and fire module 1 perforating 8142-8152' RKB. RD expro and SDFN Printed: 2/9/2006 4:20:47 PM Marathon Oil Company Page 7 of $ Operations Summary Report -Per Well Legai Well Name: KENAI BELUGA UNIT 11-8Y Common Well Name: KENAI BELUGA UNIT 11-8Y Spud Date: 7/1/2005 - -__-- ~IEvent Date .Event =Sub ' ,.Event Type --/-- Objective , 'Report Date From - To Hours Code i Code Phase SideTrack- --/-- Description of Operations _ _ 8/21/2005 _ 06:00 - 07:00 1.00 RURD_ , STIM _ CMPSTM _ __ OH --/-- Arrive location. Start frac trucks and warm up same. 07:00 - 07:30 0.50 SAFETY MTG_ CMPSTM Hold PJSM. Discuss frac operations, trips and falls, pinch points. 07:30 - 08:15 0.75 RURD_ STIM CMPSTM Perform flowback iron walk through and prime up pumps. 08:15 - 08:30 0.25 PUMP_ FRAC CMPSTM Open well. Perform injection test with 30 bbls 6% KCL. ISIP = 3315 psig. FG = 0.88 psi/ft. (Total Load = 30 bbls) 08:30 - 08:45 0.25 PUMP_ FRAC CMPSTM Frac mod 1 perfs (8142-8152' RKB) w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 5960 psi. Ramp 1.0 - 8.0 ppa. Placed 21497 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 239 bblsl. Tagged w/ ~ ~ ~ ProTechnics CFT 1000 chemical tracer and field tracer EPT 1000 (cumm. load = 269 bbls) (Strap chemical tanks post frac) 08:45 - 09:15 0.50 PUMP_ FRAC CMPSTM Perforate Module 2 at 8034 - 8044' RKB. Frac mod 2 w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 3600 psi. Ramp 1.0 - 8.0 ppa. Placed 21542 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 213 bbls. Tagged w/ ProTechnics CFT 1100 chemical tracer. (cumm. load = 482 bbls) (Strap chemical tanks post frac) 09:15 - 09:45 0.50 PUMP_ FRAC CMPSTM Perforate Module 3 at 7723 - 7733' RKB. Frac mod 3 w/ BJ Lightning V_1800 wtr based system at 15 BPM at max TP = 3218 psi. Ramp 1.0 - 8.0 ppa. Placed 21914 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 213 bbls. Tagged w/ ProTechnics CFT 1200 chemical tracer. (cumm. load = 695 bbls) (Strap chemical tanks post frac) 09:45 - 10:15 0.50 PUMP_ FRAC CMPSTM Perforate Module 4 at 7572 - 7582' RKB. Frac mod 4 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3430 psi. Ramp 1.0 - 8.0 ppa. Placed 24136 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 213 bbls. Tagged w/ ProTechnics CFT 1400 chemical tracer. (cumm. load = 908 bbls) (Strap chemical tanks post frac) 10:15 - 11:00 0.75 PUMP_ FRAC CMPSTM Spline on Sand King belt coupler broke. Replace same with new spline. 11:00 - 11:30 0.50 PUMP_ FRAC CMPSTM Perforate Module 5 at 7019 - 7029' RKB. Frac mod 5 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3570 psi. Ramp 1.0 - 8.0 ppa. Placed 20550 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 217 bbls. Tagged w/ ProTechnics CFT 1500 chemical tracer. (cumm. load = 1125 bbls) (Strap chemical tanks post frac) 11:30 - 12:00 0.50 PUMP_ FRAC CMPSTM Perforate Module 6 at 6644 - 6654' RKB. Frac mod 6 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3450 psi. Ramp 1.0 - 8.0 ppa. Placed 24174 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 212 bbls. Tagged w/ ProTechnics CFT 1600 chemical tracer. (cumm. load = 1337 bbls) (Strap chemical tanks post frac) 12:00 - 12:30 0.50 PUMP_ FRAC CMPSTM Perforate Module 7 at 6533 - 6543' RKB. Frac mod 7 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3255 psi. Ramp 1.0 - 8.0 ppa. Placed 22701 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 202 bbls. Tagged w/ ProTechnics CFT 1700 chemical tracer. (cumm. load = 1539 bbls) (Strap chemical tanks post frac) 12:30 - 13:00 0.50 PUMP_ FRAC CMPSTM Perforate Module 8 at 6277 - 6287' RKB. Frac mod 8 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3200 psi. Ramp 1.0 - 8.0 ppa. Placed 26525 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 213 bbls. Tagged w/ ProTechnics CFT 1900 chemical tracer. (cumm. load = 1752 bbls) (Strap chemical tanks post frac) 13:00 - 13:30 0.50 PUMP_ FRAC CMPSTM Perforate Module 9 at 6098 - 6108' RKB. Frac mod 9 w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 8500 psi. Extremely high surface pressure (7.5 bpm at 7000 psig). Suspect pert flow area in pipe. Pump 25 bbl scour with 1 ppg sand. Pump scour away and pressure down to 5200 psig at 15 bpm. Start frac design volumes. Ramp 1.0 - 8.0 ppa. Placed 27129 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 302 bbls. Tagged w/ ProTechnics CFT 2000 chemical tracer. (cumm. load = 2054 bbls) (Strap chemical tanks post frac) 13:30 - 16:30 3.00 RURD_ STIM CMPSTM Hold RD safety meeting. Perform pinch point survey. Rd frac equipment. RU CT. Function test blinds. Stab injector head onto wellhead. PT 4500 psig. 16:30 - 19:15 2.75 RUNPU COIL CMPSTM RIH with CT. circulating min rate of .3 bpm to 6000' CTM. Increase pump rate to 2 bpm. RIH breaking flappers Mod 9 @ 6103' CTM, Mod 4 @ 7570' CTM, Mod 3 @ 7722' CTM, and Mod 2 @ 8034' CTM. RIH to PBTD @ 8141' CTM. 19:15 - 23:00 3.75 CIRC_ CFLD CMPSTM Attempt to start nitrogen. Motor fan belt broke. Call replacement truck and RU same. POOH to 7820' CTM while circulating fluid. 23:00 - 03:45 4.75 JET_ N2_ CMPSTM Start Nitrogen at 500 scfm with fluid rate at 1.5 bpm. RIH to PBTD of 8141' CTM (no fill). Start POOH to above perforations at 6000' CTM pumping 1 bpm and 500 scfm> shut down fluid pump and jetted abover perfs with 500 scfm nitrogen. WHP r ~~ Printed: 2/9/2006 4:20:47 PM Marathon Oil Company Legal Well Name: Common Well Name: Event Date Event Report Date 'From - To Operations Summary Report -Per Wetf KENAI BELUGA UNIT 11-8Y KENAI BELUGA UNIT 11-8Y _ - - _ _ - - _ - - - Hours Code Sub Phase Event Type --/ -Objective !Code SideTrack- --/-- Description of Operations 23:00 - 03:45 I 4.75 !JET I N2 I CMPSTM 03:45 - 04:45 1.00 FLOW_ CHEK CMPSTM 04:45 - 05:30 0.75 RUNPU COIL CMPSTM 05:30 - 06:00 0.50 FLOW_ CHEK CMPSTM !!22!2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 9/23/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 9/24/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 9/25/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 9/26/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 9/27/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 9/28/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 9/29/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 9/30/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 10/1/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW 10/2/2005 06:00 - 09:30 3.50 FLOW TEST CMPFLW 09:30 - 18:00 8.50 RURD_ OTHR CMPFLW 10/22/2005 08:00 - 08:15 0.25 SAFETY MTG_ CMPFLW ~ 08:15 - 10:30 2.25 RURD_ ELEC CMPFLW 10:30 - 16:00 5.50 RUNPUL ELEC CMPFLW 16:00 - 17:30 1.50 CLNOU TBG_ CMPFLW 17:30 - 18:30 1.00 RURD_ ELEC CMPFLW /9/2006 07:00 - 07:30 0.50 SAFETY MTG_ CMPFLW 07:30 - 09:15 1.75 RURD SLIK CMPFLW 09:15 - 10:00 0.75 RUNPUL SLIK CMPFLW 10:00 - 10:30 0.50 RUNPU SLIK CMPFLW 10:30 - 14:30 4.00 LOG ~ CSG_ CMPFLW 14:30 - 15:00 0.50 RURD_ SLIK CMPFLW 15:00 - 16:00 1.00 RURD SLIK CMPFLW Page 8 of 8 Spud Date: 7/1/2005 increased from 67 psig to 400 psig. EPT-1000 field tracer detected in returns. RIH to PBTD jetting at 500 scfm WHP ranging from 200 to 400 psig. POOH to above perfs at 6000' and shut down nitrogen to monitor well response. WHP decreased from 300 psig to 0 psig. Well still flowing. WHP gradually increased to 110 psig. .POOH with CT. EPT-1000 field tracer still detected in returns. Get CT to surface. Stndby while monitoring well flow. WHP = 200 psig increased to 250 psig. Water rate = 800 to 1000 bwpd. Cum recovered = 132 bbls of 2054 total frac load. OH --/-- Flow test well. As of 0600 hrs 9122/05 well flowing 735 mcfd, FTP = 215 psig, bwpd = 350. OH --/-- Flow test well. As of 0600 hrs 9/23/05 well flowing 884 mcfd, FTP = 230 psig, bwpd = 413. OH --/-- Flow test well. As of 0600 hrs 9/24/05 well flowing 994 mcfd, FTP = 240 psig, bwpd = 198. OH --/-- Flow test well. As of 0600 hrs 9/25/05 well flowing 1083 mcfd, FTP = 255 psig, bwpd = 198. OH --/-- Flow test well. As of 0600 hrs 9/26/05 well flowing 1.13 mmcfd, FTP = 270 psig, bwpd = 188. OH --/-- Flow test well. As of 0600 hrs 9/27/05 well flowing 1.17 mmcfd, FTP = 275 psig, bwpd = 211. OH --/-- Flow test well. As of 0600 hrs 9/28/05 well flowing 1.17 mmcfd, FTP = 280 psig, bwpd = 194. OH --/-- Flow test Weil. As of 0600 hrs 9/29105 wel{ flowing 1.2 mmcfd, FTP = 285 psig, bwpd = 143. OH --/-- Flow test well. As of 0600 hrs 9/30/05 well flowing 1.2 mmcfd, FTP = 280 psig, bwpd = 213. OH --/-- Flow test well. As of 0600 hrs 10/1/05 well flowing 1.3 mmcfd, FTP = 215 psig, bwpd = 173. OH --/-- Final flow test data as of 0930 hrs 10/1/05 well flowing 1.3 mmcfd, FTP = 210 psig, bwpd = 170. Turned well over to production. RD well testing equipment and release well testers. OH --/-- Sign in at gas field, obtain work permit. Hold safety meeting. RU a-line unit to KBU 11-8y. PU and test camera. Run camera in well. Well flowing too much gas to see clearly. RIH through top three modules. Set down at 6551'. Camera shows closed, unbroken flapper. PUH to above modules and shut well in. Run through Mod. 9. See single row of bumps protruding into casing (0 deg phase) w/ occasional view of perf holes. Well begins loading with water obstructing camera's view. Getting hung up while POOH. Restore production and able to move again. POOH w/ camera. RIH w! flapper breaking assy. Contact and work through (break) flappers in modules 7, 6, 4, and 3. RD a-line unit. OH --/-- Arrive KGF. Sign in and obtain work permit. Hold PJSM Move equipment from KBU 41-6 to KBU 11-8Y. Move man lift from 14-6 pad to 41-7 pad and rig up lubricator onto KBU 11-8Y. Make up 2.3" gauge ring. RIH with gauge ring an dtag fill at 8110" SLM (8131' RKB) inbetween module 1 and 2. Module 1 covered with fill. POOH with gauge ring. Make up PLT tools and RIH with same. Run PLT at 60, 90 ,and 120 fpm on both up and down passes from 6000' to 8075' SLM (6021' - 8096' RKB) POOH RD PLT tools and slickline lubricator from well Secure well and leave location. Close out work permit and sign out. Printed: 2/9/2006 4:20:47 PM ~~ ~ _ ~ ~ ~ ~ x~ a 7 ~ ,~ ~ ~~ ~ ~~ ~ ''., ~, r ~ ,~ 4~ { ~ ,-~ ;~~ r FRANK H. MURKOWSKI, GOVERNOR ~~ OI~ ~ ~ ~ 333 W. 7TM AVENUE, SUITE 100 COrIT5ERQATI01~1T COMbII5SIOIQ ~~, ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Will Tank Advanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, TX 77253 Re: Kenai KBU 11-8Y Marathon Oil Company Permit No: 205-091 Surface Location: 89' FSL, 705' FEL, SEC. 6, T4N, R11 W, SM Bottomhole Location: 865' FNL, 1087 FWL, SEC. 8, T4N, R11 W, SM Dear Mr. Tank: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission t fitness any required test. Contact the Commission's petroleum field inspector at (90~ 659- 07 (pager). K. DATED this ~~day of June, 2005 cc: Department of Fish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. M Marathon MARATHON Oil Company June 6, 2005 Worldwide Drilling North America P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 t .„ . . John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 ~~,~t~. ~ _ ~ ~~ i' Reference: Drilling Permit Application Field: Kenai Gas Field Well: KBU 11-8Y Dear Mr. Norman Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is to drill a development well in the Beluga / i Upper Tyonek Pool in the Kenai Gas Field. No completion is desired in the Sterling pool. Please note that Marathon is requesting a waiver for 20 ACC 25.035 (e) (1) (b) requiring a ~, two pipe ram stack. The request is specified on page 12 of the attached drilling prognosis. If you require further information, I can be reached at 713-296-3273 or by a-mail at wjtank @ marathonoil.com. Sincerely, ®„~ M~.c, {"~ , Ste- i~ ~ l 2. Willard J. Tank Advanced Senior Drilling Engineer Enclosures STATE OF ALASKA SKA OIL AND GAS CONSERVATION MISSION PERMIT TO DRILL ` 20 aAC 25_no~ ~4~ ~/a~~.~s ~~ '"~ ~0~5 ia. Type of Work: Drill ~ Redrill Re-entry [] 1b. Current Well Class: Exploratory Development'Oil ~ CiRi Stratigraphic Test ~ Service ~ Development Gas ~ Q Single Zone 2. Operator Name: Marathon Oil Company 5. Bond: Blanket ~ Single Well Bond No. 5194234 11. Well Name and Number: KBU 11-8Y ~ 3. Address: P.O. Box 3128, Houston, TX 77253 6. Proposed Depth: MD: 7,854 TVD: 7,380 12. Field/Pool(s): Kenai Gas Field 4a. Location of Well (Governmental Section): Surface: 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M. 7. Property Designation: A-028142 Beluga /Upper Tyonek Pool Top of Productive Horizon: 865' FNL, 1,087' FWL, Sec. 8, T4N, R11 W, S.M. 8. Land Use Permit: 13. Approximate Spud Date: June 21, 2005 Total Depth: 865' FNL, 1,087' FWL, Sec. 8, T4N, R11W, S.M. 9. Acres in Property: 1,945 14. Distance to Nearest Property: 4,193 ft 4b. Location of Well (State Base Plane Coordinates): Surface: x - 275,205.83 y - 2,362,098.81 Zone - 4 10. KB Elevation (Height above GL): (21' AGL} 87 feet 15. Distance to Nearest Well Within Pool: 1,165 ft. to KBU 42-7 / 16. Deviated wells: Kickoff depth: 500 feet Maximum Hole Angle: 29.14 degrees 17. Maximum Anticipated Pressures in psig (see 20 AAC 25.035) Downhole: 3,454 Surface: 1,786 ~ 18. Casing Program: Size Specifications Setting Depth Top Bottom Quantity of Cement c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 20" 133 K-55 PE 113' 0' 0' 134' 134' 16" 133/8" 68 L-80 BTC 1,530' 0' 0' 1,551' 1,500' 490 sacks 12 1/4" 9 5/8" 40 L-80 BTC 5,823' 0' 0' 5,844' 5,370' 557 sacks 8 112" 3 1/2" 9.3 L-80 EUE 7,833' 0' 0' 7,854' 7,380' 957 sacks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry O perations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (tt): Effect. Depth TVD (ff): Junk (measured): Casing Length Size Cement Volume MD TVD Structural Conductor Surface Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Filing Fee ~ BOP Sketch ~ Drilling Program ~ Time v. Depth Plot Shallow Hazard Analysis Property Plat 0 Diverter Sketch Q Seabed Report ~ Drilling Fluid Program Q 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Willard J. Tank Title Advanced Senior Drilling Engineer Signature Phone 713-296-3273 Date June 6, 2005 Commission Use Only Permit to Drili Number: Z'Qs.~ 0 API Number: 50-~~ ~. 20 Permit Approval Date: ~ io - See cover letter for other requirements. Conditions of approval Sam es r u' ed Yes ~ No ~ Mud log required Yes ~ No "~ H fide measures Yes ~ No ..~ Directional survey required Yes '~{ No /~' Other: ~~ ~ a C~C.?C) r ~. / - APPROVED BY Approved THE COMMISSION Date: ~~ ~_ For -401 ed 06/2004 / Submit inDuplicate • • r ~ MARATHON MARATHON OIL COMPANY DRILLING PROGRAM Kenai Gas Field KB U 11-8Y Original 6/6/05 Originator: W.J. Tank ~~~ ~ _ Drilling Superintendent: P.K. Berga North America Drilling Manager: B.J. Roy Page 1 of 14 • ~ Table of Contents General Well Data ...................................................................................................................................................................3 Geologic Program Summary ................................................................................................................................................. ..3 Summary of Potential Drilling Hazards .................................................................................................................................. ..4 Formation Evaluation Summary ............................................................................................................................................ ..4 Drilling Program Summary .................................................................................................................................................... ..5 Casing Program ..................................................................................................................................................................... ..6 Casing Design ....................................................................................................................................................................... ..6 Maximum Anticipated Surface Pressure ............................................................................................................................... ..6 BOPS Program ...................................................................................................................................................................... ..8 Wellhead Equipment Summary ............................................................................................................................................ ..9 Directional Program Summary .............................................................................................................................................. ..9 Directional Surveying Summary ............................................................................................................................................ 10 Drilling Fluid Program Summary ........................................................................................................................................... 10 Drilling Fluid Specifications .................................................................................................................................................... 11 Solids Control Equipment ...................................................................................................................................................... 11 Cement Program Summary ................................................................................................................................................... 12 Regulatory Waivers and Special Procedures ........................................................................................................................ 12 Bit Summary .......................................................................................................................................................................... 13 Hydraulics Summary ............................................................................................................................................................. 13 Formation Integrity Test Procedure ....................................................................................................................................... 14 Page 2 of 14 • • General Well Data WeN Name KBU 11-8Y Lease/L~ense Surface Locatan 89' FSL, 705' FEL, Sec. 6, T4N, R11W, S.M . WBSCode DD.05.11696.CAP.DRL SbtJPad Pad 41-7 Field Kenai Gas Field Spud Date 6121/05 (est.) KB Elev. 87 County/Province Kenai Peninsula APP No. Ground level E{ev. 66 State /Country Alaska WeI1 Class Development Perm. Datum KB Total MD 7,854' '~ Rig Contractor Glacier Drilling Water Depth N/A Total TVD 7,380' Rig Name #1 Water Protection Depth Comments: Geologic Program Summary Formation MD -RKB ft} TVD -RKB (ft) Pore Pressure (psi) Pore Pressure ( ) Possible Fluid Content Sterling A-8 (Not a Prod Target) 3,970 3,612 0.8 - 6.5 Sandstone Gas /Water Beluga (Not a Prod Target) 5,198 4,730 1.5 - 7.3 Sandstone Gas Middle Beluga (Primary Target) 5,856 5,382 3.8 - 8.8 Sandstone Gas Tyonek (Secondary Target) 7,691 7,217 5.8 9.0 Sandstone Gas Comments: Surface Location Coordinates From Lease/Block tines 89' FSL, 705' FEL, Sec. 6, T4N, R11 W, S.M. ~ Latitude 60° 2T 35.162" N Longitude 151 ° 14' 43.278" W UTM North (Y) 2,362,098.81' UTM East (x) 275,205.83' Tolerance Horizontal. Dept Displacement {ft) MD TVD +N/-S +E/-W T~era~e Direc~ionai?arget (ft) {ft) Location (Y) {X) (ft) Middle Beluga 5,856 5,382 865' FNL, 1,087 FWL, Sec. 8, T4N, R11W, S.M. i -954 1,792 Circle 200' radius TD 7,854 7,380 865' FNL, 1,087' FWL, Sec. 8, T4N, R11W, S.M. ~ -954 1,792 Circle 200' radius Comments: Page 3 of 14 • • Summary of Potential Drilling Hazards Hazard Event Discussion Lost Circulation in Low Pressure Sterling and Belu a sands Control losses by using sufficiently sized LCM, including fibrous and calcium carbonate types. Comments: Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BLM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No HzS is anticipated. / Gas sands will be encountered from +/- 3,970 MD (3,612' TVD) to total depth of the well. These sands will run from highly depleted to slightly above normal pressure. Lost circulation and differential sticking are potential hazards in some of the Sterling and Beluga sands. The Flo-Pro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. Weighting material will available on location for proper well control.. Formation Evaluation Summary Interval LWD Electric Logs Mud Logs Surface None None None 0' - 1,551' MD Intermediate None None Basic with GCA, shale density, temperature in and out, 1,551' - 5,844' MD sample collection (10' samples). Production None Reeves Quad Gombo with pressures 5,844' - 7,854' MD through pipe. Pull GR-Neutron to surface Basic with GCA, shale density, temperature in and out, inside casing. Schlumberger sample collection (10' samples). VSP/checkshot. Schlumberger dipole sonic from TD to surface. Completion N/A GR, CCL N/A Coring Requirements: None Comments: Page 4 of 14 ~ • Drillinta Prouram Summary CONDUCTOR: 1. Drive 20" conductor to +f-100 ft. RKB. 2. Move in and rig up rotary drilling rig. 3. Install starting head 20" SLC x 21 1!4", 2M flanged. 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. ~ 5. Function test diverter and diverter valve. SURFACE: 1. Drill a 16" hole to 1,551' 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 133/8" casing. ND diverter. 4. Install i 3 318" slip lock connection X 13 5/8" 5M flanged multibowl w d. 5. NU 13 5!8" 5M BOP'S. Test SOP'S and choke manifold to 250 ,000 i. '~ 6. Set wear bushing. ~ 7. Test surface casing to 2,000 psi. INTERMEDIATE: 1. Drill out float equipment and make 20' of new hole. CBU. 2. Test shoe to leak off. Estimated EMW is 15.0 ppg. ~ 3. Drill 12 1/4" directional hole to 5,844' MD (5,370' TVD) as per directional program, short tripping as necessary (1,000' or 24 / hours, but can be extended depending on hole conditions). 4. At TD circulate hole clean. Make wiper trip. TOOH. 5. Change out variable pipe rams with 9 5/8" casing rams. Run test plug and test casing rams to 2,000 psi. ~~ 6. Run and cement 9 5/8" casing. Land hanger in multibowl wellhead. 7. Back out landing joint. Change out 95/8" casing rams with variable pipe rams. Run test plug and test rams to 250/2,000 psi. /° 8. Set wear bushing. Test casing to 2,000 psi. PRODUCTION: 1. Drill float equipment and 20' of new formation w/ 8 1/2" bit. CBU. ~ 2. Test shoe to leak off. Estimated EMW 13.0 ppg. 3. Drill a 81/2" hole to 7,854' MD (7,380' TVD) per the directional program, short tripping as necessary (1,000' or 24 hours, but can be extended depending on hole conditions). 4. At TD circulate hole clean. Make wiper trip. TOOH. 5. RU Precision. Run open hole logs as per plan. RD. RU Schlumberger. Run open hole logs as per plan. RD Schlumberger. ~- 6. TIH w/ 8 1/2" bit to TD for wiper trip. TOOH to 9 5/8" shoe and circulate until log evaluation is complete for picking EXCAPE modules. After picks are made, trip to TD and circulate clean. TOOH and laydown BHA and drill pipe. Pull wear bushing. 7. RU and run 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. Run control and electric lines out tubing head outlet. Set slips. Cut 31/2" casing. 10. LD BOP. Set 3 1/2" packoff. NU 13 5/8" 5M X 3 1/8" 5M tubing head adapter and 3 1!8" 5M 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. COMPLETION: / Completion will be done without a rig. Page 5 of 14 • Casing Program • MD ft Connection APl Ratings Casing Makeup ~ ' ~ ~, ~ Size Wert O. D. Torque Hale Size m o ' m (in) Top Bottom (ibsJft) Grade Type (in) (ft-Ibs) (in) V ~ 13 318 Surface 1,551 68 L-80 BTC 14.375 WA' 16 5,020 2,260 1,545 9 5/8 Surface 5,844 40 L-80 BTC 10.625 N/A ` 12 1/4 5,750 3,090 979 31/2 Surface 7,854 9.3 L-80 8rd 4.5 3,200 81/2 10,160 10,530 207 Comments: "' The make up of the buttress connection will be to the proper mark. Casing Design Casing Shoe Sa#ety Factors. Casing. Settlng Mud Wt 1 Fran Form Maximum Surface.. ~, g Size Weight Depth When Set Grad Press Pressure m (~) (ItNft} Grade (TVD) (t~gaq (Ib/gal) (Ib/gaq (psi} 133/8 68 L-80 i ,500 9.4 i 5.0 8.4 0 3.12 2.55 3.87 9518 40 L-80 5,370 9.5 __ 13.0 1.5 1,786 1.59 1.15 2.76 31/2 9.3 L-80 7,380 10. 15.0 9.0 1,786 1.17 2.42 1.60 Comments: Maximum Anticipated Surface Pressure Casing Size ~) Setting Depth TVD (ft) MAWP ' (f~ MASP '" (psi) MudJGas Ratio 133/8 1,500 3,428 0 30170 9518 5,370 3,997 1,786 / 30/70 31/2 7,380 6,920 1,786 30/70 * MAWP =Maximum allowable working pressure "" MASP =Maximum anticipated surface pressure Comments: MASP /MAWP CALCULATIONS: Surface casing: 13 318" (1,551' MD. 1.500' TVD) MASPr~ac =((Fracture gradient at shoe + S.F.) x .052 x TVDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPrrac = (15.0 ppg + 0.5 ppg) x .052 x 1,500' - (.1 psiift x 1,500') MASPtrac = 1,209 psi - 150 psi MASPf~~ = 1,059 psi. Page 6 of 14 • • MASPbnp = BHP, nae to -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnp = (1.5 ppg x .052 x 5,370') - (0.3 x 9.5 ppg x .052 x 5,370') - (0.7 x 0.1 psi/ft x 5,370') MASPbnp = 419 psi - 796 psi - 376 psi MASPbnp = 0 psi MASP =MASPbnp = 0 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,020) - (9.4 - 8.3) x .052 x 1,500' MAWP = 3,514 psi - 86 psi = 3,428 psi Intermediate casing: 9 5/8" (5,844' MD, 5,370' TVD) MASP,, _ ((Fracture gradient at shoe + S.F.) x .052 x TVDsnos) -Hydrostatic pressure of gas column at the shoe. MASP~,~ _ (13.0 ppg + 0.5 ppg) x .052 x 5,370' - (.1 psi/ft x 5,370') MASPrrac = 3,770 psi - 537 psi MASPtrac = 3,233 psi. MASPbnp = BHP, nae,a -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnp = (9.0 ppg x .052 x 7,380') - (0.3 x 10.0 ppg x .052 x 7,380') - (0.7 x 0.1 psi/ft x 7,380') MASPbnp = 3,454 psi - 1,151 psi - 517 psi MASPbnp = 1,786 psi MASP =MASPbnp = 1,786 psi ~ MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAW P = (0.7 x 5,750) - (9.5 - 9.4) x .052 x 5,370' MAWP = 4,025 psi - 28 psi = 3,997 psi Production casino: 3 1!2" (7.854' MD, 7.380' TVD) MASPf~ _ ((Fracture gradient at shoe + S.F.) x .052 x TVDsn~) -Hydrostatic pressure of gas column at the shoe. MASPt~ _ (15.0 ppg + 0.5 ppg) x .052 x 7,380' - (.1 psilft x 7,380') MASPf,~ = 5,948 psi - 738 psi MASPtrac = 5,210 psi. MASPbnp = BHPopa„ node to -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnp = (9.0 ppg x .052 x 7,380') - (0.3 x 10.0 ppg x .052 x 7,380') - (0.7 x 0.1 psi/ft x 7,380') MASPbnp = 3,454 psi -1,151 psi - 5i 7 psi MASPbnp =1,786 psi MASP =MASPbnp = 1,786 psi ~ MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 10,160) - (10.0 - 9.5) x .052 x 7,380' MAWP = 7,112 psi -192 psi = 6,920 psi Page 7 of 14 • BOPE Program • Casing Test Test Easing Test Fluid Pressure 5iae MAWP MASP Press Density BOPS LowlHigh Casing {in) {psi) (psi) (psi) (Ib/ al Size & Rating (psi) (1) 13-5/8" 5M annular (1) 13-518" 5M pipe ram Surface 133/8 3,428 0 2,000 9.4 (1) 13 5/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Intermediate 9 5J8 3,997 1,786 2,000 9.5 (1) 13 5/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-518" 5M pipe ram Production 3 1/2 6,920 1,786 2,000 10.0 (1) 13 518" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-118" 5M outlets Comments: Blowout Preventers The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets. z 3 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 avacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. Casing Test Pressures Casing test pressures are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. i Page 8 of 14 • • Wellhead Equipment Summarv Component Description Casing Hanger Type Casing Head 13-5J8" 3M X 13-3l8" Slip Loc W/ 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL1, 13 5/8" x 9 5/8" Fluted PRi Mandrel Tubing Bead 13-5/8" 3M Studded Bottom X 13-5l8" 5M Flg Top, Wf 2, 2-1116" 5M Studded Outlets, 13 518" x 3112" Manual U,AA,PSLI,PR1 Slip Adapter Flange 13-5/8" 5M X 3-1/8" 5M W/Seal Pocket and 3" H BPV Threads Comments: Control lines and electric cable for the EXCAPE system wiN be routed through the tubing head side outlet. Directional Program Summarv Build Tum Coorda'-atss Seo., No. Description MD (ft) TVD (ft) Rate (°/100') Rate (°l100') Dogleg (°/100'). Inclination (deg) Azimuth. (~9) +W-5 (ft) +E1-W (ft) VS (ft) 1 Tie On 0 0 0 0 0 0 118.04 0 0 0 2 KOP 500.00 500.00 0 0 0 0 118.04 0 0 0 3 Build up Section 3.00 0 ~ 3.00 118.04 4 End of Build 1,471.33 1,430.00 3.00 0 3.00 29.14 118.04 -113.62 213.35 241.72 5 Nold Section 0 0 0 29.14 118.04 6 End of Hold 4,398.85 3,987.00 0 0 0 29.14 118.04 -783.71 1,471.58 1,667.26 7 Drop Section -2.00 0 2.00 118.04 8 End of Drop to the Target 5,855.84 5,382.00 -2.00 0 2.00 0.00 118.04 -954.15 1,791.61 2,029.84 9 TD 7,853.84 7,380.00 0 0 0 0.00 118.04 -954.15 1,791.61 2,029.84 Comments: Vertical section calculated from a reference azimuth of 118.04° taken from surface location to bottom hole location. Potential Well Interference: Well Distance (ft) Depth (MDl KU 43-6A 60.24 1,338 KU 24-5 65.81 i ,676 KBU 44-6 79.60 1,026 KU 11-8 132.63 4,708 KDU 2 146.94 2,592 No serious interference exists. See attached directional plan and anticollision analysis for more details. Page 9 of 14 • • 0 0 N L a ~_ C 2 Directional Surveyinct Summary i= L C O Z t 0 Interval MWD Survey Magnetic Multishot Gyro Multishot Comments 0 - 1,551' X 1,551' - 5,844' X 5,844' - 7,854' X Comments: Drilling Fluid Program Summary Interva l - ND Minimum Inventory From To Density Gel (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite Gel, Gelex, Soda Ash, Caustic, Barite, 0 1,500 8.6 - 9.4 Gel / Gelex Spud Mud Polypac Supreme UL, Sodium Meta Bisulfate Flo-Vis, Polypac Supreme UL, KCI, 1,500 5,370 9.0 - 9.5 6% Flo-Pro w/ Safecarb SafeCarb F&M, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate Flo-Vis, Polypac Supreme UL, KCI, 5,370 7,380 9.0 -~.0~ 6% Flo-Pro w/ Safecarb SafeCarb F&M, Barite, Caustic, Conqor 404, / Sodium Meta Bisulfate Comments: See mud prognosis for details. The mud system from the intermediate section will be utilized in the production hole section instead of building a new mud for that section. Sized CaCOs (SafeCarb) will be used to control leakoff. Page 10 of 14 Vertical Section at 118.04° [2300ft/in] West(-)/East(+) [1000ft/in] • ~ Drilling Fluid Specifications Interval - TVD LSRV From (fit) To {ft) Density (Iblgal) Vis (sec/gt) 1 min (IbJ100ftz) PV (cP) YP (Ib/100 ftz) Fluid: Loss (cc) pH Drill Solids (%) 0 1,500 8.6 - 9.4 60 - 100 N/A 25 - 35 NC - 12 +/- 9.5 < 7.5 1,500 5,370 9.0 - 9.5 40,000 + 8 - 12 7 - 9 +/- 9.5 +/- 5 5,370 7,380 9.0 10.0 30,000 + 10 - 14 6 - 8 +/- 9.5 +/- 5 Comments: As a standard practice for long string completions, the drilling mud that will remain above the top of cement on the 3 ~/z' production casing will be treated with corrosion inhibitor (Congor 303A) at a concentration of 1 drum per 100 barrels of drilling fluid. See mud prognosis for details. Solids Control Eauipment o ~ ~ `m c ~ m m ~ p .~' ~ at ~}; ~ ~ m ® U ~ -c w c ~ c ~Ti _ ~ ~ ~ 0 Interval ~ 0 . e: U U N Comments 0 - 7,854' MD X X X X Closed Loop System, Full Containment Item Equipment Specifications (quantity, design type, brand, model, flow capac ,etc) Shaker 2 -Derrick Model 2E48-90F-3TA 'Desander NIA Desilter 1 -Derrick Model 0522 Mud Cleaner N/A Centrifuge 2 - MI/Swaco units Cuttings Dryer N/A Cuter fr~ection Marathon G&1 Facility Zero Discharge N/A Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. Page 11 of 14 ~ • Cement Program Summary Depth. Gauge. Top of Cement Casing Size (in) MD ft} TVD {g Hate Size fn) MD {ft) TVD (ft) Ann Vol To TOC (~) Slurry Vol (~ WOC Time ih~s) Hole Faccess (~) 133/8 1 1,500 16 0 0 704 1,229 8 75 95/8 5,84.. 5,370 121/4 3,4 3,115 765 1,106 8 50 31/2 7,854 7,380 81/2 ,30 r" 4,830 853 1,120 N/A 35 ~`-', ~ Mix Water. Compressive Casing Size Density ~ Qty ~ Yield Slurry Vol TOC MD Qty WL FVII ~~~ i) (ir-) Slurry Cement Description (Iblgal) (sx) (fts/sx) (ft~ {tt) (gaUsx) Type: (cc) {%) 8 hr 24 hr 133/8 Tait Type I Cement 12.0 490 2.51 1,229 0 11.28 Fresh 812 0 196 818 lead Class "G" 12.5 301 2.10 633 3,400 11.92 Fresh 273 769 9 5/8 Tail Class "G" 13.5 256 1.85 473 4,844 9.31 Fresh 0 0 208 981 3 1/2 Tad Class"G" 15.8 957 1.17 1,120 5,300 4.97 Fresh 24 0 226 2,632 Comments: See cement prognosis for details and spacer specifications. Regulatory Waivers and Special Procedures AOGCC Regulation 20 ACC 25.035 (e) (1) (b) Requirement for 2 pipe rams, one blind ram, and one annular for a API 5K or above BOP stack. Marathon is requesting a waiver from the above regulation for KBU 11-8Y. We are requesting that the BOP stack be configured with one pipe ram instead of two, due to rig height restrictions in the running of the 3 1/2" production casing. The height restriction involves having rig crew members routing control line and electrical line through one of the tubing head outlets after the 3 1/2" casing is cemented and the BOP stack is picked up. This is prior to setting the casing on slips and cutting the casing sticking up. These lines control firing of the perforating guns and the monitoring of downhole pressure and temperature in our EXCAPE completion system. Similar waivers have been requested for EXCAPE completion wells in the Kenai Gas Field and were granted. No problems were encountered while doing this operation on any of the wells. Also due to MASP below 2,000 psi, only a 3,000 psi BOP stack would be required for this work if it was economic to change out BOP stacks for this well. If a 3,000 psi 80P stack was used then no waiver would be necessary. Utilizing the 13 5/i3" 5M stack currently found on the Glacier Drilling #1 rig is more than sufficient for pressures to be encountered. f - ~~~~ y~,~,,~ ~~S u;~~ ~ Uk`° Page 12 of 14 • • Bit Summary interva l - MD Type Recommended E:3tanated Fran (ft To ft Size (in) Manufacturer Model No. IADC WOB (kips) RPM Rotating Hours ROP (ftfit 0 1,551 16 Christensen MX-1 115 1 - 4 80 -350 1,551 5,844 12 1/4 Christensen HCM406 M333 Up to 50 Motor 5,844 7,854 8 1!2 Christensen HCM605 M323 Up to 25 Motor Comments: 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'/z" hole section will consist of mill tooth and TCI tricone bits. See bit prognosis for additional information. Hydraulics Summary Rig mud pumps available are shown below. Max Press ® Displacement ~ Liner iD Stroke 90°,y WP 95% eff Max Rate ~g Sections Used Qty Make Model (in} ('M) (Psi) (gal/stroke) (spm/~xn) On 5 8 2,597 2.04 125 / 255 Surface 3 NatWneal` Oil A600PT 5 8 2,597 2.04 125 ! 255 Intermediate 5 8 2,597 2.04 1251255 Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Hole. Standpipe Min Nozzle Depth-MD Size Pump Rate Pressure AV ECD Size. (ft) in) ( i} (f } (lbJ ) 32"s Remarks 0-1,551 16 650+ 1,500 69 3-18's 1-15 1,551 - 5,844 12 114 662 2,000 130 6 - 13's Actual Data from CLU 8 (~ 6,722' MD) 5,844 - 7,854 8 1/2 477 1,400 247 5 - 15's Actual Data from KBU 11-SX (~ 7,659' MD) Comments: See separate hydraulics calculations. Annular velocities in the 16", 12'/a", and 8'/z" holes were calculated using 5" drillpipe. 5" drillpipe should be used to drill all hole sections to maximize hole cleaning, while minimizing stand pipe pressure. Page T3 of 14 • • Formation Intestrity Test Procedure Surface and Intermediate casing shoes will be tested to Leak-off. Prior to drilling out of casing strings, test BOPs and casing to the specified pressure listed in the BOP Program section. Plot test and record volume required on the drilling report. Leak-off tests (LOT) are to be conducted as described below: 1. Drill 20' to 25' of new formation below the casing shoe and condition the mud to the same properties in and out. 2. Pull drill string into the casing shoe and close ram preventer, and line up to the choke manifold with a closed choke. 3. Begin slowly pumping fluid down the drill string at 1/2 bpm while recording casing and drillpipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Page 14 of 14 • • Marathon Oil Well KBU 11-8Y Diverter Flow line 21 1/4" 2M Diverter _~ 16" Automatic Knife Valve ~~ Diverter Spool ~ 1 16" Diverter Line Marathon Oil Well KBU 11-8Y BOP Stack 13 5/8" 5M Cross I. Marathon Oil Well KBU 11-8Y ~ Choke Manifold To Gas Buster To Blooey Line Bleed off Line to Shakers • • Surface Use Plan for Kenai Beluga Unit, well KBU 11-8Y Surface location: Anticipated at 89' FSL, 705' FEL, Sec. 6, T4N, R11 W, S.M. 1) Existing Roads Existing roads which will be used for access to KBU 11-8Y 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 11-8Y. 3) Location of existing wells Well KBU 11-8Y will be drilled on Kenai Gas Field (KGF) pad 41-7. A pad drawing is enclosed that shows existing wells and the proposed location of KBU 11-8Y. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the KGF pad 41-7 are shown on the enclosed pad drawing. A flowline will be installed from the KBU 11-8Y wellhead to an existing line heater and separator. 5) Location of Water Supply A water supply well exists on the pad that KBU 11-8Y will be drilled from. This is shown on the pad drawing, 6) Construction Materials No construction is planned on the pad. The recent pad expansion has already been completed and is sufficient. 7) Methods of handling waste disposal; a) Mud and Cuttings Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to Pad 41-18 of the Kenai Gas Field for disposal into Well KU 24-7, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176). b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) Completion Fluids Clear fluids will be hauled to Pad 34-31 of the Kenai Gas field and injected in Well WD #1, an approved disposal well (AOGCC Permit #7-194). • d) Chemicals • Unused chemicals will be returned to the vendors that provided them. Efforts will be made to minimize the use of all chemicals. e) Sewage Sewage will be hauled to the Kenai sanitation facility. 8) Ancillary Facilities A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. S & R will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surtace KBU 11-8Y will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of KBU 11-8Y 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. 11) Operator's Representative and Certification I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that I am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: Name and Title: Wil and J. Tank, Ad nced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, TX 77253 (713) 296-3273 WELL K.B.U. 11-81~ 18" CONDUCTOR PIPE 8' DIA. WELL CELLAR --- --------- --ASPZONE4NAD27 °` E OF ~~'° N: 2362098.81 E: 275205.83 LAT: 60°27'35.162" N KENAI GAS FIELD LONG: 151°14'43.278" W PAD 41- 7 5 FSL = 89 ELEV = 66.8' (MSL) SECTION 6, TOWNSHIP 4N SECTION RANGE 11W, SM AK 6 _ CG~"JC;ftI=71= BC)X C> C°?,F GQNCHf=TE VAULT K.E3.11. 43-7X l~l/,% PIPE GUAI~13 R1: 23621)513.16 Er 274.+.x`96.79 J ~ ~ QN I o V,J I ~ ~ r ~ ~ 6 5 K.~.U.~4-~ ~ -'- - ,~' CIA '>rVEL(_ ,,I_~ 7 g N: 23619ti7.24 E: 275131.97 I ( -7 `_~ 4~L SiLC) 97 I I Cl f, I ~7~ ~ Z K. U ." , 3~-71-~ ~ WELLSIt..C7 ~ ~ 2s. sza Z I ~: <, .,.~_.~ ~ O ~ H wl SECTION ~ 7 I C 41 -~ ,EAST ~~ x.~.U. ~~-sx K.s.U. ~~-s K.Q.U. ~~-8x 1 I N:23620:i3.94 N:2362C354.15 R:2362053.G4 ~ 1 E: 275050.91 E.:275'lQa.24 E: 2]5155.87 4 ,~ C ~~ ~ ~- ~~~~ SECTION UNE 41' FNL K. ~. U. 24-6N i6'C~I 'J SELC7 E fG1ET4IOS~AL ti A. LL N:~~6197~ 98 41- 7 WEST silo . E: 276073.31 ~ `~ ~ ~` f ` ~l } ~. - 99~FEL 41 -7 PROPOSED K G F . . . K ~ ~~ ~~ PAD 41- 7 WEST 1~;~ CIA. ~~= ASP ZONE 4 NAD27 "' 236?9~-r'. E: 2 r'S 9 38.;3 N: 2361972.154 E: 274917.476 LAT: 60°27'33.861" N LONG: 151°14'48.979" W FEL = 992' FNL = 41' casvT~OL PC?INT s ELEV = 66.53' (MSL) ~~ AL.cs~P SECTION 7, TOWNSHIP 4N = 2361855.33 ~ ~ z7~{>~"1.~5 RANGE 11 W, SM AK ELE~s. _ ~G.2; ~.._..~ ! _~ .~ K.U. 43-6X WELL HQUSE N: 2361775.96 K.U. 43-6 K.E3.U. '~9-l I I 1()' E~ir1. WE?.L SILO f'' 23' '.f 97' x 17' PIPE GE.IAIZD E. 2 x,,30 I NOTES 1. BASIS OF COORDINATES IS U.S.C. & G.S. TRI STATION AUDRY IN A.S.P. ZONE 4. (NAD 27) AVERAGE CONVERGENCE OF POINTS SHOWN: D1°5'58". 2. AUDRY LOCATION: LAT: 60°30'50.559"N LONG: 151 ° 16'37.445"W NORTHING = 2,382,045.42 FASTING = 269,866.75 M MARATHON ARATHON O~ ~~~ Consuitin Grou ENGINEERING/MAPPING/SURVEYING/TESTING 9 P P.O. BOX 468 SOLDOTNA, AK.99669 McLane Testing volcE: ~soi~2a3-4z~a FAx: Iso~lza3azss EMAIL SAMCLANEQMCLANECG.COM PROJECT CONTF2C)L PC}INT 2 2" ALC~`1P ~ = 2ss2228.D5 E = 27szzs6.6~ -I I ELI~v. = 64.26 7~5' FEL ~ NORTH SCALE 0 60 120 FEET KENAI GAS FIELD PAD 41-7 WELL K.B.U. 11-8Y ASBUILT SURFACE LOCATION DIAGRAM LOCATKNJ S6 &7 T4N R11 W SEWARD MERIDIAN, AI ACllA REVISION: 1 DATE: 3/24/05 DRAWN BY: DME SCALE: ,. = so• PROJECT NO. 0530 BOOK NO. 04-15 SHEET OF ' • ~ ,,,,., --, .~, .-~ NORTH j i. _°° ', i PI{~Ime u~ Tin vre+i ~.. f~ .,11 ,e -, ` Pad.33-SO p,e``" __u_ ~ _. 1 ,... -= ~° coR`~ Yi; Y .._.% f ~ ssl Priv ats,~~0ad _J`~ ~~ •Ip ~/~.. ~ ~FEE~~ ~ i ~-.,zY~ ....-, -Pad 43-32 _ ^r, ~~18,~r'`_q~,~,\. lanema '~~ ,,, ~ Pad 34-31r•. ~ steps { ,, .. 1 _- (ias wens _ _ _ • .,n.,ra+~. KENAI (iA3 FIELD I~ •' • :~~ ~~ I Pits r ~ 1fl 6 S 4 ~' ~~ ~~ _' ~ A ~~- `r Gas wens ~~ ~ •1 , , ~ ~=- Pad 41-7 ~~ ~1 , ~ ~ ,Pad 14-4 wrwmQl',' { •~, Stri • ~~ ~ Project'Location ,._ ` ° , r Y ~ ~: 7 8 9 'O n .\ 11 ~ . ,~ ~ j ;. , • ~~ Privatsa Road ,• ~ _ •• r- '~ • y ~' k V ~ ~` I• a Pad 41-18 ~ r~ ~•~ t` _- J ` T 1 ' Echo < - ~ !c. ] E_ Lake ~~ _ -~ 14 .' `~ - f ., ~ I ...r .: , ` ,, li , ~~ _, COOK INLET P4-18 "~ 1 Abandoned ,~, - ~ .~ ~~:, ;»f. ~~®~ 2 - Kenai Unlt 13ouedary '` •' -- 1 ~ ~" ~ '-i ~~t- ,A ,i . • ~ l ~~lu~ a T - ~ 25 ~ 30 29 2~' _~~ ~6 r,..• -~ - ~ - - - - .r~ _ : - - - - _ - - (' ~ ;; F ~ r. ~ ~ 1 ~ ~~~ I~, • ~~ . ~ Reflection •~<<>' ~.~ . 36 31 32 ss ~ _ _ ~ ~ 34 - 35 r • r ,~.~ ~ - - ., .,~,,, ~ - Kasilof River ~• ~~~ ti ____ ..t. ~ .rim - :: an 3f~ - I ~ ~' _ _ - `i - _T ~ `- .- - _' - x) ~ 0-" ~-Asa-~~~ r. 1 - ~ I Ta11~41e ± /tJ~ _ t, n~ f~C% l` " r I Z ?~__• _ - _ SAP'. .. a .i Source Map: USCiS, 1961 Kenai, Alaska B-4, 1:83,380 SCALE 1.63360 4 Mlle' r-1-_l 1__1_-1 _i_ i -}-1 k:-.-__--.- -__-- -' [ _ ___. .. _.. t-- -_--_ ------..:-_.__.. .-... .--.. - XJO~ ~ ynry R(:'Nt 400D ~ !~OOU IS000 ieoal TIf10D IFFY F~-.~~~4-_ :._~. - j~~-.. Fem.. }--- '. -- i. - =z=_{ }_-_ i- i _ :.:.?- -f-- c.- 7'. .._T_ 1 S ~ ~ 1 i ~ . KILOMEFERS EiIZTi i t i i i _.:. .'- .-L_ _ - 1 __ ____ -_.? ___- -. - L_:' =-~ Marathon Oil Company Kenai Gas Field Area Map 1"m~,r-1:c'iF .4ea Aft, p,g BelugalUppa~ Tyonek Campktion • UNIT 80UhIQARY. ~~~ _~ '~ + ..: f. -• - - ~ ~ r r.1iLE hIFF..~TN~ ~N ~.1 L v~tti'P.a7JY ALA~l~..A F.EGIOh~ C ONFIDENTlAL KENAI FIELD ~_ ~ ~~: ~r: ir~a~~..~L.~ -_a~. ~. KBU ?~-8Y Locattan FaLru9r~ 2~]Cr5 ~, T5N-R1~1 W i- n s1r~EnandSkgnai'tt~el u 9AhNbi~ 11-8Y_IoG ~h ifi GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT o° -400 N I _v -0 _N c~ ~ 400 800 1200 1600 2000 2400 ~ 2800 .... yS.. 3200 Q ~ 3600 V ~ 4000 ` 4400 V 4800 5200 5600 6000 6400 6600 7200 7600 8000 ARATHON Oil Com ny Location: Kenai Peninsula, Alaska Slot: slot# KBU11-8Y Field: Kenai Gas Field Well: KBU 11-8Y Installation: Pad 41-7 Wellbore: KBU 11-8Y Ver 1 / ~ MARATHON Scale 1 cm = 100 ft East (feet) -> -400 -200 0 200 400 600 800 1000 1200 1400 1600 1800 2000 KOP 6.00 12.00 DLS: 3.00 deg/100ft 24.00 End of Build 13 3/8" Casing 600 400 KOP End of Build ~13 3/8" Casing O End of Hold ~ End of Drop /Mid Beluga ~ 9 5/8" Casing ~ TD 3 1/2" Liner End of Hold 25.12 21.12 BAKE/~ DLS: 2.00 deg/100ft 13.12 N~s s.12 INTEQ 5.12 9 5/8" Casing ~ ~ 1.12 End of Drop /Mid Beluga 3 1/2" Liner ~TD -400 -0 400 800 1200 1600 2000 2400 s~ie 1 1;m = zo~/,~rtical Section (feet) -> Azimuth 118.04 with reference 0.00 N, 0.00 E from slotlt KBU11-SY 200 0 A -200 OZ -400 tD r+ v -600 -800 -1000 iD n 3 B -1200 c 0 x WELL PROFILE DATA Point MD Inc Azi ND North Esst day100ft V.Bect Tie on 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 KOP 500.00 0.00 118.04 500.00 0.00 0.00 0.00 0.00 End of Build 1471.33 29.14 118.04 1430.00 -113.82 213.35 3.00 241.72 End of Hold 4398.85 29.14 118.04 3987.00 -783.71 1471.58 0.00 1667.26 Target KBU11-BY -Mid 5855.84 0.00 0.00 5382.00 -954.15 1791.81 2.00 2029.84 T.D. 8 Target KBU11-8Y 7853.84 0.00 0.00 7380.00 -954.15 1791.61 0.00 2029.84 created by : N18nnef Date plotted : 23May-2005 Pbt reference is KBU 11-8Y Ver 1. Raf we0path is KBU 11-8Y Ver t t;oordinates are in feet reference slot# KBU11-8Y. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rlg Datum: DaWm #1 Rig Datum to mean sea level: 87.80 ft. Plot North is aligned to TRUE NoM. • KBU11-8Y '~ Pad 41-7, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska PROPOSAL LISTING Page 1 Wellbore: KBU 11-8Y Ver 1 Wellpath: KBU 11-8Y Ver 1 Date Printed: 23-May-2005 IiNTEQ Wellbore Name Created Last Revised KBU 11-8Y Ver 1 18-Ma -2005 23-Mav-2005 Well Name vemment ID Last KBU 11-8Y 18-Ma -2005 Slot ame Grid Northi Grid astin titude Lon itude North Ea t slot# KBU11-8Y 2362098.8100 275205.8300 N60 27 35.1615 W151 14 43.2779 117.50N 428 .53E Installation Name Eason Northi Coord S tem Name nmenY Pad 41-7 270916.0101 2362063.9749 AK-4 on NORTH AMERICAN DATUM 1927 datum True Field ame Eason Northin C em Nam AI nment Kenai Gas Field 270993.1910 2361975.0460 AK-4 on NORTH AMERICAN DATUM 1927 datum True All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 118.04 degrees Bottom hole distance is 2029.84 Feet on azimuth 118.04 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated KBU11-8Y '~ Pad 41-7, MARATHON Kenai Gas Fieid,Kenai Peninsula, Alaska • PROPOSA4 LISTING Page 2 Wellbore: KBU 11-8Y Ver 1 Wellpath: KBU 11-8Y Ver 1 Date Printed: 23-May-2005 ~~~ INT~Q Weld ath Grid Re ort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg de /1 OOft Vertical Section ft Fasting. Northing; 0.00 0.00 0.00 0.00 O.OON 0.00E 0.00 0.00 __ 275205.83 2362098.81 100.00 0.00 0.00 100.00 .OON 0.00E 0.00 0.00 275205.83 2362098.81 200.00 0.00 0.00 200.00 O.OON 0.00E 0.00 0.00 275205.83 2362098.81 300.00 0.00 0.00 300.00 O.OON 0.00E 0.00 0.00 275205.83 2362098.81 400.00 0.00 0.00 400.00 O.OON 0.00E 0.00 0.00 275205.83 2362098.81 500.00 0.00 118.04 500.00 O.OON 0.00E 0.00 _ 0.00 275205.83 2362098.81 600.00 3.00 118.04 599.95 1.23S 2.31E 3.00 2.62 275208.12 2362097.54 700.00 6.00 118.04 699.63 4.92S 9.23E 3.00 10.46 275214.97 2362093.72 800.00 9.00 118.04 798.77 11.05S 20.75E 3.00 23.51 275226.37 2362087.37 900.00 12.00 118.04 897.08 19.62S 36.84E 3.00 41.74 275242.29 2362078.50 1000.00 15.00 118.04 994.31 30.59S 57.44E 3.00 65.08 275262.68 2362067.14 1100.00 18.00 118.04 1090.18 43.94S _ 82.50E 3.00 93.48 275287.49 2362053.32 1200.00 21.00 118.04 1184.43 59.63S 111.96E 3.00 126.85 __275316.64 2362037.08 1300.00 24.00 118.04 1276.81 77.61S 145.74E 3.00 165.12 _ 275350.07 2362018.46 1400.00 27.00 118.04 1367.06 97.85S 183.73E 3.00 208.16 275387.67 2361997.51 1471.33 29.14 118.04 1430.00 113.62S 213.35E 3.00 241.72 275416.99 2361981.18 1500.00 29.14 118.04 1455.04 120.18S 225.68E 0.00 255.69 275429.19 2361974.39 1600.00 29.14 118.04 1542.39 143.07S 268.66E 0.00 304.38 275471.72 2361950.69 1700.00 29.14 118.04 1629.73 165.96S 311.64E 0.00 353.07 275514.26 2361926.99 1800.00 29.14 118.04 1717.08 188.85S 354.6E 0.00 401.77 275556.80 2361903.29 1.900.00 29.14 118.04 1804.42 211.74S 397.60E 0.00 450.46 275599.33 2361879.60 2000.00 29.14 118.04 1891.76 234.63S 440.57E 0.00 499.16 275641.87 2361855.90 2100.00 29.14 118.04 1979.11 257.52S 483.55E 0.00 547.85 275684.41 2361832.20 2200.00 29.14 118.04 2066.45 280.41S 526.53E 0.00 596.55 275726.94 2361808.51 2300.00 29.14 118.04 2153.79 303.30S 569.51E 0.00 645.24 275769.48 2361784.81 2400.00 29.14 118.04 2241.14 326.19S 612.49E 0.00 693.93 275812.02 2361761.11 2500.00 29.14 118.04 2328.48 349.08S 655.47E 0.00 742.63 275854.55 2361737.42 2600.00 29.14 118.04 2415.82 371.97S 698.45E _ 0.00 791.32 275897.09 2361713.72 2700.00 29.14 118.04 2503.17 394.86S 741.43E 0.00 840.02 275939.63 2361690.02 2800.00 29.14 118.04 2590.51 417.75S 784.41E 0.00 888.71 275982.16 2361666.32 2900.00 29.14 118.04 2677.85 440.64S 827.39E 0.00 937.41_ 276024.70 2361642.63 3000.00 29.14 118.04 2765.20 463.52S 870.37E 0.00 986.10 _ 276067.24 2361618.93 3100.00 29.14 118.04 2852.54 486.42S 913.35E 0.00 1034.79 276109.77 2361595.23 3200.00 29.14 118.04 2939.88 509.30S 956.32E 0.00 1083.49 276152.31 2361571.54 3300.00 29.14 118.04 3027.23 532.19S 999.30E 0.00 1132.18 276194.85 2361547.84 3400.00 29.14 118.04 3114.57 555.08S 1042.28E 0.00 1180.88 276237.38 2361524.14 3500.00 29.14 118.04 3201.91 577.97S 1085.26E 0.00 1229.57 276279.92 2361500.45 3600.00 29.14 118.04 3289.26 600.86S 1128.24E 0.00 1278.27 276322.46 2361476.75 3700.00 29.14 118.04 3376.60 623.75S 1171.22E 0.00 1326.96 276364.99 2361453.05 3800.00 29.14 118.04 3463.94 646.64S 1214.20E 0.00 1375.65 276407.53 2361429.35 3900.00 29.14 118.04 3551.29 669.53S _ 1257.18E 0.00 1424.35 276450.07 2361405.66 4000.00 29.14 118.04 3638.63 692.42S 1300.16E 0.00 1473.04 276492.60 2361381.96 4100.00 29.14 118.04 3725.97 715.31S 1343.14E 0.00 1521.74 276535.14 2361358.26 4200.00 29.14 118.04 3813.32 738.20S 1386.12E 0.00 1570.43 276577.68 2361334.57 4300.00 29.14 118.04 3900.66 761.09S 1429.10E 0.00 1619.13 276620.21 2361310.87 4398.85 29.14 118.04 3987.00 783.71S 1471.58E 0.00 1667.26 276662.26 2361287.44 4400.00 29.12 118.04 3988.00 783.98S 1472.07E 2.00 1667.82 276662.75 2361287.17 4500.00 27.12 118.04 4076.20 806.13S 1513.67E__ 2.00 1714.94 276703.92 2361264.24 4600.00 25.12 118.04 4165.98 826.82S 1552.52E 2.00 1758.96 276742.37 2361242.82 4700.00 23.12 118.04 4257.25 846.02S 1588.58E 2.00 1799.82 276778.06 2361222.94 4800.00 21.12 118.04 4349.89 863.72S 1621.81E 2.00 1837.47 276810.95 2361204.61 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 118.04 degrees Bottom hole distance is 2029.84 Feet on azimuth 118.04 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated • KBU11-8Y Pad 41-7, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska • PROPOSAL LISTING Page 3 Wellbore: KBU 11-8Y Ver 1 Wellpath: KBU 11-8Y Ver 1 Date Printed: 23-May-2005 ~t~ INTEQ Well ath Grid Re ort ___~ MDjft} Inc[deg) Azi[deg) TVD[ft] North[ft) East(ft] ..Dogleg d 100ft Vertical ft Fasting Northing 4900.00 19.12 118.04 4443.78 879.89S 1652.17E 2.00 1871.86 276840.99 2361187.88 5000.00 17.12 118.04 4538.82 894.50S 1679.61E 2.00 1902.95 276868.15 2361172.75 5100.00 15.12 118.04 4634.89 907.55S 1704.11E 2.00 1930.71 276892.40 2361159.24 5200.00 13.12 118.04 4731.86 919.02S 1725.64E 2.00 1955.10 276913.71 2361147.37 5300.00 11.12 118.04 4829.63 928.88S 1744.16E 2.00 1976.09 276932.04 2361137.16 5400.00 9.12 118.04 4928.07 937.14S 1759.67E 2.00 1993.65 276947.38 2361128.61 5500.00 7.12 118.04 5027.06 943.77S 1772.13E 2.00 2007.77 276959.72 2361121.74 5600.00 5.12 118.04 5126.49 948.78S 1781.5E 2.00 2018.43 276969.03 2361116.55 5700.00 3.12 118.04 5226.22 952.16S 1787.87E 2.00 2025.61 276975.30 2361113.06 5800.00 1.12 118. 5326.15 953.89S 1791.13E 2.00 2029.30 276978.52 2361111.26 5855.84 0.00 0.00 5382.00 954.15S 1791.61E 2.00 2029.84 276979.00 2361111.00 5900.00 0.00 0.0 5426.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6000.00 0.00 0.00 5526.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6100.00 0.00 0.00 5626.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6200.00 0.00 0.00 5726.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6300.00 0.00 0.00 5826.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6400.00 0.00 0.00 5926.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6500.00 0.00 0.00 6026.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6600.00 0.00 0.00 6126.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6700.00 0.00 0.00 6226.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6800.00 0.00 0.00 6326.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 6900.00 0.00 0.0 6426.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 7000.00 0.00 0.00 6526.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 7100.00 0.00 0.0 6626.16 954.15S 1791.61E .00 202 .84 276979.00 2361111.00 7200.0 0.00 0.00 6726.16 954.15S 1791.61E .00 2029.84 276979.00 2361111.00 7300.00 0.00 0.00 6826.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 7400.00 0.00 0.0 6926.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 7500.00 0.00 0.00 7026.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 7600.00 0.00 0.00 7126.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 7700.00 0.00 0.00 7226.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 7800.00 0.00 0.00 7326.16 954.15S 1791.61E 0.00 2029.84 276979.00 2361111.00 7853.84 0.00 0.00 7380.00 954.15S 1791.61E _ 0.00 2029.84 276979.00 2361111.00 Ail data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 118.04 degrees Bottom hole distance is 2029.84 Feet on azimuth 118.04 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated KBU11-8Y '~ Pad 41-7, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska • PROPOSAL LISTING Page 4 Wellbore: KBU 11-8Y Ver 1 Wellpath: KBU 11-8Y Ver 1 Date Printed: 23-May-2005 1 INTEQ Comments MD ft TVD ft North ft Eas ft Continent 500.00 50 .00 O.OON 0.00E KOP 1471.33 1430.00 113.62S 213.35E End of Build 4398.85 3987.00 783.71S 1471.58E End of Hold 5855.84 5382.00 954.15S 1791.61E End of Dro /Mid Belu a 7853.84 7380.00 954.15S 1791.61E TD Hole Sections Diameter in Start M ft Start TV ft . ' Start No ft Start Eas ft End MD ft End TV ft End North ft Start st ft Wellbore ' 1 .000 0.00 0.00 O.OON 0.00E 1551.47 1500.00 131.97S 247.80E KBU 11-8Y Ver 1 12 1/4 1551.47 1500.00 131.97S 247.80E 5843.85 5370.00 954.14S 1791.59E KBU 11-8Y Ver 1 8 1/2 5843.85 5370.0 954.14S 1791.59E 7853.84 7380.00 954.15S 1791.61E KBU 11-8Y Ver 1 Casin s _ Name Top MD ft Top. TVD ft Top North ft Top Eas ft Shoe MD ft Shoe TVD ft Shoe North ft Shoe East ft Wellbore ~ 13 3/8" Casin 0.00 0.00 O.OON 0.00E 1551.47 1500.00 131.97S 247.80E KBU 11-8Y Ver 1 9 5/8" Casin 0.00 0.00 O.OON 0.00E 5843.85 5370.00 954.14S 1791.59E KBU 11-8Y Ver 1 ' 3 112" Liner 0.00 0.00 O.OON 0.00E 7853.84 7380.00 954.15S 1791.61E KBU 11-8Y Ver 1 r a r ens ____ N e North ft Fas ft TVD ft Latitude L itude tin Norhti L st vis d ' KBU11-8Y -Mid Belu a - 5/18/05 954.15S 1791.61E 5382.00 N60 27 25.76 _ W151 147.5 __ 276979.00 2361111.00 22-Apr-2004 KBU11-8Y - TD - 5/18105 954.15S 1791.61E 7380.00 N60 27 25.76 W151 147.5 - 276979.00 2361111.00 22-Apr-2004 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 118.04 degrees Bottom hole distance is 2029.84 Feet on azimuth 118.04 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~~i~ 1VfARATHON Oil Com~ny BAKER H(~~ES I Location: Kenai Peninsula, Alaska Slot: slot# KBU11-8Y ' Field: Kenai Gas Field Well: KBU 11-8Y INTEQ I Installation: Pad 41-7 Wellbore: KBU11-8YVer1 MARATH ON Scale 1 cm = 20 ft East feet) -> -40 0 40 80 120 160 200 240 80 320 360 400 440 480 520 560 600 ~__-1_-i -I~__ _L ~- 1--~ -~ -~ I -: I J _1 1 _ _ I _ -_I _-. _ I _I 1 I 1 ! L 40 ~~ . „~. ~ 0 ~ 40 - ,~. ~~ -40 ~f~ zwo, ~ ~ ~ ~ B .~ ,~ ~ ~' ~`8 1r ~ i M1'¢' ~ 5` ,p •,sm ~ • -40 - A. s~~ ~ l M1y A 1900. ,p • ~ _ .'1100 ~~ A, YI ' ~ 1800 <.,11,00 • y00 ;~ A V' -Z O ,, -120 ~ ~ ,• ~ • ,3°° ~, •„~ -120 ~ ~ r _ ~ Z-160 ~•~ •„~ -160rt - 1,00 . ~ 800• '.8100 BW .,~ -200 •8100 •,BOp ~ ~ -200 exo , nao • ~ N ° -240 ~ „~ •,.~ ~ -240 , • °-' -280 ~ ~ .~ „°° `•-.. l 1 = 20 ft S ~ ~'~ -280 n~ cm ca e East (feet) -> ~ T ~ _~ -I T ~ -, ~ ~ I i 1 T I --~ -T -~ - ~ - ~ -T ~ -40 -0 40 80 120 160 200 240 280 320 360 400 440 480 520 560 600 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 _ ~- -L 1 J l_ 1 J_- I_ -1 _~ ~ - -L I I I L I I ~- __ 1 L __ 1 I ~ _. ~ Scale ~ 1 cm = 50 ft East (feet) -> L -zoo ~ -200 ~ s M1 -300 ~' -300 ~ L ry~ I q gyp' ~ ~OQ ' 8 ~ ~ a~ ~ ~ • ~ ~ 8 aa' ~ ~ ~' ~ ~e°' M1.~ ~ ~ ~ .. -400 ~ ~ ~ • ti l ~ IV ~ ~ -500 ,~ -500 +'~+ ~ u„.~ ~' ,~ ~ ~ Z O v -600 ~ "~ ~ - M1~ ,ds rp~p - -600 3 • p ~ ryW ~ ~ ~ ~ /\ ~~ Z -700 ~ ~ ~ ~ '~ ~, -700 ~ ~ 8 ~ -800 `'200 ~ ~ ~ ~ -800 '~ ~ -900 ~ ~ ~ ' ;~'~~ ~ ~ -900 ~ .,.ao \ a ,gs ' ~ , ~ ~ 3 d -1000 ~ '~ ~' I 'n,., I -1000 N ;Q 7 3 0 ~ t i ~ 400 500 600 700 800 900 1000 1100 1200 1300 1400 1500 1600 1700 1800 1900 Scale 1 cm = 50 ft East (feet) -> _- -- -- ~! R:~ I~RATHON Oil Comp~y NUGMES Location: Kenai Peninsula, Alaska Slot: slot# KBU11-13Y INTEQ Field: Kenai Gas Field Well: KBU 11$Y Installation: Pad 41-7 Wellbore: KBU 11-13Y Ver 1 reefed by: Planner Date plotted : 2&May-2005 Plot reference is KBU 11-BY Ver 1. Ref xrellpath is KBU 11-8Y Ver 1. Coordinates are in feet reference slot# KBU11$Y. True Vertical Depths are reference Rlg Datum. Measured Depths are reference Rig Datum. Rig Dalum: Dalum #1 Rig Datum to mean sea level: 87.80 tt. Plot North is aligned to TRUE North. - _ O - - - ® ,,2600 Q1700 TRUE NORTH .2500 350 0 10 •2200 340 2 29 280 270 260 '24 'M' MARATHON 70 80 90 100 110 Normal Plane Travelling Cylinder -Feet All depths shown are Measured depths on Reference Wel MARATHON O[I Company ~~~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 CLEARANCE LISTING Page 1 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska Ellipse separations are reported ONLY if BOTH wells have uncertainty data Only Depth and Magnetic Reference Field error terms are correlated across tie points Proximities beyond ft with expansion rate of ft/1000ft are not reported Cutoff is calculated on CENTRE to CENTRE distance Summary data uses Closest Approach clearance calculation for all minima Hole size/Casings are NOT included Hole size/Casings are NOT subtracted from Centre-Centre distance Ellipses scaled to 2.OOstandard deviations. Closing Factor Confidence limit of 99.80% Errors on Ref start at Slot Permanent Datum (0.00) Report uses Revised: (D-CUE Factor Calculation ~f~ ies APl l ~,i,t Wellbore Na Crest Last Revised KBU 11-8Y Ver 1 18-Mav-2005 23-Ma -2005 Well _~ Name Government ID Last Revised _ _ _ _ I KBU 11-8Y _. 18-Mav-2005 ~ Slot 'Name Grid Nnrthina Grid Eastina Latitude Longitude North East Name Field Name. Eastin Northin Coord S stem,Name North Aiianment Kenai Gas Field 270993.1910 _ 2361975.0460 AK-4 on NORTH AMERI AN DATUM 1927 datum True Clearance Summa.. Offset WeUName Offset Wellbore_ Offset Slot Offset Structure Minimum Distance ft MD[ft] Diverging From[ft] Ellipse Separation ft Ellipse MD{ft] Clearance Factor.. Clearance MD[ft] KU 43-6A KU43-6A slot #KU 43-6A Pad 41-7 60.24 1337.70 1337.70 46.83 1337.70 4.46 1328.74 KU24-5 KU24-5 slot #KU 24-5 Pad 41-7 65.81 1676.22 1676.22 50.73 1673.23 4.34 1656.82 KU24-5 KU24-5Rd slot #KU 24-5 Pad 41-7 65.81 1676.22 1676.22 50.73 1673.23 4.34 1656.82 KBU11-8X KBU11-8X slot #KBU 11-8X Pad 41-7 67.36 0.80 0.80 66.78 164.04 24.46 1213.91 KBU 44-6 KBU 44-6 slot #KBU44-6 Pad 41-7 79.60 _ 1025.53 1025.53 75.14 1033.46 16.82 1115.49 KBU42-6 KBU42-6 Slot #KBU42-6 Pad 41-7 101.58 590.55 590.55 99.20 600.00 34.26 771.00 KU11-8 KU11-8 slot #KU 11-8 Pad 41-7 132.63 4708.01 4708.01 73.71 4658.79 2.23 4625.98 KTU32-7 KTU32-7 slot #32-7 Pad 41-7 139.52 467.43 467.43 137.58 467.43 39.87 1230.31 KDU#2 KDU#2 slot #KDU 2 Pad 41-7 146.94 2591.86 2591.86 117.16 2608.27 4.85 2837.93 KTU32-7H KTU32-7H slot #KTU32-7H Pad 41-7 148.22 1152.98 1152.98 143.27 1152.98 26.56 1328.74 KU43-6 KU43-6Rd slot #KU 43-6 Pad 41-7 152.67 1066.27 1066.27 148.64 1066.27 36.91 1131.89 KU43-6 KU43-6 slot #KU 43-6 Pad 41-7 152.67 1066.27 1066.27 148.64 1066.27 36.91 1131.89 All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated MARATHON O[I Company '~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 U CLEARANCE LISTING Page 2 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~`~ INTEQ Clearance Summa Offset Offset Offset Offset Minimum MD[ft] Diverging Ellipse Ellipse Clearance Clearance' WeIlName WeAbore Slot Structure Distance From[ft] Separation MD[ft} Factor. MD[ft] ft ft KBU33-6X KBU33-6X Slot Pad 41-7 160.94 508.53 508.53 158.78 524.93 48.21 1131.89 #KBU33-6X KTU24-6H KTU24-6H slot #24-6 Pad 41-7 181.24 0.80 0.80 180.91 131.23 52.89 1100.00 KTU24-6H KTU24-6H slot #24-6 Pad 41-7 181.24 0.80 0.80 180.91 131.23 52.89 1100.00 Pilot KTU24-6H KTU24-6H slot #24-6 Pad 41-7 181.24 0.80 0.80 180.91 131.23 52.89 1100.00 RD KU13-5 KU13-5 slot Pad 41-7 194.37 1205.48 1205.48 186.43 1213.91 22.03 1377.95 #KTU 13-5 KBU43-7X KBU43-7X Slot Pad 41-7 214.05 0.80 0.80 213.88 49.21 103.59 606.96 #KBU43-7X KBU42-7 KBU42-7 slot Pad 41-7 221.00 181.80 181.80 220.01 278.87 92.63 705.38 #KBU42-7 Reference Welibore Surve Tooi Fro ram Surve Name MD ft Surve Tool Error Model Planned 7853.84 Navi Trak Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1D) Prepared by Baker Hughes Incorporated • MARATHON O[I Company KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHQN slot# KBU11-8Y, Pad 41-7 • CLEARANCE LfSTiNG Page 3 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~~~ INTEQ C learanc e Data Reference MD[ft) Reference TVD[ft) Reference North[ft) Reference East[ft] Offset Well Offset MD[ftJ Offset TVD[ft] Offset North[ft) .Offset East[ft] Angle From Highside d Gbsest Approach Distance ft Ellipse Separation (ft) 2559.06 2380.06 362.60S 680.85E KU11-8 2507.08 2335.91 644.41S 686.85E 60.0 285.31 24.14 2600.00 2415.82 371.97S 698.45E KU11-8 2547.77 2371.44 _ 649.57S 706.01E 59.6 281.23 244.18 2700.00 2503.17 394.86S 741.43E KU11-8 2645.53 2456.41 662.35S 752.64E 58.5 271.78 232.69 2800.00 2590.51 417.75S 784.41E KU11-8 2743.15 2541.16 675.35S 799.30E 57.3 262.71 221.64 2900.0 2677.85 440.64S 827.39E KU11-8 2840.77 2625.97 689.38S 845.55E 56.2 254.75 211.75 3000.00 2765.20 463.52S 870.37E KU11-8 2940.28 2712.89 704.17S 891.70E 5 .2 247.19 202.26 3100.00 2852.54 486.42S 913.35E KU11-8 3039.65 2799.80 719.04S 937.51E 54.2 239.76 192.95 3200.00 2939.88 509.30S 956.32E KU11-8 3138.14 2885.88 734.16S 982.92E 53.2 232.78 184.14 3300.00 3027.23 532.19S 999.30E KU11-8 3236.74 2971.62 749.61S 1029.09E 51.9 226.38 176.04 3400.00 3114.57 555.08S 1042.28E KU11-8 3336.18 3057.96 765.36S 1075.85E 50.5 220.34 168.39 3500.00 3201.1 577.97S 1085.26E KU11-8 3435.76 3144.40 781.17S 1122.71E 49.1 214.47 161.02 3600.00 3289.26 600.86S 1128.24E KU11-8 _ 3534.79 3230.21 797.OOS 1169.53E 47.5 208.95 154.13 3700.00 3376.60 623.75S 1171.22E KU11-8 3633.47 3315.64 813.22S 1216.18E 45.8 204.05 147.99 3800.00 3463.94 646.64S 1214.20E KU11-8 3732.49 3401.14 829.75S 1263.31E 44.0 199.71 142.59 3900.00 3551.29 669.53S 1257.18E KU11-8 3831.09 3486.47 847.04S 1309.60E 42.4 196.11 137.95 4000.00 3638.63 692.42S 1300.16E KU11-8 3931.10 3573.28 865.12S 1355.82E 40.9 192.86 133.63 4100.00 3725.97 715.31S 1343.14E KU11-8 ___4037.03_ 3665.89 883.585 1403.80E 39.6 188.69 128.30 4200.00 3813.32 738.20S 1386.12E KU11-8 4145.76 3762.55 897.O6S 1451.70E 37.9 179.21 118.02 4300.00 3900.66 761.09S 1429.10E KU11-8 __4246.72 3853.19 907.42S 1494.94E 36.3 167.34 105.53 4398.85 3987.00 783.71S 1471.58E KU11-8 4345.45 3942.07 916.96S 1536.86E 34.4 155.03 92.83 4400.00 3988.00 783.98S 1472.07E KU11-8 4346.59 3943.09 917.07S 1537.35E 34.4 154.89 92.69 4500.00 4076.20 806.13S _ 1513.67E KU11-8 4446.30 4032.84 926.44S 1579.79E 31.6 143.97 82.10 4600.00 4165.98 826.82S 1552.52E KU11-8 4545.40 4122.45 935.91S 1621.03E 28.2 135.97 7 .17 4625.98 4189.6 831.95S 1562.16E KU11-8 4570.68 4145.25 938.36S 1631.65E 27.1 134.59 74.25 4658.79 4219.47 838.29S 1574.06E KU11-8 4602.59 4173.97 941.47S 1645.22E 25.6 133.34 73.71 4700.00 4257.25 846.02S 1588.58E KU11-8 4642.72 4209.99 945.54S 1662.45E 23.6 132.64 74.04 4708.01 4264.62 847.50S 1591.35E KU11-8 4650.67 4217.11 946.38S 1665.88E 23.2 132.63 74.24 4800.00 4349.89 863.72S 1621.81E KU11-8 4740.75 4297.1 956.24S 1705.08E 18.4 135.01 79.23 4900.00 4443.78 879.89S 1652.17E KU11-8 4839.39 4385.53 966.90S 1748.50E 12.9 142.28 89.37 5000.00 4538.82 894.50S 1679.61E KU11-8 4936.78 4472.26 978.13S 1791.37E 8.0 154.64 103.75 5100.00 4634.9 907.55S 1704.11E KU11-8 ___5033.27 4557.81 989.59S 1834.50E 3.8 172.25 122.51 5200.00 4731.86 919.02S 1725.64E KU11-8 5130.52 _ 4644.03 1001.05S 1877.99E 0.2 194.05 144.65 5300.00 4829.3 928.88S 1744.16E KU11-8 5224.87 4727.46 1012.50S 1920.53E -2.5 220.30 170.69 5400.00 4928.07 937.14S 175 .67E KU11-8 5319.75 4811.24 1024.32S 1963.47E -4.6 250.57 200.39 5500.00 5027.06 943.77S 1772.13E KU11-8 5350.00 4837.95 1028.13S 1977.15E -5.2 291.40 242.31 Offset Wellbore Surve Tool Pro rams 1I Wellbore Surve Name MD ft Surve Tool Error M t K 11-8 KU11-8 GMS <0-5350'> 5350.00 Level Rotor G ro Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1D) Prepared by Baker Hughes Incorporated • MARATHON O[I Company ~~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 CLEARANCE LISTING Page 4 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~~~ iltS INTEQ C learance Data Reference MD[ftj Reference ND[ftj Refereruu~ North[itj Reference East[ftj Offset Well Offset MD[ftj Offset ND[ftj Offset North[ttj Offset. East[ftj Angle From Highside Closest Approach Distance ft E4ipse Separation [ft] 0.00 0.00 O.OON 0.00E KTU24-6H 0.00 0.80 126.12S 130.16W -134.1 181.24 181.24 0.80 0.80 O.OON 0.00E KTU24-6H 0.00 __ 0.80 126.12S 130.16W -134.1 181.24 181.22 100.00 100.00 O.OON 0.00E KTU24-6H 98.83 99.63 125.81S 130.64W -133.9 181.37 180.94 131.23 131.23 O.OON 0.00E KTU24-6H 129.82 130.61 125.59S 130.96W -133.8 181.45 180.91 200.00 200.00 O.OON 0.00E KTU24-6H 198.32 199.10 124.915 131.9 W -133.4 181.73 181.01 300.00 300.00 O.OON 0.00E KTU24-6H 296.95 297.70 123.55S 134.20W -132.6 182.43 181.41 400.00 400.00 O.OON 0.00E KTU24-6H 394.09 394.78 123.76S 137.53W -132.0 185.09 183.64 500.00 500.00 O.OON 0.00E KTU24-6H 494.04 494.66 123.98S 141.12W -131.3 187.92 186.07 600.00 599.95 1.23S 2.31E KTU24-6H 593.92 594.49 124.17S 144.6 W 112.0 191.71 189.50 700.00 699.63 4.92 9.23E KTU24-6H 693.49 693.99 124.45S 148.1 W 114.5 197.67 195.08 800.00 798.77 11.05S 20.75E KTU24-6H 792.55 793.00 124.84S 151.30W 118.0 206.36 203.32 900.00 897.08 19.62S 36.84E KTU24-6H 890.86 891.26 125.33S 154.17W 122.2 218.39 214.80 10 .00 994.31 0.59S 57.44E KTU24-6H 988.54 988.91 125.83S 156.60W 126.7 234.34 230.16 1100.00 1090.18 43.94S 82.50E KTU24-6H 1087.07 1087.43 126.17S 158.02W 131.5 254.21 249.40 Offset Wel{bore Surve Tool Pro rams ___ Weli Wellbore Surve Name MD ff Surve Tool rror Model KTU24-6H KTU24-6H RD MWD <8844- 940> 8940.00 Navi Trak Standard All data is in Feet unless othennrise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated MARATHON Oil Company '~~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 C CLEARANCE LISTING Page 5 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska INTEQ C --_ learance Data _ Reference MD[ftj Reference TVD[ft] Reference Nortl-[ft] Reference East[ft] Offset Well Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset East[ftj Angle From° H~hside Closest Approach Distance ft Ellipse Separation [ft] 0.00 0.00 O.OON 0.00E KTU24-6H 0.00 0.80 126.12S 130.16W -134.1 181.24 181.24 0.80 0.80 O.OON 0.00E KTU24-6H 0.00 _ 0.80 126.12S 130.16W -134.1 181.24 181.22 100.00 100.00 O.OON 0.00E KTU24-6H 98.83 99.63 125.81S 130.64W -133.9 181.37 180.94 131.23 131.23 O.OON 0.00E KTU24-6H 129.82 130.61 125.59S 130.96W -133.8 181.45 180.91 200.00 200.00 O.OON 0.00E KTU24-6H 198.32 199.10 124.91 S 131.99W -133.4 181.73 181.01 300.00 300.00 O.OON 0.00E KTU24-6H 296.95 297.70 123.55S 134.20W -132.6 182.43 181.41 400.00 400.00 O.OON 0.00E KTU24-6H 394.09 394.78 123.76S 137.53W -132.0 185.09 183.64 500.00 500.00 O.OON 0.00E KTU24-6H 494.04 494.66 123.98S 141.12W -131.3 187.92 18 .07 600.00 599.95 1.23S 2.31E KTU24-6H 59 .92 5 4.49 124.17S 144.69W 112.0 191.71 189.50 700.00 699.3 4.92S 9.23E KT 24-6H 693.49 693.99 124.45S 148.10W 114.5 197.67 19 .08 800.00 798.77 11.05S 20.75E KT 24-6H 792.55 793.00 124.84S 151.30W 118.0 206.36 20 .32 900.00 897.08 19.62S 36.84E KTU24-6H 890.86 891.26 125.33S 154.17W 122.2 218.39 214.80 1000.00 994.1 30.59S 7.44E KTU24-6H 98 .54 9 8.91 125.83S 156.60W 126.7 234.34 230.16 1100.00 1090.18 43.94S 82.50E KTU24-6H 1087.07 1087.43 126.17S 158.02W 131.5 254.21 249.40 Offset Weftbore Surve Tool Pro rams WeU We{{bore Surv Name MD ft Surve Tool Error Model KTU24-6H KTU24-6H Pilot UNKN <8820-9010> 9010.00 No Tool All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated MARATHON Oil Company KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 • CLEARANCE LISTING Page 6 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~%~ INTEQ C learance Da#a Reference MD[ft] Reference 11/D[ft] Reference North[ft] Reference East[ft] Offset Well Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset East[ft] Angle From Highside Ciosest Approach Distance ft Eclipse Separation [ft] 0.00 0.00 O.OON 0.00E KTU24-6H 0.00 _ 0.80 126.12S 130.16W -134.1 181.24 181.24 0.80 0.80 O.OON 0.00E KTU24-6H 0.00 0.80 126.12S 130.16W -134.1 181.24 181.22 100.00 100.00 O.OON 0.00E KTU24-6H 98.83 99.63 125.81S 130.64W -133.9 181.37 180.94 131.23 131.23 O.OON 0.00E KTU24-6H 129.82 130.61 125.59S 130.96W -133.8 181.45 180.91 200.00 200.00 O.OON 0.00 KTU24-6H 198.32 199.10 124.91S 131.99W -133.4 181.73 181.01 300.00 300.00 O.OON 0.00E KTU24-6H 296.95 297.70 123.55S 134.20W -132.6 182.43 181.41 400.00 400.00 O.OON 0.00E KTU24-6H 3 .09 394.78 123.76S 137.53W -132.0 185.09 1 3.64 500.00 500.00 O.OON 0.00E KTU24-6H 494.04 494.66 123.98S 141.12W -1 1.3 187.92 1 6.07 600.00 599.95 1.23S 2.31E KTU24-6H 593.92 594.49 124.17S 144.69W 112.0 191.71 1 9.50 700.00 699.63 4.92 9.23E KTU24-6H 693.49 693.99 124.45S 148.10W 114.5 197.67 1 5.08 800.00 798.77 11.OSS 20.75E KTU24-6H 792.55 793.00 124.84S 151.30W 118.0 206.36 2 3.32 900.00 897.08 19.62S 36.84E KTU24-6H 890.86 891.26 125.33S 154.17W 122.2 218.39 214.80 1000.00 994.31 30.59S 57.44E KTU24-6H 988.54 988.91 125.83S 156.60W 126.7 234.34 2 0.16 1100.00 1090.18 43.94S 82.50E KTU24-6H 1087.07 1087.43 126.17S 158.02W 131.5 254.21 249.40 Offset Wellbore Surve Tool Pro rams 1NeU Wellbore Surve Name MD ft Surve Tool E Model KTU24-6H KTU24-6H MWD <0-10960> 10960.00 Navi Trak Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • MARATHON Oil Company KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 • CLEARANCE LISTING Page 7 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~p~~et liftl~ 1NTEQ C learance Data Reference MD[ft] Reference TVD[ft] Reference Nath[ft} Reference East[ft] Offset Well Offset MD[ftJ Offset TVD[ftJ ..Offset North[ft} Offset East[ft} Angle Fran Nighside Closest Approach Distance Ellipse Separation [ft] 0.00 0.00 O.OON 0.00E KBU11-8X 0.00 0.80 46.11S 49.10W -133.2 67,36 67.3fi 0.80 0.80 O.OON 0.00E KBU11-8X 0.00 0.80 46.11S 49.10W -133.2 67.36 67.34 100.00 1 0.00 O.OON 0.00E KBU11-8X 99.16 99.95 46.09S 49.17W -133.2 67.39 66.94 164.04 164.04 O.OON 0.00E KBU11-8X 163.06 163.86 46.06S 49.33W -133.0 67.49 66.78 200.00 200.00 O.OON 0.00E KBU11-SX 198.64 199.43 46.04S 49.66W -132.8 67.72 66.88 300.00 300.00 O.OON 0.00E KBU11-8X 298.82 299.62 46.43S 50.36W -132.7 68.50 67.24 400.00 400.00 O.OON 0.00E KBU11-8X 398.59 399.38 46.96S 50.78W -132.8 69.17 67.49 500.00 500.00 O.OON 0.00E KBU11-8X 498.37 499.16 47.69S 51.47W -132.8 70.17 68.07 600.00 599.95 1.23S 2. 1E KBU11-SX 597.78 598.55 48.29S 52.88W 111.4 72.54 70.14 700.00 699.63 4.92S 9.23E KBU11-8X 697.58 698.33 49.26S 54.53W 116.9 77.69 74.97 800.00 798.77 11.05S 20.75E KBU11-8X 798.28 799.03 50.49S 54.60W 124.0 85.05 81.98 900.00 897.08 19.62S 36.84E KBU11-8X 901.75 902.38 51.97S 50.48W 131.5 93.27 89.82 1 0.00 994.31 30.59S 57.44E KBU11-8X 1004.78 1004.94 53.83S 40.80W 138.7 101.51 97.58 1100.00 1090.18 43.94S 82.50E KBU11-8X 1106.94 1106.20 55.44S 27.42W 146.1 111.68 107.19 1200.00 1184.43 59.63S 111.96E KBU11-8X 1208.48 1206.36 56.38S 10.81W 153.6 124.76 119.66 1213.91 1197.40 61.99S 116.41E KBU11-8X 1223.03 1220.67 56.41S 8.16W 154.7 126.84 121.65 1300.00 1276.81 77.61S 145.74E KBU11-8X 1309.51 1305.53 56.74S 8.47E 160.7 141.79 136.06 1400.00 1367.06 97.85S 183.73E KBU11-8X 1409.19 14 2.83 56.27S 30.10E 167.1 163.13 156.75 1471.3 1430.00 113.62S 213.35E KBU11-8X 1479.96 1471.45 54.78S 47.34E 171.4 180.95 174.07 1 0.0 1455.04 120.18S 225.68E KBU11-8X 1507.14 14 7.76 54.16S 54.13E 172.9 188.72 181.64 1600.00 1542.39 143.07S 268.66E KBU11-8X 1604.56 15 1.98 52.09S 78.80E 177.5 216.30 20 .48 1700.00 1629.73 165.96S 311.64E KBU11-8X 1704.09 1687.90 51.09S 105.33E -178.9 243.19 234.56 ..Offset Welibore Surve Tool Pro rams - W It W Ilbore Surv N me MD ft Surve Tool ode{ <, KBU11-SX KBU11-8X MWD <0-7659> 7659.00 Navi Trak Ma Corrected All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1D) Prepared by Baker Hughes Incorporated • MARATHON Oil Company KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 CLEARANCE LISTING Page 8 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~~~ INTEQ C learance Data Reference MD[ft] Reference.. TVD[ftJ Reference tJorth[ft] Reference' East[ft] Offset Well Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset East[ft] Angle FrcMn Highside Closest Approach Distance ft Ellipse Separation I+ [ft] I 1197.51 1182.10 59.21 S 111.18E KU24-5 1253.97 1225.67 297.75S 193.10E 47.7 255.95 247.01 1200.00 1184.43 59.63S 111.96E KU24-5 1256.21 1227.70 297.13S 193.84E 47.6 254.92 245.93 1300.00 1276.81 77.61S 145.74E KU24-5 1346.48 1308.21 271.12S 225.26E 44.8 211.56 200.8 1400.00 1367.06 97.85S 183.73E KU24-5 1433.67 1384.76 245.35S 258.08E 40.3 166.12 153.62 1471.33 1430.00 113.62S 213.35E KU24-5 1495.22 1437.73 226.35S 283.03E 34.8 132.75 118.9 1500.00 1455.04 120.18S 225.68E KU24-5 1519.87 1458.63 218.47S 293.44E 31.1 119.44 105.04 16 0.00 1542.39 143.07S 268.66E KU24-5 1603.45 1527.99 190.15S 330.46E 9.6 79.01 63.30 16 6.82 1592.02 156.OSS 2 3.08E KU24-5 1650.07 1565.94 173.72S 351.98E -10.5 66.79 51.39 1673.23 1606.35 159.84S 300.13E KU24-5 1663.10 1576.50 169.10S 358.07E -16.8 6 .83 50.73 1676.22 1608.96 160.52S 301.42E KU24-5 1665.57 1578.49 168.22S 359.23E -18.0 65.81 50.76 17 0.00 1629.73 165. 6S 311.64E KU24-5 1685.21 1594.33 161.24S 368.51 E -27.6 67.16 52.53 1800.00 1717.07 188.85S 354.62E KU24-5 1769.57 1662.63 131.72S 408.25E -59.6 95.42 79.95 1900.00 1804.42 211.74S 397.60E KU24-5 1853.71 1731.49 103.18S 447.27E -76.2 139.90 121.47 2000.00 1891.76 234.63S 440.57E KU24-5 1937.40 1800.05 74.86S 486.04E -85.0 189.74 168.60 2100.00 1979.11 257.52S 483.55E KU24-5 2021.08 1868.60 46.54S 524.79E -90.3 241.71 218.12 Offset Wellbore Surve Toot Pro rams W 11 - We re S rv Name MD ft S rve T 1 n' M el KU24-5 KU24-5Rd MWD<3470-4816> 4823.00 ISCWSA MWD Basic MWD -ISCWSA - 28 JAN 03 OJH All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1D) Prepared by Baker Hughes Incorporated MARATHON Oil Company KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MQRATHaN slot# KBU11-8Y, Pad 41-7 CLEARANCE LISTING Page 9 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~+ . ~ ~. . INTEQ C learance Data "Reference MD[s1j ~ Reference TVD[ftj Reference Nortli[ftj Reference East[ft] Offset Well Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset East[ft] Angle From.... Highside d Closest :Approach Distance Ellipse Separation [ft] 1197.51 1182.10 59.21 S 111.18E KU24-5 1253.97 1225.67 297.75S 193.10E 47.7 255.95 247.01 1200.00 1184.43 59.63S 111.96E KU24-5 _ 1256.21 1227.70 297.13S 193.84E 47.6 254.92 245.93 1300.00 1276.81 77.61S 145.74E KU24-5 1346.48 1308.21 271.12S 225.26E 44.8 211.56 200.89 1400.00 1367.06 97.85S 183.73E KU24-5 1433.67 1384.76 245.35S 258.08E 40.3 166.12 153.62 1471.33 1430.00 11 .62S 213.35E KU24-5 1495.22 1437.73 226.35S 283.03E 34.8 132.75 118.93 1500.00 1455.04 120.18S 225.68E KU24-5 1519.7 1458.63 218.47S 293.44E 31.1 119.44 105.04 1600.00 1542.39 143.075 268.66E KU24-5 1603.45 1527,99 190.15S 330.46E 9.6 79.01 63.30 1656.82 1592.02 156.08S 293.08E KU24-5 1650.07 1565.94 173.72S 351.98E -10.5 66.79 51.39 1673.23 1606.35 159.845 300.13E KU24-5 1663.10 1576.50 169.10S 358.07E -16.8 65.83 50.7 1676.22 1608.96 160.525 301.42E KU24-5 1665.57 1578.49 168.22S 359.23E -18.0 65.81 50.76 1700.00 1629.73 165.96S 311.64E KU24-5 1685.21 1594.33 161.24S 368.51E -27.6 67.16 52.53 1800.00 1717.07 188.85S 354.62E KU24-5 1769.57 1662.63 131.72S 408.25E -59.6 95.42 79.95 1900.00 1804.42 211.745 397. OE KU24-5 1853.71 1731.49 103.18S 447.27E -76.2 139.90 121.47 2000.00 1891.76 234.63S 440.57E KU24-5 1937.40 1800.05 74.86S 486.04E -85.0 189.74 168.60 2100.00 1979.11 257.52S 483.55E KU24-5 2021.08 1868.60 46.54S 524.79E -90.3 241.71 218.12 Offset Welibore Surve Too) Pro rams - -- - 1 Wel Surv Name MD ft Serve Too rror Model KU24-5 KU24-5 GMS <0-5900'> 5900.00 Level Rotor G ro Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated MARATHON O[I Company ' KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 • CLEARANCE LISTING Page 10 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~~~ '.s INTEQ C __ learance Data Reference MD[ft]i Reference TVD[ftj Reference North[ft] Reference East[ft] Offset Well Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset Eest[ft] Angle From Highsitle d Ckrsesti ApP-oach Dtsta(tce ft, Ellipse Separation (ft] 0.00 0.00 O.OON 0.00E KTU32-7H 0.00 0.80 168.78S 30.12E 169.9 171.45 171.45 0.80 0.80 O.OON 0.00E KTU32-7H 0.00 0.80 168.78S 30.12E 169.9 171.44 171.43 100.00 100.00 O.OON 0.00E KTU32-7H 97.00 97.80 169.37S 30.17E 169.9 172.05 171. 200.00 200.00 O.OON 0.00E KTU32-7H 194.84 195.62 171.16S 30.34E 169.9 173.88 173.18 300.00 300.00 O.OON 0.00E KTU32-7H 295.83 296.58 173.60S 30.54E 170.0 176.30 175.15 400.00 400.00 O.OON 0.00E KTU32-7H 395.48 396.21 175.56S 30.53E 170.1 178.24 176.64 500.00 500.00 O.OON 0.00E KTU32-7H 494.72 495.42 177.89S 31.00E 170.1 180.63 178.57 600.00 599.95 1.23S 2.31E KTU32-7H 595.73 596.41 180.06S 31.72E 52.6 181.27 178.84 700.00 699.63 4.92S 9.23E KTU32-7H 695.90 696.56 181.88S 32.30E 54.6 178.48 175.67 800.00 798.77 11.0 S 20.75E KTU32-7H 795.61 796.26 183.33S 32.34E 58.3 172.69 169.55 900.00 897.08 19.62S 36.84E KTU32-7H 895.29 895.93 184.42S 32.09E 64.0 164.87 161.35 1000.00 994.31 30.59S 57.44E KTU32-7H 993.83 994.46 184.23S 30.85E 72.4 155.92 151.91 1100.00 1090.18 43.94S 82.50E KTU32-7H 1089.97 1090.59 183.61S 29.56E 83.1 149.37 144.79 1152.98 1140.33 51.97S 97.58E KTU32-7H 1139.37 1139.98 183.25S 28.77E 89.6 148.22 143.27 1200.00 1184.43 59.63S 111.96E KTU32-7H 1182.31 1182.92 183.24S 28.09E 95.5 149.39 144.13 1300.00 1276.81 77.61S 145.74E KTU32-7H 1273.96 1274.55 183.10S 26.49E 108.5 159.22 153.27 1328.74 1302.98 83.20S 156.23E KTU32-7H 1299.95 1300.53 183.15S 26.04E 112.1 164.14 157.97 1345.14 1317.83 86.47S 162.37E KTU32-7H 1314.57 1315.16 183.19S 25.79E 114.0 167.38 161.09 1400.00 1367.06 97.85S 183.73E KTU32-7H 1363.49 1364.07 183.25S 24.90E 120.3 180.36 173.75 1471.33 1430.00 113.62S 213.35E KTU32-7H 1425.91 1426.47 182.99S 23.64E 127.7 202.03 195.01 1500.00 1455.04 120.18S 225.68E KTU32-7H 1448.90 1449.45 182.84S 23.08E 130.3 212.14 204.96 1600.00 1542.39 143.07S 268.66E KTU32-7H 1535.07 1535.59 182.52S 20.54E 138.6 251.32 243.65 Offset Wellbore Surve Tool Pro :rams Welf Wellbore Surve Name MD ft Surve Tool Error Modef KTU32-7H KTU32-7H MWD <0 - 11857'> 11857.00 Navi Trak Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • MARATHON Oil Company ~~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 • CLEARANCE LISTING Page 11 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~.^ ~S INTEQ Clearance Data. `Reference MD(ft] Reference TVD(ft] Reference North(ftj Reference Eastjft] Offset Well Offset MD[ftj Offset ND(ft] Offset North(ft) Offset East[ft] Angle From Highside Cbsest Approach Distance ft Ellipse Separation [ft) ___ _ ` 836.61 834.87 13.91S 26.11E KU13-5 892.07 886.04 225.04S 106.08W 96.0 254.30 249.65 ' 900.00 897.08 19.62S 36.84E KU13-5 962.04 954.26 211.77S 98.18W 99.8 241.71 236.63 1000.00 994.31 30.59S 57.44E KU13-5 1066.77 1055.33 187.62S 85.11W 107.8 220.68 214.81 1100.00 1090.18 43.94S 82.50E KU13-5 1162.53 1146.61 161.72S 72.13W 118.2 202.41 195.63 1200.00 1184.43 59.63S 111.96E KU13-5 1250.96 1230.65 136.89S 60.33W 129.9 194.39 186.57 1205.48 1189.54 60.56S 113.71E KU13-5 1255.80 1235.25 135.55S 59.69W 130.6 194.37 186.49 1213.91 1197.40 61.99S 116.41E KU13-5 1263.24 1242.34 133.50S 58.71 W 131.6 194.41 186.43 1300.00 1276.81 77.61S 145.74E KU13-5 1338.77 1314.37 113.03S 48.85W 142.0 201.32 192.37 1377.95 1347.36 93.20S 175.00E KU13-5 1407.01 1379.19 93.80S 39.62W 151.1 216.97 207.12 1394.36 1362.03 96.65S 181.48E KU13-5 1420.78 13 2.22 89.77S 37.70W 152.9 221.3 211.32 1400.00 1367.06 97.85 183.73E KU13-5 1425.50 1396.69 88.39S 37.04W 153.5 222.95 212.85 1471.33 1430.00 113.62S 213.35E KU13-5 1485.69 1453.31 69.92S 28.36W 160.8 246.73 235.82 1500.00 1455.04 120.18S 225.68E KU13-5 1509.23 1475.33 62.39S 24.86W 163.6 257.91 246.68 All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes In~rporated • MARATHON Oil Company '~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 Ir1 u CLEARANCE LISTING Page 12 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska 1G~t LNTEQ Clearance Data Reference MD[ft] Reference TVD[ftJ Reference North[ft] Reference East[ft] Offset WeU Offset MD[ft] Offset TVD[ft] Offset Narth[ft] Offset East[ft] Angte From Highsitle d Gk~se>3t Approadi Distance ElNpse Separation (ft] 0.00 0.00 O.OON 0.00E KBU 44-6 0.00 0.80 131.83S 12.17W -174.7 132.39 132.39 16.40 16.40 O.OON 0.00E KBU 44-6 15.77 16.57 131.81S 12.15W -174.7 132.37 132.18 100.00 100.00 O.OON 0.00E KBU 44-6 99.68 100.48 131.68S 11.99W -174.8 132.23 131.75 200.00 200.00 O.OON 0.00E KBU 44-6 199.99 200.78 131.30S 11.45W -175.0 131.80 130.96 300.00 300.00 O.OON .00E KBU 44-6 300.12 300.91 130.74S 10.39W -175.5 131.15 129.89 400.00 400.00 O.OON 0.00E KBU 44-6 401.02 401.80 129.89S 9.35W -175.9 130.23 128.60 500.00 500.00 O.OON 0.00E KBU 44-6 502.89 503.65 128.31S 7.82W -176.5 128.60 126.58 600.00 599.95 1.23S 2.31E KBU 44-6 605.29 605.92 124.68S 4.37W 65.2 123.78 121.46 700.00 6 9.63 4.92S 9.23E KBU 44-6 707.51 707.7 118.53S 1.43E 66.4 114.18 111.51 800.00 798.77 11.05S 20.75E KBU 44-6 807.00 806.79 111.15S 7.82E 70.2 101.25 98.16 900.00 8 7.08 19.62S 36.84E KB 44-6 904.15 903.5 104.41 S 12.71E 79.0 88.40 84.80 1000.00 994.31 30.59S 57.44E KBU 44-6 998.99 998.21 99.19S 16.18E 93.6 80.15 75.91 1025.53 1018.92 33.78S 63.43E KB 44-6 1022.78 1021.98 98.25S 16.83E 98.1 79.60 75.17 1033.46 1026.55 34.79S 65.33E KBU 44-6 1030.42 1029.61 98.01S 17.00E 99.6 79.63 75.14 1100.00 1090.18 43.94S 82.50E KBU 44-6 1093.31 1092.46 96.27S 18.23E 112.3 82.92 78.00 1115.49 1104.89 46.22S 86.78E KB 44-6 1108.02 11 7.17 95.91S 18.45E 115.2 84.52 79.49 1200.00 1184.43 59.63S 111.96E KBU44-G 1186.19 1185.32 94.21S 19.11E 129.7 99.09 93.66 1300.00 1276.81 77.61S 145.74E KB 44-6 1277.41 1276.52 92.93S 19.37E 142.6 127.29 121.45 1400.00 1367.06 97.85S 183.73E KBU 44-6 1366.55 1365.66 93.31S 18.87E 150.7 164.93 158.64 1471.3 1430.00 113.62S 213.35E KBU 44-6 1429.59 1428.69 94.04S 18.32E 154.8 196.02 189.44 1500.00 1455.04 120.18S 225.68E KBU 44-6 1453.98 14 3.08 94.40S 18.09E 156.2 209.19 202.47 1600.00 1542.39 143.07S 268.66E KBU 44-6 1540.22 15 9.31 95.33S 16.94E 160.3 256.22 249.06 Offset Wellbore Surve Tool Pro rams _- Well W (bore S roe Name M ft urve Tool rr M 1 KBU 44-6 KBU 44-6 MWD <0-7440> 7440.0 Navi Trak Ma Corrected All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated 1 MARATHON O[I Company ~~~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 • CLEARANCE LISTING Page 13 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~i~ INTEQ C learance Data Reference MD[ft] Reference ND[ft] Reference North[ftj Reference East[it] Offset Well Offset MD[ft] Offset ND[ft] Offset North[ft] Offset East[ft] Ang~ From H~hside Closest Approadr ' Distarne ft Ellipse Separation [ft] 1800.00 1717.07 188.85S 54.62E KDU#2 1789.88 1702.78 453.53S 386.05E 57.4 266.92 247.39 1900.00 1804.42 211.745 397.60E KDU#2 1886.05 1783.54 451.70S 438.22E 54.0 244.27 222.69 2000.00 1891.76 234.63S 440.57E KDU#2 1982.16 1864.14 449.88S 490.54E 49.9 222.69 199.11 2100.00 1979.11 257.525 483.55E KDU#2 2078.22 1944.62 448.05S 542.96E 44.9 202.53 177.12 2200.00 2066.45 280.41 S 526.53E KDU#2 2174.39 2025.11 446.21 S 595.57E 38.8 184.30 157.44 2300.00 2153.79 303.30S 569.51E KDU#2 2270.08 2105.05 444.38S 648.13E 31.6 16 .70 140.61 2400.00 2241.14 326.195 612.49E KDU#2 2365.89 2184.89 442.53S 701.05E 23.1 156.66 127.85 2500.00 2328.48 349.08S 655.47E KDU#2 2461.49 2264.4 440.80S 754.11E 13.4 14 .16 119.90 2591.86 2408.72 370.11 S 694.95E KDU#2 2549.28 2337.33 439.61 S 802.96 4.1 146.94 117.21 2600.00 2415.82 371.97S 98.45E KDU#2 2557.11 2343.84 439.51 807.32E 3.3 146.96 117.17 2608.27 2423.04 373.86S 702.00E KDU#2 2565.07 2350.44 439.42S 811.74E 2.5 147.01 117.16 2690.29 2494.68 392.635 737.25E KDU#2 2643.58 2415.61 438.84S 855.53E -5.7 149.59 118.91 2700.0 2503.17 394.86S 741.43E KDU#2 2652.55 2423.05 438.82S 860.54E -6.6 150.13 119.33 2800.00 2590.51 417.75S 784.41E KDU#2 2748.84 2502.90 438.61 S 914.36E -15.7 158.10 125.54 2837.93 2623.64 426.43S 800.71E KDU#2 2785.41 2533.21 438.55S 934.80E -19.0 162.18 128.76 2900.00 2677.85 440.64S 827.39E KDU#2 2845.25 2582.82 438.42$ 968.26E -23.9 169.95 134.99 3000.00 2765.20 463.52S 870.37E KDU#2 2941.58 2662.69 437.94S 1022.13E -31.0 184.92 147.28 3100.00 2852.54 486.42S 913.35E KDU#2 3037.76 2742.42 437.18S 1075.90E -37.1 202.42 161.98 3200.00 2939.88 509.30S 956.32E KDU#2 3133.67 2821.89 436.29S 1129.59E -42.2 221.98 178.65 3300.00 3027.23 532.19S 999.30E KDU#2 3229.38 2901.18 435.35S 1183.20E -46.5 24 .OS 196.88 3400.00 3114.57 555.08S 1042.28E KDU#2 3325.55 2980.73 434.41S 1237.24E -50.1 26 .49 216.50 3500.00 3201.91 577.97S 1085.26E KDU#2 3421.04 3059.68 433.41S 1290.93E -53.1 288.84 237.13 .Offset Welibore Surve Tool Pro rams.. _ ___ elf WeNtaore Surve' Name M tt urv Tool Error Model KDU#2 KDU#2 MSS <0-10522'> 10522.00 Photomechanical Ma netic Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated MARATHON O[I Company '~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHQN slot# KBU11-8Y, Pad 41-7 I~ CLEARANCE LISTING Page 14 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~~~ INTEQ C learance Data Reference MD[ft} Reference ND[ftJ Referehce North[ftJ Reference East[ftJ Offset Well Offset MD[ftJ Offset ND[ft] Offset North[ftJ Offset East[ftJ Angie Fnxn Highside d Closest Approach Distance ft `' Ellipse Separation [ftJ 918.64 915.29 21.48 40.34E KU 43-6A 1039.12 1014.52 255.10S 55.42E 63.6 254.27 245.77 1000.00 994.31 30.59S 57.44E KU 43-6A 1101.94 1072.81 232.73S 62.26E 66.8 216.90 207.35 1100.00 1090.18 43.94S 82.5E KU 43-6A 1201.92 1163.44 192.42S 74.59E 74.6 1 5.76 1 .7 1200.00 1184.43 59.63S 111.96E KU 43-6A 1291.10 1241.29 150.86S 87.32E 90.4 110.29 97.85 1300.0 1276.81 77.61S 145.74E KU 43-6A 1367.46 1306.65 113.35S 99.64E 122.5 65.52 51.71 1328.74 1302.98 83.20S 156.23E KU 43-6A 1388.91 1324.97 102.855 103.36E 135.7 60.54 46.96 13 7.7 1311.09 84.99S 159.58E KU 43-6A 1395.54 13 0.65 99.60S 104.52E 139. 60.24 46.83 1400.00 1367.06 97.85S 183.73E KU 43-6A 1442.06 1370.33 76.865 113.02E 167.4 73.83 61.43 1471.3 1430.00 113.62S 213.35E KU 43-6A 1492.60 1413.34 52.03S 122.33E -172.4 111.16 98.03 1500.00 1455.04 120.18S 2 5.68E KU 43-6A 1512.83 14 0.53 41.99S 125.98E -167.1 129.06 115.48 1600.00 1542.39 143.07S 2 8.66E KU 43-6A 1581.93 14 9.11 7.46S 138.2 E -155.9 195.56 180.44 1700.00 1629.73 165.965 311.64E KU 43-6A 1647.95 1544.87 26.04N 149.50E -150.2 265.25 248.78 Offset Wellbore Surve Tool: Pro rams Weil Weilbore Surv Name MD ft Surv Tooi Error Model KU 43-6A KU43-6A MSS <0-5300'> 5300.00 Photomechanical Ma netic Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated ;7 MARATHON Oil Company KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 CLEARANCE LISTING Page 15 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~~it~ ~ f~16N~i INTEQ C learance Data Reference MD[ftJ Reference. 11/D[ftj Reference North[ft] f~eferencs East[ftJ Offset Weft Offset MD[ft] Offset ND[ft] Offset North[ft] Offset 'Eest[#tJ Angie From Highside Closest Approach Distance Ellipse Separation [ftJ 705.35 704.98 5.19S 9.74E KU43-6 788.22 782.21 236.04S 54.68W 79.6 251.81 249.22 800.00 798.77 11.05S 20.75E KU43-6 889.14 877.08 202.39S 47.78W 85.2 217.81 214.86 900.0 897.08 19.62S 36.84E KU43-6 974.57 956.25 170.39S 47.78W 5.3 182.74 179.42 1000.00 994.31 30.59S 57.44E KU43-6 1058.18 1032.97 137.51S 52.50W 110.7 158.15 154.42 1066.27 1058.01 39.17S 73.56E KU43-6 1111.45 1081.64 116.17S 56.14W 122.4 152.67 148.64 1100.00 1090.18 43.94S 82.50E KU43-6 1136.83 1104.97 106.33S 57.91 W 128.0 154.36 150.21 1131.89 1120.42 48.69S 91.42E KU43-6 1161.31 1127.59 97.13S 59.70W 133.2 158.86 154.55 1200.00 1184.43 59.63S 111.96E KU43-6 1205.02 1167.26 79.45S 64.45W 142.4 178.36 173.80 1300.00 1276.81 77.61 S 145.74E KU43-6 1261.45 1216.52 53.52S 73.61 W 153.3 228.76 223.82 Offset Welibore Surve Tool. Pro rams Well Welibore Surve Name MD ft _ Surve Tool ErrorModel. KU43-6 KU43-6Rd MWD <4250-5740> 5745.00 ISCWSA MWD Basic MWD -ISCWSA - 28 JAN 03 OJH All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • MARATHON Oil Company J~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHQN slot# KBU11-8Y, Pad 41-7 CLEARANCE LISTING Page 16 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~p~~~~ Ntl INTEQ C learance Data Reference MD[ft] Reference: TVD[ft] Reference North[ft] Reference East[ft] 'Offset Well Offset MD[ft] Offset TVD[ft] Offset tJortn[ft} Offset East[ft] Angle from Highskfe de Closest Approach Distance n Ellipse Separation [ft] 705.38 704.98 5.19S 9.74E KU43-6 788.22 782.21 236.04S 54.68W 79.6 251.81 249.22 800.00 798.77 11.05S 20.75E KU43-6 889.14 877.08 202.39S 47.78W 85.2 217.81 214.86 900.00 897.08 19.62S 36.84E KU43-6 974.57 956.25 170.39S 47.78W 95.3 182.74 179.42 1000.00 994.31 30.59S 57.44E KU43-6 1058.18 1032.97 137.51S 52.50W 110.7 158.15 154.42 1066.27 1058.01 39.17S 73.56E KU43- 1111.45 1081.64 116.17S 56.14W 122.4 152.67 148.64 1100.00 1090.18 43.94S 82.50E KU43-6 1136.83 1104.97 106.33S 57.91 W 128.0 154.36 150.21 1131.89 1120.42 48.69S 91.42E KU43- 1161.31 1127.59 97.13S 59.70W 133.2 158.86 154.55 1200.00 1184.43 59.63S 111.96E KU43- 1205.02 1167.26 79.45S 64.45W 142.4 178.36 173.80 1300.00 1276.81 77.61 S 145.74E KU43- 1261.45 1216.52 53.52S 73.61 W 153.3 228.76 223.82 .Offset Welibore Surve Tool Pro rams Well Wellbore Surv Name MD ft Surve Toot Erna Model KU 3-6 K 4 -6 GMS <0-41 9> 4179.00 Scientific Kee er G r 29-S - 3 THJ KU43-6 KU43-6 MSS <0-5706'> 5706.00 Photomechanical Ma netic Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated • MARATHON Oil Company J~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 CLEARANCE LISTING Page 17 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska INTEQ C learance Data Reference MD[ft] Reference TVD[ft] Reference North[ft] Reference East[ft] Offset Well Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset East[ft] Angle From Fiighside d Closest Approach Distance _ft Ellipse Separation- [ft] 0.00 0.00 O.OON 0. OE KBU43-7X 0.00 0.80 49.60S 208.23W -103.4 214.06 214.06 0.80 0.80 O.OON 0.00E KBU43-7X 0.00 0.80 49.60S 208.23W -103.4 214.05 214.04 49.21 49.21 O.OON 0.00E KBU43-7X 47.92 48.72 49.48S 208.37W -103.4 214.16 213.88 100.00 100.00 O.OON 0.00E KBU43-7X 97.72 98.52 49.13S 208.80W -103.2 214.51 214.10 200.00 200.00 O.OON 0.00E KBU43-7X 195.72 196.4 47.75S 210.50W -102.8 215.87 215.17 30 .00 300.00 O.OON 0.00E KBU43-TX 291.95 292.66 45.70S 213.32W -102.1 218.28 217.18 40 .00 4 0.00 O.OON 0.00E KBU43-7X 383.19 383.7 44.17S 218.08W -101.5 223.10 221.57 50 .00 500.00 O.OON 0.00E KBU43-7X 468.77 468.81 43.79S 227.41 W -100.9 233.68 231.70 60 .00 599.95 1.23S 2.31E KBU43-7X 563.06 562.14 44.65S 240.76W 1 1.5 249.80 247.41 606.96 606.90 1.41S 2.64E KBU43-7X 569.88 568.88 44.79S 241.79W 141.6 251.14 248.72 Offset Welfbore Surve Tool Pro rams I T I I` KBU43-7X KBU43-7X MWD<0-8610'> 8610.00 Navi Trak Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated C7 MARATHON O[I Company J~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 • CLEARANCE LISTING Page 18 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska -.a.'~ ~ , INTEQ C learance Data _ i Reference MD[ftj Reference TVD[ftJ Reference North[tl} Reference East[ft] Offset Well Offset MD[ft] Offset TVDjft] Offset North[ftj Offset East[ft} Angle From H~hside' Closest I Approach Distance Ellipse Separation (ftJ 0.00 0.00 O.OON 0.00E KBU42-7 0.00 0.80 126.87S 181.04W -125.0 221.07 221.07 16.40 16.40 O.OON 0.00E KBU42-7 15.64 16.44 126.85S 181.05W -125.0 221.07 220.87 100.00 100.00 O.OON 0.00E KBU42-7 99.29 100.09 126.63S 181.18W -125.0 221.05 220.55 181.80 161.80 O.OON 0.00E KBU42-7 181.00 181.80 126.12S 181.47W -124.8 221.00 220.22 200.00 200.00 O.OON 0.00E KBU42-7 199.06 199.86 126.01S 181.56W -124.8 221.01 220.16 278.87 278.87 0. ON 0.00E KBU42-7 277.28 278.08 125.76S 181.96W -124.7 221.19 220.01 300.0 300.00 O.OON 0.00E KBU42-7 297.11 297.91 125.83S 182.09W -124.7 221.35 220.10 400.00 400.00 O.OON 0.00E KBU42-7 391,20 391.96 127.77S 183.35W -124.9 223.62 222.03 500.00 500.00 O.OON 0.00E KBU42-7 485.25 485.84 132.76S 185.59W -125.6 228.62 226.64 600.00 599.95 1.23S 2.31E KBU42-7 79.22 579.40 141.O6S 188.46W 115.5 237.42 235.11 700.00 699.63 4.92S 9.23E KBU42-7 75.27 674.71 152.54S 191.51W 115.0 250.43 247.74 705.38 704.98 5.19S 9.74E KBU42-7 680.60 679.98 153.28S 191.63W 114.9 251.20 248.49 Offset Wellbore Surve Tool Pro rams Well Wellbore Surve Name MD ft Surve Tool Ertor Model KBU42-7 KBU42-7 MWD <0 - 7570> 7570.00 Navi Trak Ma Corrected All data is in Feet unless othervvise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1D) Prepared by Baker Hughes Incorporated • MARATHON Oil Company KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 • CLEARANCE LISTING Page 19 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~f~ ~$ iNTEQ C learance Data Reference MD(ft} Reference 11/D[ft} Reference North(ft} Reference East[ft] Offset Well Offset MD[ftj Offset 1'VD[ft} Offset. North[ft] Offset East[ft} Angie From Highside de Closest Approach i Distance ft Etiipse Separation.. [ft] _- 0.00 0.00 O.OON 0.00E KBU33-6X 0.00 5.40 47.79S 154.05W -107.2 161.38 161.38 16.40 16.40 O.OON 0.00E KBU33-6X 11.05 16.45 47.79S 154.05W -107.2 161.29 161.10 100.00 100.00 O.OON 0.00E KBU33-6X 94.64 100.05 47.76S 154,04W -107.2 161.27 160.74 200.00 200.00 O:OON 0.00E KBU33-6X 194.74 200.14 47.66S 153.99W -107.2 161.20 160.32 300.00 300.00 O.OON 0. OE KBU33-6X 294.76 300.16 47.51S 153.94W -107.2 161.10 159.85 400.00 400.00 O.OON 0.00E KBU33-GX 394.46 399.86 47.37S 153.94W -107.1 161.07 159.39 500.00 500.00 O.OON 0.00E KBU33-6X 495.16 500.56 47.45S 153.81 W -107.1 160.6 158.87 508.53 508.53 0.01S 0.02E KBU33-6X 503.69 509.09 47.46S 153.77W 134.8 160.94 158.82 524.93 524.93 0.08S 0.14E KBU33-6X 520.53 525.93 47.48S 153.67W 134.8 160.6 158.78 600.00 599.95 1.23S 2.31E KBU33-6X 595.89 601.29 47.28S 153.16W 135.4 162.16 159.72 700.00 699.63 4.92S 9.23E KBU33-6X 695.35 700.74 46.87S 152.50W 137.3 167.9 164.28 800.00 798.77 11.05S 20.75E KBU33-6X 795.25 800.64 46.78S 151.61W 140.0 176.03 172.82 900.00 897.08 19.62S 36.84E KBU33-6X 894.34 899.72 46.46S 150.37W 143.3 189.14 185.45 1000.00 994.31 30.59S 57.44E KBU33-6X 992.01 997.38 46.15S 149.03W 146.9 207.08 202.86 1100.00 1090.18 43.94S 82.50E KBU33-6X 1087.93 1093.29 46.04S 147.62W 150.3 230.15 225.40 1131.89 1120.42 48.69S 91.42E KBU33-6X 1118.27 1123.63 45.96S 147.21 W 151.4 238.67 233.72 Offset Welibore Surve Tool Pro rams Well WeNbore Survev Name MDR Surv Tool Error Model KBU33-6X KBU33-6X MWD<0-8405'> 8405.00 Navi Trak Ma Corrected All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated ~i MARATHON Oil Company ~~~ KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHON slot# KBU11-8Y, Pad 41-7 CLEARANCE LISTING Page 20 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska ?Ht`, '. INTEQ C learance Data Reference MD[ftj Referents TVD[ft] Reference North[ft] Reference East[ft} Offset Well Offset MD[ftl Offset TVD[ft] Offset North[fy Offset East[ftj Angle 'Fran Highside Closest Approach Distance ft Ellipse Separation (ft] 0.00 0.00 O.OON 0.00E KBU42-6 0.00 0.80 46.56S 99.73W -115.0 110.07 110.07 0.80 0.80 O.OON 0.00E KBU42-6 _ 0.00 0.80 46.56S 99.73W -115.0 110.06 110.04 100.00 100.00 O.OON 0.00E KBU42-6 98.92 99.72 46.48S 99.89W -115.0 110.17 109.70 200.00 200.00 O.OON 0.00E KBU42-6 199.41 200.21 46.18S 100.26W -114.7 110.38 109.54 300.00 300.00 O.OON 0.00E KBU42-6 300.98 301.75 44.22S 100.24W -113.8 109.57 108.37 400.00 400.00 O.OON 0.00E KBU42-6 402.18 402.81 38.93S 100.06W -111.3 107.40 105.83 500.00 500.00 O.OON 0.00E KBU42-6 504.25 504.21 27.50S 100.19W -105.3 103.98 102.01 590.55 590.52 1.01S 1.89E KBU42-6 596.38 594.61 9.93S 99.21W 146.9 101.58 99.20 600.00 599.95 1.23S 2.31E KBU42-6 605.53 603.53 7.88S 99.03W 148.2 101.62 99.20 700.00 699.63 4.92S 9.23E KBU42-6 701.89 696.75 16. 6N 96.52W 163.2 107.91 104.89 771.00 770.09 9.02S 16.94E KBU42-6 766.79 758.72 35. 7N 94.68W 173.6 120.74 117.21 787.40 786.32 10.15S 19.05E KBU42-6 781.29 772.44 40.21 N 94.28W 175.8 124.79 121.15 800.00 798.77 11.05S 20.75E KBU42-6 792.82 783.35 43.93N 93.96W 177.5 128.14 124.41 900.00 897.08 19.62S 36.84E KBU42-6 880.40 865.69 73.66N 91.50W -171.5 161.73 157.28 1000.00 994.31 30.59S 57.44E KBU42-6 964.04 943.50 104.24N 89.08W -163.8 205.50 200.35 Offset Wellbore Surve Tool Pro rams W It W Ilbor urve .Nam MD ft urve Tool M KBU42-6 KBU42-6 MWD <0-8624> __ 8624.00 Navi Trak Ma orrected All data is in Feet unless otherwise stated Coordinates are from Siot and ND`s are from Rig (Datum #1 87.Sft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1D) Prepared by Baker Hughes Incorporated • MARATHON O[I Company KBU 11-8Y Ver 1, KBU 11-8Y Ver 1 MARATHQN slot# KBU11-8Y, Pad 41-7 • CLEARANCE LISTING Page 21 Date Printed: 23-May-2005 Kenai Gas Field, Kenai Peninsula, Alaska p,~~.r ~ iFIN16HlltS INTEQ C learance Data Reference MD[ft] Reference 11/D[ft] Reference North[fY] Reference East[ft] Offset Well Offset MD[ftJ Offset ND[ft] Offset North(ft] Offset East[ft] Angle Fran Hlghside Closest Approach. Distance . ft Ellipse .Separation [ft] 0.00 0.00 O.OON 0.00E KTU32-7 0.00 0.80 127.90S 65.13W -153.0 143.53 143.53 16.40 16.40 O.OON 0.00E KTU32-7 15.86 16.66 127.87S 65.12W -153.0 143.50 143.31 100.00 100.00 O.OON 0.00E KTU32-7 99.97 100.77 127.58S 65.02W -153.0 143.19 142.71 200.00 200.00 O.OON 0.00E KTU32-7 200.83 201.63 126.65S 64.75W -152.9 142.25 141.38 300.00 300.0 O.OON 0.00E KTU32-7 301.03 301.2 125.37S 64.57W -1 2.8 141.04 139.75 400.00 400.00 O.OON 0.00E KTU32-7 400.33 401.11 123.96S 64.77W -1 2.4 13 .87 138.18 467.43 467.43 O.OON 0.00E KTU32-7 466.67 467.43 123.18S 65.53W -152.0 139.52 137.58 500.00 500.00 O.OON 0.00E KTU32-7 498.75 499.51 122.97S 66.16W -1 1.7 139.63 137.59 600.00 599.95 1.2 S 2.31E KTU32-7 595.97 596.69 123.07S 68.91 W 92.2 141.16 138.86 700.00 699.63 4.92S 9.23E KTU32-7 692.15 692.77 124.46S 72.89W 96.1 145.19 142.59 800.00 798.77 11.05S 20.75E KTU32-7 788.38 788.80 127.34S 78.42W 101.7 153.16 150.15 900.00 897.08 19.62S 36.84E KTU32-7 888.31 888.51 130.46S 84.20W 108.5 164.35 160.84 1000.00 994.31 30.59S 57.44E KTU32-7 986.14 986.22 132.66S 88.5 W 115.6 178.32 174.20 1100.00 1090.18 43.94S 82.50E KTU32-7 1083.73 1083.73 134.12S 92.16W 122.8 196.68 191.88 1200.00 1184.43 59.63S 111.96E KTU32-7 1180.17 1180.14 134.40S 94.52W 129.8 219.65 214.17 1230.31 1212.65 64.84S 121.75E KTU32-7 _ 1209.32 1209.29 134.29S 95.03W 131.8 227.66 221.95 1246.72 1227.84 67.75S 127.21E KTU32-7 1224.41 1224.37 134.22S 95.29W 132.8 232.24 226.42 1300.00 1276.81 77.61 S 145.74E KTU32-7 1274.22 1274.18 133.84S 95.95W 136.1 248.15 242.00 Offset Wellbore Surve Tool Pro rams Well Well urve am MD ft urv .Tool rror M ei KTU32-7 KTU32-7 MWD <0-8864> 8864.00 Navi Trak Ma Corrected All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 87.8ft above mean sea level ) Reference MD's are from Rig, Offset MD's are from Rig Calculation method uses Minimum Curvature method Confidence Limit of 95.45 (1 D) Prepared by Baker Hughes Incorporated Fik Edt Profiles Tabk Tods Offset Data Units Vfindow Help J ~ I ~ ~ I~ ~ 14D 1 2D 12D1S l~ I ~3D I 'tG 'sDR f~+ elfbore Details) Offset Data Welpath ITargetsl Name KBU 11-5'Y Ver 1 Start MD ' ~ ~~ ~ ft TVD ~_ MD [k] ! Inc [deg] { A; Errors) Hde Sections/Casirgsl sE~~~Q~ ~` ~® J ID 773324 Narch r ''+ '~! ~ East F ' ~ ~ Azimuth ' ~' ~ '-~ East [ft] ~ DLS a Tface ~ VS [ft] ~~___~_v~_-.__~.~_._~_.[deyt100ftJJ-..[deg] _;_..______-_--------~~,. • • Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PROJECT PLAN ICJ ~>~ f~.:~ Prepared For: MARATHON OIL COMPANY Well KBU 11-8Y Prepared by: Tony Tykalsky Reviewed by: Mark Fairbanks Presented to: Will Tank June 3, 2005 ~~ Kenai Peninsula, Alaska • ~~ Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: • Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Enclosed is the recommended drilling fluid program for the KBU 11-8y Well to be drilled this year. The following is a brief synopsis of the program. Overview: KBU 11-8y 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 Ge1/Gelex spud mud. No problems were noted in this interval while drilling KBU 24-6 and KBU 11-8X. Intermediate Interval: This interval will be drilled with aFlo-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 brid~in~ material. Mix II should be added to the mud svstem prior to drilling the Sterlins A8 sand (+/- 3970' MD). This is a highly porous depleted zone that has contributed to losses of whole mud in the past. Production Interval: This interval will be drilled with the same fluid that was used to drill the intermediate interval. The fluid will be pre-treated with Bicarb and/or citric acid prior to drilling out the cement. Any further fluid dilutions will be made in order to keep the mud properties at the recommended specifications. Fluid loss should be maintained @ 7 - 9 cc's API for this interval. Based on offset well history mud weights above 10.0 PPG ma by a 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. Tony Tykalsky Project Engineer /M-I SWACO Reference Wells: KBU 43-7X; KBU 42-7; KBU 24-6; KBU 11-8X; KBU 42-6 NOTE: This program is provided as a euide only. Well conditions will always dictate fluid properties required. • ~~ Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. EXECUTIVE SUMMARY ~.~~+ . ~, S~F F~ _ ,t .. -.: ,-..I n.; ~~RONM~~p !. ~~~ Our overall goal is no spills and no incidents while providing fluids and solids control services to Marathon Oil Company. Our goal for KBU 11-8Y is to remove drill solids from the mud system at a cost of less than $0.24 per pound. This has been the average far the last four years of centrifuge van operations With the revised fluid formulation (utilizing the intermediate interval fluid for the production interval), we expect to drill this well for a product cost of less than $26.60 per foot. Use of the MI Swaco centrifuge van for the last four years has provided an estimated savings in dilution and disposal costs to Marathon Oil of over $800,000. '~ With continued usage of our equipment, we expect to provide more savings to you during future operations. ~~ • Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Interval Benchmarks and Targets Drilling Intervals Depth Benchmark 1 Benchmark 2 Benchmark 3 Benchmark 4 Interval eft) Fluid cost per foot Volume Usage Solids Removal 0 -1551' < $5.92 ft < 1943 bbls 1551 - 5844' < $34.88 ft < 2821 bbls 5844 - 7854' < $24.87 ft < 705 bbls Total Avg. Max. Project < $26.60 ft <5469 bbls < $0.24 Ib No Spills from Targets for Centrifuge Van Drilling Operation Interval ~~ • • '~ Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Project Summary Casing Hole Casing Depth ND Mud Mud Sum Mterval Size Size Program System Weight Days Mud Cost (in) (in) (ft) (ft} Solids Control (ppg} 13-3Y8" 16" '?~ 1551' 1500' GeUGelex Spud ~;. , Mud 8.6 - 9.4 5 $13,100 ~,~~ Screens 150/180 ,. ;~~ mesh zY ,° ;N Desilter ~'~" ` Centrifuge Van ~~~ ~K~~~~P~ 9-5/8" 12-1/4" k~~' 5844' 5370' Flo-Pro "~ w/SafeCarb 9.0 - 10 $157,560 ~~~:'`l . Screens 180 - 210 < 9.5 , ''~ mesh ~} ` ~~ -,-. Desilter >.,:v ~, :~~ Centrifuge Van : ,y,; ~, 3-112" 8-1/2" 'b~ 7854' 7380' Flo-Pro '~'' w/SafeCarb 9. 7 $55,470 ~'~ Screens 230 - 210 O.Oj~' ~ mesh ~-'' Desilter Centrifuge Van 3 1/2" 8-112" .Completion 7854' 7380' 6% KCl 8.55 2 $7,100 - 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 include 2% Lubetex concentration in intermediate and production interval. ~~ Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Estimated Product Usage Summary PRODUCT. Surface 16" Intermediate 12-1/4" Production 8-1/2" Completion 3-1/2" Total Usage % of Total Cost M-I Bar 0 282 846 0 1128 4.01 M-I Gel 583 0 0 0 583 2.35 Gelex 24 0 0 0 24 0.14 Soda Ash 10 14 7 0 31 0.22 Caustic Soda 10 28 7 0 45 0.73 Conqor 404 0 6 2 0 8 4.76 Sodium Meta Bisulfate 19 28 7 4 58 1.79 Bicarb 10 14 14 0 38 0.32 Conqor 303 0 0 0 4 4 0.90 F1oVis 0 226 56 0 282 26.20 Desco CF 10 0 0 0 10 0.21 Polypac UL 10 113 28 0 151 11.16 KCl 0 11885 296 200 1683 9.99 Safecarb 0 1693 282 0 1975 17.78 Lubetex 0 22 11 0 33 11.43 Mix II 0 282 0 0 282 3.33 EMI 920 0 0 5 0 5 2.16 Citric Acid 0 0 4 0 4 0.19 Defoam X 0 31 4 0 35 1.46 Engineer Service 5 10 7 2 24 ~~ • ~~ • Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments KBU 43-7X 16" 1500 9.15 14 30 14 Spud in, drlg to casing point 12.25' 2900 9.2 5 24 16 Drlg out, disp to FIoPro (no fluid loss) 4225 9.05 9 21 16.4 Drlg ahead, encounter some coal 4810 9.32 9 30 15.6 Short trip - backream -some swelling 5112 9.4 11 30 17.6 Swelling hole -lower FL with Pac 5811 9.5 13 29 8.4 POH - OK 6477 9.6 17 42 6.0 POH -ready to run casing 8.5" 6991 9.2 12 22 4.4 New mud - drlg ahead 7795 9.3 14 26 3.6 Trip OK - drlg ahead 8570 9.85 12 44 4.4 Gas -increase mud weight 8610 10.6 15 28 4.6 Gas -increase mud weight KBU 42-7 17.5" 1006 8.9 12 30 11.2 Spud in, drlg to casing point 1760 9 12 19 116 Drlg out, LOT 15.6 ppg 12.25" 3455 9.3 10 17 8.9 Drlg ahead 4371 9.35 9 25 11 Trip OK 5205 9.4 14 11 5.5 Drlg ahead, some losses, 100% losses @ 4899' pump SafeCarb LCM (M & C) 5590 9.3 14 18 7.6 Drlg to csg point, spot LCM pill, lost 50 bbls during cementing 8.5" 6131 9.7 13 24 10.8 Drlg out, LOT 13.3 6733 10 15 19 8 Hole swelling, inc mud weight to 10.0 ppg 7000 9.9 15 19 7.8 Drlg ahead 7293 10.15 15 21 7.5 Drlg ahead, inc mud weight to 10.3 popg 7570 10.6 22 22 6.6 Dr1g to TD increase mud weigh (gas) KBU 24-6 17.5" 1008 8.85 28 67 7.5 Spud in, drlg to casing point 1525 8.65 12 26 11.4 Sweep hole prior to running csg 12.25" 1818 6.75 7 27 6.2 Drlg out, LOT 18.4 ppg 3611 6.95 8 20 6.9 Drlg ahead 4011 9 8 16 7.8 Drlg ahead 4532 8.9 8 22 8.2 Drlg ahead 4982 9.7 9 22 10 Drlg ahead 5213 9.8 11 27 8 Drlg ahead 5505 9.6 7 14 7.8 Run csg, lost returns spot LCM pill (1289 bbl losses) 8.5" 6395 9.55 8 25 7.7 Drlg out, LOT 14.5 ppg 7420 9.6 9 27 7.5 Drig ahead, inc mud ppg 7500 10.3 11 25 6.2 Spot 16.0 ppg pill on bottom, run liner KBU 11-8X 16" 720 9 13 32 14 Spud in, drill ahead 1517 9.05 13 12 16 Drlg to casing point, condition mud, POH to run casing 12.25" 2326 9.1 11 13 8.2 Drlg out, disp to FloPro, drlg ahead, keep mud thin for high GPM 3719 9.5 11 16 7.8 Drlg ahead, short trip OK, drlg ahead 4825 9.4 12 19 6.4 Drlg ahead, high torque, add lubetex 5334 9.5 11 22 7.2 Slow ROP, add lubetex for sliding 5611 9.7 13 21 7.5 Drlg to casing point, condition mud, POH to run casing 8.5" 6338 9.4 13 21 6.8 Drlg out, displace to new mud, drlg ahead 7402 9.85 13 21 6 Short trip OK, increase PPG to 9.8 7659 10 8 18 11.2 Drlg to TD, fluid loss increasing to to bacterail contamination, POH for logs 7659 10.2 11 14 9.1 Finish logging, run excape completion. I! L~ • • '~ Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Offset Well Information K8U 42-6 16" 139 8.65 14 24 13.6 Spud in 1495 9.55 12 23 7.8 Drill ahead, wiper trip OK, drlg ahead 1525 9.4 12 21 7.2 Drlg to casing point, condition mud, POH to run casing 1525 9.4 12 17 8.8 Cement casing, good cement to surface 12.25" 1525 9.05 12 18 8.8 Drlg out, displace to new mud, LOT = 15.3, ppg drlg ahead 2469 9.2 10 15 8.0 Drill ahead 4414 9.3 10 19 6.6 Drlg ahead, short trip OK, drlg ahead 5543 9.3 13 21 8.2 Drlg to 5417, lost returns pumped 3 LCM pills, stop losses, drlg ahead 6171 9.4 12 14 5.8 Drlg ahead, lost circulation, spot LCM pill 6176 9.1 10 14 7.4 Spot added L.CM pills, losses as high as 100 BPH 6176 9 11 15 7.2 Stop losses prior to running 9-5/8" casing 6176 9.2 20 13 7.4 Run & cement csg, no losses until end of cement }ob {25 bbls) 8.5" 6951 9.2 11 20 5.6 Drlg out, displace to new mud, run FIT, drlg ahead 8602 10.4 21 26 5.0 Drlg ahead, short trip OK, drlg ahead 8624 10.6 20 26 4.8 Drlg to TD, increase ppg to control gas 8624 11 22 26 5.2 POH, log well, RIH cleanout trip, OK 8624 11.05 21 25 4.4 Poh, run excape completion, cement same. • • '~ Marathon Oil Company Well Name: KBU 11-SY 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 . ~ CORROSION - Congor 404 additions should be made daily when drilling with FloPro fluid in order to maintain a Congor 404 concentration of +/- 2000 PPM. ~ CORRISION - Sodium Meta Bisulfate additions should be made daily as needed with any fluid in the hole. Maintain a DO reading of less than 3 ppm ~ SOLIDS VAN USAGE -The Solids Van should be used whenever drill solids become un- acceptably high and reduction of drill solids in the mud can be more economically done with centrifuging and dilution then just with dumping and diluting. The weight of the drilling fluid alone should not be the determining condition for when to use the Solids Van. ~ WEIGHTING UP -All increases in mud weight should be accomplished with barite additions. In the production interval, insure chloride concentration is maintained at 30,000 to minimize the need for barite additions. 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. • C Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Interval Summary -16" hole 0 -1551' -- Drlling Fluid System Ge1lGelex 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 -150 - 180 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, hole cleaning. nterval Drilling Fluid Properties Depth Mud Funnel Yield API Drill.• Interval Weight .Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec./qt) (Ib./100ftz) (ml/30min} (%)' 0-1551' 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 of < 3 PPM. - Condition mud prior to cementing casing to reduce yield point and gel strengths. - Estimated volume usage for interval -1943 barrels. - Estimated haul off volume - 3085 barrels. • Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Interval Summary -12-114" hole 1551 - 5844' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / PolyPac Supreme UL / KCl / SafeCarb 10, 40, 250 / Mix II /MI Bar / Caustic Soda / Conqor 404 /Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended initial shaker screens - 180/180!150 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Fluid Properties Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) ( ) (c .) (c s) (ml/30min) (%) 1551 - 5844' 9.0 - < 9.5 $ - 12 40,000+ 7 - 9 < 7.5 +/- 5% - Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed fluid formula. Pre-heat makeup water with steam hoses as much as possible. - After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test - As mud heats up, increase FloVis concentration to 2 PPB and install 180 mesh shaker screens on end panel. - NOTE: Beware of whole mud losses to the Sterling A8 & Upper Beluga form_ations._ Ensure adeauate bridging material (30 PPB) SafeCarb + (5 - 10 PPB) Mix II is in the mud while drilling these formations. - 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 proffer fluid properties for that purpose. - Estimated volume usage for interval - 2821 barrels. - Estimated haul off volume - 3754 barrels. - Condition mud prior to running 9-5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. I! ~ ~ • ~~ Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Fluid Formula -12-114" Interval 12-1 f4" I ntervaf fram 1551 -5844' 3 r __._.._ ~________.__ - - - - __ KBU 11-8Y _ __.___ _ .___..__.. _ IUkxi W ~ 9.0 - 9.5 ed Gel _ No - W ~ ll~eriai Code SafeCarb Prep ed Gel Co~nc_ _ ~ ___~__ __ `w - e~ SG 2.8 era wtx 6 _____ NOTE: Pre-heat m _ akeup water with steam hoses as much as possible. -1 bbl i Order of Products Ctrncentr~i~n Volume Prod~t 'P+dd4~r 1=i~d, ~ Lab Fte3si, bbl Lam, ml ~ 1 Water 298.70 298.70 4}_853 298.70 2 Soda Ash 0.25 025 4?_a(}(? (}_14) Reduce Hardr~ss 3 Flovs 125 1.25 0.003 11.83 Viscos~ 4 Pal Su reme UL 2.4)41 2.00 0.004 1.25 Fluid Lass Control 5 Caustic Soda 0.5(1 0.50 0.001 023 Control 6 Potassium Chlonds 19.07 19.07 0.023 7.98 Inhibition 7a Saf+eCarb 10 5.00 5.00 0.005 1.80 B ~ i nt 7b SafeCarb 40 24}_60 20.00 0.0241 7.20 B ~ ~ nt 7c SafeCarb 250 5.4)0 5.00 0.005 1.841 B . M Plan on addn 5 - 10 PPB Mix II to the mud m ror to drilln into the Sterlin A8 sand +t- 3970' MD ~ 8 Mix it 10.00 10.00 0.020 ~ 6.25 LCM I f for ue becomes a roblem, or slidin is difficult, add 1 - 3X of the followin i 9 Lubetex 14.00 14.00 0.041 14.43 Lubric~ ~ If bit batlin becomes a roblem, add t he followin 10 d-D CWT 1.00 1.00 0.003 1.00 Reduce BMA Ba11i f Total 399 399 1.000 350 _- ~ Calculated Mud We' ht 9.500 Estimated Vohrme 2821 Barrels ..__.___ Total Chloride 29600 f ~ • Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska.. Interval Summary - 8-1/2" hole 5844 - 7854' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / Polypac Supreme UL / KCl / SafeCarb 10 & 40 ! MI Bar / Caustic Soda / Conqor 404 !Sodium Meta Bisulfate I EMI 920 Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Fluid Properties: Depth Mud Plastic LSRV API Drlk Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (ppg) (cp.) (cps) (mU30min) (%) 5844 - 7854' 9.0 - 10.0+ 10 - 14 30,000+ 6 - 8 < 7.5 +1- 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 to maintain proper specifications. - NOTE: Based on offset well history. mud weights l0A PPG or higher may be rectuired .for wellbore stabili - NOTE: If metal-to-metal torque is a problem after drilling out the 9-5/8" casin~,_ then add 0.5 - 1 % EMI 920 prior to adding Lubetex. - If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. - Estimated additional volume for interval - 705 barrels. - Estimated haul off volume - 2060 barrels. - Condition mud prior to running 3-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. I~ • ~~ • Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Dilution Formula -- 8-1/2" Interval 812" Interval from 5844 - 7854' 1 ion KBU 11-8Y il~,+d UV - 9.0 - 10_Q ~~ ed ~ Na __. W - 144aterial Code Ml BaR ed GQl C~c_ _ _.__ _..____. ~ __ _ W " ildatesial S~ 42 Kq Wt% 6 _ r _ ~ _.___p__. __ _____ __~ _. _ _ __ -1 bbl Order of Products Colt Va{ume Product A~tis~n Field, lb Lab, 1~ield, bbl Lab, [td 1 Water 325.19 325.19 0.929 325.19 2 Soda Ash 0.25 Q.25 0.000 0.10 Reduce Hardness 3 FloVis Plus 2.OQ 2,00 0.005 1.34 Viscose 4 Po ac Su reme UL 2.00 2.00 0.004 1.33 Fluid Loss Control 5a SafeCarb 10 15.OD 22.50 0.017 5.fi7 8 . i 5b SafeCarb 4Q 5. QO 7.50 0.006 1.89 B . nt fi Potassium Chloride 20.7fi 20.76 0.025 8.68 inhibition 7 C4NQOR 404 2.00 2.Q0 O.Q04 1.43 Corrosion Control 8 Caustic Soda 0.50 0.50 0.001 0.23 H Control 9 Sodium Meta Bisulfate 0.50 0.25 0.001 0.25 O r If hi h for ue i n incured while drillin out the 9-518" casin ~ add 0.5-1.Q%EM1920 11 EMl 920. 3.50 3.5Q 1.500 ~ 3.50 Metal to Metal Lub If slidin or hi h tar ue becomes a roblem add 1 - 3'%- of the follow%n 10 Lubetex 7.00 7.00 0.021 7.00 Lubric If sloughing coals become a roblem add 2 - 4 b of the followin 11 As besot Su reme 2.00 2.OQ 0.004 1.33 Wellbore Stabil. Mix fluid in the order listed above. __ ~ Total 380.1 38Q1 Estimated Volume 705 Barrels __n ~ _ ~ ~ Calculated Mud V11e` ht 9.05Q _ . __ _...__ _r._ Total Chloride 29600 I • n~ Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Interval Summary -Completion Procedures Corrosion Control Additive in Casing x Tubing Annulus Well KBU 11-8Y r i ~ Volumes: Tubing Volume 3-tJ2" Tubing 50.84 barrels _ Annular Volume casing x tub. 358.x2 barrels 5sa4 n Open Hole x ~ 120.23 barrels Total Annular Volum• 478.65 Tubing Volume 50.84 Total Hole Volume 529.49 r - Treatment Procedures. 1. After the 3-1f2" tubing is run and the drilling fluid is circulated and conditioned for the cement job, circulate an additiona1360 barrels of drilling fluid. 2. Add 1 drum of Conqor 303A and 1 sack of Sodium Meta Bisutfatefor each 90 barrels of drilling fluid pumped (4 drums 8 4 sacks total) 3. After the 360 barrels of drilling fluid with treatment have been pumped downhole, begin the cement job. 4. This procedure will place corrosion control in the 3-112" x 9-618" annulus. ~~ • • '~ Marathon Oil Company Well Name: KBU 11-8Y 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. ~~ • C7 t~ Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all hoses and connections between the van and the rig are secure. ~~ • • Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Flammabilit Reacfivit PPE M-I BAR Weighting Agent *1 0 0' E M-I 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-Garb F,M,C Bridging and weighting agent *1 p p E Nut Plug Loss Circulation Material *1 1 0 E M-I Seal F, M, C Loss circulation Material *1 1 0 E Mix II F,M,C Loss circulation Material *1 1 0 E DESCO CF Dispersant 1 1 0 E SALT (Solar) Densifier 1 0 0 E POTASSIUM CHLORIDE Shale Inhibitor 1 0 0 E CAUSTIC SODA Alkalinity control 3 0 1 X BORAX Inorganic Borate 1 0 0 E SAPP Sodium Pyrophosphate *1 0 0 E SODA ASH Alkalinity control 1 1 0 E SODIUM BICARBONATE Alkalinity control 1 0 0 E CITRIC ACID pH Adjuster 1 0 0 E BIOBAN BP-PLUS Biocide *2 0 0 - J GREEN CIDE 25G - Biocide 3 0 0 .l DEFOAM X - Defoamer 1 1 ` 0 .1 G-SEAL Sized graphite LCM 1 1 0' E EMI 920 Lubricant 1 1 0 " J LOBE TEX Lubricant 1 1 K Q,:~~;u,;, J D-D CWT Detergent 2 1 .1 Concor 404 Corrosion Inhibitor 1 1 J SAFEKLEEN Drilling fluid additive 1 1 J Asphasol Supreme Shale Inhibitor 1 1 J Sodium Meta Bisulfate Oxygen Scavenger 1 1 J ~~ • • Marathon Oil Company Well Name: KBU 11-8Y 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 • ~~ Marathon Oil Company Well Name: KBU 11-8Y Location: Kenai, Alaska. Contacts Contact Title a-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 ttykalsky@miswaco.com 907 274-5011 907 227-2412 MI SWACO Richard Couey Warehouse Manager rcouey@miswaco.com 907 776-8722 907 776-8680 MI SWACO Michael Barry Senior Field gratefulmen@hotmail.com 907 260-4666 907 590-3636 MI SWACO Engineer (home) Locke Rooney Field Engineer rooneyl@alaska.net 907 235-0598 907 590-3636 MI SWACO (home) Roland Lawson / Drilling Foremen 907 283-1312 Larry Myers !Dave Morris Marathon Responsibilities - MI Project Engineer and will coordinate daily between the Marathon office, rig, warehouse, and the M-I field engineers. - Well progress will be monitored to look for any changes, which will improve the efficiency of the operation or avert trouble. - Field Engineers will monitor and supervise product inventory to include re-palletizing any products for shipment to other locations at the end of the well. - Field Engineers will communicate with office personnel (Marathon & MI 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, andlor utilization of any third party service. i Marathon Oil Company Direct Inquiries to: HnCjI 9 Check No Check Date Bank Bank No Vendor No ACCOUfVTS PAYABLE DEPARTMENT P. O. Box 22164 Accts Payable Contact Center 1178369 06/09/2005 NCBAS 7780 5001123 Tulsa, OK ~at2t-2164 Phone: sts-925-6097 HS inv4lGe Nu;nb2r IY7volc9 pate pacument No f72a0t Gommpttt Gross Amount ... Dcscau~t invoieelPayAmount 1L100.00 06/09/2005 1900030275 100.00 100.0 TOTAL: 100.00 100.0 ~~ ~` ~~"~ - c, ~~a (FOLD ON PERFORATION BELOW AND DETACH CHECK STUB BEFORE DEPOSITING) V-?50~ REV. 5/00 ~ __._. _ ,u!i~~~iZedRepresentahyQ( „, ~// N~TIOAiAL,Ct7Y BANK ~~ ~~ f~untirrd and Oplld(7 t~>Itan ~ ~' ~shiand, QhiQ ~," _ ~°~~ ~ o.... TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# CHECK WHAT ADD-ONS "CLUE" APPLIES (OPTIONS) MULTI The permit is for a new wellbore segment of LATERAL existing well , Permit No, API No. (If API number Production should continue to be reported as last two (2) digits a function of the original API number stated are between 60-69) above. PILOT HOLE In accordance with 20 AAC 25.005(f), all (p)er records, data and togs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 - 70/80) from records, data and logs acquired for well (name on permit). SPACING The permit is approved subject to full EXCEPTION compliance with 20 AAC 25.055. Approval to perforate and produce/infect is contingent upon issuance of a conservation order approving a spacing exception. (Comaany Name) assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the SAMPLE Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Rev: 04(01(05 C\jody\transmittaf_checklist WELL PERMIT CHECKLIST Field & Pool KENAI, UPPER TYONEK BELUGA GAS -44857 Well Name: KENAI BELUGA UNIT 11-SY Program DEV Well bore seg ^ PTD#:2050910 Company MARATHON OIL CO Initial Class(1-ype DEV / 1-GAS GeoArea Unit On10ff Shore On Annular Disposal ^ Administration 1 Pe[mikfeeattached__.______-__-___-__-__-_- -__._ _-_-_-__Yes_-_-_- _,_-_-_____------------------ 2 Lease number appropriate- _ - Yes 3 Uniquewell_nameandnumb_er_____________________________ _________Yes-___--_ -,_---________--__ 4 Well locatedin.a-defnedpool___-.-___-___-_ Yes-___-_ __.- - - 5 Well located p[oper di_stance_ f[om drilling unit-boundary. _ - _ _ _ _ _ _ - - - - - _ _ . _ -Yes - - - - - - - - - - - - - - - - - - _ _ _ . _ 6 Well located properdistancefromotherwells___________ ________ ______-_Yes_____-_ __-._-_______-___-_-_--_.__ -__ ~7 Sufficient acreage available in drillingunit____-_-__------------- ---------YeS_-____- _- - - 8 If deviated,is_wellboreplat_included_______________________- .__-___ -Ye5_---_._ _- 9 Operator only affected party - - - Yes - ~10 Ope[aiorhas-approprjate_bondinforce. ------- -- - - -- - - - .-.-YeS-- --- - - - ------- -- -- --- -- ------ -- - -- -- --- 11 Pefmitc_anbeissuedwithoutconserva_tionorder__________________ -_-_-__Yes_._-___ _-_-__.______-_-_. Appr Date 12 Permit-can be issued without administrative-approval Y_es - - - - - - - - - - - - - - - - RPC 6!8!2005 13 Can permit be approved before 15-day wait Yes 14 Well located within area and-strata authprized by Injection 0[de[ # (put10# in_comments)_(For. NA_ _ - _ _ - _ - _ - _ _ - . - _ _ _ _ _ - _ - _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ - - - _ - _ - .. _ - - - - - - _ - - 15 All wells_within 114_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 ACMP-Finding of Consistency.has beenissued_for_thisprojecr - . - - . - - . NA_ _ _ - - - -------- Engineering 18 C_onducto[ string_provided _ - - - _ - _ - - - , - - _Yes _ _ 20" ~a 134'. _ 19 Su_rfacecasing-protectsall_knownUSDWs------------_----- ----,-.--Yes------ -------------- ------------------------------------- -----_ 20 C_MT_voladequate-to circulate-onconductor_&surfcsg_.___ -_-_.__ -_-_--_-_Yes-____ Adequateexcess,_-_-_-_--___________ ______________--__---_.-_--_----- 21 CMT_voladequate_totie-in long string to surf csg____-.___._____.__ __._-__No_-_---_ __-- -__,_ 22 CMT_willcoverallkno_wnproductivehorizons_-_,____-_ Yes_______ ______________- 23 Casing designs adequate for C,T,B&.permafrost___________ ___-_ _---__--_Yes-____,_ - __-___ 24 Adequatetankage_or[e_servepit--- ------------- _-__--- __--_--_Yes__-__ GlacierRig#1_.-_-__-__-___ ~25 If_a_re-drill, has_a 10-403 for abandonment been approved - _ - _ - _ - _ _ _ - - _ _ _ - - - - _ NA_ _ - _ _ _ New well, . _ _ _ _ - - _ _ _ - _ - _ - - 26 Adequatewellb°reseparationproposed_____________________-_ __--__---Yes______ --__-_-___-._--_ 27 lfdiverterrequired,doesitmeetregu_lations__-__________________ _______-Yes-_-__._ -_ -__-_ ----- ------------------------------------------------------ Appr Date 28 Drillingfluid_programschematic-&equiplistadequate,_- _-_--_-__-_ ___-___-Yes____-_ MaxMW-10,0-ppg.___-_--_.______-__ -_--_______-_-____-___------_ WGA 61912005 29 BO_PES,_do they meet regulation - - - - Yes - - - - - - - - - - 30 BOPE-press rating appropriate; test t_o_(put prig in comments)- _ - - . _ _ Yes - - - - - - Test to 2400 psi, -MSP 1786 psi.- . _ - - - _ - _ --------------------- 31 Choke_manif4ldcomp_Iiesw/APLRP-53 (May84)____ ____________ _________Yes_-____- ___-_-_____-__-_-_-___---__----___._- 32 Work willoccurwithoutoperationshutdown__________________--- _- Yes____ --.-_--_-_- _,_-__ _ _ _ (33 Is presence-ofH2S gas probable--------------.-----------. --------- N°------- - - - __--- _-_-_-__-_,_-__-____----___-__-______- NoH2Si_narea,- - - - - ~34 Mechanical condition ofweliswithinAORyerified(Fors_ervicewellonly)__--_ -____._ NA___.____ - - - - -------------------------------------- ---- -_,___ __--_---------------__--_,-_-_------_-.___ Geology 35 Permit-can be issuedwlohydrogen.s-ulfidemeasures_,___-___-__ -_-- ----Yes____--_ __----------------------_------ 36 Data_presented 4n_ potential overpressure zones _ _ _ - _ _ . _ _ _ _ _ _ _ - _ - _ _ NA_ _ - - - - - - - - - - - - - Appr Date 37 Seismic analysisofshallowgas_zones- -___-___-__.___-__,_ __- -_-__ NA________ __________ RPC 61812005 38 Seabed condition survey (if off-shore) - - - - - - - - -- - - - - - - - - - - NA - - - - - 39 Contact name/phone for weekly progress reports [exploratory only! - - - - - - - - - - - - - NA_ - - Geologic Engineering Public Commissioner: Date: Commissioner: Date Co ' ner Date ~~s 6~~~s ,l~ ~-g-®s 6~0 0