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205-141
From:Jacob Flora To:Brian Glasheen Subject:FW: Cementing Follow Up Report: Excape Control Lines Date:Wednesday, October 25, 2023 10:24:20 AM Boom From: Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent: Monday, July 12, 2021 2:20 PM To: bryan.mclellan@alaska.gov Cc: Taylor Wellman <twellman@hilcorp.com>; Donna Ambruz <dambruz@hilcorp.com>; Jake Flora - (C) <Jake.Flora@hilcorp.com> Subject: Cementing Follow Up Report: Excape Control Lines Bryan, Below are the ¼” control lines we squeezed with the grease pump and Halliburton’s FineCem squeeze cement on the Excape IA squeezed wells we did in early January 2021. As you will notice the lines took a varying amount of cement. The 0.25” lines have an ID of 0.152” and capacity of 0.00094 gllons/ft. 2 gallons equates to 2127’ of control line. I plan on updating the WBDs and notating the cement volume pumped on each. Let me know if there is anything additional you would like to see here- Thanks, Jake PTD Well cement volume pumped date cemented 202-091 KBU 11-08Y 2 gallons on each line (7/2/2021) 205-141 KBU 41-06 1.5 gal red, 2 gal yellow and 2 gal green 205-141 KBU 41-06 1.5 gal red, 2 gal yellow and 2 gal green (7/2/2021) 204-209 KBU 42-06 2 gal yellow, 1.5 green and 1 gal red (7/2/2021) 200-179 KBU 44-06 1 gal red and 2 gal green (7/2/2021) 207-149 KBU 14-06Y 1.5 gal green and 0.5 gal red (7/2/2021) 203-217 KBU 23-07 1 gal red, .5 gal green and 1 gal yellow (7/2/2021) 203-025 BCU-11 2 gallons on each line (7/3/2021) (7/2/2021) David 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 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: N/2, Cement Packer 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: 4965, 5327, 5815 Total Depth measured 9,733 feet 7500, 7975 feet true vertical 7,837 feet 8,356 (fill) feet Effective Depth measured 5,291 feet N/A feet true vertical 3,883 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 10,160psi 137' 1,648' 5,750psi 5,020psi Collapse 2,260psi 3,090psi 10,540psi Casing Structural 20" 13-3/8" 9-5/8" Length 137' 1,862' 7,214' 9,722' 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. 321-048 23 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 18 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 205-141 50-133-20555-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 400 Kenai Beluga Unit (KBU) 41-06 N/A FEDA028142 7,214' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Field / Sterling Gas Pools 5.1, 4, 3, and Sterling UndefinedN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 3-1/2"9,722' 5,341' 7,826' WINJ WAG 0 Water-Bbl MD 137' 1,862' 0 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 3:45 pm, Apr 09, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.04.09 11:26:07 -08'00' Taylor Wellman (2143) RBDMS HEW 4/13/2021 SFD BJM 7/21/21 DSR-4/12/21 SFD 4/15/2021 Rig Start Date End Date 2/8/21 3/17/21 02/08/2021 - Monday MIRU Yellow Jacket E-line unit. Set CIBP at 7,500'. Dump bail 35' of cement on top of CIBP. Pressure up tubing to 2,000 psi. Jet cut tubing at 5,850'. Pressure dropped on tubing indicating good cut. 02/16/2021 - Tuesday Rig up hot oil truck. Circulate down tubing taking returns up annulus. 530 bbls circulated. Will reverse circ the following day. 02/17/2021 - Wednesday Load supply tank with 400 bbls of fresh water. Circulate 670 bbls at 3.5 bbls/min 1,487 psi pump pressure. Total circulated for both days 1,200 bbls. Rig down hot oil truck. Rig pump in sub and return iron to tank. 02/18/2021 - Thursday Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 41-06 50-133-20555-00-00 205-141 No activity to report. 02/19/2021 - Friday Halliburton cementers arrive on location with pump truck and two bulk trucks. 3rd bulk truck had two blown tires while en route to location. 3rd bulk truck on location and spotted. PTW, JSA with personnel. Rig up HES cementing equipment. Tie 1502 pump iron into tubing pump in sub. 330 bbls loaded in upright tank, fresh water temperature is 95°F. Pulled two 65 bbl loads from upright. Load into rig upright. Replace with 42°F fresh water from G&I. Looking for 70-80°F for blending cement. Pre pump safety meeting. Open well, lined up to pump down tubing and taking returns up IA to open top rain for rent tank. Break circulation. Pump 20 bbls. Close in 2x2 block valve. Perform low and high PT 4,000 psi. Pump water spacer 20 bbls at 3 bbls/min 208 psi. Mix and pump 980 sacks 214 bbls at 15.3 ppg @ 3.5 bbls/min 250 psi. Shut down and line up to ball launcher. Launch two 4" wiper plugs. Pump displacement of 51.6 bbls (.75 bbls over disp.) First 10 bbls had 2 gallons of cement retarder to take care of any potential cement stringer possibilities. Shut down after 51.6 bbls pumped. FCP and rate was 3 BPM, 1,077 psi. Final SITP 880 psi. Swab, upper master, IA gate valve closed. Rig down iron and wash up cement equipment. Manifest and haul returns to G&I for processing. HES depart location. Location walk around completed. Move pump in sub, iron and hot oil truck to next well 44-06. 02/20/2021 - Saturday Logged Memory CBL with READ Cased Hole. 02/26/2021- Friday PTW and JSA. Spot equip and rig up lubricator. Wait on Tri-plex. We had 3 jobs today. PT to 250 psi low and 3,000 psi high. TP - 1,100 psi. RIH w/ 2-1/2" x 8' HC , 4 spf, 60 deg and tie into GR/CLL log dated 2-24-21. Tagged at 5,869.5'. Ran 400' correlation log and send to town. Town said to subtract 4' and perf from 5,845' to 5,853' with 1,080 psi. Spotted nd fired gun with 1,080 psi. Good indication gun fired. Pressure was 1,080 psi for the full 15 min. POOH. All shots fired. TP - 1,075 psi. Rig down lubricator off well. Put night cap on and turn well over to field. TP - 1,075 psi. Set CIBP at 7,500'. Dump bail 35' of cement on top of CIBP. Logged Memory CBL with READ Cased Hole. d perf from 5,845' to 5,853' fired gun with 1,080 psi. Jet cut tubing at 5,850'. Pump displacement of 51.6 bbls Mix and pump 980 sacks 214 bbls at 15.3 ppg @ 3.5 bbls/min 250 psi. Rig Start Date End Date 2/8/21 3/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 41-06 50-133-20555-00-00 205-141 03/06/2021 - Saturday Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 250 psi low and 2,500 psi high. TP - 1,085psi. RIH w/2.75" CIBP and tie into AKE-Line Perf Log. Ran correlation log and send to town. Get ok to set CIBP at 5,815' with at least 1,000 psi on tubing. Spot and set plug at 5,815' with 1,081 psi on tubing. Lost 200 lbs of line tension when plug set. Wait 5 min, pick up 30' and go back and tag plug. POOH. Good set. Bleed well down to 7.8 psi and wait over 10 min to make sure the plug is holding. This is the negative test for the AOGCC. Test passed, no increase in pressure and is recorded on SCADA. RIH w/ 2-1/2" x3 0' cmt dump bailer filled with 17 ppg cement. Had a little trouble with bailer going thru swab valve. Found bailer bent a little. Tagged at 5,815'. Dump 18' of cement on top of plug. POOH. Good dump. RIH w/ 2-1/2" x 30' cmt dump bailer filled with 17 ppg cement (18') and dump cement on top of the first run at 5,797'. POOH. Good dump. Cement in place at 1600 hrs , est TOC - 5779' (36' total cement on top of plug). RIH w/ 2-1/8" x 10' 4 spf, 60 deg phase and tie into plug log. Run correlation and send to town. Told to add 10' and re-send. Added 10' and sent to town. Get ok to perforate from 5,367' to 5,377' with 515 psi on tubing. Spotted and fired gun. After 5 min - 516 psi, 10 min - 515 psi and 15 min - 514. POOH. All shots fired. Can't tell if dry/wet w/strip gun. Fired gun at 1818 hrs. RIH w/ 2-1/8" x 10' 4 spf, 60 deg phase and tie into plug log. Run correlation and send to town. Get ok to perf from 5,357' to 5,367' with 368.2 psi. Spotted and fired gun at 2017 hrs. After 5 min - 372 psi, 10 min - 375.8 psi and 15 min - 374.2 psi. POOH. All shots fired. Rig down off well. Turn well over to field. Rig equipment down. 03/04/2021 - Thursday Sign in. Mobe to location. Temp below zero on pad. Equipment would not start. Wait on heater to be released. Heat up crane and wireline unit. Rig back up. PT lubricator to 250 low 2,500 psi high. Started pressuring up with field gas. RIH w/ 2-1/2" x 10', 4 spf, 60 deg phase and tie into last correlation log. Tagged at 5,848' (btm/gun) (5,847' btm shot. top shot 5,837') Run correlation log and send to town. On depth and get ok to perf from 5,847' to 5,937' with 1,250 psi, spot and fire gun, After 5 min - 1,232 psi, 10 min- 1,228 psi and 15 min - 12,25 psi. They had to set jars off 4 times to get free. POOH. All shots fired/couldn't tell if dry. RIH w/ 2-1/2" x 10', 4 spf, 60 deg phase and tie into last correlation log. Tagged at 5,841'. Could not go deep enough to not perforate 5' above top zone at 5,835'. Re-measeured strip and found 3' left in hole. Call town and was told to POOH and rig down. POOH. Rig down lubricator and turn over to field. 03/08/2021 - Monday RU Pollard Slickline. IFL 2,000'. Swab 12 runs, recover 15 bbls. FL staying at 2,200', seeing inflow. RDMO. est TOC - 5779' (36' total cement on top of plug) perf from 5,847' to 5,937' with 1,250 psi, spot and fire gun, A Bleed well down to 7.8 psi and wait over 10 min to make sure the plug is holding. T Typo 5837' bottom shot bjm perf from 5,357' to 5,367' with 368.2 psi. Spotted and fired gun Dump 18' of cement on top of plug. t CIBP at 5,815' with a o perforate from 5,367' to 5,377' with 515 psi on tubing. Spotted and fired gun. Rig Start Date End Date 2/8/21 3/17/21 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 41-06 50-133-20555-00-00 205-141 Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 200 psi low and 2,500 psi high. RIH w/ 2.75" Owen CIBP to 4,950' CCL depth and logged correlation pass up to 4,700'. Send log to town. Town wants to add 2' and set plug @ 4,965' due to collar @ 4,970'. Add 2' and pulled short pass to ensure on depth. Pull into position **********SET 2.75" CIBP @ 4,965'********* (CCL to ME = 25' - puts CCL stop depth @ 4,940'. Good indication of plug set at surface, retag and confirmed plug in place. POOH. OOH bleed off. Take off setting tool and wt bar. Rig up for perf gun run. RIH w/ 2-1/8" strip gun (20'). Logged correlation pass. Sent to town. Town said depth good. Pull into position and ************PERFORTATED 20' INTERVAL @ 4,900' - 4,920'********* (CCL to top shot = 17.3' / CCL stop depth = 4,882.7'). Initial tbg psi @ 965# @ 15:14 hrs. 5 min = 965#. 10 min = 964#. 15 min = 963.3#. OOH. Bleed off and confirmed gun fired. Conferred with town on pressures not changing. Decision made to rig down and spot up on next well @ 44-06 and bring well on to see what it does and possibly make further plans. Rigged down off of 41-06 and spot up on 44-06. Depart location. 03/12/2021- Friday Sign in. Mobe to location. PTW and JSA. Spot equipment and rig up lubricator. PT to 1,200 psi low and 2,500 psi high. RIH w/2.75" CIBP/GPT and tie into perf log. Ran correlation log and send to town. Town said to subtract 2' from log when we perforated. Spotted and set plug at 5,327' w/957 psi on tubing. Lost 150 lbs of line tension when set. Pick up 30 ' and go back down and tag plug. POOH. Good set. Tools look ok. RIH w/ 2-1/2" x 30' Cement dump bailer filled with 17 ppg of cement (18'), tie into plug correlation log and tag plug at 5,327'. Pick up 18' and dump 18' of cement on top of plug. POOH. Good dump. Fill and RIH w/another bailer like the last one and dump 18' more of cement on top of the 18' already dumped (36' total). Cement in place at 1521 hrs and estimated Top of Cement at 5,291'. POOH Good dump. RIH w/ 2-1/8" x 10', 4 spf, 60 deg phase spiral strip gun and tie into plug correlation log. Send log to town and get ok to perforate from 5,002'to 5,012' w/938.8 psi. After 5 min- 927.9 psi, 10 min - 914.7 psi, 15 min- 901.0 psi. POOH. All shots fired. Rig down lubricator off well. Secure well and turn over to field. 03/17/2021 - Wednesday perforate from 5,002'to 5,012' Top of Cement at 5,291' tag plug. *SET 2.75" CIBP @ 4,965' Spotted and set plug at 5,327' w/957 psi on tubing. 7/2/21 - Excape control lines squeezed with Haliburton Finecem cement. See attached report. BJM y dumped (36' total). Cement 5/17/21 MITIA to 1500 psi passed. See attached. BJM *PERFORTATED 20' INTERVAL @ 4,900' - 4,920' retag and confirmed plug in place. CIBP2 _____________________________________________________________________________________ Updated by DMA 03-24-21 SCHEMATIC Kenai Gas Field Well: KBU 41-6 Last Completed: 12/8/2005 PTD: 205-141 CEMENT DETAIL 13-3/8"16" hole Cmt w/ 600 sks (275 bbls) of 12.0 ppg, Type 1 cmt, 100% returns 9-5/8"12-1/4" hole Cmt w/ 723 sks of Class G, (178 bbls)of Lead @ 12.5 ppg & (78 bbls) of Tail @ 13.5 ppg 7”8-1/2" hole Cmt w/ 1,160 sks (242 bbls) of 15.58ppg, class G cmt 3.5” x 9.625” IA Cemented with 214 bbls of 15.3# cement ESCAPE SYSTEM DETAILS * 15 Excape modules placed *Green control line fired module 1 *Yellow control line fired modules 2 thru 8 * Red control line fired modules 9 thru 15 * Ceramic flapper valves below each module as follows: *14 Conventional flappers *No flapper at Module-1 JEWELRY DETAIL No Depth ID Item 1 4,965’ CIBP 03/17/21 2 5,327’ CIBP w 36’ cement, 03/12/21 3 5,815’ CIBP w 36’ cement, 03/05/21 4 7,500’CIBP w 35’ cement, 02/8/21 5 7,975’ CIBP 6 8,453’A-Stop PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT Comments A8 4,900’ 4,920’ 3,629’ 3,642’20’3/17/21 A10 5,002’5,012’3,695’ 3,702’10’3/12/21 B2A 5,357’5,377’5,357’ 3,939’20’3/6/21 B5A 5,837’5,847’4,247’ 4,254’10’3/4/21 5,845’5,853’ 4,253’ 4,258’8’2/26/21 Beluga 7,526’ 7,533’ 5,639’ 5,645’ 7’Isolated 7,757’ 7,771’ 5,866’ 5,879’14’Isolated 7,991’ 8,001’ 6,097’ 6,106’10’Isolated 8,048’ 8,058’ 6,153’ 6,163’10’Isolated 8,281’ 8,291’ 6,385’ 6,395’10’Isolated 8,325’ 8,335’ 6,429’ 6,439’10’Isolated 8,393’ 8,403’ 6,497’ 6,507’10’Isolated 8,439’ 8,449’ 6,543’ 6,553’10’Isolated 8,482’ 8,492’ 6,586’ 6,596’10’Isolated 8,550’ 8,560’ 6,654’ 6,664’10’Isolated 8,598’ 8,608’ 6,702’ 6,712’10’Isolated Tyonek 8,877’ 8,887’ 6,981’ 6,991’10’Isolated 9,020’ 9,030’ 7,124’ 7,134’10’Isolated 9,239’ 9,249’ 7,343’ 7,353’10’Isolated 9,280 9,290’ 7,384’ 7,394’10’Isolated 9,549’ 9,559’ 7,653’ 7,663’10’Isolated 9,627’ 9,636’ 7,731’ 7,740 10’Isolated FLAPPERS MD (RKB) Module 15 - 8,010' Module 14 - 8,067' Module 13 - 8,300' Module 12 - 8,344' Module 11 - 8,412' Module 10 - 8,458' Module 9 - 8,501' Module 8 - 8,569' Module 7 - 8,617' Module 6 - 8,896' Module 5 - 9,039' Module 4 - 9,258' Module 3 - 9,299' Module 2 - 9,568' Module 1 - NA TD =9,733’MD / 7,837’ (TVD) 20” RKB = 21’ (AGL) 13-3/8” 9-5/8”4 1 PBTD =BB 5,291’MD / 3,883’ (TVD) 5 Jet Cut tbg @ ~5850’ (2/8/21) 3-1/2 x 9-5/8 TOC @ 2340’ 2/21/21 CBL 9-5/8 TOC @ 3541’ Calculated w 25% was hout 2 3 6 CASING DETAIL SIZE TYPE WT GRADE CONN ID TOP BTM. 20" Conductor 131 X-52 N/A N/A Surf. 137' 13-3/8' Surface 68 L-80 BTC 12.415 Surf. 1,862' 9-5/8" Intermediate 40 L-80 BTC 8.835 Surf. 7,214' 3-1/2" Production 9.3 L-80 EUE 2.992 Surf. 9,722' Sterl Gas Pool 3 Isolated Sterr Sterl Gas Pool 5.2 SFD 4/15/21 Sterl Gas Pool 4 Notes:0 psi on tubing, 0 psi on IA, 0 psi on OA, 1.8 bbls to pressure up, bled off and pumped another 1.2 bbls to test. Customer:Hilcorp Customer Contact:Cole Bartlewski LSD: Job #: Date: Fluid Pumped: KBU 41-06 IA MIT WATER 2021-05-17 14:59 Ticket #: Phone #: Operator: 41-6 COLE BARTLEWSKI 907-690-2854 Total Fluid Pumped:117.6 USG 1 Winston, Hugh E (CED) From:Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent:Monday, July 12, 2021 2:20 PM To:McLellan, Bryan J (CED) Cc:Taylor Wellman; Donna Ambruz; Jake Flora - (C) Subject:Cementing Follow Up Report: Excape Control Lines Bryan, Below are the ¼” control lines we squeezed with the grease pump and Halliburton’s FineCem squeeze cement on the Excape IA squeezed wells we did in early January 2021. As you will notice the lines took a varying amount of cement. The 0.25” lines have an ID of 0.152” and capacity of 0.00094 gllons/ft. 2 gallons equates to 2127’ of control line. I plan on updating the WBDs and notating the cement volume pumped on each. Let me know if there is anything additional you would like to see here‐ Thanks, Jake PTD Well cement volume pumped date cemented 202‐091 KBU 11‐08Y 2 gallons on each line (7/2/2021) 205‐141 KBU 41‐06 1.5 gal red, 2 gal yellow and 2 gal green (7/2/2021) 204‐209 KBU 42‐06 2 gal yellow, 1.5 green and 1 gal red (7/2/2021) 200‐179 KBU 44‐06 1 gal red and 2 gal green (7/2/2021) 207‐149 KBU 14‐06Y 1.5 gal green and 0.5 gal red (7/2/2021) 203‐217 KBU 23‐07 1 gal red, .5 gal green and 1 gal yellow (7/2/2021) 203‐025 BCU‐11 2 gallons on each line (7/3/2021) 2 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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: 04/07/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 41-06 (PTD 205-141) PERF 02/26/2021 Please include current contact information if different from above. PTD: 2051410 E-Set: 34919 Received by the AOGCC 04/08/2021 04/08/2021 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: 04/07/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 41-06 (PTD 205-141) PLUG-PERF 03/12/2021 Please include current contact information if different from above. PTD: 2051410 E-Set: 34920 Received by the AOGCC 04/08/2021 04/08/2021 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: 04/07/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 41-06 (PTD 205-141) PERF 02/26/2021 Please include current contact information if different from above. PTD: 2051410 E-Set: 34919 Received by the AOGCC 04/08/2021 04/08/2021 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: 03/31/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 41-06 (PTD 205-141) PLUG-PERF 03/17/2021 Please include current contact information if different from above. PTD: 2051410 E-Set: 34865 Received by the AOGCC 03/31/2021 03/31/2021 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: 03/31/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 41-06 (PTD 205-141) CIBP Cement PERF 03/06/2021 Please include current contact information if different from above. PTD: 2051410 E-Set: 34864 Received by the AOGCC 03/31/2021 03/31/2021 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: 03/08/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 41-06 (PTD 205-141) Memory Total Depth Determination Log 02/24/2021 Please include current contact information if different from above. PTD: 2051410 E-Set: 34758 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 : 03/01/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KU 41-06 (PTD 205-141) MCBL Memory Cement Bond Log 02/21/2020 Please include current contact information if different from above. PTD: 2051410 E-Set: 34749 Received by the AOGCC 03/08/2021 03/09/2021 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 Nitrogen 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 9733'8356' (Fill) Casing Collapse Structural Conductor 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 Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: February 5, 2021 N/A 9,722' Perforation Depth MD (ft): 7,214' See Attached Schematic 9,722'7,826'3-1/2" 20" 13-3/8" 137' 9-5/8"7,214' 1,862'5,020psi 137' 1,648' 5,341' 137' 1,862' N/A TVD Burst N/A 10,160psi MD 5,750psi Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 205-141 50-133-20555-00 Kenai Beluga Unit 41-6 Kenai Field / Sterling Gas Pools 5.1, 4, 3, and Sterling Undefined COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic jake.flora@hilcorp.com N/A and N/A N/A and N/A Perforation Depth TVD (ft): Tubing Size: 7837' 8356' 6460' 1,185 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. By Samantha Carlisle at 10:59 am, Jan 25, 2021 321-048 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2021.01.25 10:02:47 -09'00' Taylor Wellman gls 1/27/21 GAS DLB 01/25/2021 / cement packer DSR-1/27/21 X 10-404 Perforate New Pool -00 DLB * CBL required over 3.5" cemented tubing prior to perforating well. * verify control line integrity after perforating. Required? Yes 1/28/21 dts 1/28/2021 JLC 1/28/2021 RBDMS HEW 1/29/2021 Well Prognosis Well: KBU 41-6 Date: 01/25/2021 Well Name: Kenai Unit 41-6 API Number: 50-133-20555-00 Current Status: SI Gas completion Leg: N/A Estimated Start Date: 02/05/2021 Rig: N/A Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Tom Fouts 777-8398 Permit to Drill Number: 205-141 First Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 Second Call Engineer: Todd Sidoti (907) 632-4113 Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Maximum Expected BHP: ~1600psi @ 4150’ TVD (Based on psi/ft water gradient of 0.45 ) Max. Allowable Surface Pressure: ~1185psi (Based on 0.01 psi/ft gas gradient) Well Status: KBU 41-06 is currently a shut-in Excape well that has been offline since October 2008. Brief Well Summary: KBU 41-06 drilled and completed in 2005 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. It is the most northerly Excape well in the Kenai Gas Field and the only one drilled from 43- 32 Pad. The well came online making only 2 MMCFD. The well went offline in 2008 from sanding up. A perf add to the Middle Beluga in 2013 was unsuccessful. The well has cum’d just under 1.1 BCF and 14.3 MBW of water. Objective: The purpose of this non-rig workover is to isolate the existing open perfs, cement the backside of the 3-1/2” up above all hydrocarbon bearing zones, and recomplete in the Sterling formation(s). A pulse neutron log will need to be run to determine sand intervals to perforate. Wellbore Notes: - 01/14/2021 Log CBL from 7450’ – Surface, 3-1/2” x 9-5/8” TOC = 6060’ - 01/12/2021 MITIA Passed 1500psi - 11/23/2013 Perforated 7526-7533’ w 2-1/8” 7’ gun E-Line & Pump Truck Procedure 1. RU E-Line, set CIBP at ~ 7500’, dump 35 ft of cement on CIBP to abandon Upper Beluga perforations. 2. Load tubing with water. 3. Pressure up on tubing to 2000 psi. 4. Jet Cut tubing at ~ 5850’. Confirm circulation / communication to IA. 5. RD E-Line. 6. Circulate IA clean. Fullbore Cement Procedure 7. RU Cementers. Establish circulation down the tubing and up the IA. 8. Mix and pump 214 bbls cement slurry. Planned TOC in 3-1/2” x 9-5/8” annulus = 2500’. 9. Drop wiper ball, displace with 50.5 bbls water. 10. Shut in well with both master valves to trap pressure. 11. WOC minimum of 3 days. (.0087 x 5800 ft = 50 bbls) cut tubing 5850ft 3 1/2" x 9 5/8" = .0639 bbl/ft (place cement packer in 3 1/2 x 9 5/8" ) The purpose of this non-rig workover is to isolate the existing open perfs, cement the backside of the 3-1/2” up above all hydrocarbon bearing zones, and recomplete in the Sterling formation(s). A pulse neutron log will need to be run to determine sand intervals to perforate. MIT-T 5850' - 2500 ft x .0639 = 214 bbls Well Prognosis Well: KBU 41-6 Date: 01/25/2021 Slick-Line / E-Line Procedure 12. RU Slick-line, PT lubricator. Log memory CBL from TD to surface. 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. 13. Swab well down to 5800’. RD Slick-Line. 14. Pressure well to perforate with well gas. 15. RU E-line, PT lubricator. 16. Perforate the below zones from the bottom up: FORMATION Pool INTERVAL (Status) MD TOP MD Base Total Ftg TVdss TOP TVDss Bot Sterling Sterling Pool 5.1 & above Determine from PNL Log ~4600 ~5800 TBD TBD TBD 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. 17. POOH. 18. RD E-Line. 19. 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. D See attached email for perforation intervals. gls MIT-IA after upper set of perfs is completed. (submit CBL to AOGCC for review) 12a. retest MIT-T and MIT-IA 1500 psi for 10 min each. CBL Well Prognosis Well: KBU 41-6 Date: 01/25/2021 Attachments: Current Well Schematic Proposed Well Schematic Standard Well Procedure – N2 Operations CTU BOP Schematic _____________________________________________________________________________________ Created By: JMF 01/05/2021 SCHEMATIC Kenai Gas Field Well: KBU 41-6 Last Completed: 12/8/2005 PTD: 205-141 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT 7,526’ 7,533’ 5,639’ 5,645’ 7’ Beluga 7,757’ 7,771’ 5,866’ 5,879’14’ 7,991’ 8,001’ 6,097’ 6,106’10’ 8,048’ 8,058’ 6,153’ 6,163’10’ 8,281’ 8,291’ 6,385’ 6,395’10’ 8,325’ 8,335’ 6,429’ 6,439’10’ 8,393’ 8,403’ 6,497’ 6,507’10’ 8,439’ 8,449’ 6,543’ 6,553’10’ 8,482’ 8,492’ 6,586’ 6,596’10’ 8,550’ 8,560’ 6,654’ 6,664’10’ 8,598’ 8,608’ 6,702’6,712’10’ Tyonek 8,877’ 8,887’ 6,981’ 6,991’10’ 9,020’ 9,030’ 7,124’ 7,134’10’ 9,239’ 9,249’ 7,343’ 7,353’10’ 9,280 9,290’ 7,384’ 7,394’10’ 9,549’ 9,559’ 7,653’ 7,663’10’ 9,627’ 9,636’ 7,731’ 7,740 10’ JEWELRY DETAIL No Depth Item 1 7,975’ CIBP 2 8,453’ A-Stop OPEN HOLE / CEMENT DETAIL 13-3/8" 16" hole Cmt w/ 600 sks (275 bbls) of 12.0 ppg, Type 1 cmt, 100% returns 9-5/8"12-1/4" hole Cmt w/ 723 sks of Class G, (178 bbls)of Lead @ 12.5 ppg & (78 bbls) of Tail @ 13.5 ppg 7”8-1/2" hole Cmt w/ 1,160 sks (242 bbls) of 15.58ppg, class G cmt TD =9,733’MD / 7,837’ (TVD) 20” RKB = 21’ (AGL) 13-3/8” 9-5/8” PBTD =BB 9,684’44 MD / 7,788’ (TVD) 3-1/2 x 9-5/8 5 TOC @ 6060’ 1/14/21 CBL 9-5/8 TOC @ 3541’ Calculated w 25% was hout CASING DETAIL SIZE TYPE WT GRADE CONN ID TOP BTM. 20" Conductor 131 X-52 N/A N/A Surf. 137' 13-3/8' Surface 68 L-80 BTC 12.415 Surf. 1,862' 9-5/8" Intermediate 40 L-80 BTC 8.835 Surf. 7,214' 3-1/2" Production 9.3 L-80 EUE 2.992 Surf. 9,722' FLAPPERS MD (RKB) Module 15 - 8,010' Module 14 - 8,067' Module 13 - 8,300' Module 12 - 8,344' Module 11 - 8,412' Module 10 - 8,458' Module 9 - 8,501' Module 8 - 8,569' Module 7 - 8,617' Module 6 - 8,896' Module 5 - 9,039' Module 4 - 9,258' Module 3 - 9,299' Module 2 - 9,568' Module 1 - NA ESCAPE SYSTEM DETAILS * 15 Excape modules placed *Green control line fired module 1 *Yellow control line fired modules 2 thru 8 * Red control line fired modules 9 thru 15 * Ceramic flapper valves below each module as follows: *14 Conventional flappers *No flapper at Module-1 _____________________________________________________________________________________ Created By: JMF 01/05/2021 PROPOSED Kenai Gas Field Well: KBU 41-6 Last Completed: 12/8/2005 PTD: 205-141 PERFORATION DETAIL Sands Top (MD) Btm (MD) Top (TVD) Btm (TVD) FT planned Sterling A6 ~4600’~5800’ to B4B 7,526’ 7,533’ 5,639’ 5,645’ 7’ Beluga 7,757’ 7,771’ 5,866’ 5,879’14’ 7,991’ 8,001’ 6,097’ 6,106’10’ 8,048’ 8,058’ 6,153’ 6,163’10’ 8,281’ 8,291’ 6,385’ 6,395’10’ 8,325’ 8,335’ 6,429’ 6,439’10’ 8,393’ 8,403’ 6,497’ 6,507’10’ 8,439’ 8,449’ 6,543’ 6,553’10’ 8,482’ 8,492’ 6,586’ 6,596’10’ 8,550’ 8,560’ 6,654’ 6,664’10’ 8,598’ 8,608’ 6,702’6,712’10’ Tyonek 8,877’ 8,887’ 6,981’ 6,991’10’ 9,020’ 9,030’ 7,124’ 7,134’10’ 9,239’ 9,249’ 7,343’ 7,353’10’ 9,280 9,290’ 7,384’ 7,394’10’ 9,549’ 9,559’ 7,653’ 7,663’10’ 9,627’ 9,636’ 7,731’ 7,740 10’ JEWELRY DETAIL No Depth Item 1 7,975’ CIBP 2 8,453’ A-Stop OPEN HOLE / CEMENT DETAIL 13-3/8" 16" hole Cmt w/ 600 sks (275 bbls) of 12.0 ppg, Type 1 cmt, 100% returns 9-5/8"12-1/4" hole Cmt w/ 723 sks of Class G, (178 bbls)of Lead @ 12.5 ppg & (78 bbls) of Tail @ 13.5 ppg 7”8-1/2" hole Cmt w/ 1,160 sks (242 bbls) of 15.58ppg, class G cmt TD =9,733’MD / 7,837’ (TVD) 20” RKB = 21’ (AGL) 13-3/8” 9-5/8” PBTD =BB 9,684’44 MD / 7,788’ (TVD) Set CIBP @ ~7500’ Jet Cut @ ~5850’ 3-1/2 x 9-5/8 5 TOC @ 6060’ 1/14/21 CBL 9-5/8 TOC @ 3541’ Calculated w 25% was hout Planned Sterling Perfs ~4600-5800’ CASING DETAIL SIZE TYPE WT GRADE CONN ID TOP BTM. 20" Conductor 131 X-52 N/A N/A Surf. 137' 13-3/8' Surface 68 L-80 BTC 12.415 Surf. 1,862' 9-5/8" Intermediate 40 L-80 BTC 8.835 Surf. 7,214' 3-1/2" Production 9.3 L-80 EUE 2.992 Surf. 9,722' FLAPPERS MD (RKB) Module 15 - 8,010' Module 14 - 8,067' Module 13 - 8,300' Module 12 - 8,344' Module 11 - 8,412' Module 10 - 8,458' Module 9 - 8,501' Module 8 - 8,569' Module 7 - 8,617' Module 6 - 8,896' Module 5 - 9,039' Module 4 - 9,258' Module 3 - 9,299' Module 2 - 9,568' Module 1 - NA ESCAPE SYSTEM DETAILS * 15 Excape modules placed *Green control line fired module 1 *Yellow control line fired modules 2 thru 8 * Red control line fired modules 9 thru 15 * Ceramic flapper valves below each module as follows: *14 Conventional flappers *No flapper at Module-1 2500’ Planned TOC see attached email for intervals 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. Coiled Tubing HydraCo 60K Injector Head & Gooseneck Weight = 3500 lbs 3" 500psi ArmorPak Stripper Bowen Type 5K 5.5" Lubricator 5K CJS ArmorPak Guide Bowen Type 5K x 5-1/8" 10K Flange 5-1/8" 10K Quad BOP 1.ArmorPak 1.5" x 1.5" Pipe Ram 2.ArmorPak 1.5" x 1.5" Pipe Ram 3.Shear Ram 4.Blind Ram 5-1/8 10K Spool with 2-1/16" 10K Outlets - Kill Port Manual Valve 1: 2-1/16" 10K Manual Valve 2: 2-1/16" 10K Manual Valve 3: 2" Weco 1502 Adapter Spool 5-1/8" 10K x 7-1/16" 5K Adapter Spool 7-1/16" 5K x 5-1/8" 5K 5-1/8" 5K ArmorPak 1.5" x 1.5" CT Head Wellhead 1 Carlisle, Samantha J (CED) From:Jake Flora - (C) <Jake.Flora@hilcorp.com> Sent:Wednesday, January 27, 2021 4:20 PM To:Schwartz, Guy L (CED) Subject:FW: KBU 41-06 Proposed Perfs (PTD 205-141) Follow Up Flag:Follow up Flag Status:Flagged Guy, Belowaretheproposedperforations.Letmeknowifyouwantthemaddedinthesundryapplicationandthewhole thingresubmitted,notroubletodoso. Thanks, Jake From:BenjaminSiks Sent:Wednesday,January27,20213:58PM To:JakeFloraͲ(C)<Jake.Flora@hilcorp.com>;TrudiHallett<thallett@hilcorp.com> Subject:KBU41Ͳ06Perfs Well:KBU41Ͳ06Project:RWO/RTP SandMDTopMDBottom Total Footage (MD) TVDTopTVDBottomPA P3_A8±4,889'±4,932'43'±3,622'±3,665'SterlingSTER P3_A10±4,991'±5,033'42'±3,687'±3,729'SterlingSTER P3_A11±5,104'±5,144'40'±3,761'±3,801'SterlingSTER P4_B2A±5,345'±5,377'32'±3,918'±3,950'SterlingSTER P5.1_B3±5,416'±5,440'24'±3,964'±3,988'SterlingSTE P5.1_B4A±5,595'±5,616'21'±4,085'±4,106'SterlingSTE P5.1_B4A±5,671'±5,694'23'±4,135'±4,158'SterlingSTE P5.2_B5A±5,835'±5,859'24'±4,245'±4,269'SterlingSTE Ben Siks Senior Geologist – Kenai Asset Team 2 Office – 907-777-8388 Cell –----907-229-0865 bsiks@hilcorp.com The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 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. ~QJ~ - ~ ~ ~ Well History File Identifier Organizing (done) ^ Two-sided III IIIIII II III II III ^ Rescan Needed III II'lII II II III II RE CAN DIGITAL DATA OVERSIZED (Scannable) 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: ^ Other:: BY: _ ~ Maria Date: ~.., ~' ~ ~ ~ O /s/ Project Proofing BY: Date: ~ I III 111111 IIIII II III /s/ 'i ' 1 _ ~ ~ Scanning Preparation ~,~, x 30 = ~ + ~ =TOTAL PAGES_~ Q (Count does not include cover sheet) ~ BY Maria Date: ~ ~ ~ 1 ©C] /s/ t Production Scanning III IIIIIIIIIII II III Stage 1 Page Count from Scanned File: ----F- ~- (Count does include cover sheet) Page Count Matches Number in Scanning Preparation: V YES NO BY: •. 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III II'I II I II II I I III ReScanned BY: Maria Date: /s/ Comments about this file: Quality Checked III II~III III III II 10!612005 Well History File Cover Page.doc STATE OF ALASKA • AL, A OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Repair Well U Plug Perforations U Perforate U Other U CIBP Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development 0 Exploratory ❑ 205-141 • 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-133-20555-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 ' Kenai Beluga Unit 41-6 • 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Field/Up Tyonek Beluga Gas 11.Present Well Condition Summary: Total Depth measured 9,733 feet Plugs measured 7,975 feeR E C E I V E D true vertical 7,837 feet Junk measured N/A feet DEC 0 6 2013 Effective Depth measured 7,975 feet Packer measured N/A feet ^(✓� true vertical 6,081 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 137' 20 137' 137' Surface 1,862' 13-3/8" 1,862' 1,648' 5,020psi 2,260psi Intermediate 7,214' 9-5/8" 7,214' 5,341' 5,750psi 3,090psi Production 9,722' 3-1/2" 9,722' 7,826' 10,160psi 10,540psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic BANNED APP 4 ,r 2 �J 14 Tubing(size,grade,measured and true vertical depth) N/A N/A N/A N/A Packers and SSSV(type,measured and true vertical depth) N/A N/A N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A Treatment descriptions including volumes used and final pressure: N/A 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 0 160 Subsequent to operation: 0 0 0 0 160 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development Q • Service ❑ Stratigraphic ❑ Daily Report of Well Operations X 16.Well Status after work: Oil ❑ Gas El . WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 313-572 Contact Jeremy Mardambek Email jmardambek(a�hiICorp.com Printed Name Jeremy Mardambek Title Reservoir Engineer Signature / Phone 907-777-8388 Date 12/6/2013 1 ..-.... An AAA 17 ..•:.....d.1111•1/11,) Cm"Z3•/ / c,dtmi+/lrinin•ml/lnI.. Kenai Gas Field Well: KBU 41-6 SCHEMATIC Last Completed: 12/8/2005 Hilcorp Alaska,LLC PTD: 205-141 CASING DETAIL RK6=21'(AGL) SIZE TYPE WT GRADE CONN ID TOP BTM. L20" Conductor 131 X-52 N/A N/A Surf. 137' 13-3/8' Surface 68 L-80 BTC 12.415 Surf. 1,862' 9 5/8" Intermediate 40 L-80 BTC 8.835 Surf. 7,214' I 3-1/2" Production 9.3 L-80 EUE 2.992 Surf. 9,722' 13-3/8" ESCAPE SYSTEM DETAILS Last Tag JEWELRY DETAIL * 15 Excape modules placed No Depth Date No Depth Item 1 8,360'(MD) 10/20/2013 1 7,975' CIBP Yellow 2 8,453' A-Stop I f C ( PERFORATION DETAIL ' Sands Top(MD) Btm(MD) Top(TVD) Btm(TVD) FT 35/8" x *Ceramic flapper valves below =...v.' l each module as follows: 7,526' 7,533' 5,639' 5,645' 7' 1 3� `°_ *14 \/ 7,757' 7,771' 5,866' 5,879' 14' 4+ , I' Conventional flappers ` r *No flapper at Module-1 7,991' 8,001' 6,097' 6,106' 10' 4 ^M' 8,048' 8,058' 6,153' 6,163' 10' 0, = 1 c 113Q FLAPPERS MD(RKB) 't , '?, 8,281' 8,291' 6,385' 6,395' 10' A ',4 Module 15-8,010' ..rti ,� 8,325' 8,335' 6,429' 6,439' 10' Module 14-8,067' Beluga I 8,393' 8,403' 6,497' 6,507' 10' ,,,,,i-1 Module 13-8,300' 8,439' 8,449' 6,543' 6,553' 10' '' Module 12-8,344' 8,482' 8,492' 6,586' 6,596' 10' p!a ) Module 11-8,412' 8,550' 8,560' 6,654' 6,664' 10' i s i Module 10-8,458' 8,598' 8,608' 6,702' 6,712' 10' ' Module 9-8,501' ��i � 8,877' 8,887' 6,981' 6,991' 10' wq ,I :7,,..4, r3 Module 8-8,569' 9,020' 9,030' 7,124' 7,134' 10' z:• i '; Module 7-8,617' 9,239' 9,249' 7,343' 7,353' 10' ,'4 ► Module 6-8,896' Tyonek 9,280 9,290' 7,384' 7,394' 10' )4k frt, Module 5-9,039' 9,549' 9,559' 7,653' 7,663' 10' Module 4-9,258' t 0 2 9,627' 9,636' 7,731' 7,740 10' ( Module 3-9,299' Module 2-9,568' Module 1- NA I l' `! otl 4, l� A, OPEN HOLE/CEMENT DETAIL v t` 13-3/8" 16"hole Cmt w/600 sks(275 bbls)of 12.0 ppg,Type 1 cmt,100%returns W.. I' 9-5/8" 12-1/4"hole Cmt w/723 sks of Class G,(178 bbls)of Lead @ 12.5 ppg&(78 bbls)of Tail @ 13.5 ppg Irl ta'' 7" 8-1/2"hole Cmt w/1,160 sks(242 bbls)of 15.58ppg,class G cmt i."/ 10 ;' i 0 ray ` 4:1' eI 4 + ��J +t is 1 ' 'M TD=9,733'MD/7,837'(TVD) PBTD=9,684'MD/7,788'(TVD) Created By:TDF 12/6/2013 Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 41-6 50-133-20555-00 205-141 11/10/13 11/22/13 Daily Operations: 11/6/2013 -Wednesday No Operations to Report. 11/7/2013 -Thursday No Operations to Report. 11/8/2013 - Friday No Operations to Report. 11/9/2013-Saturday No Operations to Report. 11/10/2013 -Sunday Mobe to location and rig up equipment. Pressure test lubricator to 250psi low and 2,500psi high. RIH with CIBP with gammma ray tool and tie into Expro CBL log. Set bridge plug at 7,975'. Picked up and tagged plug. POOH. Well had 300psi. Bled well to 100psi for neg test, ok. RIH w/2"x14' strip perf gun and tie into log. Spot shot from 7,757'to 7,771' per final approved perf sheet dated 28 Oct 13, by SCR. Fired gun and saw little change. POOH. Rig down lubricator,turn well over to field and cleaned up area. 11/11/2013 - Monday No Operations to Report. 11/12/2013 -Tuesday No Operations to Report. Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 41-6 50-133-20555-00 205-141 11/10/13 11/22/13 Daily Operations: 11/20/2013 -Wednesday No operations to report. 11/21/2013 -Thursday Mobe to location and rig up equipment. Pressure test lubricator to 250 psi low and 2,500 psi high. Waited for wind to lay down. Decided to shut down due to high wind. 11/22/2013 - Friday Mobe to location and rig up equipment. PT lubricator to 250 psi low and 2,500 psi high. RIH w/2-1/8" x 7', 0 deg phase, 6 spf strip gun and tied into Priority CCL/Gmma ray log dated 11/10/13. Spotted shot from 7,526' to 7,533' per final approved perf sheet dated 11/19/13 signed by Geologist. Fired perf gun. Rig down lubricator, clean up work area and turn well over to 11/23/2013 -Saturday No operations to report. 11/24/2013 -Sunday No operations to report. 11/25/2013 - Monday No operations to report. 11/26/2013 -Tuesday No operations to report. . OF T w P V THE STATE s Alaska Oil and Gas F„, Of A LAsKA. h,..,(nanservation Commission GOVERNOR SEAN PARNELL 333 West Seventh Avenue OF Q. Anchorage, Alaska 99501-3572 ALAS Main: 907.279.1433 Fax: 907.276.7542 Mike Dunn ca05-.. 114 Operations Engineer Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 100 Anchorage, AK 99503 Re: Kenai Field, Upper Tyonek Beluga Gas Pool, Kenai Beluga Unit 41-6 Sundry Number: 313-572 Dear Mr. Dunn: scow° hu,{ -) 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, Commissioner DATED this et-clay of November, 2013. Encl. • STATE OF ALASKA �� r ALASKA OIL AND GAS CONSERVATION COMMISSION 0 C T 3 0 2013 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 O 1.Type of Request: Abandon❑ Plug for Redrill ❑ Perforate New Pool ❑ Repair Well❑ Change Approved Program ❑ Suspend❑ Plug Perforations ❑ Perforate 0 Pull Tubing ❑ Time Extension ❑ Operations Shutdown❑ Re-enter Susp.Well ❑ Stimulate ❑ Alter Casing❑ Other: Isolate 0 ' 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska,LLC Exploratory ❑ Development 0 • 205-141 ' 3.Address: Stratigraphic ❑ Service ❑ 6.API Number. 3800 Centerpoint Drive,Anchorage AK,99503 50-133-20555-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? NW./ ,�.t3 Will planned perforations require a spacing exception? Yes ❑ Non Kenai Beluga Unit 41-6 • 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028142 - Kenai Field/Up Tyonek Beluga Gas 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD(ft): Effective Depth TVD(ft): Plugs(measured): Junk(measured): 9,733' 7,837' • 8,356' 6,460' N/A 8,356'(Fill) Casing Length Size MD TVD Burst Collapse Structural Conductor 137' 20" 137' 137' Surface 1,862' 13-3/8" 1,862' 1,648' 5,020psi 2,260psi Intermediate 7,214' 9-5/8" 7,214' 5,341' 5,750psi 3,090psi Production 9,722' 3-1/2" 9,722' 7,826' 10,160psi 10,540psi Liner Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic N/A N/A N/A Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): N/A and N/A N/A and N/A 12.Attachments: Description Summary of Proposal 1151 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic❑ Development 12 Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: 11/5/2013 Oil ❑ Gas ID - WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: N/A WINJ ❑ GINJ ❑ WAG ❑ Abandoned ❑ Commission Representative: N/A GSTOR ❑ SPLUG ❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Mike Dunn Email mdunna,hilcorp.com Printed Name Mike Dunn / Title Operations Engineer Signature / Phone 777-8382 Date 10/30/2013 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 33— �'j -12 Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ pt Other: RB MS NOV 15 2°,1.t Spacing Exception Required? Yes ❑ No © Subsequent Form Required: / Q'" 1 0 Y I APPROVED BY Approved by, 'I COMMISSIONER THE COMMISSION Date: I(- V 13 SubmA Form and a`/ `,�� , Form 10-403(Revised 10/2012) Approve r i nths from the to of approval. ttachme sin Duplicate ' ■J� 13 . Well Prognosis Well: KU 41-6 Hilcarp Alaska,LID Date:3/22/2013 Well Name: Kenai Unit 41-6 API Number: 50-133-20555-00 Current Status: SI Gas completion Leg: N/A Estimated Start Date: Nov 5th, 2013 Rig: N/A Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Regulatory Contact: Tom Fouts 777-8398 Permit to Drill Number: 205-141 First Call Engineer: Mike Dunn (907)777-8382 (0) (907) 351-4191 (M) Second Call Engineer: Reg.Approval Req'd? 10-403 Date Reg.Approval Rec'vd: Current Bottom Hole Pressure: —2,750psi Maximum Expected BHP: —2,750psi @ 6,702' TVD (Based on psi/ft water gradient of 0.45 ) Max. Allowable Surface Pressure: —2,190psi (Based on 0.03 psi/ft gas gradient) . Brief Well Summary: KBU 41-06 is a Beluga Excape producer drilled in late 2005. It is the most northerly Excape well in the Kenai Gas Field and the only one drilled from pad 43-32. The initial production rates were disappointing with rates below 2 MMSCFD compared to an average of the Kenai Excape wells of 3.75 MMCFD. The well was briefly shut in from 8/2007 through 3/2008 for an unknown reason and only produced for another 6 months until it quit producing, making 1 MMSCFD with 4 BWPD @ 100 psi FTP. A recent tag on 10/22/2013 showed fill at 8,360' (above module#11) and a fluid level at 620' SLM indicated an open set of perforations containing near virgin pressure water sand. Due to the poor performance of this well to date, and a tubing A-stop fish stuck at 8,453' RKB, a coiled tubing cleanout is considered too risky from a reservoir and mechanical standpoint. Justification: Several perforation targets have been identified above the LB2A sand, specifically in the MB sands. The well is a 3.5" monobore and the target zone is likely low permeability. Reactive charges are recommended in order to minimize skin in the perforation tunnels. The plug should be set as deep as possible and not across a collar. No cement cap is needed as the added perforations are in the same Pool as the current perforations. Summary Procedure: 1. RU E-line and test lubricator to 250psi low/2,500psi high. 2. RIH with GR/CCL&CIBP and correlate on depth and set same at±7,975. ELOH. 3. RIH with GR/CCL& perf guns and correlate on depth and perforate±7,757'to±7,771'.ELOH. 4. RD Eline. 5. Turn well over to production &flow test well. Contingency 1: 1. RU E-line and test lubricator to 250psi low/2,500psi high. 2. RIH with GR/CCL&CIBP and correlate on depth and set same at±7,750. ELOH. 3. RIH with GR/CCL& perf guns and correlate on depth and perforate ±7,657'to±7,667'.ELOH. 4. RD Eline. 5. Turn well over to production &flow test well. • • ll onosi Well:We Pr Kr s 41-6 'Bleary Alaska,Lb Date:3/22/2013 Contingency 2: 1. RU E-line and test lubricator to 250psi low/2,500psi high. 2. RIH with GR/CCL&CIBP and correlate on depth and set same at±7,650. ELOH. 3. RIH with GR/CCL& perf guns and correlate on depth and perforate ±7,523'to±7,530'.ELOH. 4. RD Eline. 5. Turn well over to production &flow test well. Attachments: 1. As-built Well Schematic 2. Proposed Well Schematic • • KBU 41 -6 Pad 41-7 Permit#: 205-141 41' FSL, 994' FEL API#: 50-133-2-133-2 0555-00 Prop.Des: A-028142 Sec. 6, T4N, R11 W, S.M. MARATHON KB Elevation: 87' (21'AGL) X: 274,916.45 Y: 2,362,064.63 Conductor Latitude: 60°27'34.673"N 20" X-52 131 ppf Thickness Longitude: -151°14'49.031"W p' Top Bottom 0.625" Spud: 10/07/2005 -, MD D 0 137' TD: 10/26/2005 Rig Released: 08:00hrs 11/01/2005 Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,862' ' ND 0' 1,648' IA 16"hole Cmt w/600 sks(275 bbls)of Tree cxn=4-3/4"Otis a 12.0 ppg,Type 1 cmt,100%returns "i ,. Intermediate Casing Top of Cement 9-5/8" L-80 40 ppf BTC (est.)( 6,714'MD `, Top Bottom 500'above 9-5/8"shoe ', MD 0' 7,214' TVD 0' 5,341' 12-1/4"hole Cmt w/723 sks of Class G,(178 bbls) of Lead @ 12.5 ppg&(78 bbls)of Tail @ 13.5 ppg Production Casing 3-1/2" L80 9.3 ppf EUE Tagged fill @ 8,356'MD(10/11/08) ��' Top Bottom 8rd `^ MD 0' 9,722' TVD 0' 7,826' ,e," 8-1/2"hole Cmt w/1,160 sks(242 bbls)of +r 15.58ppg,class G cmt A-Stop @'8,453'MD(10/8/08) ::..,,,,,l' { i Excape System Details: x. Ir * 15 Excape modules placed *Green control line fired module 1 Excape System Details: - control line fired modules 2 Ceramic flapper valves below thru 8 each module as follows: 'Red contol line fired modules 9 thru 15 *14 Conventional flappers *Ceramic flapper valves below each *No flapper at Module-1 - iq module except for module 1 Flappers MD(RKB): t Perfs MD(RKB): Module 15-8,010' Module 15-7,991'-8,001'(Beluga) Module 14-8,067' Module 14-8,048'-8,058'(Beluga) Module 13-8,300' - Module Module 13-8,281'-8,291'(Beluga) Module 12-8,344' Module 12-8,325'-8,335'(Beluga) Module 11 -8,412' ni Module 11 -8,393'-8,403'(Beluga) Module 10-8,458' ? Module 10-8,439'-8,449'(Beluga) Module 9-8,501' 1 - Module 9-8,482'-8,492'(Beluga) Module 8-8,569' Module 8-8,550'-8,560'(Beluga) Module 7-8,617' Module 7-8,598'-8,608'(Beluga) Module 6-8,896' Module 6-8,877'-8,887'(Beluga) Module 5-9,039' Module 5-9,020'-9,030'(Beluga) Module 4-9,258' Module 4-9,239'-9,249'(Tyonek) Module 3-9,299' , ` Module 3-9,280'-9,290'(Tyonek) Module 2-9,568' Module 2-9,549'-9,559'(Tyonek) Module 1 - NA Module 1 -9,627'-9,636'(Tyonek) "r TD PBTD 9,733'MD 9,684' MD 7,837'TVD 7,788'ND Well Name&Number: Kenai Beluga Unit 41-6 Lease Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 7,991'-9,636' Perf(TVD): 6,097'-7,740' Angle @ KOP&Depth: -2.8°/100' @ 350 ft Angle @ Perfs: 7.7°->0.4° Date Completed: 12/8/2005 Ground Level: 66.5'(AMSL) RKB: 21'(AGL) Revised by: Craig Rang Revision Date: 3-18-2010 r • � • Kenai Gas Field . , , Et Well: KBU 41-6 PROPOSED Last Completed: 12/8/2005 Hilcorp Alaska,LLC PTD: 205-141 CASING DETAIL RK6=21'(AGL) SIZE TYPE WT GRADE CONN ID TOP BTM. 20 20" Conductor 131 X-52 N/A N/A Surf. 137' "J 3/8' Surface 68 L-80 BTC 12.415 Surf. 1,862' 9-5/8" Intermediate 40 L-80 BTC 8.835 Surf. 7,214' 3-1/2" Production 9.3 L-80 EUE 2.992 Surf. 9,722' 13-3/8 ESCAPE SYSTEM DETAILS Last Tag JEWELRY DETAIL * 15 Excape modules placed No Depth Date No Depth Item 1 8,360'(MD) 10/20/2013 1 ±7,975' CIBP Yellow 2 8,453' A-Stop PERFORATION DETAIL Sands Top(MD) Btm(MD) Top(ND) Btm(ND) FT *Ceramic flapper valves below each module as follows: ±7,757' ±7,771' ±5,866' ±5,879' ±14' 7,991' 8,001' 6,097' 6,106' 10' * 14 Conventional flappers 9-5/8" "`' t,/ *No flapper at Module-1 8,048' 8,058' 6,153' 6,163' 10' 1 8,281' 8,291' 6,385' 6,395' 10' FLAPPERS MD(RKB) 8,325' 8,335' 6,429' 6,439' 10' t { ` Module 15-8,010' Beluga 8,393' 8,403' 6,497' 6,507' 10' Module 14-8,067' 8,439' 8,449' 6,543' 6,553' 10' Module 13 8,300' 8,482' 8,492' 6,586' 6,596' 10' t Module 12-8,344' 8,550' 8,560 6,654' 6,664' 30' 6 ;x Module 11-8,412' 8,598' 8,608' 6,702' 6,712' 10' Module 10-8,458' 8 877' 8,887' 6,981' 6,991' 10' Module 9 8,501' 9,020' 9,030' 7,124' 7,134' 10' I 1.° Module 8-8,569' 9,239' 9,249' 7,343' 7,353' 10' Module 7-8,617' Tyonek 9,280 9,290' 7,384' 7,394' 10' 10' IV 1 Module 6-8,896' 9,549' 9,559' 7,653' 7,663' " f� Module 5-9,039' 9,627' 9,636' 7,731' 7,740 10' 2 Module 4-9,258' .,,,, g Module 3-9,299' P Module 2-9,568' 11; Module 1- NA i OPEN HOLE/CEMENT DETAIL '` 13-3/8" 16"hole Cmt w/600 sks(275 bbls)of 12.0 ppg,Type 1 cmt,100%returns 9-5/8" 12-1/4"hole Cmt w/723 sks of Class G,(178 bbls)of Lead @ 12.5 ppg&(78 bbls)of Tail @ 13.5 ppg 7" 8-1/2"hole Cmt w/1,160 sks(242 bbls)of 15.58ppg,class G cmt tp, t4 i, i i x 5• ,.$ TD=9,733'MD/7,837'(ND) PBTD=9,684'MD/7,788'(T D) Created By:TDF 10/30/2013 KBU 41-6 Coil Tubing Clean Out Maunder, Thomas E {DOA) From: Maunder, Thomas E (DOA) Sent: Wednesday, June 18, 2008 1:26 PM To: 'Skiba, Kevin J.' Cc: kdwalsh@marathonoil.com Subject: RE: KBU 41-6 (205-141) Coil Tubing Clean Out Kevin, You do not need to submit a sundry, however as noted please report the work with a 404. Call or message with any questions. Tom Maunder, PE AOGCC Page 1 of 1 From: Skiba, Kevin J. [mailto:kskiba@marathonoil.com] Sent: Wednesday, June 18, 2008 12:39 PM To: Maunder, Thomas E (DOA) Cc: kdwalsh@marathonoil.com Subject: KBU 41-6 Coil Tubing Clean Out ~~;,~~~® SUN ~ ~ 2~0~ Tom, We recently tagged the fill in KBU 41-6 wellbore at 8,125' MD. The tag indicates that 13 of the 15 modules are covered over with solids. We would like to clean this fill out to improve production. We are going to perform a similar clean out operation of the KBU 42-6 wellbore. You indicated that a 10-403 sundry was not required but the work was to be documented on the follow up 10-404 Sundry. Would you advise that we handle the KBU 41-6 clean out reporting in the same fashion as you indicated for KBU 42-6, or do I need to submit a 10-403 Sundry to complete this work? Thanks, Kevin Slaba Engineering Technician Marathon Oil Company Office (907) 283-1371 Cell (907) 394-1332 Fax (907) 283-1350 6/18/2008 • ~ ~10~~ ;~a~R ~ ~ 2GG~ .. ~~IN1 _ ~(, Laboratories, Inc. Ai,~s~a Oii ~ ~~F Corns. Cc~r)~6ssion ~is~chnfa~ (832) 237-4000 Fax: (832) 237-4700 8845 Fallbrook Drive, Houston, Texas 77064 Release Form Date: 4/24/2006 OMNI Employee Authorizing Release: David Sutton/Jennifer Benefield ~/ Means Of Delivery: Fed Ex OMNI File Number: H-34210 Well Information: Marathon Oil Company I KBU 41-6 Kenai Peninsula Borough County AK, USA 39 Chip samples (Core 1), 61 Chip Samples (Core 2), 92 Chip Samples (Core Material Released: 3) Individual Requesting Release: Jennifer Enos -Marathon Individual Authorizing Release: Jennifer Enos -Marathon Purpose Of Release: Per Client Request Address Material Was Delivered To: State of Alaska Oil & Gas 333 7th Ave. Phone: 907-279-1433 Anchorage, AK 99503 Delivery Accepted By: v~,~,~,-~ Date: o~ ~'~ / old~-s 6 Printed Name: `~ avJ a~~ ®~C,La~ ,~~:~~~!!~~ i~AR ~ ~ 2005 ~.tCs.i~pl:. Q„L~aA~ A-~-~ haA.~a~n ~a~.m, amd ~O-y: ba.~t~ ~ g~a - a33 - 8 ~ g . U ~ ~~~ ~,_ ~~MNI State of Alaska Chip Samples Marathon Oil Company File: H-34210 KBU 41-6 Date:4-2406 Kenai Peninsula Borough County, Alaska CO RE 1 Plug Diameter Requested Actual Plug Length Sample Sample Drlllin Fluld Core Depth, Depth, Chip samples No. feet feet B Notchin W/Trim Saw "U -Hole" Direct/on 1 7735.00 7735.40 1 7736.00 7736.60 1 7737.00 7737.50 1 7738.00 7738.60 1 7739.00 7739.40 1 7740.00 7740.40 1 7741.00 7741.45 1 7742.00 7742.50 1 7743.00 7743.40 1 7744.00 7744.45 1 7745.00 7745.50 1 7746.00 7746.50 1 7747.00 7747.60 1 7748.00 7748.40 1 7749.00 7749.25 1 7750.00 7750.35 1 7751.00 7751.50 1 7752.00 7752.45 1 7753.00 7753.40 1 7754.00 7754.50 1 7755.00 7755.85 1 7756.00 7756.75 1 7757.00 7757.55 1 7758.00 7758.65 1 7759.00 7759.65 1 7760.00 7760.65 1 7761.00 7761.75 1 7762.00 7762.70 1 7763.00 7763.70 1 7764.00 7764.60 1 7765.00 7765.55 1 7766.00 7766.55 1 7767.00 7767.50 1 7768.00 7768.45 1 7769.00 7769.60 1 7770.00 7770.60 1 7771.00 7771.20 1 7772.00 7772.40 1 7773.00 7773.10 • QMNI State of Alaska Chip Samples Marathon Oil Company KBU 41-6 File: H-34210 Kenai Peninsula Borough County Date: 4-24-06 0 CORE 2 Plug Diameter Requeste Actual Plug Length Sample Sample Drillin Fluid Core Depth, Depth, Comments: Orientate End Trim No. feet feet B Notchin W/Trlm Saw "U Hole" Direction 2 7776.00 7776.60 2 7777.00 7777.40 2 7778.00 7778.30 2 7779.00 7779.50 2 7780.00 7780.40 2 7781.00 7781.45 2 7782.00 7782.30 2 7783.00 7783.70 2 7784.00 7784.30 2 7785.00 7785.50 2 7786.00 7786.90 2 7787.00 7787.50 2 7788.00 7788.50 2 7789.00 7789.70 2 7790.00 7790.50 2 7791.00 7791.50 2 7792.00 7795.50 2 7793.00 .7793.50 2 7794.00 7794.50 2 7795.00 7795.50 2 7796.00 7796.00 2 7797.00 7797.70 2 7798.00 7798.50 2 7799.00 7799.50 2 7800.00 7800.75 2 7801,00 7801.50 2 7$02.00 7802.50 2 7803.00 7803.50 2 7804.00 7804.50 2 7805.00 7805.50 2 7806.00 7806.50 2 7807.00 7807.50 2 7808.00 7808.50 2 7809.00 7809.50 2 7810.00 7810.50 2 7811.00 7811.50 2 7812.00 7812.20 • • • 2 7813.00 7813.75 2 7814.00 7814.65 2 7815.00 7815.40 2 7816.00 7816.20 2 7817.00 7817.40 2 7818.00 7818.40 2 7819.00 7819.50 2 7820.00 7820.50 2 7821.00 7821.35 2 7822.00 7822.50 2 7823.00 7823.50 2 7824.00 7824.30 2 7825.00 7825.30 2 7826.00 7826.50 2 7sz7.oo 78a7.as 2 7828.00 7828.50 2 7829.00 7829.35 2 7830.00 7830.70 2 7831.00 7831.50 2 7832.00 7832.35 2 7833.00 7833.50 2 7834.00 7834.65 2 7835.00 7835.60 2 7836.00 7836.50 • MNI State of Alaska Chip Samples Marathon Oil Company File: H-34210 KBU 41-6 Date: 4/24/06 Kenai Peninsula Borough County, Alaska CORE 3 Plug Diameter Requeste Actual Plug Length Sample Sample Drillin Fluid Core Depth, Depth, Comments: Orientate End Trim No. feet feet 8 Notchin W/Trim Saw "U -Hole" Direction 3 8445.00 8445.60 3 8446.00 8446.50 3 8447.00 8447.50 3 8448.00 8448.50 3 8449.00 8449.90 3 8450.00 8450.80 3 8451.00 8451.50 3 8452.00 8452.50 3 8453.00 8453.50 3 8454.00 8454.40 3 8455.00 8455.50 3 8456.00 8456.50 3 8457.00 8457.70 3 8458.00 8458.50 3 8459.00 8459.50 3 8460.00 8460.65 3 8461.00 8461.30 3 8462.00 8462.50 3 8463.00 8463.80 3 8464.00 8464.80 3 8465.00 8465.90 3 8466.00 8466.60 3 8467.00 8467.30 3 8468.00 8468.25 3 8469.00 8469.50 3 8470.00 8470.25 3 8471.00 8471.50 3 8472.00 8472.25 3 8473.00 8473.80 • 3 8474.00 8474.50 3 8475.00 8475.50 3 8476.00 8476.90 3 8477:00 8477.50 3 8478.00 8478.50 3 8479.00 8479.65 3 8480.00 8480.70 3 8481.00 8481.45 3 8482.00 8482.60 3 8483.00 8483.60 3 8484.00 8484.70 3 8485.00 8485.90 3 8486.00 8486.80 3 8487.00 8487.50 3 8488.00 8488.50 3 8489.00 8489.85 3 8490.00 8490.80 3 8491.00 8491.20 3 8492.00 8492.50 3 8493.00 8493.50 3 8494.00 8494.20 3 8495.00 8495.60 3 8496.00 8496.40 3 8497.00 8497.90 3 8498.00 8498.50 3 8499.00 8499.30 3 8500.00 8500.50 3 8501.00 8501.70 3 8502.00 8502.70 3 8503.00 8503.80 3 8504.00 8504.50 3 8505.00 8505.30 3 8506.00 8506.50 3 8507.00 8507.50 3 8508.00 8508.70 3 8509.00 8509.50 3 8510.00 8510.45 3 8511.00 8511.30 3 8512.00 8512.50 3 8513.00 8513.50 • • 3 8514.00 8514.40 3 8515.00 8515.50 3 8516.00 8516.50 3 8517.00 8517.80 3 8518.00 8518.60 3 8519.00 8519.50 3 8520.00 8520.35 3 8521.00 8521.80 3 8522.00 8522.20 3 8523.00 8523.40 3 8524.00 8524.10 3 8525.00 8525.35 3 8526.00 8526.90 3 8527.00 8527.50 3 8528.00 8528.50 3 8529.00 8529.85 3 8530.00 8530.80 3 8531.00 8531.35 3 8532.00 8532.85 3 8533.00 8533.50 3 8534.00 8534.65 3 8535.00 8535.40 3 8536.00 8536.20 • OI- ~;~ , _J2 ~RL`;TION 333 44Test 7th ~laren~.a.e, Site 100 ~~.a`h~rage, AI6 99301-3533 P~.~ne: (907) 279-1433 FdXo (907 276-7542 Fax Trarasrr~ia~i®n The information contained in this fax is confidential and/or privileged. 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If you do not receive all the pages or have any problems with this fax. please ca[I for assistance at (907} 793-1223. $%1AW • • Operations Summary Report by J. • Marathon Oil Well Name: KENAI BELUGA UNIT 41 -6 ?rD Zcx"- PI Qtr /Qtr, Block, Sec, Town, Range Field Name License # State /Province Country 006004N011 W01 KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) I KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.121 26.52 6.40 10/7/2005 Daily Operations Report Date: 11/29/2005 Job Category: COMPLETION 24 Hr Summary Ran CBL. Tagged bottom high at 9600' (above bottom module). Saw good bond up to +/- 5800'. Ops Trouble Start Time End Time Dur (hr) Ops Code - Activity Code Status Code Com 12:15 12:30 0.25 SAFETY MTG AF Sign in at office, obtain work permit, hold safety meeting. 12:30 12:45 0.25 SAFETY MTG AF Hold location safety meeting, spot equipment leaving room to MI Rain for Rent tanks 12:45 13:45 1.00 RURD ELEC AF RU E -line unit. 13:45 18:45 5.00 LOG CSG AF Run CBL, encounter software problems, etc. Final CBL shows cement and GR w/ very noisy CCL. Tagged high at 9600' above bottom module. Saw good bond up to +/- 5800'. 18:45 20:00 1.25 PUMP TRET TA WD_ Stuck in ice at surface in the tree. Pumped methanol to thaw. Had to RU heater and warm tree. 20:00 20:30 0.50 RURD ELEC AF Rig back unit for night. Report Date: 11/30/2005 Job Category: COMPLETION 24 Hr Summary Move in frac tanks to location along with miscellaneous equipment. - ' Ops Trouble - - - -- ' -- - - Start Time End Time Dur (hr) - Ops Code Activity Code Status - Code -- - Com - 06:00 18:00 12.00 RURD STIM AF Move in frac tanks on location along with miscellaneous equipment. Report Date: 11/30/2005 Job Category: COMPLETION 24 Hr Summary Bailed fill out of tubing to 9615' WLM (9636' KB). Retrieved wet cement. Ops . Trouble - - - - - - - - - . - Start Time End Time Dur (hr) Ops Code Activity Code Status Code - Com 08:30 08:45 0.25 SAFETY MTG AF Sign in at office, obtain work permit, discuss job, hold safety meeting. 08:45 10:15 1.50 RURD SLIK AF RU slickline unit 10:15 11:15 1.00 BAIL FILL AF ' RIH w/ 2.25 - DD bailer to 9574' WLM. Work bailer to 9582'. POOH w/ wet cement. 11:15 12:20 1.08 BAIL FILL AF RIH w/ same to 9583'. Work bailer to 9592'. POOH w/ same. 12:20 13:20 1.00 BAIL FILL AF RIH w/ same to 9594'. Work to 9602'. POOH w/ same. 13:20 14:10 0.83 BAIL FILL AF RIH w/ same to 9603'. Work to 9610'. POOH w/ same. 1 POOH same. Required 1 14:10 15:00 0.83 BAIL FILL AF RIH w/ same to 9610', wo rk to 9615' WLM. 00 w/ sa e q uired 6 00# overpull. 15:00 16:00 1.00 RURD SLIK AF RD slickline equipment and plug in at office in prep for CLU work tomorrow. Report Date: 12/1/2005 Job Category: COMPLETION 24 Hr Summary Place liner for frac tanks. Spot tanks and manifold same. Continue moving in frac equipment. Ops ' - Trouble - . . . . Start Time End Time Dur (hr) -` Ops Code Activity Code Status Code Com . 06:00 18:00 12.00 RURD STIM AF Place liner for frac tanks. Spot frac tanks and manifold up same. Continue moving in flowback iron and tanks. Report Date: 12/2/2005 Job Category: COMPLETION 24 Hr Summary Started hauling water and filling frac tanks. , - Ops trouble . Start Tune -; End Time . Dur (hr) , Ops Code Activity Code . Status Code Com . 06:00 18:00 12.00 RURD STIM AF Start hauling water and filling frac tanks. Report Date: 12/3/2005 Job Category: COMPLETION 24 Hr Summary Finish hauling water and filling frac tanks. Start lining location for other frac equipment. Ops Trduble . Start Time . End Time Dur(hr) - Ops Code Activity Code _ Status Code . Com - - - 06:00 18:00 12.00 RURD STIM AF Finish hauling water and filling frac tanks. Start lining location for rest of frac equipment. Report Date: 12/4/2005 Job Category: COMPLETION 24 Hr Summary Mix 6% KCL in all frac dtanks. Finished lining location for frac equipment. Sstart flowback equipment RU. .. - - - Ops Trouble • - - - - Start Time End Time Dur(hr) Ops Code Activity Code Status Code Com 06:00 18:00 12.00 RURD STIM AF Mix 6% KCL in all frac tanks. Finish lining location for all frac equipment. Start spotting flowback tanks and lines. 'U la VA kp�� NN JUN 2 1 'Ula www.peloton.com Page 1/6 Report Printed: 8/3/2011 .0 41/ Operations Summary Report by Jill Marathon Oil Well Name: KENAI BELUGA UNIT 41 -6 Qtr /Qtr, Block, Sec, Town, Range Field Name License # State /Province Country 006004N011W01 I KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.12 26.52 6.40 10/7/2005 Daily Operations Report Date: 1215/2005 Job Category: COMPLETION 24 Hr Summary Move in well testing equipment and spot same. Finished RU of flowback iron, choke manifold, sand buster, gas buster and lines. Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 06:00 18:00 12.00 RURD STIM AF Move in well testing equipment and spot same. Finished RU of flowback iron, choke manifold, sand buster, gas buster and lines. Report Date: 12/6/2005 Job Category: COMPLETION 24 Hr Summary Move in Coil Tubing Unit and equipment. Continue RU frac lines, chemical add unit, heat fluid. Finish RU of well testing lines and equipment. _ - - - Ops Trouble - Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 06:00 18:00 12.00 RURD STIM AF Move in Coil Tubing Unit and equipment. Continue RU frac lines, chemical add unit, heat fluid. Finish RU of well testing lines and equipment. Report Date: 12/7/2005 Job Category: COMPLETION 24 Hr Summary Finish RU CTU and equipment/lines. Perform complet location / equipment inspection and line walk out. RU Expro and perforated Module 1 perfs at 9627' - 9637'. Guns fired with 6300 psi on green line. Good indication of gun firing. _ -_ - Ops Trouble - - - - Start Time End Time Dur (hr) Ops Code - Activity Code Status Code Com 06:00 18:00 12.00 RURD STIM AF Finish RU CTU and equipment/lines. Perform complete location / equipment inspection and line walk out. RU Expro and perforated Module 1 perfs at 9627' - 9637'. Guns fired with 6300 psi on green line. Good indication of gun firing. Report Date: 12/8/2005 Job Category: COMPLETION 24 Hr Summary Hold PJSM. Frac Module 1. Job screened out with 70% of designed pumped. Flow 94 bbls back. Attempt to pump tubing volume without success. RU CTU. RIH with CT to 9647' CTM. CBU x 2. POOH with CT. RD CT and secure well for the night. Ops Trouble Start Time End Time Dur (hr) . Ops Code Activity Code - Status Code Com 06:00 07:00 1.00 INSPCT EQIP AF Arrive location. Inspect frac equipment and lines. Start up frac trucks. Check chemical tanks and lines. 07:00 07:30 0.50 SAFETY MTG AF Hold PJSM. Discuss weather effects on job (slips trips falls). Discuss frac tracing and firing line pressures. Emergency response procedures. 07:30 09:30 2.00 TEST EQIP AF Pressure test frac trucks and lines to 10,000 psi. Pressure test well testers lines and choke manifold to 4400 psi. Good tests. 09:30 09:45 0.25 PUMP WTR AF Open well. SITP = 60 psig (estimated BHP = 3517 psig) Perform injection test with bbls 6% KCL. ISIP = 3254 psig. FG = 0.876 psi /ft. (Total Load = 61 bbls) 09:45 10:15 0.50 PUMP FRAC AF Frac mod 1 perfs (9627 -9637' RKB) w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 6100 psi. Ramp 1.0 - 8.0 ppa. Screened out perforations with 45 bbls flush pumped and 8 ppg on perfs (39 bbls short) Placed 17471 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand) or 70% of design. Tot Load = 178 bbls). Tagged w/ ProTechnics CFT 2500 chemical tracer, field tracer AUM 01, and SC-46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 239 bbls) (Strap chemical tanks post frac) 10:15 12:30 2.25 FLOW BACK AF Open well to flowback tank and attempt to flowback tubing volume of 84 bbls. Well flowing and gaining strength then tapered off to light flow. Unloading flex and frac sand. Flowback total of 94 bbls. 12:30 15:00 2.50 PUMP FRAC AF Attempt to pump tubing volume back into module 1 perfs. Pump total of 49 bbls and perfs screened out. Open well back up to flow and call for CTU crew. Monitor well flow. Flowed back total of 45 bbls. Well slugging with very little fluid rate 4 -6 BPH. 15:00 17:00 2.00 PUMP FRAC AF CTU crew on location. Attempt to pump tubing volume into mod 1 perfs. Pump total of 50 bbls into well over 4 pump cycles. Perfs continue to screenout. SD and clean up frac equipment. 17:00 19:30 2.50 RURD COIL AF RU Coil Tubing Unit. Test coil and BOP body to 6000 psi. Test rams 200/4500 psi. 19:30 00:15 4.75 RUNPUL COIL AF Open well and RIH with Coil Tubing pumping 6% KCL at 1.5 bpm. Tag firm frac sand at 8460' CTM. Sand would not wash off at 1.5 bpm. Increase pump rate to 2 to 2.3 bpm and start washing sand. Wash sand from 8460' to 9647' CTM. Unable to wash further. 00:15 01:10 0.92 CIRC CFLD AF CBU x 2. 01:10 02:30 1.33 RUNPUL COIL AF POOH with CT. www.peloton.com Page 2/6 Report Printed: 8/3/2011 /lA /J Operations Summary Report by Jo Marathon Oil Well Name: KENAI BELUGA UNIT 41 -6 Qtr /Qtr, Block, Sec, Town, Range Field Name License # State /Province Country 006004N011W01 I KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.12 26.52 6.40 10/7/2005 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 02:30 03:30 1.00 RURD COIL AF RD CT and secure well for the night. Report Date: 12/9/2005 Job Category: COMPLETION 24 Hr Summary Frac treated modules 2 through 15. RD frac lines /equip. RU CTU. RIH and broke 9 fo 14 flappers. Started to jet well in with nitrogen. Ops Trouble - Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 06:00 07:00 1.00 INSPCT EQIP AF Arrive location. Inspect frac equipment. Start trucks and warm up same. Gel up fluid. 07:00 07:30 0.50 SAFETY MTG AF Hold PJSM. Discussed rain and icy conditions on slips trips and falls, high pressure frac ops, production alarms, emergency response actions. 07:30 08:00 0.50 TEST EQIP AF Pressure test frac trucks and lines to 10000 psig. Monitor lines, no leaks, good test 08:00 08:30 0.50 PUMP FRAC AF Perforate and Frac mod 2 perfs from 9549 - 9559' w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 5600 psi. Ramp 2.0 - 8.0 ppa. Place 23393 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 238 bbl. Tagged w/ ProTechnics CFT 2400 chemical tracer and Sc -46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 477 bbls) (Strap all chem tanks post frac) 08:30 09:00 0.50 PUMP FRAC AF Perforate and Frac mod 3 perfs from 9280 - 9290' w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 6500 psi. Ramp 2.0 - 8.0 ppa. Place 22378 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 208 bbl. Tagged w/ ProTechnics CFT 2200 chemical tracer and Sc-46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 685 bbls) (Strap all chem tanks post frac) 09:00 10:30 1.50 PUMP FRAC TA MDSM Perforate mod 4 perfs from 9239 - 9249' Attempt to establish injection into perfs without success, max TP = 9900 psi. (Good indications of perf guns firing on both firing line and tree movement. Not able to pump in indicates flapper also isolating mod 4 from mod 3. Slight pressure communication between tubing and dead string also indicates some holes in pipe. Possible hole size issue with some sand still across perfs ? ? ?) Attempt 3 flowback and pump in cycles without success.(Total load = 10 bbls) (cumm. load = 695 bbls) Discuss options with Houston. Decied to move on to mod 5. 10:30 11:00 0.50 PUMP FRAC AF Perforate and Frac mod 5 perfs from 9020 - 9030' w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 5200 psi. Ramp 2.0 - 8.0 ppa. Place 22022 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 206 bbl. Tagged w/ ProTechnics CFT 2100 chemical tracer and Sc-46 and Ir -192 RA markers in pad and slung volumes, respectively. (cumm. load = 901 bbls) (Strap all chem tanks post frac) 11:00 11:30 0.50 PUMP FRAC AF Perforate and Frac mod 6 perfs from 8877 - 8887' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4540 psi. Ramp 2.0 - 8.0 ppa. Place 21404 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 206 bbl. Tagged w/ ProTechnics CFT 2000 chemical tracer and Sc-46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1107 bbls) (Strap all chem tanks post frac) 11:30 12:00 0.50 PUMP FRAC AF Perforate and Frac mod 7 perfs from 8598 - 8608' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4460 psi. Ramp 1.0 - 8.0 ppa. Place 20090 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 219 bbl. Tagged w/ ProTechnics CFT 1900 chemical tracer and Sc-46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1326 bbls) (Strap all chem tanks post frac) 12:00 12:30 0.50 PUMP FRAC AF Perforate and Frac mod 8 perfs from 8550 - 8560' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 5005 psi. Ramp 2.0 - 8.0 ppa. Place 22618 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 205 bbl. Tagged w/ ProTechnics CFT 3000 chemical tracer and Sc-46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1531 bbls) (Strap all chem tanks post frac) www.peloton.com Page 3/6 Report Printed: 8/3/2011 /l it, /J Operations Summary Report by S Marathon Well Name: KENAI BELUGA UNIT 41 -6 Qtr /Qtr, Block, Sec, Town, Range Field Name License # State /Province Country 006004N011 W01 I KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.12 26.52 6.40 10/7/2005 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 12:30 13:00 0.50 PUMP FRAC AF Perforate and Frac mod 9 perfs from 8482 - 8492' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 5700 psi. Ramp 1.0 - 8.0 ppa. Place 21430 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 219 bbl. Tagged w/ ProTechnics CFT 1700 chemical tracer and Sc-46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1750 bbls) (Strap all chem tanks post frac) 13:00 13:30 0.50 PUMP FRAC AF Perforate and Frac mod 10 perfs from 8439 - 8449' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3780 psi. Ramp 1.0 - 8.0 ppa. Place 20413 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 218 bbl. Tagged w/ ProTechnics CFT 1600 chemical tracer and Sc -46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1968 bbls) (Strap all chem tanks post frac) 13:30 14:15 0.75 PUMP FRAC AF Perforate mod 11 perfs from 8393 - 8403' frac mod 11 & 12 w/ BJ Lightning_V_1600 wtr based system aT 15 BPM at max TP = 3800 psi. Ramp 1.0 - 8.0 ppa. Place 27588 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand) or 69% of design. Went to flush at 29 bbls into 8 ppg stage due to increasing surface and bottom hole pressures. Tot Load = 253 bbl. Tagged w/ ProTechnics CFT 1500 chemical tracer and Sc-46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. load = 2221 bbls) (Strap all chem tanks post frac) 14:15 14:30 0.25 PUMP FRAC AF Perforate module 12 perfs from 8325 - 8335'. Break perfs down with 20 bbls of BJ Lightning_V_1600 wtr based system. Max TP = 6259 psi. Broke back to injection pressure of 4000 psi at 15 bpm Total Toad = 20 bbls. Tagged with ProTechnics CFT 1400 chemical tracer and SC-46 RA marker. (cumm. load =2241 bbls) (strap all chem tanks post breakdown) 14:30 15:00 0.50 PUMP FRAC AF Perforate and Frac mod 13 perfs from 8281 - 8291' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4000 psi. Ramp 1.0 - 8.0 ppa. Place 20096 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 214 bbl. Tagged w/ ProTechnics CFT 1400 chemical tracer and Sc -46 and Ir -192 RA markers in pad and slurry volumes, respectively. (cumm. Toad = 2455 bbls) (Strap all chem tanks post frac) 15:00 15:30 0.50 PUMP FRAC AF Perforate mod 14 perfs from 8048 - 8058' frac mod 14 & 15 w/ BJ Lightning_V_1600 wtr based system aT 15 BPM at max TP = 5500 psi. Ramp 1.0 - 8.0 ppa. Place 36428 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand) Tot Load = 282 bbl. Tagged w/ ProTechnics CFT 1200 chemical tracer and Ir -192 RA marker in pad and slurry volumes. (cumm. load = 2737 bbls) (Strap all chem tanks post frac) 15:30 16:00 0.50 PUMP FRAC AF Perforate and Frac mod 15 perfs from 7991 - 8001' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3850 psi. Ramp 2.0 - 8.0 ppa. Place Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 209 bbl. Tagged w/ ProTechnics CFT 1100 chemical tracer and Sc -46 RA markers in pad and slurry volumes. (cumm. load = 2946 bbls) (Strap all chem tanks post frac) 16:00 18:00 2.00 RURD STIM AF Hold break down and clean up meeting. RD and clean up frac lines, trucks, and equipment 18:00 19:00 1.00 RURD COIL AF Hold PJSM. RU CTU. Test injector head 200/4500 19:00 22:00 3.00 RUNPUL COIL AF RIH with CT. Broke flappers on modules 15, 13, 12, 11, 10, 9, 5, 4 at 8014, 8303, 8348, 8417, 8463, 8506, 9045, and 9264, respectively. RIH to PBTD of 9654' CTM. 22:00 22:45 0.75 CIRC CFLD AF CBU until returns good and clean. 22:45 23:45 1.00 RUNPUL COIL AF POOH and work through each flappers not found. Found module 2 flapper at 9575, Did not find flappers for module 3 at 9305, module 6 at 8902, module 7 at 8622, module 8 at 8575, and module 14 at 8071'. 23:45 00:30 0.75 RUNPUL COIL AF RIH with CT with 500 scfm Nitrogen and .75 bpm fluid to 9650' CTM 00:30 01:45 1.25 JET N2 AF Jet well in from below module 1 perforations with 500 scfm and no fluid rate. Start taking water samples as 0100 hrs. POOH to above top perforation at 7950' EPT test indicates fluid flow from module 1. Well appears to be flowing. 01:45 02:30 0.75 RUNPUL COIL AF Shutdown nitrogen and POOH with CT. 02:30 03:15 0.75 FLOW CHEK AF Monitor well for continuous flow. Well loading up with FTP down to 65 psi. www.peloton.com Page 4/6 Report Printed: 8/3/2011 JJ Operations Summary Report by J Marathon Oil Well Name: KENAI BELUGA UNIT 41 -6 Qtr /Qtr, Block, Sec, Town, Range Field Name I License # State /Province Country 006004N011 W01 KENAI ALASKA USA Casing Flange Elevation (m) 'Ground Elevation (m) KB- Casing Flange Distance (m) KB -Ground Distance (m) Spud Date Rig Release Date 0.001 20.12 26.52 6.40 10/7/2005 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 03:15 06:00 2.75 JET N2 AF RIH with CT to 7950 with nitrigen at 500 scfm. Continue in hole to 9640' CTM and jet below perfs with 500 scfm. FTP = 350 psi Well unloading fluid at rate of 1872 bpd. Cum load recovery = 255 bbls or 8.7% of total frac load volume of 2946 bbls. Report Date: 12/10/2005 Job Category: COMPLETION 24 Hr Summary Jetted well with 500 scfm nitrogen from below perfs. POOH with CT and shutdown nitrogen above perfs. RD CTU and monitored well flow. Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 06:00 07:30 1.50 JET N2 AF Continue to jet well in from below module 1 perforations. Well consistantly unloading 30 -32 bbl every 30 min with TP = 315 psi 07:30 08:00 0.50 JET N2 AF Start POOH to above perforations while jetting with 500 scfm of nitrogen 08:00 09:00 1.00 RUNPUL COIL AF Shutdown nitrogen above perfs and monitor well response while POOH with CT. EPT field chemical still present in returns indicating fluid flow from module 1. Continue POOH with CT. 09:00 10:00 1.00 RURD COIL AF RD CT injector head and secure CT equipment. Send crews home for rest while well testers monitor well for flow. 10:00 06:00 20.00 FLOW TEST AF Monitor well for flow. FTP = 50 psig. Gradually increase to 195 psig. Routed well through both flowlines and FTP decreased to 115 psig. Continued to monitor flow. FTP gradually increase to 140 psig. Water rate over entire monintoring period decreased form 2179 bpd to +/- 300 bpd. Put well back though one flowline and prepare to place in test separator. (Cumm fluid recovery = 887.5 or 30% of frac load) Report Date: 12/11/2005 Job Category: COMPLETION 24 Hr Summary Flow tested well - Well making 1.4 mmcfd, 170 bwpd, 230 psig FTP, estimated 670 psig BHP. Ops Trouble Start Time - - End Time , Dur (hr) Ops Code Activity Code Status - Code Com - - 06:00 06:00 24.00 FLOW TEST AF Monitor well flow and test same. Well making 1.4 mmcfd, 170 bwpd, 230 psig FTP, estimated 670 psig BHP. Making practically no solids (prop, flex, or fines) Cumm fluid recovery = 1112 bbls or 38% og total frasc load of 2946 bbls. Report Date: 12/12/2005 Job Category: COMPLETION 24 Hr Summary Flow tested well. FTP = 245 psig, Est. BHP = 663 psig, Gas = 1.44 mmcfd, Water = 132 bpd. • - Ops Trouble - StartTune ; - -, End Time - Dur(hr) - ,, • - Ops Code , Activity Code Status - Code - - - Com - - - 06:00 06:00 24.00 FLOW TEST AF Flow tested well. FTP = 245 psig, Est. BHP = 663 psig, Gas = 1.44 mmcfd, Water = 132 bpd. Cumm fluid recovery = 1282 bbls or 43.5% frac load. Report Date: 12/13/2005 Job Category: COMPLETION 24 Hr Summary Flow tested well. FTP = 240 psig, Est. BHP = 663 psig, Gas = 1.44 mmcfd, Water = 133 bpd. Shut in well for pressure build up. Opened up well and continued flow testing. Ops Trouble StartTime End Time Dur (hr) Ops Code - Activity Code - - - Status Code • Com 06:00 08:45 2.75 FLOW TEST AF Flow tested well. FTP = 240 psig, Est. BHP = 663 psig, Gas = 1.44 mmcfd, Water = 133 bpd. Cumm recovery = 1300 bbls or 44% of frac load. 08:45 15:00 6.25 TEST PBU AF Shut well in to confirm BHP estimates. Initial FTP = 245 psig BHP = 663 psig. Final SITP = 1980 psig BHP = 2103 psig. BHP broke over at 2126 psig indicating possible cross flow. 15:00 06:00 15.00 FLOW TEST AF Opened well back to flow test. As of 0500 hrs 12/13/05 FTP = 235 psig, Est. BHP = 671 psig, gas = 1.48 mmcfd, water = 196 bpd. Cumm fluid recovery = 1425 bbls or 48.4% of frac load (2946 bbls) Report Date: 12/14/2005 Job Category: COMPLETION 24 Hr Summary Continued flow testing well - 1.56 mmcfd, FTP = 255 psig, Est. BHP = 678 psig, bwpd = 196. Ops Trouble Start Time . End Time Dur (hr) Ops Code Activity Code Status Code Com 06:00 06:00 24.00 FLOW TEST AF Continued to flow test well. As of 0600 hrs 12 -14 -05 well making 1.56 mmcfd, FTP = 255 psig, Est. BHP = 678 psig, bwpd = 196. Report Date: 12/15/2005 Job Category: COMPLETION 24 Hr Summary Continued to flow test well - 1.62 mmcfd, FTP = 265 psig, Est. BHP = 673 psig, bwpd = 172. www.peloton.com Page 5/6 Report Printed: 8/3/2011 • Operations Summary Report by J* Marathon Coil Well Name: KENAI BELUGA UNIT 41 -6 Qtr /Qtr, Block, Sec, Town, Range Field Name License # State/Province Country 006004N011 W01 KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.12 26.52 6.40 10/7/2005 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code - Com 06:00 06:00 24.00 FLOW TEST AF Continued to flow test well. As of 0600 hrs 12 -15 -05 well making 1.62 mmcfd, FTP = 265 psig, Est. BHP = 673 psig, bwpd = 172. Report Date: 12/16/2005 Job Category: COMPLETION 24 Hr Summary Continued to flow test well - 1.62 mmcfd, FTP = 250 psig, Est. BHP = 653 psig, bwpd = 174. - -- _ - Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 06:00 06:00 24.00 FLOW TEST AF Continued to flow test well. As of 0600 hrs 12 -16 -05 well making 1.62 mmcfd, FTP = 250 psig, Est. BHP = 653 psig, bwpd = 174. Report Date: 12/17/2005 Job Category: COMPLETION 24 Hr Summary Flow tested well - 1.63 mmcfd, FTP = 245 psig, Est. BHP = 637 psig, bwpd = 100 -200. Released well testers at 0930 hrs 12- 16 -05. RD testing equipment and tumed well over to production. Ops Trouble - Start Time End Time Dur (hr) - Ops Code Activity Code Status Code - Com - 06:00 09:30 3.50 FLOW TEST AF Continued to flow test well. Final test report data as of 0915 hrs 12 -16 -05 well making 1.63 mmcfd, FTP = 245 psig, Est. BHP = 637 psig, bwpd = 100- 200. 09:30 18:00 8.50 RURD OTHR AF Release well testers and RD testing lines and equipment. Final post frac well test report Report Date: 1/8/2006 Job Category: COMPLETION 24 Hr Summary RU slickline and ran 2.35 "" swedge. Ran Spectral gamma ray log. Ran PLT. RD slickline and secured well. Ops - Trouble Start Time - End Time -- Dur (hr) Ops Code Activity Code Status Code Com 07:00 07:30 0.50 SAFETY MTG AF Arrive KGF and sign in. Obtain work permit and Hold PJSM 07:30 08:30 1.00 RURD SLIK AF RU slickline unit and make up tool string with 2.35 "" swedge 08:30 09:30 1.00 RUNPUL SLIK AF RIH and tagged fill at 9530' SLM (9551' RKB) Bottom two modules covered up with fill. Broke excape module flappers at 8071', 8575', 8902', and 9045' RKB in modules 14, 8, 6, & 5. (Module 5 flapper was broken during CT post frac cleanout with very good indication with 4000# down weight ? ?) 09:30 10:00 0.50 RUNPUL SLIK AF POOH with swedge. 10:00 10:30 0.50 PULD EQIP AF Break of swedge and Make up ProTechnics Spectral Gamma Ray tool (SGR). 10:30 13:00 2.50 LOG CSG AF RIH and Make down pass with SGR from 7600' to 9400' SLM. POOH and make up pass from 9400' to 7600' SLM. POOH with SGR. 13:00 14:30 1.50 RURD OTHR AF RD SGR and download and ensure good data. Good data obtained. RU ProTechnics PLT and QC same. 14:30 19:00 4.50 LOG CSG AF RIH with PLT. Set down at 8390 SLM. Worked through same with well shut in. Continue RIH to 9350' SLM. Opened well back up and stabilized flow. Make up and down pass from 9350 to 7600' at 60 fpm. Make up and down pass at 90 fpm. Make up and down pass at 120 fpm 19:00 19:45 0.75 RUNPUL SLIK AF POOH with PLT tools 19:45 21:00 1.25 RURD SLIK AF LD PLT and download data. Secure well, tum well over to production, leaave location, turn in work permit and sign out. www.peloton.com Page 6/6 Report Printed: 8/3/2011 ~~~. ~.~~ DATA SUBMITTAL COMPLIANCE REPORT 2/6/2008 Permit to Drill 2051410 Well Name/No. KENAI BELUGA UNIT 41-6 Operator MARATHON OIL CO API No. 50-133-20555-00-00 MD 9733 TVD 7837 Completion Date 12/8/2005 Completion Status 1-GAS Current Status 1-GAS UIC N REQUIRED INFORMATION Mud Log No Samples No Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: SP/GR-IEL-Density/Neutron-Sonic-Single Arm Caliper. MFTs Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Type Med/Frmt Number Name Scale Media No __ _ . - -- - Well Cores/Samples Information: Name ADDITIONAL INFORMATION Well Cored? Y r~ Chips Received? '~t`7-N~--~ Analysis ~L.~L.-~- Received? Comments: ~ .S Compliance Reviewed By: Interval Stan. Stop ~'~. ~ ~ ~~~ .°~s (data taken from Logs Portion of Master Well Data Maint Interval OH / Start Stop CH Received Comments A Directional Survey Log is required to be submitted. This record automatically created from Permit to Drill i Module on: 9/30/2005. Sample Set Sent Received Number Comments Daily History Received? _ Y // N Formation Tops ('/ N Date: u L • M Marathon MARATHON oil Company February 22, 2006 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, Alaska 99501 Reference: Completion Report 10-407 for Permit #205-141 Field: Kenai Gas Field /Beluga /Tyonek Well: KBU 41-6 Dear Mr. Aubert: Alaska Business Unit Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 ~E~~ FEe 2 ~ zaos Alaska Oi9 ~ l~a~ f;~s:".~ ~ , ~ ,i~siiYl~ ,r~ct'it~CagB Enclosed please find the Well Completion Report with associated attachments for Kenai Beluga Unit Well No. 41-6. 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. If additional information is required, please contact me at 907-529-0524 or 713-296-2730 or by email, JRThompson@MarathonOil.com. Sincerely, G~~' James R. Thompson Senior Completions Engineer Attachments: Directional Survey Wellbore Diagram Well Operations Summary STATE OF ALASKA ~~~c'` ~~ ALAS IL AND GAS CONSERVATION COMMI N G 1® WELL COMPLETI OR RECOMPLETION RORT AN OG ~~ 1a. Well Status: Oil Gas ~ Plugged Abandoned zoAAC 2s.1os GINJ^ WINJ^ WDSPL^ No. of Completions Suspended WAG^ 2oAAC 2s.11o 1 Other 1b. Well Class: Developm 8~ d ~s Expl~or„atory ^ Service [~ ~tt~til'~$&st~rirrl 2. Operator Name: Marathon Oil Company 5. Date Comp., Susp., or Aband.: 12/8/2005 12. Permit to Drill Numb IiC arage 205-141 3. Address: P. O. Box 3128, Houston, TX 77253 6. Date Spudded: October 7, 2005 13. API Number: 50-133-20555-00 4a. Location of Well (Governmental Section): Surface: 41' FSL, 994' FEL Sec 6, T4N, R 11 W, S.M. 7. Date TD Reached: October 26, 2005 14. Well Name and Number: Kenai Beluga Unit 41-6 Top of Productive Horizon: 4532' FSL, 720' FEL, Sec 6, T4N, R11 W, S.M. 8. KB Elevation (ft): 87' RKB 15. Field/Pool(s): Kenai Gas Field Total Depth: 4724' FSL, 707' FEL, Sec 6, T4N, R11 W, S.M. 9. Plug Back Depth(MD+ND): 9684' / 7788' Beluga/Upper Tyonek Pool 4b. Location of Well (State Base Plane Coordinates): Surface: x- 274,916.45 y- 2,362,054.63 Zone- 4 10. Total Depth (MD + ND): 9733' / 7837' 16. Property Designation: A-028142 TPI: x- 275,275.78 y- 2,366,539.79 Zone- 4 Total Depth: x- 275,292.31 y- 2,366,731.29 Zone- 4 11. Depth Where SSSV Set: N/A 17. Land Use Permit: 18. Directional Survey: Yes Q No 19. Water Depth, if Offshore: N/A feet MSL 20. Thickness of Permafrost: NA 21. Logs Run: SP/GR-IEL-Density/Neutron-Sonic-Single Arm Caliper. MFTs 22. CASING, LINER AND CEMENTING RECORD CASING WT. PER GRADE SETTING DEPTH MD SETTING DEPTH ND HOLE SIZE CEMENTING RECORD AMOUNT FT TOP BOTTOM TOP BOTTOM PULLED 20" 131 X-52 0 137' 0 137' Driven NA NA 13 3/8 68# L-80 0 1862' 0 1648' 16" 600 sks Class G NA 9 5/8" 40# L-80 0 7214' 0 5341' 12 1/4" 723 sks Class G NA 3 1/2" 9.3# L-80 0 9722' 0 7826' 8 1/2" 1160 sks Class G 85,000 23. Perforations open to Production (MD + ND 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 v2" 9722' N/A Module 1:9627-9637' 7731-7741 Module 2: 9549-9559' 7653-7663 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Module 3: 9280-9290' 7384-7394 DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Module 4: 9239-9249' 7343-7353 Module 1:9627-9637' Lightning, 24,696 Ibs prop, 20/40 Ottawa & Flex Sand Module 5: 9020-9030' 7124-7134 Module 2: 9549-9559' Lightning, 23,393 Ibs prop, 20/40 Ottawa & Flex Sand Module 6: 8877-8887 6981-6991 Module 3: 9280-9290' Lightning, 22,378 Ibs prop, 20/40 Ottawa 8 Flex Sand Module 7: 8598-8608 6702-6712 Module 4: 9239-9249' Perforated but could not treat Module 8: 8550-8560 6654-6664 Module 5: 9020-9030' Lightning, 22,020 Ibs prop, 20/40 Ottawa & Flex Sand Module 9: 8482-8492 6586-6596 Module 6: 8877-8887 Lightning, 21,404 Ibs prop, 20/40 Ottawa & Flex Sand Continued on back Continued on back 26. PRODUCTION TEST Date First Production: December 10, 2005 Method of Operation (Flowing, gas lift, etc.): FIOWIn Date of Test: 12/16/2005 Hours Tested: 24 Production for Test Period Oil-Bbf: NA Gas-MCF: 1627 Water-Bbl: 272 Choke Size: 128/64 Gas-Oil Ratio: NA Flow Tubing Press. 245 Casing Press: 0 Calculated 24-Hour Rate ~ Oil-Bbl: Na Gas-MCF: 1627 Water-Bbl: 272 Oil Gravity -API (corr): NA 27. CORE DATA Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water (attach separate sheet, if necessary) ~ , , ~~ Submit core chips; if none, state "none". ~ ,,~~,; ;~~ ~ ,; Lithology -interbedded gas charged sandstone, shale and coal. Core chips submitted. # ~. f 2 ~ ry'6ry^ JC ei& F ° 'Llj i 4 ~ 3 k -..........M x KBU 41-6 Alaska Cmpl_10-407.x19 Form 10-407 Revised 12/2003 2/23/2006 2:47 PM CONTINUED ON REVERSE SSIOR 28. GEOLOGIC MARKERS 29. FORMATION TESTS NAME MD TVD Include and briefly summari results. List intervals tested, and attach detailed supporting data as n ary. If no tests were conducted, state "None". Zone Top MD Top TVD Pressure Middle Beluga 7264 5387 Tyonek 9628 7732 n/a Tyonek 9202 7306 Tyonek 9550 7654 n/a Tyonek 9280 7384 3079 Tyonek 9240 7344 1955 Lower Beluga 9020 7124 3770 Lower Beluga 8877 6981 3551 Lower Beluga 8598 6702 2260 Lower Beluga 8550 6654 2840 Lower Beluga 8480 6584 2806 Lower Beluga 8438 6542 3034 Lower Beluga 8392 6496 na Lower Beluga 8324 6428 2964 Lower Beluga 8278 6382 na Lower Beluga 8046 6151 2758 Middle Beluga 7990 6096 2708 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: 2/22!2006 INSTRUCTIONS General T Is form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this fore 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: If 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: 8598-8608 Lightning, 20,090 Ibs prop, 20/40 Ottawa & Flex Sand Module 8: 8550-8560 Lightning, 22,618 Ibs prop, 20/40 Ottawa & Flex Sand Module 9: 8482-8492 Lightning, 21,430 Ibs prop, 20/40 Ottawa & Flex Sand Module 10: 8439-8449 Lightning, 20,413 Ibs prop, 20/40 Ottawa 8~ Flex Sand Module 11:8393-8403 Lightning, 27,5881bs prop, 20/40 Ottawa & Flex Sand Module 12: 8325-8335 Perforated and borke down perforations only Module 13: 8281-8291 Lightning, 20,096 Ibs prop, 20/40 Ottawa & Flex Sand Module 14: 8048-8058 Lightning, 36,428 Ibs prop, 20!40 Ottawa & Flex Sand Module 15: 7991-8001 Lightning, 23,564 Ibs prop, 20/40 Ottawa & Flex Sand 23. Perforations open to Production (MD + TVD of Top and Bottom Interval, Size and Number; if none, state "none"): MD RKB ND RKB Module 10: 8439-8449 6543-6553 Module 11:8393-8403 6497-6507 Module 12: 8325-8335 6429-6439 Module 13: 8281-8291 6385-6395 Module 14: 8048-8058 6153-6163 Module 15: 7991-8001 6097-6706 KBU 47-6 Alaska_Cmpl_10-407.x1s 2/23/2006 8:18 AM MARATHON Oil Com an Slot #KBU41-6 Pad 41-7, M p y, MARATHON Kenai Gas Field,Cook Inlet, Alaska (Kenai Penninsulaj SURVEY LISTING Page 1 Wellbore: KBU41-6 Wellpath: MWD <0-9733> Date Printed: 31-Oct-2005 BAKER IW6HE5 INTEQ Slot Name Grid Northin Grid Easlin Latitude Lon itude North East 4 1 77 4 Installation Name Eastina Northing Coord Svstem Name ___. Alignment Pad 41-7 270916.0101 2362063.9749 AKA 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 ( 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.95 Feet on azimuth 3.51 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~ MARATHON Oil Com an Slot #KBU41-6 M p Y~ Pad 41-7, MARATHON Kenai Gas Field,Cook Inlet, Alaska (Kenai Penninsula) SURVEY LISTING Page 2 Wellbore: KBU41-6 Wellpath: MWD <0-9733> Date Printed: 31-Oct-2005 BAKER ^ 1WliNES INTEQ Well ath Gr id Re ort MD[tt] Inc[deg] Azi[deg] ND[ft] North[ft] East[ft] Dogleg de /100ft Vertical Section ft Easting Northing 4 4 198.00 0.20 206.00 198.00 0.33S 0.19E 0.59 -0.32 274916.63 2362054.30 4 4 410.00 1.70 6.80 409.98 1.98N 0.50E 1.50 2.01 274916.98 2362056.60 4 7 7.1 4 1 592.00 5.80 5.70 591.58 13.41 N 0.91E 2.90 13.44 274917.61 2362068.02 1 807.00 16.40 7.70 802.61 52.55N 6.58E 6.04 52.85 274924.02 2362107.04 4. 1 1 7 997.00 25.70 2.70 979.84 120.23N 11.81E 5.20 120.73 274930.53 2362174.61 1 1186.00 32.90 4.60 1143.35 214.59N 17.25E 1.91 215.25 274937.75 2362268.85 4 7 1 4 7 4 1375.00 36.80 2.30 1298.18 322.69N 24.04E 1.79 323.56 274946.60 2362376.79 4 4 . 1564.00 42.20 3.40 1443.58 443.25N 28.09E 3.15 444.14 274952.93 2362497.25 1754.00 48.80 6.20 1576.84 578.08N 38.94E 3.72 579.38 274966.32 2362631.85 2004.00 46.30 5.90 1743.70 763.06N 59.05E 1.27 765.24 274989.94 2362816.41 2190.00 49.10 0.90 1873.21 896.12N 68.90E 8.01 898.65 275002.30 2362949.24 2380.00 50.80 359.90 1992.66 1043.86N 68.80E 0.95 1046.11 275005.00 2363096.95 2570.00 49.20 0.30 2116.30 1188.11 N 69.05E 0.97 1190.10 275007.98 2363241.16 2758.00 49.00 4.30 2238.32 1331.04N 73.18E 2.74. 1333.02 275014.81 2363383.98 3138.00 50.10 5.30 2481.81 1621.72N 97.75E 0.29 1624.66 275044.89 2363674.14 3517.00 50.30 3.40 2724.59 1911.83N 120.33E 0.17 1915.61 275072.95 2363963.75 3895.00 49.10 4.70 2968.90 2199.57N 140.17E 0.47 2204.03 275098.23 2364251.06 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig ( 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.95 Feet on azimuth 3.51 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated 1 MARATHON Oil Company,Slot #KBU41-6 3 Pad 41-7, Mt MARAiHflN Kenai Gas Field,Cook Inlet, Alaska ~ (Kenai Penninsula) SURVEY LISTING Page 3 Wellbore: KBU41-6 Wellpath: MWD <0-9733> Date Printed: 31-Oct-2005 BAKER ~ MUG~FIES INTEQ Well ath Gr id Re ort MD[tt] Inc[deg] Azi[degJ ND[tt] North[ft] East[ft] Dogleg d /100ft Vertical Section ft Easting Northing 1 1 4276.00 48.90 3.40 3220.69 2484.55N 163.35E 1.10 2489.89 275126.80 2364535.54 7 7 7 1 7 7 1 7. 4653.00 48.80 1.00 3468.94 2768.OON 174.69E 0.17 2773.51 275143.51 2364818.71 17 . 4 5031.00 49.20 1.60 3713.92 3055.73N 183.58E 0.53 3061.24 275157.85 2365106.20 1 1 71 5409.00 48.70 1.80 3960.49 3342.07N 193.08E 0.49 3347.62 275172.76 2365392.30 7 1 4 71 5787.00 47.50 3.30 4213.24 3622.89N 204.58E 0.64 3628.62 275189.58 2365672.83 7 74 7 4 1 1 72 1 1 .4 5977.00 45.60 3.30 4343.42 3761.O6N 212.31E 1.59 3767.00 275199.92 2365810.82 1 4 7 6167.00 43.70 4.20 4477.88 3895.02N 220.76E 1.68 3901.24 275210.91 2365944.60 4 4. 6358.00 40.70 5.10 4619.29 4022.90N 231.83E 2.20 4029.55 275224.40 2366072.24 6548.00 37.30 5.80 4767.02 4141.84N 242.62E 1.76 4148.93 275237.44 2366190.95 6736.00 34.50 5.60 4919.10 4251.85N 253.02E 2.27 4259.37 275249.91 2366300.74 6925.00 29.50 5.70 5078.87 4352.03N 264.72E 3.40 4360.07 275263.51 2366400.67 7113.00 23.50 2.30 5247.28 4435.02N 272.24E 3.02 4443.37 275272.60 2366483.50 7302.00 19.40 2.70 5422.99 4504.47N 274.99E 2.50 4512.85 275276.66 2366552.88 7490.00 13.20 5.70 5603.44 4556.84N 276.80E 3.55 4565.24 275279.46 2366605.21 7678.00 10.00 10.80 5787.90 4592.56N 282.33E 0.32 4601.23 275285.66 2366640.82 7867.00 10.00 10.50 5973.97 4625.17N 288.24E 0.39 4634.14 275292.19 2366673.31 8054.00 6.10 7.90 6159.08 4651.08N 292.70E 2.66 4660.27 275297.14 2366699.12 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig ( 87.Ott above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.95 Feet on azimuth 3.51 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON O[I Company,Slot #KBU41-6 1 M Pad 41-7, MARATIit3td Kenai Gas Field,Cook Inlet, Alaska (Kenai Penninsula) SURVEY G Page 4 Wellbore: KBU41-6 Wellpath: MWD <0-9733> Date Printed: 31-Oct-2005 BAKER • iIKl6EIE5 INTEQ Well ath Gr id Re ort MD[ft] Inc[deg] Azi[deg] TVD[ft] North[ft] East[ft] Dogleg d /100ft Vertical Section ft Easting Northing 17 7 1 8244.00 2.80 358.70 6348.51 4665.30N 293.89E 1.15 4674.54 275298.60 2366713.33 7 8436.00 2.80 358.30 6540.28 4674.66N 293.31E 0.32 4683.85 275298.20 2366722.69 1 7 7 8686.00 0.40 353.50 6790.13 4682.44N 292.09E 1.04 4691.54 275297.13 2366730.50 4 7 7 9064.00 0.30 267.00 7168.13 4683.82N 291.19E 0.19 4692.86 275296.26 2366731.89 7 9441.00 0.20 265.40 7545.12 4683.89N 289.10E 0.24 4692.81 275294.17 2366732.00 7 7 4 9733.00 0.40 259.00 7837.11 4683.15N 287.26E 0.00 4691.95 275292.31 2366731.29 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig ( 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.95 Feet on azimuth 3.51 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON Oil Company,Slot #KBU41-6 Pad 41-7, M Kenai Gas Field Cook Inlet Alaska MARATHON (Kenai Penninsula) SURVEY LISi7NG Page 5 Wellbore: KBU41-6 Wellpath: MWD <0-9733> Date Printed: 31-Oct-2005 BA1 EAR • NIJGNES INTEQ Comments 9733.00 7837.11 4683.15N 287.26E Pro'ection toTD Hole Sections Diameter Start Start Start Start End End End Start Wellbore 16.000 137.00 137.00 0.16S 0.12E 1862.00 1647.11 659.66N 47.34E KBU41-6 4 1 447 N Casin s Name Top Top Top Top Shoe Shoe Shce Shce Wellbore 7 1 1 13 3/8" Surface 0.00 0.00 O.OON 0.00E 1862.00 1647.11 659.66N 47.34E KBU41-6 9 5/8" Intermediat casin 0.00 0.00 O.OON 0.00E 7214.00 5340.56 4473.70N 273.54E KBU41-6 7 4 1 7. All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig ( 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.95 Feet on azimuth 3.51 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated s= o -aoo N n o a~ c~ !q 400 800 lzoo 1600 zooo 2400 2800 .-. .+ m 3200 w t w ~ 3600 D is V 4000 m m aaoo I'- N 4800 5200 5600 6000 6400 6800 7200 7600 8000 8400 ri.~ BAKER ^N~~ll~! THON Oil Comp y LOCatIOn: Cook Inlet, Alaska (Kenai Penninsula) $IOt: Slot #KBU41-s Field: Kenai Gas Field Well: KBU41-6 Installation: Pad 41-7 Wellbore: Ksua1-s 20" Conductor - 0.17 Inc, 137.00 Md, 137.00 ND, -0.15 VS MARATHQN Scale 1 cm = 200 ft East (feet) -> -400 -0 400 800 1 t t I 5200 3 1/2" Liner KBU41-6 480U KBU41-6 - TD -8/22/05 9 5/6-Intennediate Casing 44Q0 4000 13 3/8" Surface casing - 48.64 Inc, 1862.00 Md, 1647.11 ND, 661.32 VS 3600 3200 2800 ^ Z 2400 ~ S .-. 2000 W v 1600 1200 800 13 3/6" Surface Casing 400 ~ n w m 20" conductor Q 9 5/8" Intermediate casing - 21.50 Inc, 7214.00 Md, 5340.56 ND, 4482.06 VS ~ 3 KBU41-6 - T/Mid Beluga - 9/16/05 11 -400 0 0 WELL DATA ID Slot ~ .Well Wellbore well ap th P1a)900 a~eosa~ Slot Nla)Wt8 sa sKSUa,_e KBW1.8 «eua,.e KBW1-6 ~a,u,c ve.z mmv+ Keua i-s v<~~z rested by : tanner Date plotted : 31-Oct-2005 lot reference is KB1141-6. Ref wellpaih is MW D <p-9733>. Coordinates are in feel reference Slol #KBU41-6. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: 3 1/2" Liner - 0.40 Inc, 9733.00 Md, 7837.11 ND, 4691.95 VS Rig Datum to mean sea level: 87.00 fl. Plot Narth is ali ned to TRUE North. KBU4' KBU41-6 - TD - 8/22/05 -400 0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 Scale 1 cm = 200 ft Vertical Section (feet) -> Azimuth 3.49 with reference 0.00 N, 0.00 E from Slot #KBU41-6 API: 50-133-20555-00 RT-GL: 21.00' RT-TH F: 21.70' 41' FSL, 994' FEL, Sec. 6, T4N, R11W, S.M. Tree cxn = 4-3/4" Otis ~ TOC (est.) - 500' above 9-5/8" shoe - Ceramic flapper valves below each module as follows: Module 1 - NA Module 2 - 9575' Module 3 - 9305' Module 4 - 9264' Module 5 - 9045' Module 6 - 8902' Module 7 - 8622' Module 8 - 8575' Module 9 - 8506' Module 10 -8463' Module 11 -8417' Module 12 -8348' Module 13 -8304' Module 14 -8071' Module 15 -8014' KBU 41-6 • M MARATNOM Drive Pipe: 20", 131 ppf, X-52 to 137 ' Surface Casing: 13-3/8", 68 ppf, L-80, BTC @ 1862' Cmt w/ 275 bbls. of Type 1 at 12.0 PP9• Int. Casing: 9-5/8", 40 ppf, L-80, BTC @ 7214' Cmt w/ 177.5 bbl of class G lead @ 12.5 ppg and 78.4 bbls Class G tail @ 13.5 PP9 Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 9722' Cmt w/ 1160 sx of class G at 15.8 ppg - 15 Excape modules placed - Green control line fired module 1 - Yellow control line fired modules 2 thru 8 - Red contol line Fred modules 9 thru 15 -Ceramic flapper valves below each module except for module 1 Module 1 - 9627 -9637' (Tyonek) Module 2 - 9549 - 9559' (Tyonek) Module 3 - 9280 - 9290' (Tyonek) Module 4 - 9239 - 9249' (Tyonek) Module 5 - 9020 - 9030' (Beluga) Module 6 - 8877 - 8887' (Beluga) Module 7 - 8598 - 8608' (Beluga) Module 8 - 8550 - 8560' (Beluga) Module 9 - 8482 - 8492' (Beluga) Module 10 -8439 - 8449' (Beluga) Module 11 -8393 - 8403' (Beluga) Module 12 -8325 - 8335' (Beluga) Module 13 -8281 - 8291' (Beluga) Module 14 -8048 - 8058' (Beluga) Module 15 -7991 - 8001' (Beluga) Well Name & Number: KBU 41-6 Lease: Kenai Gas Field County or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) See Above (TVD) Angle!Perfs Angle @ KOP and Depth BHP: BHT: Completion Fluid: 6% KCL Dated Completed: Prepared By: J. R. Thompson Last Revison Date: 12/2/2005 TD - 9733' PBTD - 9684' Marathon Oil Company Page 1 of 14 Operations Summary. Report. -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 Event Date I Event Sub Event Type --/-- Objective Hours Code Phase ' Report Date From - To Code ~ SideTrack- --/-- Description of Operations 10/4/2005 Event ORIGINAL DRILLING --/-- Exploitation Gas 10/5/2005 08:00 - 12:00. 4.00 RURD_ RIG_ MIRU OH --/-- PJSM; Load Out Generator,Boiler,Water Tank, Pump& Pit Units. Prep Carrier, Mud Boat And Substructure F/ Transport 12:00 - 00:00 12.00 RURD_ RIG_ MIRU PJSM; Spot Generator, Boiler,Water Tank, Pits, Pump Room, Sub, And Carrier. Raise Sub Align Pits And Pump Units. Install Trip Tank. Set Mech. Shop And Parts Trailers Set MI Unit, D/D, Co. Man And T/P Units. Set In Change Trailers. Set Fuel Tank& Derrick House. Prep Derrick And Raise. Install Dersser Sleeves& R/U Pump Lines. Pull Wires and Set Up Lights on pits. Un Load Trailers. 00:00 - 01:30 1.50 RURD_ RIG_ MIRU PJSM; R/U Service & Electrical Lines. R/U Stand Pipe, Cement Lines, Shock Hose, Set Cuttings Tank, Unload Trailers And VFD's. 01:30 - 03:30 2.00 RURD_ RIG_ MIRU PJSM; R/U W/ Crane- Outriggers, Carrier Landings, Stairs, Conex & Flow Line. (Suspend Crane Operations Due To Wind's Gusting To 40 MPH) 03:30 - 06:00 2.50 RURD_ RIG_ MIRU R/U Gas BusterLines, Cuttings Tank,Oil Dock And Accmulator Lines. 10/6/2005 06:00 - 06:00 24.00 RURD_ RIG_ MIRU OH --/-- PJSM, cont RU on KBU 41-6, spot /offload all remaining loads. Scope out mast, connect all attending lines. Install /test starting hd while rig up. Cont set /rig up slide, pipe racks, make plumbing /elect conn's. Begin take on water for spud mud. Slow going, high winds, crane delay. Move - 100% Rig up - 80% No acc / do time 10/7/2005 06:00 - 13:00 7.00 RURD_ RIG_ MIRU OH --/-- PJSM, complete rig up on KBU 41-6. 13:00 - 22:00 9.00 NUND BOPE SURDRL PJSM, nipple up diverter system, function all components. 22:00 - 23:30 1.50 TEST_ ROPE SURDRL PJSM, test diverter system, perform accumulator time /volume /press test. All tests successful. Witness waived by Mr Jim Regg AOGCC. 23:30 - 00:00 0.50 PULD_ BHA_ SURDRL PJSM, MU spud BHA, RIH same. 00:00 - 02:30 2.50 DRILL_ ROT_ SURDRL Tag /spud well at 43 ft, drill ahead 16" hole 43 - 196 ft. Rot 2.5 hrs, AST 0 hrs 02:30 - 03:00 0.50 CIRC_ MUD_ SURDRL Circ / recip pipe for BHA change. 03:00 - 05:00 2.00 PULD_ BHA_ SURDRL POH, MU dretnl BHA, surface test, RIH same. 05:00 - 06:00 1.00 REPAIR RIG_ SURDRL Repair hyd leak top drive. Glacier rig #1 accepted this date 10/7/05 - 1300 hrs 10/8/2005 06:00 - 03:30 21.50 DRILL_ ROT_ SURDRL OH --/-- Cont drill ahead 16 "hole dretnl, 196 - 1862 ft (Csg pt) ART = 2.6 hrs, AST = 10.4 hrs No gain /loss, connections free Normal quantity /quality returns at shaker. 03:30 - 04:00 0.50 CIRC_ MUD_ SURDRL Circ / cond fluids in prep for wiper trip. 04:00 - 06:00 2.00 TRIP_ WIPR SURDRL PJSM, flow check, POH wiper trip to shoe. No drag /gain /loss, correct hole fill. No acc / do time. 10/9/2005 06:00 - 06:30 0.50 SERVIC RIG_ SURDRL OH --/-- Service rig 06:30 - 07:30 1.00 TRIP WIPR SURDRL PJSM, flow check, RIH 5" DP wiper trip. Precaution wash 60 ft, 10 ft fill. Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 went Date Event Hours Code Sub phase Report Date From - To Code 06:30 - 07:30 1.00 TRIP_ WIPR SURDRL 07:30 - 09:00 1.50 CIRC MUD SURDRL 09:00 - 12:00 3.00 TRIP DP SURDRL 12:00 - 13:00 1.00 PULD_ BHA_ SURDRL 13:00 - 16:00 3.00 RURD_ CSG_ SURCSG 16:00 - 17:00 1.00 RUN CSG SURCSG 17:00 - 20:30 3.50 RUN CSG SURCSG 20:30 - 21:30 1.00 RURD_ CSG_ SURCSG 21:30 - 23:00 1.50 RURD_ OTHR SURCSG 23:00 - 03:30 4.50 TRIP_ DP_ SURCSG 03:30 - 05:00 1.50 CIRC_ MUD_ SURCSG 05:00 - 06:00 1.00 PUMP CMT SURCSG 10/10/2005 06:00 - 07:30 I 1.50, PUMP_ CMT_ I SURCSG 07:30 - 09:00 1.50 PUMP_ CMT_ SURCSG 09:00 - 11:30 2.50 TRIP_ DP_ SURCSG 11:30 - 12:00 0.50 CLEAN_ RIG_ SURCSG 12:00 - 18:30 6.50 NUND BOPE SURCSG 18:30 - 21:00 2.50 NUND WLHD SURCSG 21:00 - 21:30 0.50 TEST_ WLHD SURCSG 21:30 - 03:30 6.00 NUND BOPE SURCSG 03:30 - 06:00 2.50 TEST_ BOPE SURCSG 10/11/2005 06:00 - 09:00 3.00 TEST BOPE SURCSG 09:00 - 10:00 1.00 TEST_ CSG_ SURCSG 10:00 - 13:30 3.50 PULD_ BHA_ SURCSG 13:30 - 22:00 i 8.50 PULD DP SURCSG 22:00 - 00:00 2.00 _ DRILL_ _ CMT_ SURCSG 00:00 - 00:30 0.50 DRILL_ ROT_ SURCSG 00:30 - 01:30 1.00 CIRC_ MUD_ SURCSG 01:30 - 02:30 1.00 TEST LOT SURCSG Event Type --/-- Objective SideTrack- --/-- Description of Operations Page 2 of 14 Spud Date: 10/7/2005 No gain /loss. Correct dispacement. No bridge. Circ /cond fluids / wellbore, fluid caliper = 5% washout. Shaker clean, returns normal. PJSM, flow check, POH 5" DP for 13 3/8 csg. No drag /swab /gain /loss. Flow check, lay do BHA #2, dretnl assy. PJSM, RU csg equip, inspect same. MU shoe track (Shoe, 2 jts 13 3/8 68# L80 BTC, float collar) Clean /thread lock all conn's, RIH same. Check floats. Follow shoe track with 13 3/8 csg, total 46 jts. Correct displacement, no bridge, wash 40 ft, 2 ft fill. Shoe - 1862, Float - 1776 ft. PJSM, rig do csg equip, clear rig floor. PJSM, RU for inner string 5" DP, MU stab in tool / centralizer RIH 5" DP, space out, stab in float collar at 1776 ft Circ /cond fluids (190 spm, 290 psi) while PJSM cmt operation. Pump 45 bbls spacer, test lines 2500 psi. OH --/-- Cont cmt 13 3/8 csg: Mix /pump 275 bbls cmt (type 1, 12 ppg). Load DP wiper plug, confirm plug pumped. Displace with cmt unit 31.5 bbls drlg mud. Sting out float collar, floats holding. 100% returns during job. ICP = 140 psi, FCP = 300 psi 38 bbls dense 12 ppg cmt to surface, cmt top of annulus. Cmt in place 0722 hrs Flush BOP, circ string clean, trace cmt at surface. PJSM, POH 5" DP, rabbit for DP plug, pipe clear. Clear rig floor, LD all related cmt equip. PJSM, ND diverfer, cut csg, remove diverter from sub. PJSM, install multi bowl wellhead Test multi bowl 1500 psi / 15 min, test successful. PJSM, NU BOPE, all related components. PJSM, test BOPE. OH --/-- Cont. test BOPE /all related equip, accumulator press /volume 250 / 2000 10 min. All tests successful, no re-tests. Witness waived by Mr Tim Lawler BLM, Jeff Jones AOGCC PJSM, test 13 3/8 csg 1000 psi / 30 min. Test successful. MU BHA #3, bit #2, scribe /orient MWD, RIH, surface test same. PJSM, PU 5" DP, stand bk in mast for drill out. Drill shoe track at tag 1776 ft -shoe at 1862 ft Dense cmt, no voids. Drill 12 1/4 hole 1862 - 1882 ft new fmtn for LOT Circ /cond fluids, displace spud mud mud with 8.9 ppg Flo Pro, shaker clean. PJSM, flow check, perform LOT at 1882 MD / 1647 TVD resulting in 511 psi surface press / 14.87 EMW. Hold 30 min, drop to 495 psi and stable. Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Page 3 of 14 Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 - - Event Date Event Ho Sub urs Code Phase ~ - - Event Type --/-- Objective I Report Date From - To ~ Code SideTrack- --l-- Descri tion of O erations p p 02:30 - 06:00 3.50 DRILL_ ROT IN1 DRL Drill ahead 12 1/4 hole dretnl 1882 - 2060 ft No gain /loss, cuttings normal quantity /quality ART = 1.9 hrs, AST = .6 hrs WOB 10, RPM 45, SPP 1200, SPM 244 Up 80, Dn 65, Rot 68 No acc / do time 10/12/2005 06:00 - 06:00 24.00 DRILL_ ROT_ IN1DRL OH --/-- Cont. drill ahead 12 1/4 hole dretnl 2060 - 4016 ft. Connections free, no drag, no gain /loss. Cuttings return normal quantity /quality. Hi Vis sweeps return approx 15 / 20% addtnl cuttings, clearing before sweep complete. ART = 12.2 hrs / ROP 142, AST = 3.6 hrs / ROP 66 WOB 2/20, RPM 70, SPP 1327, SPM 255 Up 125, Dn 80, Rot 90 10/13/2005 106:00 - 08:30 08:30 - 09:30 09:30 - 10:00 10:00 - 10:30 10:30 - 06:00 2.50 ~ DRILL_ ROT_ IN1DRL 1.00 CIRC_ MUD_ IN1DRL 0.50 TRIP DP IN1DRL No acc / do time OH --/-- Cont. drill ahead 12 1/4 hole dretnl 4016 - 4206 ART = 1.8 hrs, AST = 0 Circ for wiper trip. PJSM, flow check, POH wiper trip to 3450 ft (750 ft) No drag /swab /gain /loss. Correct hole fill. Flow check, RIH wiper trip, precaution wash 30 ft, no fill. Drill ahead 12 1/4 hole dretnl 4206 -5400 ft ART = 9.5 hrs, AST = 2.4 hrs Incur losses at 5278 ft during connection. Slow pump rate to 400 gpm while re-cip pipe. Regain 100% returns, resume connection. Slow build while drill to 500 gpm, 100% returns. WOB = 10, RPM = 70, SPM = 264, SPP = 1480 Up 150, Dn 85, Rot 105 Connections free, sweeps 200 ft intervals No acc / do time OH --/-- Drill ahead 12 1/4 hole dretnl 5400 - 6589 ft Hi Vis sweeps at 500 ft intervals, 5/10 % increase cuttings Connections free, no drag /gain /loss, max gas 130 units. ART = 7.1 hrs, AST = 4.7 hrs WOB 20, RPM 80, SPP 1588, SPM 270 Up 155, Dn 100, Rot 125 0.50 TRIP_ DP_ IN1DRL 19.50 DRILL ROT IN1DRL 10/14/2005 ~ 06:00 - 06:00 ~ 24.00 ~ DRILL_ ROT_ IN1 DRL 10/15/2005 106:00 - 15:00 15:00 - 16:00 9.00 ~ DRILL_ ROT_ IN1DRL 1.00 TRIP_ ~ WIPR ~ IN1 DRL No acc / do time OH --/-- Drill ahead 12 1/4 hole dretnl 6589 - 6897 ft Torque build to max limits, prepare wiper trip. ART = 2 hrs, AST = 3.1 hrs PJSM, flow check, Recover sweep, POH wiper trip to 6222 ft. Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Page 4 of 14 Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 vent Date Event Sub I Event Type --/-- Objective phase Hours Code Report Date .From - To Code SideTrack- --/-- Description of Operations 15:00 - 16:00 1.00 TRIP_ WIPR IN1 DRL No drag /swab /gain /loss. Correct hole fill. 16:00 - 16:30 0.50 TRIP_ WIPR IN1DRL Flow check, RIH wiper trip, precaution wash 30 ft, no fill. No do drag /bridge /tight hole. No gain /loss. 16:30 - 04:00 11.50 DRILL_ ROT_ IN1DRL Drill ahead 12 1/4 hole dretnl 6897 - 7220 ft Connections free, no drag /gain /loss, max gas 25 units. ART = 2.1 hrs, AST = 4.3 hrs (Tot 11.5 hrs on btm drlg time) Survey time = 3 hrs, Recip /work pipe = 6 hrs (torque) 04:00 - 06:00 2.00 CIRC_ MUD_ IN1DRL Circ collect samples as per MOC Geo (TD confirmation) 10/16!2005 06:00 - 07:00 1.00 CIRC_ MUD_ IN1DRL OH --/-- Cont circ samples as per MOC Geo. TD 7220 ft confirmed. 07:00 - 12:30 5.50 TRIP_ WIPR IN1 DRL PJSM, flow check, POH wiper trip to 13 3/8 shoe 1862 ft. Wellbore free, no drag /swab /gain /loss. Correct hole fill. 12:30 - 13:30 1.00 SLPCUT DLIN IN1DRL PJSM, Cut drlg line 13:30 - 14:00 0.50 SERVIC RIG_ IN1 DRL Service rig 14:00 - 14:30 0.50 TRIP_ DP_ IN1DRL PJSM, flow check, RIH wiper trip to tight hole at 2980 ft 14:30 - 15:00 0.50 REAM_ OH_ INIDRL Wash i ream 2950 - 3010 ft, take 5K wt, no cuttings at shaker 15:00 - 17:00 2.00 TRIP_ DP_ IN1DRL Resume RIH wiper trip to tight hole at 5276 ft. 17:00 - 17:30 0.50 REAM_ OH_ IN1 DRL Wash /ream 5250 - 5300 ft, take 5K wt, no cuttings at shaker 17:30 - 18:30 1.00 TRIP_ DP_ IN1DRL Resume RIH wiper trip, precaution wash 30 ft to 7220 ft. no fill. 18:30 - 21:00 2.50 CIRC_ MUD_ IN1 DRL Circ / cond fluids for csg run, no gain /loss, shaker clean. Pump wt pill while prep for POH. 21:00 - 02:30 5.50 TRIP_ DP_ INIDRL PJSM, flow check, POH to BHA for 9 5/8 Csg. No drag /swab /gain /loss. Correct hole fill. 02:30 - 04:00 1.50 PULD_ BHA IN1 DRL Flow check, lay do dretnl BHA, clear floor. 04:00 - 05:30 1.50 RURD_ CSG_ IN1CSG PJSM, install 9 5/8 rams, test 2000 psi, test successful. 10/17/2005 06:00 - 06:30 0.50 TEST_ BOPE IN1 CSG OH --/-- Cont. test 9 5/8 rams, pull test plug, set wear ring. 06:30 - 12:00 5.50 RURD_ CSG_ IN1CSG Rig up floor/ csg equip 12:00 - 23:00 11.00 RUN CSG_ IN1CSG PJSM, flow check (6 bbl / hr static loss) Commence run 9 5/8 csg as follows: MU shoe track (Shoe,2 jts csg, float collar) thread lock. Check floats, RIH same. Follow shoe track with 175 jts 9 5/8, 40#, L80, BTC csg Centralizers as per program. Circ btms up 2000 ft intervals. No loss /gain, correct displacement. Land hgr (Shoe 7214 ft, float 7129 ft) no fill. 23:00 - 02:30 3.50 CIRC_ MUD_ IN1CSG Circ / cond fluids, spot LCM in annulus (58 bbl 75 ppg Cal Carb) PJSM, cmt operation during circ /cond. 02:30 - 06:00 3.50 PUMP_ CMT_ IN1CSG Commence cmt 9 5/8 csg: Test lines 3500 psi, mix /pump 30 bbls MCS-4D. Drop btm plug, confirm plug dropped. Mix !pump 177.5 bbls lead (G, 12.5 ppg). Mix /pump 78.4 bbls tail (G, 13.5 ppg). Drop top plug, confirm plug dropped. Pump 5 bbls H2o, displace 473 bbls (Tot 535.3 to bump) 100% returns, Plug nearing bump at 0600 hrs. r Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Page 5 of 14 Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 _ ~ _- ~ - -- ~Event Date Event ~ Sub Event Type --/-- Objective eport Date From -To Hours Code Gode ~ Phase SideTrack- --/-- Description of Operations 10/18/2005 06:00 - 06:30 0.50 PUMP_ CMT_ IN1CSG OH --/-- Resume displace cmt 535 bbls total. Bump plug, build to 1100 psi / 5 min, bleed, floats holding. 100% returns during job. Plug bumped / cmt in place 0623 hrs ICP 325 psi 4 bpm, FCP 726 psi 2.3 bpm. No loss /gain 06:30 - 07:30 1.00 PUMP_ CMT_ IN1 CSG Flush BOPE, RD cmt equip, clear floor, release BJ 07:30 - 08:30 1.00 TEST_ WLHD IN1CSG PJSM, set 9 5/8 pkf, test same 5000 psi ! 15 min Test successful. 08:30 - 09:30 1.00 NUND BOPE INICSG PJSM, install 5" pipe rams 09:30 - 15:30 6.00 TEST_ BOPE IN1CSG PJSM, test BOPE, all related equip 250 / 2000 psi (5 min test) Perform accumulator time /press /volume test. Pull test plug, set wear ring, clear floor. Witness waived Mr Jim Regg AOGCC 15:30 - 16:30 1.00 RURD_ OTHR IN1CSG Rig up floor (torque tube, bails, elevators, etc) for DP 16:30 - 17:30 1.00 TEST_ CSG_ IN1CSG PJSM, test 9 5/8 csg 2000 psi / 30 min, test successful. 17:30 - 20:00 2.50 PULD_ BHA_ INICSG PJSM, MU dretnl BHA #4, bit #3, RIH, surface test same. 20:00 - 01:30 5.50 REPAIR RIG_ IN1CSG Troubleshoot top drive (No torque) 01:30 - 05:30 4.00 TRIP_ DP_ IN1CSG Follow BHA with 5" DP to 7096 ft 05:30 - 06:00 0.50 REPAIR RIG_ IN1CSG Troubleshoot top drive (No torque) No acc / (6 hrs do time top drv) 10/19/2005 06:00 - 10:00 4.00 REPAIR RIG_ IN1CSG OH --/-- Cont. repair top drive, replace hyd motor. 10:00 - 12:30 2.50 LOG_ CSG_ IN1CSG Test log LWD tool 7050 - 7129 ft 12:30 - 13:30 1.00 REPAIR RIG_ IN1CSG Troubleshoot top drive (no torque), adjust, test, OK. 13:30 - 15:30 2.00 DRILL_ CMT_ IN1CSG Drill shoe track / cmt. Tag float 7128 /shoe 7213 ft. Dense cmt, no voids. 15:30 - 16:00 0.50 DRILL_ ROT_ IN1CSG Drill ahead 8 1/2 hole dretnl 7220 - 7240 ft for LOT ART = .5 hrs 16:00 - 16:30 0.50 CIRC_ MUD_ IN1CSG Circ btms up for mud displacement. 16:30 - 17:30 1.00 CIRC_ MUD_ IN1CSG Displace well new mud Flo-Pro 9 ppg for coring. 17:30 - 18:30 1.00 TEST_ LOT_ INICSG Perform LOT MD 7240, TVD 5436 = Surface press 1950 psi, EMW 15.9 ppg 18:30 - 19:30 1.00 DRILL_ ROT_ PR1 DRL Drill ahead 8 1/2 hole dretnl 7240 - 7283 ft ART = 1 hr 19:30 - 21:00 1.50 CIRC_ MUD_ PR1 DRL Circ / cond fluids (EM 920 additive blanking shaker screens) 21:00 - 06:00 9.00 DRILL_ ROT_ PR1 DRL Drill ahead 8 1/2 hole dretnl 7283 - 7700 ft ART = 3.5 hrs, AST = 2.8 hrs Connections free, no drag, torque normal Returns norma- quantity /quality No gain /loss No acc / 6.5 hrs do time ~, ~.J r Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Page 6 of 14 Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 _ (Event Date Event ~ I Sub Event Type --/ Objective H C ours ode Code Phase SideTrack- --/-- Description of Operations Report Date From - To 10/20/2005 06:00 - 07:00 1.00 CIRC_ MUD_ PR1 DRL OH --/-- Circ. for samples @ 7700'. 07:00 - 07:30 0.50 DRILL_ ROT_ PR1DRL Drill F/7704' to 7735'(ART=.5hrs). 07:30 - 09:00 1.50 CIRC_ MUD_ PR1 DRL Circ. for samples @ 7735'. 09:00 - 10:00 1.00 TRIP_ WIPR PR1 DRL POOH to shoe. 10:00 - 11:00 1.00 REPAIR RIG_ PR1 DRL Trouble shoot PLC for Rig Drawworks. 11:00 - 11:30 0.50 TRIP_ WIPR PR1DRL RIH to 7735'. 11:30 - 12:30 1.00 CIRC_ MUD_ PR1 DRL Circ. clean(CBUX1,RPM 90, 1300psi, 460gpm). Flow check. Pump dry job. 12:30 - 16:00 3.50 TRIP_ DP_ PR1 EVL POOH W/DP(SLM 6' difference from drilling tally no correction). 16:00 - 17:00 1.00 TRIP_ BHA_ PR1EVL POOH w/BHA. 17:00 - 18:30 ~ 1.50 TRIP_ BHA_ PR1 EVL PJSM. P/U core assy and M/U. 18:30 - 22:30 4.00 TRIP_ BHA_ PR1 EVL RIH. Wash last 90' to bottom and tag@7735'. 22:30 - 00:00 1.50 CIRC_ MUD_ PR1 EVL CBU(300gpm, 13RPM, 450psi,18units TG). 00:00 - 00:30 0.50 CIRC_ MUD_ PR1EVL Add 5' pup and drop ball and circ. down(100psi inc). 00:30 - 06:00 5.50 CORE_ CONV PR1 EVL Core F/7735' to 7768(5.9hrs). 10/21/2005 06:00 - 10:00 4.00 CORE_ CONV PR1 EVL OH --/-- Core F/7768' to 7776'(lost torque and change in pump pressure). 10:00 - 10:30 0.50 CORE_ CONV PR1 EVL Attempt to get core restarted. 10:30 - 12:30 2.00 CIRC_ MUD_ PR1EVL CBU(300gpm, 503psi, 13RPM). Flow check. Pump dry job. 12:30 - 16:00 3.50 TRIP_ DP_ PR1 EVL POOH w/DP. 16:00 - 17:30 1.50 TRIP_ BHA_ PR1 EVL PJSM. POOH w/BHA. 17:30 - 19:30 2.00 TRIP_ BHA_ PR1 EVL Log and UD core -cut 41' and recovered 38' -while trying to get a 60' core. 19:30 - 20:30 1.00 TRIP_ BHA_ PR1EVL Check bit and M/U BHA. 20:30 - 01:00 4.50 TRIP_ DP_ PR1EVL RIH to 7672'. 01:00 - 01:30 0.50 WASH FILL PR1EVL Wash fill to 7776'. 01:30 - 02:30 1.00 CIRC_ MUD_ PR1 EVL CBU. 02:30 - 03:00 0.50 CIRC_ MUD_ PR1 EVL Dop ball and circ. down. 03:00 - 06:00 3.00 CORE_ CONY PR1 EVL Core F/7776' to 7806'(ART=3.2hrs). 10/22/2005 06:00 - 10:00 4.00 CORE_ CONV PR1 EVL OH --/-- Core F/7806' to 7836'(ART=3.8hrs). 10:00 - 11:00 1.00 CIRC_ MUD_ PR1EVL CBU@7835'. 11:00 - 11:30 0.50 CIRC_ MUD_ PR1 EVL Flow check. Pump dry job. 11:30 - 15:00 3.50 TRIP_ DP_ PR1 EVL POOH w/DP. 15:00 - 16:00 1.00 TRIP_ BHA_ PR1 EVL POOH w/BHA. 16:00 - 18:00 2.00 TRIP_ BHA_ PR1EVL PJSM. UD core and core assy(cut 60' recover 60'). 18:00 - 19:00 1.00 TRIP_ BHA_ PR1 EVL M/U bit and dir tools and RIH w/BHA. 19:00 - 21:30 2.50 TRIP_ DP_ PR1EVL RIH w/DP to 7662'. 21:30 - 23:00 1.50 LOG_ OTHR PR1 EVL W/R and log GR to 7836'. 23:00 - 06:00 7.00 DRILL_ ROT_ PR1 DRL Dir drill and survey F/7836' to 8100'(ART= 2.Ohrs AST=2.Ohrs). Note: due to high torque added 4 drums lubtex before torque: 12-13K ft-Ib after torque: 9-10K ft-Ib torque. 10/23/2005 06:00 - 12:30 6.50 DRILL_ ROT_ PR1 DRL OH --/-- Dir drill and survey F/8100' to 8380'(ART=2.25hrs AST=1.60hrs). 12:30 - 13:00 0.50 CIRC_ MUD PR1DRL Circ. samples @ 8380'. 13:00 - 14:00 1.00 DRILL_ ROT_ PR1 DRL Drill F/8380' to 8435'(ART=1.Ohrs). 14:00 - 14:30 0.50 CIRC_ MUD_ PR1DRL Circ. samples @8435'. 14:30 - 14:45 0.25 DRILL_ ROT_ PR1 DRL Drill F/8435' to 8445'(ART=.25hrs). r ~ r`_.J Primed: 2/23/2006 92:01:20 PM Marathon Oil Company Operations Summary Report -Per Well Page 7 of 14 Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 _- _- - -, Event Date Event Sub Event Type --/-- Objective Report Date From - To Hours Code Code Phase SideTrack --/-- Description of Operations 14:45-15:30 0.75 CIRC_ MUD_ PR1DRL 15:30 - 16:30 1.00 TRIP_ WIPR PR1DRL 16:30 - 18:30 2.00 CIRC_ MUD_ PR1 DRL 18:30 - 22:00 3.50 TRIP_ DP_ PR1EVL 22:00 - 00:00 2.00 TRIP_ BHA_ PR1EVL 00:00 - 02:00 2.00 TRIP_ BHA_ PR1 EVL 02:00 - 04:00 2.00 TRIP_ DP_ PR1EVL 04:00 - 05:30 1.50 SLPCUT DLIN PR1EVL 05:30 - 06:00 0.50 TRIP_ DP_ PR1 EVL 10/24/2005 06:00 - 07:00 1.00 TRIP_ DP_ PR1 EVL 07:00 - 08:30 1.50 CIRC_ MUD_ PR1EVL 08:30 - 13:30 5.00 CORE_ CONY PR1EVL 13:30 - 15:00 1.50 CIRC_ MUD_ PR1 EVL 15:00 - 15:30 0.50 TRIP_ DP_ PR1EVL 15:30 - 16:00 0.50 REPAIR RIG_ PR1EVL 16:00 - 20:30 4.50 TRIP_ DP_ PR1 EVL 20:30 - 21:30 1.00 TRIP_ BHA_ PR1 EVL 21:30 - 23:00 1.50 TRIP_ BHA_ PR1 EVL 23:00 - 23:30 0.50 TRIP_ BHA_ PR1EVL 23:30 - 00:30 1.00 TRIP_ BHA_ PR1 EVL 00:30 - 01:30 1.00 TRIP_ BHA_ PR1 EVL 01:30 - 02:00 0.50 SERVIC RIG_ PR1 EVL 02:00 - 03:30 1.50 TRIP_ DP_ PR1 EVL 03:30 - 06:00 2.50 TRIP_ DP_ PR1EVL 10/25/2005 06:00 - 06:30 0.50 TRIP_ DP_ PR1EVL 06:30 - 07:30 1.00 REAM_ OH_ PR1 DRL 07:30 - 20:00 12.50 DRILL_ ROT_ PR1 DRL 20:00 - 21:00 1.00 CIRC_ MUD_ PR1 DRL 21:00 - 22:30 1.50 TRIP DP PR1DRL 22:30 - 00:00 1.50 TRIP_ DP_ PR1 DRL 00:00 - 06:00 6.00 REPAIR RIG PR1 DRL 10/26/2005 06:00 - 07:00 1.00 REPAIR RIG_ PR1 DRL 07:00 - 08:00 1.00 TRIP_ DP_ PR1DRL 08:00 - 23:00 15.00 DRILL ROT PR1DRL 23:00 - 01:30 2.50 CIRC_ MUD_ PR1DRL 01:30 - 05:00 3.50 TRIP WIPR PR1DRL 05:00 - 06:00 1.00 TRIP WIPR PR1DRL - - -.. _ - Circ. clean. Flow check. POOH to 7690'(tight@8234', 8210', 8075', 8050', 7947'). Circ. clean(CBUX1, 470gpm, 1600psi). POOH w/DP. POOH w/BHA. UD GR probe. Program MWD. PJSM. M/U core tools. RIH w/BHA. RIH to 7075'. PJSM. Slip and cut DRLG line. RIH w/DP(7500' @ 06:OOhrs). OH --/-- RIH to 8440'. Space out and wash last 50' down and tag @ 8445'. CBU (300GPM, 10RPM, 590psi, max gas 56 units). Core F/8445' to 8535' (ART=4.7hrs). CBU (300 GPM, 660 psi, 60 RPM). Flow check and pump dry job. POOH to 8383' (tight in core area @ 8453' and 8447'). Repair TD link tilt (had to function float valve to clear peice of trash). Cont. POOH w/DP. POOH w/BHA. PJSM. UD core (cut 90' recovered 90'). UD core barrels and tools. PJSM. Cont. to UD core barrels. M/U bit and Dir BHA check MWD and RIH. Service rig. P/U 48jnts 5" DP while RIH. Cont. to RIH w/DP (7500 '@ 06:00 hrs). OH --/-- Cont. to RIH to 8369'. W/R core area to 8535' Dir drill and survey F/8535' to 9064'(ART=7.0 AST=2.1). Top drive overheating. Add 8bbls lubtex while circ and work pipe. Circ. clean(CBUX1, 480gpm, 1500psi, ORPM). Before UP 215k DN 125K After UP 205K DN130K. POOH tight @ 8731', 8711', 8672', 8670', 8646', 8644'. W/R 8656' to 8608' POOH tight @ 8559'. W/R 8604' to 8546'. POOH tight @ 8530'. W/R 8543' to 8485'. POOH to 8360'. Pump dry job. POOH to 7169'. Trouble shoot top drive hydraulic oil cooling system. Found rubber F/hoses in filters. C/O filter and hoses. Clean shuttle valves and flow meters. OH --/-- Cont. to C/O hoses and filters on top drive hydraulic system. Test run top drive. RIH wash last 60' to 9064'. Dir drill and survey F/9064' to 9733"(ART=11.7) Before lubtex addition and wiper trip UP 215K DN 125K torque 13-15K After Up 200K DN 125K torque 10-12K. Trip gas 116units. At 9186' started adding metal to metal lubricant. Added total 2bbls. Noticed very little reduction in torque. Circ. clean while waiting on decision from Geology(CBUX3, 465GPM, 74RPM, 1900psi). POOH tight @ 9659', 9631', 9408', 9379'. W/R 9432' - 9375'. POOH tight @ 9350'. W/R 9372'-9310'. POOH tigh t@ 9204'. W/R 9243'-9185'. POOH tight @ 8991'. W/R 8995'-8935'. POOH to 8300' tight @ 8888', 8795', 8710', 8541'. RIH to 9733'. Printed: 2!23/2006 12:01:20 PM Marathon Oil Company Page $ of 14 Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 .- - -_ - _ - Event Date Event Sub Event Type --/-- Objective (Report Date From - To Hours Code Code .Phase SideTrack- --/-- Description of Operations 10/27/2005 06:00 - 08:30 2.50 CIRC_ MUD_ PR1 DRL OH --/-- Circ. clean(CBUX2, 500gpm, 2100psi, 70RPM). 2845 units B/U gas. Large amount of dime sized coal and large amount of clay across shakers. Increase MW to 10.6ppg. 08:30 - 10:00 1.50 TR{P DP_ PR1 DRL Wiper trip to 8860'(Tight @ 9568'. W/R 9595' to 9538'. Tight @ 9413', 9392'). 10:00 - 10:30 0.50 TRIP DP_ PR1DRL RIH to 9733'. 10:30 - 13:00 2.50 CIRC_ MUD_ PR1DRL Circ. clean(CBUX2, 500GPM, 2100psi, 70RPM). 145 units B/U gas. Drop carbide and circ. out. Carbide indicated 25% washout. Flow check and pump dry job. Drop 2.75" rabbit. 13:00 - 20:30 7.50 TRIP_ DP_ PR1 DRL POOH(SLM). Work tight spots @ 8813' and 8800' 20:30 - 21:00 0.50 CLEAN_ RIG_ PR1 DRL Clean Rig Floor And Blown Down Mud Lines 21:00 - 22:00 1.00 RURD_ ELEC PR1 EVL PJSM; R/U Precision WLS & M/U Quad Combo Tools 22:00 - 01:30 3.50 LOG OH_ PR1EVL RIH W/ Quad Combo & Log. Monitor Well With Returns To Trip Tank. 01:30 - 02:00 0.50 LOG_ OH_ PR1 EVL POH W/ Precision E-Line 02:00 - 03:00 1.00 RURD_ ELEC PR1 EVL Flow Check ; R/D Precision WLS Tools & UD 03:00 - 05:30 2.50 TRIP_ DP_ PR1EVL RIH W / 5" Drill Pipe( Open Ended) T/ 7213. 05:30 - 06:00 0.50 SLPCUT DLIN PR1EVL Slip and cut drlg line. 10/28/2005 06:00 - 07:30 1.50 SLPCUT DLIN PRIEVL OH --/-- Slip and cut DRLG line. 07:30 - 09:00 1.50 TRIP_ DP_ PR1 EVL RIH w/open ended DP. 09:00 - 10:00 1.00 CIRC MUD PR1EVL Circ. clean(CBUX1, 500gpm, 1200psi, 70RPM, B!U gas 280units). 10:00 - 11:00 1.00 _ TRIP_ _ DP_ PR1 EVL POOH to 8634'. 11:00 - 12:00 1.00 LOG_ OH_ PR1 EVL Blow down mud line. R/U precision E/L. 12:00 - 13:00 1.00 LOG_ OH_ PR1 EVL PJSM. Cont. R/U Precision E/L. 13:00 - 15:00 2.00 LOG_ OH_ PR1 EVL Run Precision MFT tool. 15:00 - 16:00 1.00 LOG_ OH_ PR1EVL POOH w/MFT and R/D precision. 16:00 - 17:00 1.00 TRIP_ DP_ PR1EVL POOH to shoe. 17:00 - 17:30 0.50 RURD_ ELEC PR1EVL ~P/U & M/U E-line MFT Tools 17:30 - 22:00 4.50 LOG_ OH_ PR1EVL RIH W i MFT On E- Line & Log F 8634 To 7213 22:00 - 23:00 1.00 LOG_ OH_ PR1 EVL POH W/ E- Line MFT Tools 23:00 - 00:00 1.00 RURD_ ELEC PR1 EVL PJSM; R/D Precision WLS Tools And Logging Unit Begin CompletionPhase At 00:00 HRS. 10/28/2005 Event ORIGINAL COMPLETION --/-- Exploitation -Gas 00:00 - 04:00 4.00 TRIP_ DP_ PR1CSG PJSM;Monitor Well, POH W/ Drill Pipe. No G/L Correct Hole Fill. 04:00 - 04:30 0.50 TRIP_ BHA_ PR1 CSG M/U 8 1/2 Clean Out Assy. 04:30 - 06:00 1.50 TRIP_ DP_ PR1CSG RIH Wiper Trip W 5" Drill Pipe 10/29/2005 06:00 - 10:00 4.00 TRIP_ DP_ PR1CSG OH --/-- RIH w/DP. 10:00 - 14:30 4.50 CIRC_ MUD_ PR1CSG Circ. and cond (CBUX4, 495GPM, 1730psi,70RPM, 417units B/U gas). Large quantity of coal across shakers. Continued to come across in waves of moderate quantities. Pumped around 300bb1s of 10ppb asphasol pill. 14:30 - 16:00 1.50 TRIP_ DP_ PR1CSG POOH to CSG shoe. 16:00 - 22:00 6.00 PULD_ DP_ PR1CSG UD 5" DP. F-7212' 22:00 - 00:00 2.00 TRIP_ DP_ PR1CSG Run 50 Stands DP From Derrick In Hole 00:00 - 04:00 4.00 PULD_ DP_ PR1CSG PJSM; UD DP 04:00 - 04:30 0.50 RUNPUL WBSH PR1CSG Pull Wear Bushing • Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: - KENAI BELUGA UNIT 41-6 (Event Date Ev- e~ Sub Hours Code Phase Leport Date From - To Code 04:30 - 06:00 1.50 RURD_ OTHR PR1 CSG 10/30/2005 06:00 - 07:30 1.50 RURD_ CSG_ PR1CSG 07:30 - 10:00 2.50 RURD_ CSG_ PR1CSG 10:00 - 10:30 0.50 RUN_ CSG_ PR1CSG 10:30 - 15:30 5.00 RUN_ CSG_ PR1CSG 15:30 - 16:00 0.50 CIRC_ MUD_ PR1CSG 16:00 - 01:30 9.50 RUN_ CSG_ PR1 CSG 01:30 - 02:00 0.50 CIRC_ MUD_ PR1CSG 02:00 - 04:30 2.50 RUN CSG PR1CSG 04:30 - 06:00 1.50 CIRC_ MUD_ PR1CSG 10/31/2005 06:00 - 07:00 1.00 RUN_ CSG_ PR1CSG 07:00 - 09:00 2.00 CIRC MUD PR1CSG 09:00 - 12:30 3.50 LOG_ CSG_ PR1 CSG 12:30 - 13:30 1.00 CIRC MUD PR1CSG 13:30 - 16:30 3.00 _ PUMP_ _ CMT_ PR1CSG 16:30 - 00:30 8.00 WAITON CMT_ PR1CSG 00:30 - 03:30 3.00 NUND BOPE PR1CSG 03:30 - 04:30 1.00 NUND WLHD PR1CSG 04:30 - 06:00 1.50 NUND TREE PR1 CSG 11/1/2005 06:00 - 08:00 2.00 NUND TREE PR1CSG 08:00 - 11:00 3.00 NUND TREE PR1CSG 11:00-12:00 1.00 TEST TREE PR1CSG 12:00 - 00:00 12.00 RURD RIG RDMO 00:00 - 06:00 6.00 RURD_( RIG_ ~ RDMO Page 9 of 14 Spud Date: 10/7/2005 Event Type --/-- Objective SideTrack- --/-- Description of Operations R/D Rig Tongs, Spinners, UD All 5" DP Handling Tools & Subs OH --/-- CIO bales and elevators. R/U CSG tools. PJSM prior to running excape completion. R/U Expro control line sheave. R/U fill up line. Hang banding equipment. M/U 3 1/2" CSG shoe track. Cont. to run 3 1/2" Excape completion(15 modules) to 1783'. Circ. CSG(236gpm, 470psi). Cont to run 3 1I2" 9.3PPF L-80 EUE-Mod CSG To 7224' Circ At 7224' 9 5/8 Shoe, @ 550 psi No Gain/ Loss Correct Hole Fill Cont. To Run 3 1/2 Excape Csg. F 7224 t 9719' Ran 15 Modules W 2Controll and 1 Sacrificial Line.( No Fill Gains Or Loss And Correct Displacement. Note; Day Light Savings Time In Effect Set Time Back 1 Hour. Circ Bttms Up @ 9714' 396GPM 900 psi B/U gas 220units. OH --/-- Cont. to circ. and reciprocate gas peak slow to come up. Drop carbide. Cont to circ. and reciprocate(311CPM, 1870psi). First carbide came up at theoretical gauge hole and tailed out to 100% over. R/U Expro E/L. Run Correlation GR log. R/D Expro E/L. R/U BJ cement head and cement lines. Pump 250bb1s inhibited mud. PJSM prior to cementing. Blow back BJ lines with air. Pump 5bbls water ahead. Test lines to 3500psi. Mix and pump 50bbls 11.5ppg spacer. Mix and pump 1160sxs class"G" cement w/1.2%BA-56, .15%R-3, .5%EC-1, .2%SMS, lgphs FP-6L to yield 242bb1s 15.8ppg slurry. Wash lines out to slop tank. Drop plug and displace w/85bbls 6%KCL brine. Bump plug w/2500psi 500psi over last displacement pressure. Hold pressure for 5min. Bleed off pressure and check floats. CIP@16:10hrs. 100% Returns/ Reciprocate Pipe During Cement Job. F/C @ 9685.18' Shoe @ 9721.78' PJSM; WOC, R/D Flowlines, Drip Pan, Clean Pits, PJSM; Nipple Down BOP Set Slips, Cut 3 1/2 /20.72' Removed. Instal{ Pack Off, Test To 5000 psi F- 5 Min, Terminate Control Lines Test Same PJSM;Install TWC. Install Tree. OH --/-- Install X-mas tree. test tree void to 5000psi/10min. Test tree to 10000psi/10min. Attempt to pull TWC. Could not get TWC through flow cross. N/D tree to top of master valves. Pull TWC and install BPV. N/U new flo cross and NiU wing valve and swab valve. Cont. to clean pits and prep for R/D rig while work on tree. Test tree from upper master valve to tree cap 10000psi/10min. Install BPV.. Clean Pits During N/U Of Tree Pjsm; R/D Shock Hoses,Cuttings Tank,Clean Mud Boat Sumps, R/D Top Drive& Torque Tube And Monkey Board. Prep Derrick, R/D Drillers Console, Beaver S1ide& Cat Walk. RID Cellar Remove Trip Tank. R/D Gas Buster & Lines. Remove Carrier Tarps And Frame. Steam Out Sub Legs. Blow Down Rig Water System. Set Matting Boards On KBU 11-7 R/D M/I & Dlr. Driller Units. Scope Down Derrick PJSM; Cont R/D Crane Work, Remove Wind Walls Dog & Choke House F Rig Floor UD Derrick Pull Electrical & Control Lines From Sub. Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Page 10 of 14 Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 T - Event Date Event Sub I Event Type --/-- Objective eport Date ,From - To ~ Hours Code ~ Code Phase SideTrack- --/-- Description of Operations 11/2/2005 06:00 - 08:00 2.00 RURD_ RIG_ RDMO OH --/-- Cont. to pull wires and prep for rig move. PJSM prior to moving rig. Rig released to KBU 11-7 @ 08:OOhrs 11/01/2005. 11/2/2005 Event ORIGINAL COMPLETION --/-- Exploitation -Gas 11!29/2005 12:15 - 12:30 0.25 SAFETY MTG_ PR1 CSG OH --/-- Sign in at office, obtain work permit, hold safety meeting. 12:30 - 12:45 0.25 SAFETY MTG_ PR1CSG Hold location safety meeting, spot equipment leaving room to MI Rain for Rent tanks 12:45 - 13:45 1.00 RURD_ ELEC PR1CSG RU E-line unit. 13:45 - 18:45 5.00 LOG_ CSG_ PR1CSG Run CBL, encounter software problems, etc. Final CBL shows cement and GR w/ very noisy CCL. Tagged high at 9600' above bottom module. Saw good bond up to +/- 5800'. 18:45 - 20:00 1.25 PUMP_ TRET PR1 CSG Stuck in ice at surface in the tree. Pumped methanol to thaw. Had to RU heater and warm tree. 20:00 - 20:30 0.50 RURD_ ELEC PR1CSG Rig back unit for night. 11/30/2005 08:30 - 08:45 0.25 SAFETY MTG_ WBPREP OH --/-- Sign in at office, obtain work permit, discuss job, hold safety meeting. 06:00 - 18:00 .12.00 RURD_ STIM CMPSTM Move in frac tanks on location along with miscellaneous equipment. 08:45 - 10:15 1.50 RURD_ SLIK WBPREP RU slickline unit 10:15 - 11:15 1.00 BAIL_ FILL WBPREP RIH w/ 2.25" DD bailer to 9574' WLM. Work bailer to 9582'. POOH w/ wet cement. 11:15 - 12:20 1.08 BAIL_ FILL WBPREP RIH w/ same to 9583'. Work bailer to 9592'. POOH w/ same. 12:20 - 13:20 1.00 BAIL_ FILL WBPREP RIH w/ same to 9594'. Work to 9602'. POOH w/ same. 13:20 - 14:10 0.83 BAIL_ FILL WBPREP RIH w/ same to 9603'. Work to 9610'. POOH w/ same. 14:10 - 15:00 0.83 BAIL_ FILL WBPREP RIH w/ same to 9610', work to 9615' WLM. POOH w/ same. Required 1600# overpull. 15:00 - 16:00 1.00 RURD_ SLIK WBPREP RD slickline equipment and plug in at office in prep for CLU work tomorrow. 12/1/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM OH --/-- Place liner for frac tanks. Spot frac tanks and manifold up same. Continue moving in flowback iron and tanks. 12/2/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM OH --/-- Start hauling water and filling frac tanks. 12/3/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM OH --/-- Finish hauling water and filling frac tanks. Start lining location for rest of frac equipment. 12/4!2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM OH --1-- Mix 6°f° KCL in all frac tanks. Finish lining location for all frac equipment. Start spotting flowback tanks and lines. 12/5/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM OH --/-- Move in well testing equipment and spot same. Finished RU of flowback iron, choke manifold, sand buster, gas buster and lines. 12/6/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM OH --/-- Move in Coil Tubing Unit and equipment. Continue RU frac lines, chemical add unit, heat fluid. Finish RU of well testing lines and equipment. 12/7/2005 06:00 - 18:00 12.00 RURD_ STIM CMPSTM OH --/-- Finish RU CTU and equipment/lines. Perform complete location /equipment inspection and line walk out. RU Expro and perforated Module 1 perfs at 9627' - 9637'. Guns fired with 6300 psi on green line. Good indication of gun firing. 12/8/2005 06:00 - 07:00 1.00 INSPCT EOIP CMPSTM OH --/-- Arrive location. Inspect frac equipment and lines. Start up frac trucks. Check chemical tanks and lines. 07:00 - 07:30 0.50 SAFETY MTG_ CMPSTM Hold PJSM. Discuss weather effects on job (slips trips falls). Discuss frac tracing and firing line pressures. Emergency response procedures. 07:30 - 09:30 2.00 TEST_ EQIP CMPSTM Pressure test frac trucks and lines to 10,000 psi. Pressure test well testers lines and choke manifold to 4400 psi. Good tests. 09:30 - 09:45 0.25 PUMP_ WTR_ CMPSTM Open well. SITP = 60 psig (estimated BHP = 3517 psig) Perform injection test with bbls 6% KCL. ISIP = 3254 psig. FG = 0.876 psi/ft. (Total Load = 61 bbls) 09:45 - 10:15 0.50 PUMP_ FRAC CMPSTM Frac mod 1 perfs (9627-9637' RKB) w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 6100 psi. Ramp 1.0 - 8.0 ppa. Screened out perforations with 45 bbls flush pumped and 8 ppg on perfs (39 bbls short) Placed 17471 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand) or 70% of design. Tot Load = 178 bbls). Tagged w/ ProTechnics CFT 2500 chemical tracer, field tracer AUM 01, and SC-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 239 bbls) (Strap chemical tanks post frac) ~, ._J .7 Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Page 11 of 14 Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 _ -_ _- Event Date Event Hours Code Sub Phase Event Type --/-- Objective Repoli Date From - To ! 'Code SideTrack- --/-- Description of Operations 10:15 - 12:30 2.25 FLOW_ BACK CMPSTM Open well to flowback tank and attempt to flowback tubing volume of 84 bbls. Well flowing and gaining strength then tapered off to light flow. Unloading flex and frac sand. Foowback total of 94 bbls. 12:30 - 15:00 2.50 PUMP_ FRAC CMPSTM Attempt to pump tubing volume back into module 1 perfs. Pump total of 49 bbls and perfs screened out. Open well back up to flow and call for CTU crew. Monitor well flow. Flowed back total of 45 bbls. Well slugging with very little fluid rate 4-6 BPH. 15:00 - 17:00 2.00 PUMP_ FRAC CMPSTM CTU crew on location. Attempt to pump tubing volume into mod 1 perfs. Pump total of 50 bbls into well over 4 pump cycles. Perfs continue to screenout. SD and clean up frac equipment. 17:00 - 19:30 2.50 RURD_ COIL CMPSTM RU Coil Tubing Unit. Test coil and BOP body to 6000 psi. Test rams 200/4500 psi. 19:30 - 00:15 4.75 RUNPUL COIL CMPSTM Open well and RIH with Coil Tubing pumping 6% KCL at 1.5 bpm. Tag firm frac sand at 8460' CTM. Sand would not wash off at 1.5 bpm. Increase pump rate to 2 to 2.3 bpm and start washing sand. Wash sand from 8460' to 9647' CTM. Unable to wash further. 00:15 - 01:10 0.92 CIRC_ CFLD CMPSTM CBU x 2. 01:10 - 02:30 1.33 RUNPUL COIL CMPSTM POOH with CT. 02:30 - 03:30 1.00 RURD_ COIL CMPSTM RD CT and secure well for the night. 12/9/2005 06:00 - 07:00 1.00 INSPCT EQIP CMPSTM OH --/-- Arrive location. Inspect frac equipment. Start trucks and warm up same. Gel up fluid. 07:00 - 07:30 0.50 SAFETY MTG_ CMPSTM Hold PJSM. Discussed rain and icy conditions on slips trips and falls, high pressure frac ops, production alarms, emergency response actions. 07:30 - 08:00 0.50 TEST_ EOIP CMPSTM Pressure test frac trucks and lines to 10000 psig. Monitor lines, no leaks, good test 08:00 - 08:30 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 2 perfs from 9549 - 9559' w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 5600 psi. Ramp 2.0 - 8.0 ppa. Place 23393 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 238 bbl. Tagged w/ ProTechnics CFT 2400 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 477 bbls) (Strap all chem tanks post frac) 08:30 - 09:00 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 3 perfs from 9280 - 9290' w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 6500 psi. Ramp 2.0 - 8.0 ppa. Place 22378 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 208 bbl. Tagged w/ ProTechnics CFT 2200 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, I respectively. (cumm. load = 685 bbls) (Strap all chem tanks post frac) 09:00 - 10:30 1.50 PUMP_ FRAC CMPSTM Perforate mod 4 perfs from 9239 - 9249' Attempt to establish injection into perfs without success, max TP = 9900 psi. (Good indications of pert guns firing on both firing line and tree movement. Not able to pump in indicates flapper also isolating mod 4 from mod 3. Slight pressure communication between tubing and dead string also indicates some holes in pipe. Possible hole size issue with some sand still across perfs???) Attempt 3 flowback and pump in cycles without success.(Total load = 10 bbls) (cumm. load = 695 bbls) Discuss options with Houston. Decied to move on to mod 5. 10:30 - 11:00 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 5 perfs from 9020 - 9030' w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 5200 psi. Ramp 2.0 - 8.0 ppa. Place 22022 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 206 bbl. Tagged w/ ProTechnics CFT 2100 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 901 bbls) (Strap all chem tanks post frac) 11:00 - 11:30 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 6 perfs from 8877 - 8887' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4540 psi. Ramp 2.0 - 8.0 ppa. Place 21404 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 206 bbl. Tagged w/ Pro7echnics CFT 2000 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1107 bbls) (Strap all chem tanks post frac) 11:30 - 12:00 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 7 perfs from 8598 - 8608' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4460 psi. Ramp 1.0 - 8.0 ppa. Place 20090 lbs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 219 bbl. Tagged w/ ProTechnics CFT 1900 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Page 12 of 14 Operations Summary Report -Per Well Legal Well Name: KE NAI BEL UGA U NIT 41-6 Common W ell Name: KE NAI BEL UGA U NIT 41-6 Spud Date: 10/7/2005 Event Date Event Hour de Sub phase Event Type --/-- Objective iReport Date __ From -To _ _ Code SideTrack- --/-- Description of Operations 11:30 - 12:00 0.50 PUMP_ -. FRAC CMPSTM _ respectively. (cumm. load = 1326 bbls) (Strap all chem tanks post frac) 12:00 - 12:30 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 8 perfs from 8550 - 8560' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 5005 psi. Ramp 2.0 - 8.0 ppa. Place 22618 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 205 bbl. Tagged w/ ProTechnics CFT 3000 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1531 bbls) (Strap all chem tanks post frac) 12:30 - 13:00 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 9 perfs from 8482 - 8492' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 5700 psi. Ramp 1.0 - 8.0 ppa. Place 21430 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 219 bbl. Tagged w/ ProTechnics CFT 1700 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1750 bbls) (Strap all chem tanks post frac) 13:00 - 13:30 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 10 perfs from 8439 -8449' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3780 psi. Ramp 1.0 - 8.0 ppa. Place 20413 Ibs prop (87.5 °1° 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 218 bbl. Tagged w/ ProTechnics CFT 1600 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 1968 bbls) (Strap all chem tanks post frac) 13:30 - 14:15 0.75 PUMP_ FRAC CMPSTM Perforate mod 11 perfs from 8393 -8403' frac mod 11 & 12 w/ BJ Lightning_V_1600 wtr based system aT 15 BPM at max TP = 3800 psi. Ramp 1.0 - 8.0 ppa. Place 27588 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand) or 69% of design. Went to flush at 29 bbls into 8 ppg stage due to increasing surface and bottom hole pressures. Tot Load = 253 bbl. Tagged w/ ProTechnics CFT 1500 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 2221 bbls) (Strap all chem tanks post frac) 14:15 - 14:30 0.25 PUMP_ FRAC CMPSTM Perforate module 12 perfs from 8325 - 8335'. Break perfs down with 20 bbls of BJ Lightning_V_1600 wtr based system. Max TP = 6259 psi. Broke back to injection pressure of 4000 psi at 15 bpm Total load = 20 bbls. Tagged with ProTechnics CFT 1400 chemical tracer and SC-46 RA marker. (cumm. load =2241 bbls) (strap all chem tanks post breakdown) 14:30 - 15:00 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 13 perfs from 8281 - 8291' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4000 psi. Ramp 1.0 - 8.0 ppa. Place 20096 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12!20 Flex Sand). Tot Load = 214 bbl. Tagged w/ ProTechnics CFT 1400 chemical tracer and Sc-46 and Ir-192 RA markers in pad and slurry volumes, respectively. (cumm. load = 2455 bbls) (Strap all chem tanks post frac) 15:00 - 15:30 0.50 PUMP_ FRAC CMPSTM Perforate mod 14 perfs from 8048 - 8058' frac mod 14 & 15 w/ BJ Lightning_V_1600 wtr based system aT 15 BPM at max TP = 5500 psi. Ramp 1.0 - 8.0 ppa. Place 36428 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand) Tot Load = 282 bbl. Tagged w/ ProTechnics CFT 1200 chemical tracer and Ir-192 RA marker in pad and slurry volumes. (cumm. load = 2737 bbls) (Strap all chem tanks post frac) 15:30 - 16:00 0.50 PUMP_ FRAC CMPSTM Perforate and Frac mod 15 perfs from 7991 - 8001' w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3850 psi. Ramp 2.0 - 8.0 ppa. Place Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 209 bbl. Tagged w/ ProTechnics CFT 1100 chemical tracer and Sc-46 RA markers in pad and slurry volumes. (cumm. load = 2946 bbls) (Strap all chem tanks post frac) 16:00 - 18:00 2.00 RURD_ STIM CMPSTM Hold break down and clean up meeting. RD and clean up frac lines, trucks, and equipment 18:00 - 19:00 1.00 RURD_ COIL CMPFLW Hold PJSM. RU CTU. Test injector head 200/4500 19:00 - 22:00 3.00 RUNPU COIL CMPFLW RIH with CT. Broke flappers on modules 15, 13, 12, 11, 10, 9, 5, 4 at 8014, 8303, 8348, 8417, 8463, 8506, 9045, and 9264, respectively. RIH to PBTD of 9654' CTM. 22:00 - 22:45 0.75 CIRC_ CFLD CMPFLW CBU until returns good and clean. 22:45 - 23:45 1.00 RUNPU COIL CMPFLW POOH and work through each flappers not found. Found module 2 flapper at 9575, Did not find flappers for module 3 at 9305, module 6 at 8902, module 7 at 8622, module 8 at 8575, and module 14 at 8071'. 23:45 - 00:30 0.75 RUNPUL COIL CMPFLW RIH with CT with 500 scfm Nitrogen and .75 bpm fluid to 9650' CTM 00:30 - 01:45 1.25 JET_ N2_ CMPFLW Jet well in from below module 1 perforations with 500 scfm and no fluid rate. Start taking water samples as 0100 hrs. Printed: 2/23/2006 12:01:20 PM Marathon Oil Company Operations Summary Report -Per Wel! Page 13 of 14 Legal Well Name: KENAI BELUGA UNIT 41-6 Common Well Name: KENAI BELUGA UNIT 41-6 Spud Date: 10/7/2005 (Event Date Event Sub Event Type --/-- Objective Report Date From - To ~ Hours Gode Code ~ Phase SideTrack- --/-- Description of Operations - ~ - - 00:30 - 01:45 1.25 JET_ N2_ CMPFLW _ - - - POOH to above top perforation at 7950' EPT test indicates fluid flow from module 1. Well appears to be flowing. 01:45 - 02:30 0.75 RUNPUL COIL CMPFLW Shutdown nitrogen and POOH with CT. 02:30 - 03:15 0.75 FLOW_ CHEK CMPFLW Monitor well for continuous flow. Well loading up with FTP down to 65 psi. 03:15 - 06:00 2.75 JET_ N2_ CMPFLW RIH with CT to 7950 with nitrigen at 500 scfm. Continue in hole to 9640' CTM and jet below perfs with 500 scfm. FTP = 350 psi Well unloading fluid at rate of 1872 bpd. Cum load recovery = 255 bbls or 8.7% of total frac load volume of 2946 bbls. 12/10/2005 06:00 - 07:30 1.50 JET_ N2_ CMPFLW OH --/-- Continue to jet well in from below module 1 perforations. Well consistantly unloading 30-32 bbl every 30 min with TP=315 psi 07:30 - 08:00 0.50 JET_ N2_ CMPFLW Start POOH to above perforations while jetting with 500 scfm of nitrogen 08:00 - 09:00 1.00 RUNPUL COIL CMPFLW Shutdown nitrogen above perfs and monitor well response while POOH with CT. EPT field chemical still present in returns indicating fluid flow from module 1. Continue POOH with CT. 09:00 - 10:00 1.00 RURD_ COIL CMPFLW RD CT injector head and secure CT equipment. Send crews home for rest while well testers monitor well for flow. 10:00 - 06:00 20.00 FLOW TEST CMPFLW Monitor well for flow. FTP = 50 psig. Gradually increase to 195 psig. Routed well through both flowlines and FTP decreased to 115 psig. Continued to monitor flow. FTP gradually increase to 140 psig. Water rate over entire monintoring period decreased form 2179 bpd to +/- 300 bpd. Put well back though one flowline and prepare to place in test separator. (Cumm fluid recovery = 887.5 or 30% of frac load) 12/11/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW OH --/-- Monitor well flow and test same. Well making 1.4 mmcfd, 170 bwpd, 230 psig FTP, estimated 670 psig BHP. Making practically no solids (prop, flex, or fines) Cumm fluid recovery = 1112 bbls or 38% og total frasc load of 2946 bbls. 12/12/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW OH --1-- Flow tested well. FTP = 245 psig, Est. BHP = 663 psig, Gas = 1.44 mmcfd, Water = 132 bpd. Cumm fluid recovery = 1282 bbls or 43.5% frac load. 12/13/2005 06:00 - 08:45 2.75 FLOW_ TEST CMPFLW OH --/-- Flow tested well. FTP = 240 psig, Est. BHP = 663 psig, Gas = 1.44 mmcfd, Water = 133 bpd. Cumm recovery = 1300 bbls or 44% of frac load. 08:45 - 15:00 6.25 TEST_ PBU_ CMPFLW Shut well in to confirm BHP estimates. Initial FTP = 245 psig BHP = 663 psig. Final SITP = 1980 psig BHP = 2103 psig. BHP broke over at 2126 psig indicating possible cross flow. 15:00 - 06:00 15.00 FLOW_ TEST CMPFLW Opened well back to flow test. As of 0500 hrs 12/13/05 FTP = 235 psig, Est. BHP = 671 psig, gas = 1.48 mmcfd, water = 196 bpd. Cumm fluid recovery = 1425 bbls or 48.4% of frac load (2946 bbls) 12/14/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW OH --/-- Continued to flow test well. As of 0600 hrs 12-14-05 well making 1.56 mmcfd, FTP = 255 psig, Est. BHP = 678 psig, bwpd = 196. 12/15/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW OH --/-- Continued to flow test well. As of 0600 hrs 12-15-05 well making 1.62 mmcfd, FTP = 265 psig, Est. BHP = 673 psig, bwpd = 172. 12/16/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPFLW OH --/-- Continued to flow test well. As of 0600 hrs 12-16-05 well making 1.62 mmcfd, FTP = 250 psig, Est. BHP = 653 psig, bwpd = 174. 12/17/2005 06:00 - 09:30 3.50 FLOW_ TEST CMPFLW OH --/-- Continued to flow test well. Final test report data as of 0915 hrs 12-16-05 well making 1.63 mmcfd, FTP = 245 psig, Est. BHP = 637 psig, bwpd = 100-200. 09:30 - 18:00 8.50 RURD OTHR CMPFLW Release well testers and RD testing lines and equipment. Final post frac well test report 1/8/2006 07:00 - 07:30 0.50 SAFETY MTG_ PRDTST OH --/-- Arrive KGF and sign in. Obtain work permit and Hold PJSM 07:30 - 08:30 1.00 RURD_ SLIK PRDTST RU slickline unit and make up tool string with 2.35" swedge 08:30 - 09:30 1.00 RUNPU SLIK PRDTST RIH and tagged fill at 9530' SLM (9551' RKB) Bottom two modules covered up with fill. Broke excape module flappers at 8071', 8575', 8902', and 9045' RKB in modules 14, 8, 6, & 5. (Module 5 flapper was broken during CT post frac cleanout Printed: 2/23/2006 12:01:20 PM M Marathon MARATHON Oil Company September 26, 2005 ~~;~'J1,~'~'T SEP ~ ~ 2Q05 Alaska Qil & Gas Cores. v~r1'Rtt~ssit~ri John Norman Anchorage Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7t" Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Kenai Gas Field Well: KBU 41-6 Dear Mr. Norman Worldwide Drilling North America P.O. Box 3128 Houston, TX 77253-3128 Telephone 713-629-6600 Fax 713-499-6737 Enclosed please find the PERMIT TO DRILL application, along with the associated attachments and filing fee of $100. The intent is to drill a well in the Beluga / Upper Tyonek Pool in the Kenai Gas Field. No completion is desired in the Sterling pool. ~' If you require further information, I can be reached at 713-296-3273 or by a-mail at wjtank@marathonoil.com. Sincerely, Qr~l~-~y=, ~ wT~ Willard J. Tank Advanced Senior Drilling Engineer s Enclosures STATE OF ALASKA AL . IL AND GAS CONSERVATION COM JN PERMIT TO DRILL ~n ,nat : ~~ nnti ~~~~~, Z:~ds ~~ ~r~~ SEP 2 s 2005 Als.b., na n. n__ .. 1a. Type of Work: Drill Q Redrill ~ Re-entry ~ r.ravn 1b. Current Well Class: Exploratory Development Oil~n (Multiple Zone ~ Stratigraphic Test ~ Service ^ Development Gas ~ rgle Zone 2. Operator Name: Marathon Oil Company 5. Bond: Blanket ~ Single Well Bond No. 5194234 11. Well Name and Number: KBU 41-6 / 3. Address: P.O. Box 3128, Houston, TX 77253 6. Proposed Depth: MD: 9,721 TVD: 7,837 12. FieldfPool(s): Kenai Gas Field 4a. Location of Well (Governmental Section): Surface: 41' FSL, 994' FEL, Sec. 6, T4N, R11W, S.M. 7. Property Designation: A-028142 Beluga /Upper Tyonek Pool Top of Productive Horizon: 4,551' FSL, 719' FEL, Sec. 6, T4N, R11W, S.M. 8. Land Use Permit: 13. Approximate Spud Date: October 1, 2005 ~ Total Depth: 4,723' FSL, 708' FEL, Sec. 6, T4N, R11W, S.M. 9. Acres in Property: 1,945 14. Distance to Nearest Property: 780 ft 4b. Location of Well (State Base Plane Coordinates): Surface: x - 274,916.45 y - 2,362,054.63 Zone - 4 10. KB Elevation (Height above GL): (21' AGL) 87 feet 15. Distance to Nearest Well Within P ol: 1,620 ft. to KBU 42-6 16. Deviated wells: Kickoff depth: 200 feet Maximum Hole Angle: 49.46 degrees 17. Maximum Anticipated Pressures in psig (see 20 2:'035) Downhole: 3,668 Surface: 1 96 ~ 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 116' 0' 0' 137' 137' 16" 13 3/8" 68 L-80 BTC 1,829' 0' 0' 1,850' 1,652' 580 sacks 12 1/4" 9 518" 40 L-80 BTC 7,253' 0' 0' 7,274' 5,412' 781 sacks i 8 1/2" 3 1/2" 9.3 L-80 EUE 9,700' 0' 0' 9,721' 7,837' 1,136 sacks 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re-Entry Operations) Total Depth MD {ft): Total Depth TVD (ft}: Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD 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 Q Diverter Sketch ~ 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 ~~ ~ ritJ,T~ Phone 713-296-3273 Date September 26, 2005 Commission Use Only Permit to Drill Number: ~ p ~ API Number: r 50- ~j3~- .2.Q SJ ~j Permit A r Date: d See cover letter for other requirements. Conditions of approval S ples r uired Yes ~ No ~ Mud log required Yes ~ No _ro sulfide measures Yes ~ No Directional survey required Yes ~ No Other:.-.. ~;. ~ © ~~ ~ ~ ~ ~ S~e: , APPROVED BY Approved by: THE COMMISSION Date: Form 10-401 Revised 06/2004 v ~ _ QR~GINAL ,~ ,~ Submit inDuplicate • • MARATHON OIL COMPANY DRILLING PROGRAM Kenai Gas Field KBU 41-6 Original 10/26/05 Originator: W.J. Tank Drilling Superintendent: P.K. Berga North America Drilling Manager: B.J. Roy Page 1 of 13 • Table of Contents General Well Data ................................................................................ Geologic Program Summary ................................................................ Summary of Potential Drilling Hazards ................................................. Formation Evaluation Summary ........................................................... Drilling Program Summary ............................................... .................... Casing Program .................................................................................... Casing Design ...................................................................................... Maximum Anticipated Surface Pressure .............................................. BOPE Program ..................................................................................... Wellhead Equipment Summary ........................................................... Directional Program Summary ............................................................. Directional Surveying Summary ............................................ ............... Drilling Fluid Program Summary .......................................................... Drilling Fluid Specifications ................................................................... Solids Control Equipment ..................................................................... Cement Program Summary .................................................................. Bit Summary ......................................................................................... Hydraulics Summary ............................................................................ Formation Integrity Test Procedure ...................................................... ................................................................................3 ................................................................................3 ................................................................................4 ................................................................................4 ................................................................................5 ................................................................................6 ................................................................................6 ................................................................................ 6 ................................................................................ 8 ................................................................................ 9 ................................................................................ 9 ..............................................................................10 ..............................................................................10 ..............................................................................11 ..............................................................................11 .............................................................................12 .............................................................................12 .............................................................................12 .............................................................................13 Page 2 of 13 • ~ General Wetl Data Well Name. KBU 41-6 Lease/License Surface Location 41' FSL, 994' FEL, Sec. 6, T4N, R11W, S.M. WBS Code DX.05.12608.CAP.DRL Slot/Pad Pad 41-7 Field Kenai Gas Field Spud Date 10/1/05 (est.) KB Elev. 87 County/Province Kenai Peninsula API No. Ground Level Elev. 66 State/Country Alaska WeII Class Development Perm. Datum KB Total MD 9,721' Rig Contractor Glacier Drilling Water Depth N/A Total TVD 7,837 Rig Name #1 Water Protection Depth Comments: Geologic Program Summary Formation MD - RKB (ft) TVD - RKB (ft) Pore Pressure (psi) Pore Pressure (ppg) Lithology Possible Fluid Content Sterling A-8 (Not a Prod Target) 4,873 3,617 0.8 - 6.5 Sandstone Gas /Water Beluga (Not a Prod Target) 6,495 4,727 1.5 - 7.3 Sandstone Gas Middle Beluga (Primary Target) 7,296 5,432 3.8 - 8. Sandstone Gas Tyonek (Secondary Target) 9,211 7,327 5.8 9.0 Sandstone Gas Comments: ~~ :Surface Location Coordinates From Lease/Block Lines 41' FSL, 994' FEL, Sec. 6, T4N, R11W, S.M. ~ Latitude 60° 2T 34.673" N Longitude 151° 14' 49.031" W UTM North (Y) 2,362,054.63' UTM East (x) 274,916.45' Tolerance Depth Horizontal Displacement (ft) MD TVD +N/-S +E/-W Tolerance Directional Target (ft) (ft) Location (Y) (X) (ft) Middle Beluga 7,296 5,432 4,551' FSL, 719' FEL, Sec. 6, T4N, R11W, S.M. 4,510 275 Circle 250' radius TD 9,721 7,837 4,723' FSL, 708' FEL, Sec. 6, T4N, R11W, S.M. ~ 4,682 286 Circle 250' radius Comments: Page 3 of 13 • Summarv of Potential Drilling Hazards Hazard Event Discussion Lost Circulation in Low Pressure Sterling and Beluga 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 +/- 4,873 MD (3,617' 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 Summarv Interval LWD Electric logs `Mud Logs Surface None None None 0' - 1,850' MD Intermediate None None Basic with GCA, shale density, temperature in and out, 1,850' - 7,274' MD sample collection (10' samples). Production None Reeves Quad Combo with pressures 7,274' - 9,721' MD throw h i e. Pull GR-Neutron to surface g p p Basic with GCA, shale density, temperature in and out, inside casing. sample collection (10' samples). Completion N/A GR, CCL N/A Coring Requirements: 2 - 90' cores to be taken in the Middle and Lower Beluga zones. Comments: Page 4 of 13 Drilling Program Summary CONDUCTOR: 1. Drive 20" conductor to +/-130 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 va ve, and 16" diverter line. 5. Function test diverter and diverter valve. SURFACE: 1. Drill a 16" hole to 1,850' MD (1,652' TVD) per the directional plan. ~ 2. RIH with 13 3/8" casing and hang off in the elevators. Make up stab-in sub and centralizer on 5" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 13 3/8" casing. Sting out, shear out drill pipe wiper plug, and circulate drill pipe clean. TOOH with inner string. 3. Cut off 13 3/8" casing. ND diverter. 4. Install 13 3/8" slip lock connection X 13 5/8" 5M flanged multibowl wellhead./ 5. NU 13 5/8" 5M BOP'S. Test BOP'S and choke manifold to 250/2,000 psi. 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 7,274' MD (5,412' 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. Pull wear bushing. 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 9 5/8" 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 8 1/2" hole to 9,721' MD (7,837' 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. 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 3 1/2" 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 13 C Casing Program MD (ft) Connection API Ratings Casing Size {in) Top Bottom Weight (Ibs/ft) i;rade Type O. D. (in) Makeup Torque (ft-Ibs) Hole Size (in) ~ ...., m o- a = o ~- v o N ~ ~,°-' F-' 13 3/8 Surface 1,850 68 L-80 BTC 14.375 N/A * 16 5,020 2,260 1,545 9 5/8 Surface 7,274 40 L-80 BTC 10.625 N/A * 12 1/4 5,750 3,090 979 31/2 Surface 9,721 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' Safety Factors Casing Setting Mud Wt Frac. Form Maximum Surface a o Size Weight Depth When Set Grad Press Pressure ~ o c (in) (Ib/ft) Grade (TVD) (Ib/gal) (Ib/gal) (Ib/gal) (psi) ~ 0° U ~ 13 3/8 68 L-80 1,652 9.4 15.0 8.4 0 3.10 2.81 3.82 9 5/8 40 L-80 5,412 9.5 13.0 1.5 1,896 1.58 1.16 2.62 31/2 9.3 L-80 7,387 10.0 15.0 9.0 1,896 1.15 2.52 1.30 Comments: Max overpull on the 3 1/2" casing must be limited to 90,000 lbs. Maximum Anticipated Surface Pressure Casing Size (m) Setting Depth'" TVD (ft) MAWP * - (psi) MASP "* (psi) ', Mud/Gas Ratio 13 3/8 1,652 3,420 0 30/70 9 5/8 5,412 3,997 1,896 30/70 31/2 7,387 6,908 1,896 30/70 - mHVVr = nnaximum allowable working pressure ** MASP =Maximum anticipated surface pressure Comments: MASP / MAWP CALCULATIONS: Surface casing: 13 3/8"~1 850' MD 1 652' TVD) MASPfrac _ ((Fracture gradient at shoe + S.F.) x .052 x TVDSnoe) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 x 1,652' - (.1 psi/ft x 1,652') MASPfrac = 1,332 psi - 165 psi MASPfrac = 1,167 psi. Page 6 of 13 • MASPbnP = BHPope„ nae fa -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnP = (1.5 ppg x .052 x 5,412') - (0.3 x 9.5 ppg x .052 x 5,412') - (0.7 x 0.1 psi/ft x 5,412') MASPbnP = 422 psi - 802 psi - 379 psi MASPbnP = 0 psi MASP =MASPbnP = 0 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAW P = (0.7 x 5,020) - (9.4 - 8.3) x .052 x 1,652' MAWP = 3,514 psi - 94 psi = 3,420 psi Intermediate casing: 9 5/8" (7 274' MD 5 412' ND) MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x NDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (13.0 ppg + 0.5 ppg) x .052 X 5,412' - (.1 psi/ft x 5,412') MASPrrac = 3,799 psi - 541 psi MASPrrac = 3,258 psi. MASPbnP = BHPaPe„ noiefa -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnP = (9.0 ppg x .052 x 7,837') - (0.3 x.10.0 ppg x .052 x 7,837') - (0.7 x 0.1 psi/ft x 7,837') MASPbnP = 3,668 psi -1,223 psi - 549 psi MASPnnP = 1,896 psi MASP =MASPbnP = ,896~si 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 5,412' MAWP = 4,025 psi - 28 psi = 3,997 psi Production casing: 3 1/2" (9 721' MD 7 837' TVD) MASPfrac =((Fracture gradient at shoe + S.F.) x .052 x NDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPfrac = (15.0 ppg + 0.5 ppg) x .052 X 7,837' - (.1 psi/ft x 7,837') MASPfrac = 6,317 psi - 784 psi MASPfrac = 5,533 psi. MASPbnP = BHPoPe„ Hole to -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnP = (9.0 ppg x .052 x 7,837'} - (0.3 x 10.0 ppg x .052 x 7,837') - (0.7 x 0.1 psi/ft x 7,837') MASPbnP = 3,668 psi - 1,223 psi - 549 psi MASPbnP = 1,896 psi MASP =MASPbnP = ,89 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 7,837' MAWP = 7,112 psi - 204 psi = 6,908 psi Page 7 of 13 • • BOPE Program Casing Test Test. Casing Test Fluid Pressure Size MAWP MASP press Density BOPS. Low/High Casing (in) (psi) (psi) (psi) (Ib/gal) Size & Rating (psi) (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Surface 13 3/8 3,420 0 2,000 9.4 (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) 13-5/8" 5M pipe ram Intermediate 9 5/$ 3,997 1,896 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) 13-5/8" 5M pipe ram Production 3 1/2 6,908 1,896 2,000 10.0 (1) 13 5/8" 5M blind ram 250/2,000 (1) 13-5/8" 5M drilling spool with 3-1 /8" 5M outlets Comments: Blowout Preventers I The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-118" x 5000 psi outlets. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke: Also included is a poor-boy gas buster, and 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. Page 8 of 13 • • Wellhead Equipment Summary Component Description Casing Hanger Type Casing Head 13-5/8" 3M X 13-3/8" Slip Loc W/ 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL1, 13 5/8" x 9 5!8" Fluted PR1 Mandrel Tubing Head 13-5/8" 3M Studded Bottom X 13-5/8" 5M Flg Top, W/ 2, 2-1l16" 5M Studded Outlets, 13 5/8" x 3 1/2" Manua! U,AA,PSL1,PR1 Siip Adapter Flange 13-5l8" 5M X 3-1t8" 5M W/ Seal Pocket and 3" H BPV Threads ~.ommenis: c;omroi Imes ana eiectrlc cable for the EXCAPE system will be routed through the tubing head side outlet. Directional Program Summary Build Turn Coordinates Sec. No. Description MD (ft) TVD (ft) Rate (°/100') Rate. (°/100') Dogleg. (°/100') Inclination (deg).: Azimuth (deg) +N/-S (ft) +EI-W (ft)` VS (ft) 1 Tie On 0 0 0 0 0 0 3.49 0 0 0 2- KOP 200.00 200.00 0 0 0 0 3.49 0 0 0 3 Build up Section 3.00 0 3.00 / 3.49 4 End of Build 1,848.52 1,651.30 3.00 0 3.00 49.46 3.49 667.14 40.68 668.38 5 Hold Sectiart 0 0 0 49.46 3.49 6 End of Hold 5,822.98 4,234.86 0 0 0 49.46 3.49 3,681.74 224.50 3,688.58 7 t7rap Section -2.00 0 2.00 3.49 3 Drop to the Target 7,295.76 5,432.00 -2.00 0 2.00 20.00 3.49 4,510.00 275.00 4,518.38 9 End of Drop 8,295.76 6,411.82 -2.00 0 2.00 0.00 3.49 4,682.45 285.52 4,691.14 10 TD 9,720.94 7,837.00 0 0 0 0.00 3.49 4,682.45 285.52 4,691.14 Comments: Vertical section calculated from a reference azimuth of 3.49° taken from surface location to bottom hole location. Potential Well Interference: Well Distance (ft) Depth (MD) KBU 43-7X 53.83 574 KBU 33-6 98.07 0 KBU 42-7 131.30 230 KBU 33-6X 134.17 413 KTU 24-6H 171.75 344 KBU 42-6 186.63 549 No serious interference exists. See attached directional plan and anticollision analysis for more details. ~ Page 9 of 13 • ~ 1 c O O N_ t a m m _U N N 2 - - _ _.__ -2000 -1000 0 1000 2000 West(-East(+) (1500 ft/in) Directional Surveying Summary Interval MWD Survey Magnetic Multishot Gyro Multishot Comments 0 - 1,850' X ___ 1,850' - 7,274' X 7,274' - 9,721' X Comments: Drilling Fluid Program Summary Interval - TVD Minimum Inventory From -To, Density Gel --- (ft) (ft) (Ib/gal) Fluid. Description Additives Viscosifier Barite 0 1,652 8.6 - 9.4 Gel / Gelex Spud Mud Gel, Gelex, Soda Ash, Caustic, Barite, Polypac Supreme UL, Sodium Meta Bisulfate Flo-Vis, Polypac Supreme UL, KCI, 1,652 5,412 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, 5,412 7,837 9.0 - 10.0 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 13 • Drilling Fluid Specifications C, ' .Interval -TVD LSRV From (ft) To (ft) Density (Ib/gal) Vis (sec/gt) 1 min (Ib./100ftZ) PV (cP) YP (Ib/100 ft2) Fluid Loss (cc) RH Drill Solids (%) 0 1, 652 8.6 - 9.4 60 - 100 N/A 25 - 35 NC - 12 +f- 9.5 < 7 5 1 . , 652 5,412 9.0 - 9.5 40,000 + 8 - 12 7 - 9 +/- 9.5 +/- 5 5,412 7,837 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 %2°' 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 Equipment o ~ a~ ~~ 'c rn L ~ ~ p L ~ . (~ m . 0). Interval t ~ N. o ~ . o ~ ~ C U ~ U w U Q N Comments 0 - 9,721' MD X X X X Closed Loop System, Full Containment Item Equipment Specifications. (quantity, design type, brand, model, flow. capacity, etc) Shaker 2 -Derrick Model 2E48-90F-3TA Desander• N/A Desilter 1 -Derrick Model 0522 Mud Cleaner NIA Centrifuge 2 - MI/Swaco units Cuttings Dryer N/A Cuttings Injection Marathon G&I Facility Zero Discharge N/A Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. Page 11 of 13 • ~ Cement Program Summary De pth. Gauge Top of Cement Casing Hole .Ann Vol Slurry WOC Size MD TVD Size MD TVD To TOC Vol Time (~n) (ft) (ft) (in) (ft) (ft) (ft3) (ft3) (hrs) 13 3!8 1,850 1,652 16 0 0 849 1,457 8 9 5f8 7,274 5,412 12 1/4 4,000 3,050 1,025 1,572 8 3112 9,721 7,837 81/2 6,700 4,897 1,007 1,329 N/A Open Hole Excess 75 50 40 Casing ` Mix Water Compressive Size i l Density Qty Yield Slurry Vol TOC MD Qty WL FW Strength (Psi) ( n} 13 3/8 S urry Cement Description (Ib/gal) (sx) (ft3/sx) (ft3) (ft) (gal/sx) Type (cc) (%) 8 hr 24 hr Tail Type I Cement 12.0 580 2.51 1,457 0 11.28 Fresh 812 0 196 818 " " 9 5/8 Lead Class G 12.5 509 2.10 1,068 4,000 11.92 Fresh 273 769 T il " " . a Class G 13.5 272 1.85 504 6,274 9.31 Fresh 0 0 208 981 3 112 " " Tail G Class 15.8 1,136 1.17 1,329 6,700 4.97 Fresh 24 0 226 2,632 comments: See cement prognosis for details and spacer specifications. Bit Summary Interval - MD TYpe Recomm nded e Estima ted .From To Size' WOB -- Rotating -- - ROP (ft) (ft) _ (in) Manufacturer Model No. IADC (kips) RPM. . Hours (ft/hr•) 0 1,850 16 Christensen MX-1 115 1 - 4 80 - 350 1,850 7,274 12 1!4 Christensen HCM406 M333 Up to 50 Motor 7,274 9,721 8 112 Christensen HCM605 M323 Up to 25 Motor Comments: If a second bit is necessary for the 12'/<" hole a MX-C3 (IADC 137) should be used to finish this section. Back up bits for the 8 %" hole section will consist of mill tooth and TCI tricone bits. See bit prognosis for additional information. Hydraulics Summary Rig mud pumps available are shown below. Max Press @ Displacement @ Liner ID Stroke 90o/a Wp 95°/a eff Max Rate Qty Make Model (in) (in} (psi) (gal/stroke) (spm/gpm) Hole Sections Used On National Oil 5 8 2'597 2.04 125 / 255 Surface 3 Well A600PT 5 8 2,597 2.04 125 / 255 Intermediate 5 8 2,597 2.04 125 / 255 Production Page 12 of 13 .7 Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Depth-MD (ft) Hole Size (in) Pump Rate (gPm) Standpipe Pressure (Psi) Min AV (fpm) ECD (1b/gal) Nozzle Size (32"s) Remarks 0 -1,850 16 650+ 1,500 69 3 -18's 1-15 1 850 7 2 , - , 74 7 274 12 1/4 662 2,000 130 6 - 13's Actual Data from CLU 8 (@ 6,722' MD) , - 9,721 8 1/2 477 1,400 247 5 -15's Actual Data from KBU 11-8X (@ 7,659' MD) Comments: See separate hydraulics calculations. Annular velocities in the 16", 12'/4", and 8 %" 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. Formation Inteprity 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 13 of 13 MARATHON Oil Company Location: Kenai Peninsula, Alaska Slot: Slot #KBU41-6 Field: Kenai Gas Field Well: KBU41-6 Installation: Pad 41-7 Wellbore: KBU41-ti Vert M~R~tT~(~~1 Scale 1 cm = 200 ft East (feet) -> KOP -400 -0 400 800 ' 6.00 I ' I I 5200 12.00 DLS: 3.00 deg/100ft 4800 24.00 3 112" Liner TD Top Mid Beluga 30.00 9 5/8" Casing 4400 36.00 42.00 48.00 4000 13 3i8" Casing End of Build End of Hold 3600 3200 2800 Z 2400 ~ 3 -w 2000 ~ ..r 1600 End of Hold 45.46 1200 41.46 DLS: 2.00 degl100ft 33.46 800 29.46 End of Build 1~3 3/8" Casing WELL PROFILE DATA Point MD Inc Azi TVD North East degn00n V. Sect Tie on OAO 0.00 0.00 0.00 0.00 0.00 D.00 0.00 KOP 200.00 0.00 3.49 200.00 0.00 0.00 0.00 0.00 End of Build 1848.52 49.46 3.49 1651.30 687.14 40.68 3.00 668.38 Entl of Hold 5822.98 49.46 3.49 4234.86 3681.74 224.50 0.00 3686.68 Target 7295.76 20.00 3.49 5432.00 4510.00 275.00 2.00 4518.36 End of Drop 8295.78 0.00 3.49 6411.82 46112.45 285.52 2.00 4691.14 T.D. & End of Hold 9720.94 0.00 3.49 7837.00 4682.45 285.62 0.00 4691.14 Created by: Planner Date plotted : i6Sep-2005 Plot reference is KBU41-6 Ver 2. Ref wellpafh is KBUAS-6 Ver 2. Coordinates are in feet reference Slot #KBU41~. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Planned G1 Rig Datum to mean sea level: 87.00 ft. Plot North is aligned to TRUE North. 25.46 9 518" Casin ~ 400 ~ g 21.46 m Top Mid Beluga m 16.00 KOP 0 ~ 3 12.00 I I DLS: 2.00 deg/100ft -400 0 O 4.00 ~ End of Drop BA1^i~Es~R !~ I L~IP~.~ 3 1/2" Liner TD -400 -0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 Scale 1 cm = 200 ft Vertical Section (feet) -> Azimuth 3.49 with reference 0.00 N, 0.00 E from Slot #KBU41-6 PROPOSAL LISTING Page 1 Wellbore: KBU41-6 Ver 2 Wellpath: KBU41-6 Ver 2 Date Printed: 16-Sep-2005 BAKER HUG~~$ I~TE(~ Wellbore Name Created Last Revised KBU41-6 Ver 2 22-Au -2005 16-Se -2005 Well -_ - - Name GovernmentlD Last Revised - -- --- KBU41-6 30-Au -2005 - Slot ~--- ---- -- ___Name_.___~ _Grid Northin Grid Easting }-- Latitude-_ ___L_on itude-_ North_~ E-as-t- Slot #KBU41-6 ~ 2362054 6300 274916 4500 I N60 27 34 6726 W151 14 49 0310 ~67 75N I 4000 05E Created By ,Comments --_ _ All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Planned G1 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.14 Feet on azimuth 3.49 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated • MARATHON Oil Company,Slot #KBU41-6 Pad 41-7, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska PROPOSAL LISTING Page 2 Wellbore: KBU41-6 Ver 2 Wellpath: KBU41-6 Ver 2 Date Printed: 16-Sep-2005 II!'pKER NU+GHE 1~TEt~ Well ath Grid Re ort MD[ftj Inc[degl Azi[degl ND[ft] North[ft] Easf[ft} Dogleg de /1AOft Vertical Section ft Fasting Northing 0.00 0.00 0.00 0.00 O.OON 0.00E 0.00 0.00 274916.45 2362054.63 100.00 0.00 0.00 100.00 O.OON 0.00E 0.00 0.00 274916.45 2362054.63 200.00 0.00 3.49 200.00 O.OON 0.00E 0.00 0.00 274916.45 2362054.63 300.00 3.00 3.49 299.95 2.61N 0.16E 3.00 2.62 274916.66 2362057.24 400.00 6.00 3.49 399.63 10.44N 0.64E 3.00 10.46 274917.28 2362065.06 500.00 9.00 3.49 498.77 23.47N 1.43E 3.00 23.51 274918.33 2362078.07 600.00 12.00 3.49 597.08 41.66N 2.54E 3.00 41.74 274919.78 2362096.23 700.00 15.00 3.49 694.31 64.96N 3.96E 3.00 65.08 274921.64 2362119.50 800.00 18.00 3.49 790.1 93.30N 5.69E 3.00 93.48 274923.90 2362147.80 900.00 21.00 3.49 884.43 126.62N 7.72E 3.00 126.85 274926.57 2362181.07 1000.00 24.00 3.49 976.81 164.81N 10.05E 3.00 165.12 274929.62 2362219.21 1100.00 27.00 3.49 1067.06 207.78N 12.67E 3.00 208.16 274933.05 2362262.12 1200.00 30.00 3.49 1154.93 255.40N 15.57E 3.00 255.87 274936.86 2362309.68 1300.00 33.00 3.49 1240.18 307.55N 18.75E 3.00 308.12 274941.02 2362361.75 1400.00 36.00 3.49 1322.59 364.07N 22.20E 3.00 364.75 274945.54 2362418.20 1500.00 39.00 3.49 1401.91 424.83N 25.90E 3.00 425.62 274950.39 2362478.88 1600.00 42.00 3.49 1477.94 489.65N 29.86E 3.00 490.56 274955.57 2362543.60 1700.00 45.00 3.49 1550.47 558.35N 34.05E 3.00 559.38 274961.06 2362612.21 1800.00 48.00 3.49 1619.30 630.74N 38.46E 3.00 631.91 274966.84 2362684.50 1848.52 49.46 3.49 1651.31 667.14N 40.68E 3.00 668.38 274969.75 2362720.85 1900.00 49.4 3.49 1684.77 706.19N 43.06E 0.00 707.50 274972.87 2362759.84 2000.00 49.46 3.49 1749.78 782.04N 47.69E 0.00 783.49 274978.93 2362835.59 2100.00 49.46 3.49 1814.78 857.89N 52.31E 0.00 859.48 274984.99 2362911.33 220 .00 49.4 3.49 1879.78 933.74N 56.94E 0.00 935.47 274991.05 2362987.08 2300.00 49.46 3.49 1944.79 1009.59N 61.56E 0.00 1011.46 274997.11 2363062.82 2400.00 49.46 3.49 2009.79 1085.43N 66.19E 0.00 1087.45 275003.17 2363138.57 2500.00 49.46 3.49 2074.79 1161.28N 70.81E 0.00 1163.44 275009.23 2363214.31 2600.00 49.46 3.49 2139.80 1237.13N 75.44E 0.00 1239.43 275015.29 2363290.06 2700.00 49.46 3.49 2204.80 1312.98N 80.06E 0.00 1315.42 275021.35 2363365.80 2800.00 49.46 3.49 2269.80 1388.83N 84.69E 0.00 1391.41 275027.41 2363441.55 2900.00 49.46 3.49 2334.81 1464.68N 89.31E 0.00 1467.40 275033.47 2363517.29 3000.00 49.46 3.49 2399.81 1540.53N 93.94E 0.00 1543.39 275039.53 2363593.04 3100.00 49.46 3.49 2464.82 1616.38N 98.56E 0.00 1619.38 275045.59 2363668.78 3200.00 49.46 3.49 2529.82 1692.23N 103.19E 0.00 1695.37 275051.65 2363744.53 3300.00 49.46 3.49 2594.82 1768.08N 107.81E 0.00 1771.36 275057.71 2363820.27 3400.00 49.46 3.49 2659.83 1843.93N 112.44E 0.00 1847.35 275063.77 2363896.02 3500.00 49.46 3.49 2724.83 1919.78N 117.06E 0.00 1923.34 275069.83 2363971.76 3600.00 49.46 3.49 2789.84 1995.63N 121.68E 0.00 1999.33 275075.89 2364047.51 3700.00 49.46 3.49 2854.84 2071.47N 126.31E 0.00 2075.32 275081.95 2364123.25 3800.00 49.46 3.49 2919.84 2147.32N 130.93E 0.00 2151.31 275088.01 2364198.99 3900.00 49.46 3.49 2984.85 2223.17N 135.56E 0.00 2227.30 275094.07 2364274.74 4000.00 49.46 3.49 3049.85 2299.02N 140.18E 0.00 2303.29 275100.13 2364350.48 4100.00 49.46 3.49 3114.86 2374.87N 144.81E 0.00 2379.28 275106.19 2364426.23 4200.00 49.46 3.49 3179.86. 2450.72N 149.43E 0.00 2455.27 275112.25 2364501.97 4300.00 49.46 3.49 3244.86 2526.57N 154.06E 0.00 2531.26 275118.31 2364577.72 4400.00 49.46 3.49 3309.87 2602.42N 1.58.68E 0.00 2607.25 275124.37 2364653.46 4500.00 49.46 3.49 3374.87 2678.27N 163.31E 0.00 2683.24 275130.43 2364729.21 4600.00 49.46 3.49 3439.87 2754.12N 167.93E 0.00 2759.23 275136.49 2364804.95 4700.00 49.46 3.49 3504.88 2829.97N 172.56E 0.00 2835.22 275142.55 2364880.70 4800.00 49.46 3.49 3569.88 2905.82N 177.18E 0.00 2911.21 275148.61 2364956.44 4900.00 49.46 3.49 3634.89 2981.67N 181.81E 0.00 2987.20 275154.67 2365032.19 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Planned G1 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.14 Feet on azimuth 3.49 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated • MARATHON Oil Company,Slot #KBU41-6 Pad 41-7, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska • PROPOSAL LISTING Page 3 Wellbore: KBU41-6 Ver 2 Wellpath: KBU41-6 Ver 2 Date Printed: 16-Sep-2005 IEIt~'lKER IEUCslrl<E I~TEC~ Well .ath Grid Re ort MD[ft] Inc[deg] Azi[deg] 7VD[ft] North[ft] East[ft] Dogleg Vertical Fasting _ Northing de 7100ft Sec ion ft 5000.00 49.46 3.49 3699.89 3057.51 N 186.43E 0.00 3063.19 275160.73- 2365107 93 5100.00 49.46 3.49 3764.89 3133.36N 191.06E 0.00 3139.18 275166.79 . 2365183 68 5200.00 49.46 3.49 3829.90 3209.21 N 195.68E 0.00 3215.17 275172.85 . 2365259 42 5300.00 49.46 3.49 3894.90 3285.O6N 200.31E 0.00 3291.16 .275178.91 . 2365335 17 5400.00 49.46 3.49 3959.91 3360.91N 204.93E 0.00 3367.15 275184.97 . 2365410 91 5500.00 49.46 3.49 4024.91 3436.76N 209.56E 0.00 3443.14 275191.03 . 2365486 66 5600.00 49.46 3.49 4089.91 3512.61N 214.18E 0.00 3519.13 275197.09 . 2365562.40 5700.00 49.46 3.49 4154.92 3588.46N 218.81E 0.00 3595.13 275203.15 2365638 15 5800.00 49.46 3.49 4219.92 3664.31N 223.43E 0.00 3671.12 275209.21 . 2365713 89 5822.98 49.46 3.49 4234.86 3681.74N 224.50E 0.00 3688.58 275210.60 . 2365731 30 5922.98 47.46 3.49 4301.18 3756.44N 229.05E 2.00 3763.42 275216.57 . 2365805 89 6022.98 45.46 3.49 4370.06 3828.79N 233.46E 2.00 3835.90 275222.35 . 2365878 14 6122.98 43.46 3.49 4441.44 3898.69N 237.72E 2.00 3905.93 275227.94 . 2365947 95 6222.98 41.46 3.49 4515.22 3966.06N 241.83E 2.00 3973.43 275233.32 . 2366015 23 6322.98 39.46 3.49 4591.30 4030.82N 245.78E 2.00 4038.31 275238.49 . 2366079 90 6422.98 37.46 3.49 4669.61 4092.90N 249.57E 2.00 4100.50 275243.45 . 2366141 89 6522.98 35.46 3.49 4750.04 4152.20N 253.18E 2.00 4159.92 275248.19 . 2366201 11 6622.98 33.46 3.49 4832.49 4208.67N 256.63E 2.00 4216.49 275252.70 . 2366257 50 6722.98 31.46 3.49 4916.86 4262.23N 259.89E 2.00 4270.15 275256.98 . 2366310 99 6822.98 29.46 3.49 5003.06 4312.82N 262.98E 2.00 4320.84 275261.02 . 2366361 51 6922.98 27.46 3.49 5090.98 4360.38N 265.88E 2.00 4368.48 275264.82 . 2366409 00 7022.98 25.46 3.49 5180.50 4404.85N 268.59E 2.00 4413.03 275268.38 . 2366453 41 7122.98 23.46 3.49 5271.52 4446.17N 271.11E 2,00 4454.43 275271.68 . 2366494 67 7222.98 21.46 3.49 5363.94 4484.29N 273.43E 2.00 4492.62 275274.72 . 2366532 74 7295.76 20.00 3.49 5432.00 4510.OON 275.00E 2.00 4518.38 275276.78 . 2366558 41 7395.76 18.00 3.49 5526.55 4542.49N 276.98E 2.00 4550.93 275279.37 . 2366590 86 7495.76 16.00 3.49 5622.17 4571.68N 278.76E 2.00 4580.17 275281.70 . 2366620.01 7595.76 14.00 3.49 5718.76 4597.51 N 280.34E 2.00 4606.05 275283.77 2366645 80 7695.76 12.00 3.49 5816.19 4619.96N 281.70E 2.00 4628.54 275285.56 . 2366668.22 7795.76 10.00 3.49 5914.35 4639.01 N 282.87E 2.00 4647.62 275287.08 2366687.24 7895.76 8.00 3.49 6013.11 4654.62N 283.82E 2.00 4663.26 275288.33 2366702 84 7995.76 6.00 3.49 6112.36 4666.78N 284.56E 2.00 4675.45 275289.30 . 2366714 98 8095.76 4.00 3.49 6211.98 4675.48N 285.09E 2.00 4684.17 275290.00 . 2366723 67 8195.76 2.00 3.49 6311.84 4680.71 N 285.41E 2.00 4689.40 275290.42 . 2366728 89 8295.76 0.00 3.49 6411.82 4682.45N 285.51E 2.00 4691.14 275290.55 . 2366730 62 8300.00 0.00 3.49 6416.06 4682.45N 285.51E 0.00 4691.14 275290.55 . 2366730 62 8400.00 0.00 3.49 6516.06 4682.45N 285.51E 0.00 4691.14 275290.55 . 2366730.62 8500.00 0.00 3.49 6616.06 4682.45N 285.51E 0.00 4691.14 275290.55 2366730 62 8600.00 0.00 3.49 6716.06 4682.45N 285.51E 0.00 4691.14 275290.55 . 2366730 62 8700.00 0.00 3.49 6816.06 4682.45N 285.51E 0.00 4691.14 275290.55 . 2366730 62 8800.00 0.00 3.49 6916.06 4682.45N 285.51E 0.00 4691.14 275290.55 . 2366730 62 8900.00 0.00 3.49 7016.06 4682.45N 285.51E 0.00 4691.14 275290.55 . 2366730 62 9000.00 0.00 3.49 7116.06 4682.45N 285.51E 0.00 4691.14 275290.55 . 2366730 62 9100.00 0.00 3.49 7216.06 46$2.45N 285.51E 0.00 4691.14 275290.55 . 2366730.62 9200.00 0.00 3.49 7316.06 4682.45N 285.51E 0.00 4691.14 275290.55 2366730.62 9300.00 0.00 3.49 7416.06 4682.45N 285.51E 0.00 4691.14 275290.55 2366730.62 9400.00 0.00 3.49 7516.06 4682.45N 285.51E 0.00 4691.14 275290.55 2366730 62 9500.00 0.00 3.49 7616.06 4682.45N 285.51E 0.00 4691.14 275290.55 . 2366730.62 9600.00 0.00 3.49 7716.06 4682.45N 285.51E 0.00 4691.14 275290.55 2366730.62 9700.00 0.00 3.49 7816.06 4682.45N 285.51E 0.00 4691.14 275290.55 2366730.62 9720.94 0.00 3.49 7837.00 4682.45N 285.51E 0.00 4691.14 275290.55 2366730.62 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Planned G1 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.14 Feet on azimuth 3.49 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated s PROPOSAL LISTING Page 4 Wellbore: KBU41-6 Ver 2 Wellpath: KBU41-6 Ver 2 Date Printed: 16-Sep-2005 NI~#GN I~TEQ _ ('_nmrrsnr~f~ - MD ft ND ft North ft Eastft Comment 200.00 200.00 O.OON 0.00E KOP 1848.52 1651.31 667.14N 40.68E End of Build 5822.98 4234.86 3681.74N 224.50E End of Hold 7295.76 5432.00 4510.OON 275.00E To Mid Belu a 8295.76 6411.82 4682.45N 285.51E .End of Dro 9720,94 7837.00 4682.45N 285.51E TD ~ _ ~ Diameter ~n _L ___ Hole Sections Start Start Start Start End ~ ---~--- ~ ~- MD ft NDLj_ North ft _ .Eastft _ MD ft ~ End - - ~-End NDfft1 NorthL~ __ _ Start ~- Eastft ___ ' Wellbore 16.000 0.00 0.00 O.OON 0.00E 1850.00 1652.27 668.26N 40.75E KBU41-6 Ver 2 12 114 1850.00 1652.27 668.26N 40.75E 7274.44 5412.00 4502.65N 274.55E KBU41-6 Ver 2 8 1/2 7274.44 5412.00 4502.65N 274.55E 9720.94 7837.00 4682.45N 285.51E KBU41-6 Ver 2 --T--- Name ~ Top __ _~_ MDfftl -- Top NDfftl r- T- Casin s Top Top Shoe NorthLl _ Eastft MD ft --- Shoe N.Dfftl _ Shoe North ft - - ~ Shoe ~ Wellbore East[fll _ __ _ 13 3i8" Casin 0.00 0.00 O.OON 0.00E 1850.00 1652.27 668.26N 40.75E __ KBU41-6 Ver 2 9 5/8" Casin 0.00 0.00 O.OON 0.00E 7274.44 5412.00 4502.65N 274.55E KBU41-6 Ver 2 3 112" Liner 0.00 0.00 O.OON 0.00E 9720.94 7837.00 4682.45N 285.51E KBU41-6 Ver 2 r - -- - -- --- - ----- --- - ----- ~ _ _ __ Tar ets I Name _ North ft East ftL TVDjftL _ _ ~__Latitude _ ___ _ _ Lon itude ~ Eastin~ ~- Norhting -{ Last Revised I KBU41-6 -TD - 4688.94N 291.84E 7837.00 N60 28 20.84 W151 1443.20 _ 275297.00 __ _ 2366737.00 _ 22-Apr-2004 8/22/05 KBU41-6 -T/Mid 4688.94N 291.84E 5432.00 N60 28 20.84 W151 1443.20 275297.00 2366737.00 22-Apr-2004 Reluna _ 9/1F/n5 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Planned G1 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 3.49 degrees Bottom hole distance is 4691.14 Feet on azimuth 3.49 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~-,~R MARATHON Oil Company N(,~~~ Location: Kenai Peninsula, Alaska Slot: Slot #KBU41-6 Field: Kenai Gas Field Well: KBU41-6 rNTEQ Installation: Pad 41-7 Wellbore: KBU41-6 Ver 2 lV1ARATHQN scale 1 cm = 25 ftEast (feeta -> Scale 1 cm = 100 ~aSt feet -> -150 -100 -50 0 5 100 150 .200 -400 -200 -0 00 )400 600 800 ybU i0 4800 900 ~0 4600 850 i0 4400 800 ~0 4200 750 i0 4000 700 ~p 3800 650 i0 3600 600 ~p 3400 550 ;p 3200 ~ 500 ~p 3000 450 ;0 ~ 2800 Z 400 i0 2600 350 ;p 2400 300 i0 2200 250 0 2000 200 ip 1800 150 p 1600 100 0 ~ 1400 N 50 i~ 1200 U 0 N 1000 ~ -50 4800 4600 4400 4200 4000 3800 3600 3400 3200 A 3000 OZ 3 2800 ~D rr ~... 2600 2400 2200 2000 1800 1600 1400 ~ n m 1200 ~ I 1000 O -150 -100 -50 -0 50 100 150 200 -400 -200 0 200 400 600 800 scale 1 cm = 25 ftEast (feet) -> Scale 1 cm =100 ~BSt (feet) -> ~K~ MARATHON Oil Company H1f116,E1ES Location: Kenai Peninsula, Alaska Slot: Slot #KBU41-li Field: Kenai Gas Field Weli: KBU41-6 ~~T~Q Installation: Pad 41-7 Wellbore: KBU41-6 Ver 2 Created by : Planner Date plotted : 16-Sep-2005 Plot reference is KBU41-6 Ver 2. Ref wellpaM is KBU41-6 Ver 2 Coordinates are in feet reference Slot#KBU4t-G. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Planned G1 Rig Datum to mean sea level: 87.00 ft. Plat Norlh is a{igned to TRUE North. 290 280 270 260 250 TRUE NORTH 350 0 10 NIARAiHQN 70 80 90 100 10 Normal Plane Travelling Cylinder - FeetAll depths shown are Measured depths on Reference Well 340 20 • • n~Al~arwoN 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-C)!E Factor Calculation Wellbore Created _ Installation MARATHON Oil Company CLEARANCE LISTING Page 1 ~ ' KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 NUGtIEES Slot #KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, Alaska ~~~~~ ~_ _ _Pad 41-7 _ i - -- -_Name _ - r Kenai Gas Field `--- -- 101 Field Coord S_ stem _ - - Eastin~ _ Northin~_ _ Coord System Name __- - _ North Al~mei __ 270993.1910- _ 2361975.0460 i AK-4 on NORTH AMERICAN DATUM 1927 datum True ___ - __ _ Clearance Summary Offset ~ WellNarne __ ~---- Offset ~ Offset Offset Minimum MD[ft] ~~Diverging Ellipse ~-Ellipse Clearance Clearance Wellbore ~ Slot Structure Distance F ft S ~ l --~ rom[ j eparation MD[ftj Factor MD[ft] L ~ 1 1-- -- I~---~----- --- KBU43-7X -~-- KBU43-7X Slot Pad 41-7 53.83 574.15 574.15 51.30 574.15 20.01 639.76 #KBU43-7X KBU33-6 KBU33-6 slot Pad 41-7 98.07 0.00 0.00 #KBU33-6 KBU42-7 KBU42-7 slot Pad 41-7 131.30 229.66 229.66 130.34 229.66 64.06 771.00 #KBU42-7 KBU33-6X KBU33-6X Slot Pad 41-7 134.17 412.99 412.99 132.52 442.91 39.36 951.44 #KBU33-6X KTU24-6H KTU24-6H slot#24-6 Pad 41-7 171.75 344.49 344.49 170.46 360.89 59.29 935.04 KTU24-6H KTU24-6H slot #24-6 Pad 41-7 171.75 344.49 344.49 170.46 360.89 59.29 935.04 Pilot KTU24-6H KTU24-6H slot#24-6 Pad 41-7 171.75 344.49 344.49 170.46 360.89 59.29 935.04 RD KBU42-6 KBU42-6 Slot Pad 41-7 186.63 549.14 549.14 177.76 1459.97 7.65 2181.76 #KBU42-6 KBU11-8X KBU11-8X slot Pad 41-7 236.36 557.96 557.96 234.00 574.15 55.35 1049.87 #KBU11-8X All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 KBU41-6 Ver 2, KBU41-6 Ver 2 14tAltATNON Slot #KBU41-6, Pad 41-7 CLEARANCE LISTING Page 2 ~~> ~i Date Printed: 16-Sep-2005 HUGHES Kenai Gas Field, Kenai Peninsula, INTEQ Alaska _ Gleara nce Summer, Offset WeIlName Offset Weltbore Offset Slot Offset Structure Minimum Distance ft MD[ftJ Diverging From[ft} Ellipse Separation. ft Ellipse MD[ft] Clearance Clearance Factor MD[ftj KTU32-7 KTU32-7 slot #32-7 Pad 41-7 236.63 213.25 213.25 235.68 229.66 64.88 967.85 KU13-5 KU13-5 slot Pad 41-7 262.35 0.00 0.00 262.02 49.21 85.19 623.36 #KTU 13-5 KBU 11-8Y KBU 11-8Y s{ot# Pad 41-7 284.68 535.79 535.79 282.57 557.74 83.13 803.81 KBU11-8Y KBU 44-6 KBU 44-6 slot Pad 41-7 288.30 0.00 0.00 287.91 164.04 139.73 557.74 #KBU44-6 KU43-6 KU43-6 slot #KU 43-6 Pad 41-7 304.45 1281.27 1281.27 297.29 1281.27 40.72 1328.74 KU43-6 KU43-6Rd slot#KU 43-6 Pad 41-7 304.45 1281.27 1281.27 297.29 1281.27 40.72 1328.74 ___ Reference Weltbore Surve~Tool Program Survey Name ___ - _~_ __MDfftl Survev Tool _ Error Model ~ ~ Planned I 9720 94 Navi Trak Standard All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Planned G1 87.Oft 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 MARATHON Oil Company KBU41-6 Ver 2, KBU41-6 Ver 2 Slot #KBU41-6, Pad 41-7 • CLEARANCE LISTING Page 3 Date Printed: 16-Sep-2005 Kenai Gas Field, Kenai Peninsula, Alaska QAKER HUGHES l ti TEQ ~~ Clearance Data Reference MQjftj Reference TVD[ft} Reference Notth[ft] Reference East[ft] OffseYWell Offset MD[ft] Offset TVD[ft] __ Offset North[ft] Offset East[ft] _ Angle From Highside de Closest Approach. Distance ft Ellipse .Separation [ft] 0.00 0.00 O.OON 0.00E KTU24-6H 0.54 0.54 76.475 158.34E 115.8 175.84 175.82 100.00 100.00 O.OON 0.00E KTU24-6H 101.61 101.61 76.14S 157.85E 115.8 175.26 174.77 200.00 200.00 O.OON D.OOE KTU24-6H 203.74 203.72 75.20S 156.42E 115.7 173.59 172.78 300.00 299.95 2.61N 0.16E KTU24-6H 305.06 305.00 73.865 154.05E 113.0 171.92 170.85 344.49 344.35 5.45N 0.33E KTUZ4-6H 349.49 349.41 73.96S 152.53E 114.1 171.75 170.47 360.89 360.70 6.76N 0.41E KTU24-6H 365.83 365.73 74.01S 151.96E 114.6 171.80 170.46 400.00 399.63 10.44N 0.64E KTU24-6H 404.71 404.60 74.14S 150.60E 116.0 172.25 170.75 500.00 498.77 23.47N 1.43E KTU24-6H 504.04 503.86 74.355 147.03E 120.3 175.48 173.55 600.00 597.08 41.66N 2.54E KTU24-6H 602.11 601.87 74.53S 143.53E 125.7 182.76 180.32 700.00 694.31 64.96N 3.96E KTU24-6H 698.60 698.30 74.81S 140.24E 131.5 195.25 192.28 800.00 790.18 93.30N 5.69E KTU24-6H 793.72 793.37 75.20S 137.17E 137.3 213.75 210.26 900.00 884.43 126.62N 7.72E KTU24-6H 887.25 886.86 75.66S 134.44E 142.7 238.70 234.70 935.04 917.03 139.45N 8.50E KTU24-6H 919.74 919.34 75.83S 133.54E 144.4 248.97 244.77 1000.00 976.81 164.81N 10.05E KTU24-6H 978.84 978.42 76.13S 132.13E 147.4 270.11 265.57 1033.46 1007.26 178.66N 10.89E KTU24-6H 1008.72 1008.29 76.26S 131.56E 148.8 282.04 277.30 Offset Weilbore Survev Tool Proarams All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 • 1~4ARATHDN MARATHON Oil Company KBU41-6 Ver 2, KBU41-6 Ver 2 Slot #KBU41-6, Pad 41-7 • CLEARANCE LISTING Page 4 Date Printed: 16-Sep-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~li~ BAKER HUGifE 1NTE(~ _ Clearance Data Reference MD[ft] Reference" TVD[ft] Reference North(ft] Reference East{ft] Offset Welf Offset MD[ft} Offset TVD[ft] Offset ° Northlft] Offset East[ft] Angle From Highs~de de _ Closest Approach Distance ft Ellipse Separation [ft} 0.00 0.00 O.OON 0.00E KTU24-6H 0.54 0.54 76.47S 158.34E 115.8 175.84 175.82 100.00 100.00 O.OON 0.00E KTU24-6H 101.61 101.61 76.14S 157.85E 115.8 175.26 174.77 200.00 200.00 O.OON 0.00E KTU24-6H 203.74 203.72 75.20S 156.42E 115.7 173.59 172.78 300.00 299.95 2.61N 0.16E KTU24~H 305.06 305.00 73.86S 154.05E 113.0 171.92 170.85 344.49 344.35 5.45N 0.33E KTU24-6H 349.49 349.41 73.96S 152.53E 114.1 171.75 170.47 360.89 360.70 6.76N 0.41E KTU24-6H 365.83 365.73 74.01S 151.96E 114.6 171.80 170.46 400.00 399.63 10.44N 0.64E KTU24-6H 404.71 404.60 74.14S 150.60E 116.0 172.25 170.75 500.00 498.77 23.47N 1.43E KTU24-6H 504.04 503.86 74.35S 147.03E 120.3 175.48 173.55 600.00 597.08 41.66N 2.54E KTU24-6H 602.11 601.87 74.53S 143.53E 125.7 182.76 180.32 700.00 694.31 64.96N 3.96E KTU24-6H 698.60 698.30 74.81S 140:24E 131.5 195.25 192.28 800.00 790.18 93.30N 5.69E KTU24-6H 793.72 793.37 75.20S 137.17E 137.3 213.75 210.26 900.00 884.43 126.62N 7.72E KTU24-6H 887.25 886.86 75.66S 134.44E 142.7 238.70 234.70 935.04 917.03 139.45N 8.50E KTU24-6H 919.74 919.34 75.83S 133.54E 144.4 248.97 244.77 1000.00 976.81 164.81N 10.05E KTU24-6H 978.84 978.42 76.13S 132.13E 147.4 270.11 265.57 1033.46 1007.26 178.66N 10.89E KTU24-6H 1008.72 1008.29 7 .26S 131.56E 148.8 282.04 277.30 Wellbore Survey Tool Programs All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 KBU41-6 Ver 2, KBU41-6 Ver 2 MARATHON Slot #KBU41-6, Pad 41-7 CLEARANCE LISTING Page 5 Date Printed: 16-Sep-2005 Kenai Gas Field, Kenai Peninsula, Alaska ~^ BAKER HtlIGt11:~ v`I'EQ - _ C learance Data Reference MD[ft] Reference ND(ftJ Reference North[ft] Reference East[ft] Offset Well Offset MD[ft] Offset ND[ft] Offset North[ftJ Offset East[ft] Angle .From ~ Highside de TClosest Approach ~ Distance ft Ellipse Separation (ft] 0.00 0.00 O.OON 0.00E KTU24-6H 0.54 0.54 76.47S 158.34E 115.8 175.84 175.82 100.00 100.00 O.OON 0.00E KTU24-6H 101.61 101.61 76.145 157.85E 115.8 175.26 174.77 200.00 200.00 O.OON 0.00E KTU24-6H 203.74 203.72 75.205 156.42E 115.7 173.59 172.78 300.00 299.95 2.61N 0.16E KTU24-6H 305.06 305.00 73.865 154.05E 113.0 171.92 170.85 344.49 344.35 5.45N 0.33E KTU24-6H 349.49 349.41 73.965 152.53E 114.1 171.75 170.47 360.89 360.70 6.76N 0.41E KTU24-6H 365.83 365.73 74.015 151.96E 114.6 171.80 170.46 400.00 399.63 10.44N 0.64E KTU24-6H 404.71 404.60 74.14S 150.60E 116.0 172.25 170.75 500.00 498.77 23.47N 1.43E KTU24-6H 504.04 503.86 74.355 147.03E 120.3 175.48 173.55 600.00 597.08 41.66N 2.54E KTU24-6H 602.11 601.87 74.53S 143.53E 125.7 182.76 180.32 700.00 694.31 64.96N 3.96E KTU24-6H 698.60 698.30 74.815 140.24E 131.5 195.25 192.28 800.00 790.18 93.30N 5.69E KTU24-6H 793.72 793.37 75.20S 137.17E 137.3 213.75 210.26 900.00 884.43 126.62N 7.72E KTU24-6H 887.25 886.86 75.665 134.44E 142.7 238.70 234.70 935.04 917.03 139.45N 8.50E KTU24-6H 919.74 919.34 75.83S 133.54E 144.4 248.97 244.77 1000.00 976.81 164.81N 10.05E KTU24-6H 978.84 978.42 76.13S 132.13E 147.4 270.11 265.57 1033.46 1007.26 178.66N 10.89E KTU24-6H 1008.72 1008.29 76.26S 131.56E 148.8 282.04 277.30 Offset Wellbore Survey Tool Programs All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 • • N[ARATH{~N MARATHON O[I Company CLEARANCE LISTING Page 6 ~~~~ KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 NUGNES Slot #KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, TNTEt~ Alaska Clearance Data - Reference !ND[ft] Reference TVD[ft] Reference North[ft] Reference East[ft] OffsefWell Offset MD[ft] Offset TVD[ft] Offset North[ft} Offset East(ft] - Angle from Highside de Closest Approach Distance ft ---- Ellipse Separation [ftJ 0.00 0.00 O.OON 0.00E KTU32-7 0.01 0.01 78.255 223.38E 109.3 236.69 236.69 100.00 100.00 O.OON 0.00E KTU32-7 100.02 100.02 77.92S 223.49E 109.2 236.69 236.20 200.00 200.00 O.OON 0.00E KTU32-7 200.32 200.31 77.OOS 223.76E 109.0 236.63 235.77 213.25 213.25 0.05N 0.00E KTU32-7 213.57 213.57 76.85S 223.79E 105.5 236.63 235.71 229.66 229.66 0.23N 0.01E KTU32-7 229.98 229.97 76.66S 223.83E 105.5 236.66 235.68 300.00 299.95 2.61N 0.16E KTU32-7 300.88 300.87 75.72S 223.93E 105.8 237.09 235.89 400.00 399.63 10.44N 0.64E KTU32-7 402.67 402.65 74.28S 223.72E 107.3 238.64 237.08 500.00 498.77 23.47N 1.43E KTU32-7 504.53 504.48 73.28S 222.23E 110.1 241.14 239.18 600.00 597.08 41.66N 2.54E KTU32-7 603.77 603.68 73.47S 219.33E 114.3 245.55 243.11 700.00 694.31 64.96N 3.96E KTU32-7 701.86 701.67 75.035 215.14E 119.6 253.47 250.46 800.00 790.18 93.30N 5.69E KTU32-7 797.39 796.99 77.99S 209.54E 125.6 266.35 262.73 900.00 884.43 126.62N 7.72E KTU32-7 889.21 888.61 80.83S 204.26E 131.3 285.80 281.57 967.85 947.33 152.OON 9.27E KTU32-7 951.25 950.57 82.29S 201.44E 134.9 303.04 298.37 Offset Wellbore Surve Tool Pro rams Well Wellbore ~ Surve Name MD ft _ Survey Tool Error Model __ 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 (Planned G1 87.Oft 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 CLEARANCE LISTING Page 7 KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 ~UdNES MARATHON Slot #KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, I\TE(~ Alaska _ C learance Data Reference MD[ft] Reference TVD[ft] Reference North[ft] Reference East[ft] Offset Well Offset MD[ft] Offset TVDift] Offset Niirth[ft] Offset East[ft] Ahgle From Hghside de Closest Approach ' Distance ft Ellipse Separation [ft] 0.00 0.00 O.OON 0.00E KBU 11-SY 1.34 0.54 49.65N 288.50E 80.2 292.74 292.71 100.00 100.00 O.OON 0.00E KBU 11-SY 102.41 101.61 49.35N 288.23E 80.3 292.43 291.92 200.00 200.00 O.OON 0.00E KBU 11-8Y 203.75 202.94 48.57N 287.51E 80.4 291.60 290.75 300.00 299.95 2.61N 0.16E KBU 11-SY 304.24 303.42 47.56N 286.62E 77.6 289.99 288.80 400.00 399.63 10.44N 0.64E KBU 11-8Y 403.94 403.11 46.45N 285.45E 79.4 287.10 285.59 500.00 498.77 23.47N 1.43E KBU 11-8Y 497.71 496.87 44.69N 285.58E 82.3 284.95 283.07 535.79 534.06 29.40N 1.79E KBU 11-8Y 529.36 528.4 43.74N 286.06E 83.5 284.68 282.64 557.74 555.65 33.34N 2.03E KBU 11-8Y 550.80 549.91 42.98N 286.52E 84.5 284.71 282.57 600.00 597.08 41.66N 2.54E KBU 11-8Y 589.50 588.57 41.47N 287.60E 86.3 285.19 282.87 700.00 694.31 64.96N 3.96E KBU 11-8Y 676.93 675.79 37.30N 291.91E 91.0 289.87 286.98 500.00 790.18 93.30N 5.69E KBU 11-8Y 758.46 756.87 31.99N 298.53E 96.0 301.04 297.45 803.81 793.80 94.48N 5.76E KBU 11-8Y 761.67 760.05 31.75N 298.84E 96.2 301.61 297.99 __ Offset Wellbore Surve Tool Pro rams __ _ _ Well _Wellbore T Surrre Name ~ MD ft Sunrey Toal ~ Error Model _ KBU 11-8Y~ KBU 11-8Y MWD <0-8220> 8220 00 Navi Trak ~ Mag Corrected All data is in Feet unless othervvise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 • r~alzArl~oN MARATHON Oil Company KBU41-6 Ver 2, KBU41-6 Ver 2 Slot #KBU41-6, Pad 41-7 CLEARANCE LISTING Page 8 Date Printed: 16-Sep-2005 Kenai Gas Field, Kenai Peninsula, Alaska BAM(ER Mv6NES i~'`T~Q C learance Data Reference MD[ftJ Reference TVD[ft] Reference North(ft] Reference East[ft] Offset Welt Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset East[ft} Angte From Highside de Closest Approach Distance ft Ellipse Separation [ft] 1246.72 1195.10 279.21N 17.02E KU43-6 1404.42 1338.20 71.39N 189.55E 142.7 305.66 298.76 1281.27 1224.42 297.45N 18.14E KU43-6 1425.00 1356.22 80.94N 186.79E 143.4 304.45 297.29 1300.00 1240.18 307.55N 18.75E KU43-6 1437.50 1367.39 86.41N 185.50E 143.8 304.77 297.47 1328.74 1264.17 323.35N 19.72E KU43-6 1450.81 1379.43 91.97N 184.43E 144.2 306.52 298.99 [~_ Offse_tWellbore_Survey Tool Programs ~ - We0 ~7 Wellbore _ Suwe Name ~ MDlftl _ __Survev Tool. _Error Modei 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 (Planned G1 87.Oft 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 MARATHON Oil Company KBU41-6 Ver 2, KBU41-6 Ver 2 Slot #KBU41-6, Pad 41-7 CLEARANCE LISTING Page 9 Date Printed: 16-Sep-2005 Kenai Gas Field, Kenai Peninsula, Alaska BAKER HUGHES li~TE(~ _ Clearance Data Reference MD[ft] Reference TVD[ftj Reference North[ft] Reference. East[ft} Offset Well Offset MD[ft] Offset ND[ft] Offset Northjftj Offset East[ft] Angle From Highside de Closest Approach Distance ft Ellipse Separation [ft] 1246.72 1195.10 279.21N 17.02E KU43-6 1404.42 1338.20 71.39N 189.55E 142.7 305.66 298.76 1281.27 1224.42 297.45N 18.14E KU43-6 1425.00 1356.22 80.94N 186.79E 143.4 304.45 297.29 1300.00 1240.18 307.55N 18.75E KU43-6 1437.50 1367.39 86.41N 185.50E 143.8 304.77 297.47 1328.74 1264.17 323.35N 19.72E KU43-6 1450.81 1379.43 91.97N 184.43E 144.2 306.52 298.99 _ Offset Wellbor_e Survey Tool Pr~rams ~ Well _ Wellbore ~_ Survev Name _ MD ft Survev Tool _ __ Error Model _ KU43-6 KU43-6 GM5 <0-4129> 4179.00 Scientific Kee er G ro 29-Se -03 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 (Planned G1 87.Oft 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 • • MARA"CHON MARATHON O[I Company CLEARANCE LISTING Page 10 BAK a KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 MUts}~~5, Slot #KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, INTEQ Alaska Clearance Data Reference MD[ft] Reference TVD[ft] Reference North[ftJ Reference East[ft] Offset Well Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset' East[ft] _ Angle From Highside de Closest Approach Distance ft ~ Ellipse ~ Separatioh {ft} 0.00 0.00 O.OON 0.00E KBU43-7X 0.23 0.23 0.05N 80.28E 90.0 80.28 80.27 100.00 100.00 O.OON 0.00E KBU43-7X 101.16 101.16 0.55N 79.67E 89.6 79.68 79.25 200.00 200.00 O.OON 0.00E KBU43-7X 201.94 201.91 2.02N 77.86E 88.5 77.91 77.18 300.00 299.95 2.61N 0.16E KBU43-7X 302.92 302.82 4.17N 74.76E 85.4 74.68 73.60 400.00 399.63 10.44N 0.64E KBU43-7X 406.47 406.14 5.69N 68.45E 91.1 68.29 66.77 500.00 498.77 23.47N 1.43E KBU43-7X 507.52 506.39 5.65N 55.79E 105.6 57.71 55.64 574.15 571.76 36.46N 2.22E KBU43-7X 579.8 577.66 4.67N 45.26E 123.5 53.83 51.30 600.00 597.08 41.66N 2.54E KBU43-7X 604.22 602.01 4.OON 41.49E 130.8 54.40 51.74 639.76 635.89 50.31N 3.07E KBU43-7X 641.99 639.29 2.67N 35.56E 141.9 57,77 54.88 700.00 694.31 64.96N 3.96E KBU43-7X 698.49 694.96 0.19N 26.28E 156.8 68.50 65.33 800.00 790.18 93.30N 5.69E KBU43-7X 788.59 783.58 5.20S 10.93E 173.0 98.86 95.15 900.00 884.43 126.62N 7.72E KBU43-7X 875.17 868.45 12.56S 4.54W -178.3 140.63 136.30 1000.00 976.81 164.81N 10.05E KBU43-7X 952.57 944.20 21.23S 19.41W -173.5 191.16 186.21 1100.00 1067.06 207.78N 12.67E KBU43-7X 1023.33 1012.16 32.315 34.34W -170.4 250.73 245.15 Offset Wellbore Survey Tool Programs Weq_ __ Weflbore_1r Survev Name_ __ ~- MDiftl _~- Survey Too ~ Error Model KBU43-7X ~ KBU43-7X I MWD<0-8610'> i 8610 00 ~ Navi Trak I Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 • mARarI~I~N MARATHON Oil Company KBU41-6 Ver 2, KBU41-6 Ver 2 S{ot#KBU41-6, Pad 41-7 CLEARANCE LISTING Page 11 Date Printed: 16-Sep-2005 Kenai Gas Field, Kenai Peninsula, Alaska EIAfCER NUGl~ES I:~TEQ __ Clearance Data Reference Reference Reference Reference Offset Well Offset Offset Offset Offset Angle Closes Ellipse MD[ft] TVD[ftj, North[tt] East[ft] MD[ft] TVD(ft] North[ft] East[ft] From Approach Separation. Highside Distance [ft] _ de ft 0.00 0.00 O.OON 0.00E KBU 44-6 0.00 0.00 82.18S 276.34E 106.6 288.30 288.30 0.00 0.00 O.OON 0.00E KBU 44-6 0.00 0.00 82.18S 276.34E 106.6 288.30 288.30 16.40 16.40 O.OON 0.00E KBU 44-6 16.12 16.12 82.16S 276.36E 106.6 288.31 288.12 100.00 100.00 O.OON 0.00E KBU 44-6 99.15 99.15 82.03S 276.52E 106.5 288.43 287.95 164.04 164.04 O.OON 0.00E KBU 44-6 163.19 163.19 81.825 276.78E 106.5 288.62 287.91 200.00 200.00 O.OON 0.00E KBU 44-6 197.34 197.34 81.66S 277.03E 106.4 288.83 287.99 300.00 299.95 2.61N 0.16E KBU 44-6 297.85 297.84 81.105 278.10E 103.2 290.28 289.10 400.00 399.63 10.44N 0.64E KBU 44-6 397.72 397.70 80.28S 279.12E 104.4 292.89 291.39 500.00 498.77 23.47N 1.43E KBU 44-6 495.59 495.55 78.825 280.54E 106.3 297.28 295.40 557.74 555.65 33.34N 2.03E KBU 44-6 550.41 550.33 77.24S 282.02E 107.6 301.08 298.92 Offset Wellbore Surve Tool Pro rams ------^~ Well ~ _Wellbore - . _ Survey Name __ __MDfftl Surve Tool _ Error Model KBU 44-6 KBU 44-6 MWD <0-7440> 7440.00 _. Navi Trak Mag Corrected All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 MARATHON Oil Company CLEARANCE LISTING Page 12 BAKER KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 ~~~,}~~ Slot#KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, 1~TEt~ Alaska C learance Data Reference MD[ftJ Reference ND[ff] Reference North[ft) Reference East[ft) Offset-Well Offset MD[ft] Offset ND[ft) Offset North[ft) Offset East[ft) _ Angle From Highside de Closest- Approach Distance ft Ellipse Separatioh [ft] 0.00 0.00 O.OON 0.00E KU13-5 3.31 -0.69 207.34S 160.73E 142.2 262.35 262.27 49.21 49.21 O.OON 0.00E KU13-5 51.13 47.13 207.51S 160.73E 142.2 262.49 262.02 100.00 100.00 O.OON 0.00E KU13-5 101.05 97.04 208.025 160.73E 142.3 262.90 262.22 200.00 200.00 O.OON 0.00E KU13-5 200.32 196.31 209.40S 160.87E 142.5 264.09 262.76 300.00 299.95 2.61N 0.16E KU13-5 299.86 295.84 210.925 161.29E 139.4 267.54 265.62 400.00 399.63 10.44N 0.64E KU13-5 401.64 397.60 212.16S 161.79E 140.4 274.82 272.25 500.0 498.77 23.47N 1.43E K 13-5 504.75 00.70 211.75S 162.85E 141.7 285.28 282.33 600.00 597.08 41.66N 2.54E KU13-5 609.65 605.51 208.19S 165.28E 143.0 298.29 294.89 623.36 619.90 46.65N 2.84E KU13-5 634.99 630.79 206.70S 166.11E 143.3 301.59 298.05 __ ___ Offset Wellbore Survey Tool Programs Well Wellbore Survey Name MDlftl Survey Tool Error Model KU13-5 KU13-5 GMS <0-8120'> 8120.00 Level Rotor G ro _ Standard All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 CLEARANCE LISTING Page 13 KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 w~6HES }KARAtHON Slot#KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, Alaska I~1'TEQ Clearance Data Reference Reference. Reference Reference Offset Well Offset Offset Offset Offset Angle Closest _ Ellipse MD[ft] ND(ft] North[ft] East[ftj MD[ft] ND[ft] North[ftj East[ftj From Approach Separation Highside Distance [ft] de ft 0.00 0.00 O.OON 0.00E KBU33-6X 0.00 4.60 1.86N 134.46E 89.2 134.55 134.55 4.60 4.60 O.OON 0.00E KBU33-6X 0.00 4.60 1.86N 134.46E 89.2 134.47 134.42 100.00 100.00 O.OON 0.00E KBU33-6X 95.38 99.98 1.89N 134.47E 89.2 134.48 133 96 200.00 200.00 O.OON 0.00E KBU33-6X 195.33 199.93 2.OON 134.51E 89.2 134.53 . 133.65 300.00 299.95 2.61N 0.16E KBU33-6X 295.28 299.88 2.14N 134.57E 86.7 134.41 133 23 400.00 399.63 10.44N 0.64E KBU33-6X 395.19 399.79 2.28N 134.56E 90.0 134.17 . 132 64 412.99 412.55 11.85N 0.72E KBU33-6X 408.11 412.71 2.29N 134.55E 90.6 134.17 . 132 57 442.91 442.26 15.40N 0.94E KBU33-6X 437.61 442.21 2.28N 134.55E 92.1 134.25 . 132 52 500.00 498.77 23.47N 1.43E KBU33-6X 493.55 498.15 2.21N 134.69E 95.5 134.95 . 132.98 600.00 597.08 41.66N 2.54E KBU33-6X 591.76 596.36 2.34N 135.31E 102.7 138.47 135.97 700.00 694.31 64.96N 3.96E KBU33-6X 688.99 693.58 2.77N 135.97E 111.0 145.93 142.80 800.00 790.18 93.30N 5.69E KBU33-6X 784.33 788.92 2.85N 136.78E 119.7 159.27 155.46 900.00 884.43 126.62N 7.72E KBU33-6X 878.66 883.24 3.13N 137.94E 128.0 179.47 174 96 951.44 932.20 145.66N 8.88E KBU33-6X 926.33 930.91 3.29N 138.58E 131.8 192.59 . 187 70 1000.00 976.81 164.81N 10.05E KBU33-6X 971.01 975.59 3.44N 139.18E 135.2 206.68 . 201.48 1100.00 1067.06 207.78N 12.67E KBU33-6X 1060.82 1065.38 3.57N 140.49E 141.2 240.92 23 06 1200.00 1154.93 255.40N 15.57E KBU33-6X 1151.29 1155.84 3.90N 141.66E 146.2 281.34 . 274.84 Offset Wellbore Survey Tool Programs All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 CLEARANCE LISTING Page 14 ~` KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 MVEGRI~E~ M~ItATHON Slot #KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, Alaska INTEQ Clearance Data Reference Reference Reference Reference Offset-Well Offset Offset Offset _ Offset Angle Closest _ Ellipse MD(ft] 1VD[ft] North(ft] East[ft] MD[ftj TVD[ft] North[ft] East[ftj From Approach Separation Highside bistance [ft] 0.00 0.00 O.OON 0.00E KBU42-6 0.22 0.22 3.10N 188.77E de 89.1 ft 188 80 188 79 100.00 100.00 O.OON 0.00E KBU42-6 100.67 100.67 3.17N 188.61E 89.0 . 188 64 . 188 16 200.00 200.00 D.OON 0.00E KBU42-6 200.51 200.51 3.49N 188.24E 88.9 . 188 27 . 187 43 300.00 299.95 2.61N 0.16E KBU42-6 299.22 299.20 5.37N 188.26E 85.7 . 188 12 . 187 01 400.00 399.63 10.44N 0.64E KBU42-6 399.91 399.74 10.55N 188.45E 86.5 . 187 81 . 186 40 500.00 498.77 23.47N 1.43E KBU42-6 499.62 498.83 21.47N 188.31E 87.2 . 186 89 . 185 05 549.14 547.20 31.78N 1.94E KBU42-6 547.00 545.52 29.47N 188.5E 87.2 . 186 63 . 184 50 600.00 597.08 41.66N 2.54E KBU42-6 596.31 593.75 39.71 N 189.3E 87.0 . 186 80 . 184 34 700.00 94.31 64.96N 3.96E KBU42-6 694.60 688.94 64.02N 191.77E 86.5 . 187 89 . 184 58 800.00 790.18 93.30N 5.69E KBU42-6 794.75 784.38 94.20N 194.59E 85.9 . 189 00 . 184 59 900.00 884.43 126.62N 7.72E KBU42-6 894.49 878.06 128.29N 197.40E 85.6 . 189 80 . 184 11 1000.00 976.81 164.81N 10.05E KBU42-6 993.91 970.23 165.44N 200.32E 85.8 . 190 38 . 183 23 1100.00 1067.06 207.78N 12.67E KBU42-6 1093.65 1060.72 207.24N 203.41E 86.2 . 190 85 . 182 06 1200.00 1154.93 255.40N 15.57E KBU42-6 1193.27 1149.50 252.32N 206.61E 87.0 . 191 14 . 180 53 1300.00 1240.18 307.55N 18.75E KBU42-6 1292.19 1236.39 299.46N 210.07E 88.5 . 191 52 . 178 97 1400.00 1322.59 364.07N 22.20E KBU42-6 1390.69 1321.52 348.81N 214.26E 90.7 . 192 67 . 178 03 1459.97 1370.55 400.01N 24.39E KBU42-6 1449.94 1371.66 380.25N 217.13E 92.1 . 193.75 . 177 76 1500.00 1401.91 424.83N 25.90E KBU42-6 1489.41 1404.63 401.85N 219.21E 93.1 194 69 . 177 81 1600.00 1477.95 489.65N 29.86E KBU42- 1587.54 1486.09 456.25N 224.92E 9 .2 . 198 07 . 178 93 1700.00 1550.47 558.35N 34.05E KBU42-6 1687.23 1567.34 513.64N 231.44E 99.9 . 203 10 . 181 62 1800.00 1619.30 630.74N 38.46E KBU42-6 1789.37 1648.37 575.46N 237.95E 104.0 . 209 04 . 185 20 1848.52 1651.30 667.14N 40.68E KBU42-6 1839.73 1687.13 607.48N 240.83E 105.9 . 211 91 . 186 91 1900.00 1684.77 706.19N 43.06E KBU42-6 1890.01 1725.61 639.72N 243.56E 108.0 . 215 14 . 189 00 2000.00 1749.77 782.04N 47.69E KBU42-6 1989.60 1803.08 702.11N 248.28E 112.4 . 222 41 . 194 26 2100.00 1814.78 857.89N 52.31E KBU42-6 2088.98 1881.13 763.57N 251.23E 116.9 . 229 93 . 200 06 2181.76 1867.92 919.90N 56.09E KBU42-6 2166.89 1942.67 811.27N 253.86E 120.3 . 237 70 . 206 61 2200.00 230 0 1879.78 933.74N 56.94E KBU42-6 2183.59 1955.88 821.47N 254.50E 121.1 . 239.64 . 208.32 0. 0 1944.79 1009.59N 61:56E KBU42-6 2281.90 2033.57 881.56N 258.76E 124.9 251 32 218 66 2400.00 2009.79 1085.43N 66.19E KBU42-6 2379.84 2110.42 942.12N 263.23E 128.2 . 263.61 . 229 70 2500.00 2074.79 1161.28N 70.81E KBU42-6 2475.03 2186.07 999.76N 266.99E 131.4 277 41 . 242 52 2600.00 2139.80 1237.13N 75.44E KBU42-6 2571.86 2263.11 1058.23N 271.65E 134.3 . 292.77 . 256 89 2700.00 2204.80 1312.98N 80.06E KBU42-6 2673.24 2342.65 1120.78N 277.93E 136.7 308.38 . 271 35 2800.00 2269.81 1388.83N 84.69E KBU42-6 2774.45 2421.26 1184.26N 283.57E 138.7 323.03 . 284 86 2900.00 2334.81 1464.68N 89.31E KBU42-6 2869.99 2495.66 1243.96N 289.08E 140.4 338.38 . 299.16 __ _ Offset Wellbore Survey Tool Programs All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 CLEARANCE LISTING Page 15 Bl1K R KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 NU~,,HES MARA7HI~N Slot #KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, Alaska i~TEt~ Clearance Data. Reference Reference. Reference Reference Offset Well Offset Offset Offset Offset Angle Closest Ellipse MD[ft} TVD[ft] North[ft] East[ft} MD[ft] ND[ft] North[ft} East[ft] From Approach Separation Highside Distance [ft] 0.00 0.00 O.OON 0.00E KBU42-7 0.19 0.19 77.22S 107.47E de 125.7 ft 132 33 132 32 100.00 100.00 O.OON 0.00E KBU42-7 100.58 100.58 76.97S 107.32E 125.7 . 132 07 . 131 58 200.00 200.00 O.OON 0.00E KBU42-7 200.98 200.98 76.35S 106.94E 125.5 . 131 40 . 130 55 229.66 229.66 0.23N 0.01E KBU42-7 230.64 230.63 76.17S 106.79E 122.1 . 131 30 . 130 34 300.00 299.95 2.61N 0.16E KBU42-7 300.26 300.25 76.20S 106.40E 123.1 . 132 28 . 131 11 400.00 399.63 10.44N 0.64E KBU42-7 398.61 398.56 78.38S 105.02E 126.7 . 137 06 . 135 58 500.00 498.77 23.47N 1.43E KBU42-7 494.00 493.77 83.715 102.69E 132.6 . 147 53 . 14 65 600.00 597.08 41.66N 2.54E KBU42-7 586.28 585.61 92.15S 99.81E 139.3 . 165 83 . 163 45 700.00 694.31 64.96N 3.96E KBU42-7 674.30 672.95 102.76S 97.02E 145.6 . 192 99 . 190 03 771.00 762.53 84.57N 5.16E KBU42-7 735.75 733.77 111.41S 96.01E 149.3 . 217 92 . 214 51 800.00 790.18 93.30N 5.69E KBU42-7 761.84 759.59 115.19S 96.03E 150.7 . 229 27 . 225 70 900.00 884.43 126.62N 7.72E KB 42-7 846.58 843.38 127.63S 98.05E 154.1 . 272.93 . 268.74 ~__ Offs et Wellbore Sur v e Tool ~ Pro rams g __ Well _ _ _ ~ _ Wellbore Survev Name _ _ _ -~ _ --- MDfftl - -- ~_ --- _ Survey Tool _ T __ ___ Error Mndel KBU42-7 KBU42-7 ~ MWD <0 7570> 7570.00 ~ Navi Trak _ ~ _ nn~„ r..~.e,.~°a All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 144~4RATHt1N MARATHON O[I Company KBU41-6 Ver 2, KBU41-6 Ver 2 Slot #KBU41-6, Pad 41-7 CLEARANCE LISTING Page 16 Date Printed: 16-Sep-2005 Kenai Gas Field, Kenai Peninsula, Alaska B NtK1~H~5'i II~TEt,? - - -~ _ Clearance Data __ _ Reference Reference Refere~nce~Re~ference Offset WeA Offset Offset Offset Offset Angle Closest~~ Ellips~i MD[ft] 7VD[ft] North(ft] I East[ft] MD[ft] ND(ft] North[ft] East[ft] From Approach ~ Separation I, Highside Distance [ft] de ft 0.00 0.00 O.OON 0.00E KBU11-8X 0.10 0.10 3.54N 239.40E 89.2 239.43 239.42 100.00 100.00 O.OON 0.00E KBU11-SX 100.30 100.30 3.56N 239.34E 89.2 239.36 238.90 200.00 200.00 O.OON 0.00E KBU11-8X 202.48 202.48 3.61N 238.81E 89.1 238.85 238.00 300.00 299.95 2.61N 0.16E KBU11-8X 301.16 301.15 3.21N 238.14E 86.4 237.98 236.80 400.00 399.63 10.44N 0.64E KBU11-8X 400.57 400.56 2.67N 237.72E 88.4 237.21 235.66 500.00 498.77 23.47N 1.43E KBU11-8X 501.59 501.58 1.95N 237.00E 91.8 236.56 234.58 557.96 555.86 33.39N 2.04E KBU11-SX 559.26 559.24 1.67N 236.23E 94.3 236.36 234.05 574.15 571.76 36.46N 2.22E KBU11-8X 575.13 575.11 t.56N 235.99E 95.1 236.38 234.00 600.00 597.08 41.66N 2.54E KBU11-SX 600.55 600.53 1.34N 235.58E 96.4 236.53 234.04 700.00 694.31 64.96N 3.96E KBU11-8X 697.04 697.00 0.38N 233.98E 102.0 238.93 235.87 800.00 790.18 93.30N 5.69E KBU11-SX 786.33 786.28 0.66S 233.77E 107.8 246.71 243.00 900.00 884.43 126.62N 7.72E KBU11-SX 870.81 870.71 1.87S 236.19E 113.3 262.49 258.11 1000.00 976.81 164.81N 10.05E KBU11-SX 952.57 952.22 3.19S 242.31E 118.3 287.70 282.61 1049.87 1022.10 185.65N 11.32E KBU11-8X 992.63 992.07 3.955 246.35E 120.5 303.46 297.97 Ilbore Survev Tool Programs All data is in Feet unless otherwise stated Coordinates are From Slot and ND's are from Rig (Planned G1 87.Oft 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 MARATHON Oil Company CLEARANCE LISTING Page 17 ttAKER KBU41-6 Ver 2, KBU41-6 Ver 2 Date Printed: 16-Sep-2005 M~iGI{E5 Slot #KBU41-6, Pad 41-7 Kenai Gas Field, Kenai Peninsula, iNT~Q Alaska Clearance Data Reference MD[ft] Reference TVD[ft] Reference PJorth(ft] Reference East(ft] Offset Well Offset MD[ft] Offset lVD[ft] Offset North[ft] Offset East[ftJ Angle From Highside de Closest Approach Distance ft __ Ellipse Separation [ft] 0.00 0.00 O.OON 0.00E KBU33-6 0.00 0.00 78.79S 58.40E 143.5 98.07 0.00 0.00 O.OON 0.00E KBU33-6 0.00 0.00 78.79S 58.40E 143.5 98.07 100.00 100.00 O.OON 0.00E KBU33-6 99.67 99.66 79.21S 58.13E 143.7 98.26 200.00 200.00 O.OON 0.00E KBU33-6 199.69 199.68 80.03S 57.57E 144.3 98.59 300.00 299.95 2.61N 0.16E KBU33-6 299.81 299.79 80.87S 56.73E 142.3 100.84 400.00 399.63 10.44N 0.64E KBU33-6 399.49 399.47 81.735 55.66E 145.5 107.35 500.00 495.77 23.47N 1.43E KBU33-6 498.60 498.56 82.64S 54.32E 149.7 118.56 600.00 597.08 41.66N 2.54E KBU33-6 599.89 599.83 83.OOS 52.28E 154.4 134.24 700.00 694.31 64.96N 3.96E KBU33-6 701.24 701.08 80.76S 48.73E 159.0 152.59 800.00 790.18 93.30N 5.69E KBU33-6 802.04 801.70 76.215 44.63E 163.1 174.31 900.00 884.43 126.62N 7.72E KBU33-6 908.28 907.47 67.55S 39.94E 166.8 198.16 1000.00 976.81 164.81N 10.05E KBU33-6 1024.71 1022.29 49.41S 34.42E 170.0 220.35 1100.00 1067.06 207.78N 12.67E KBU33-6 1129.07 1123.97 26.63S 28.92E 172.6 241.76 1200.00 1154.93 255.40N 15.57E KBU33-6 1236.95 1228.17 0.52N 22.43E 175.0 265.28 1300.00 1240.18 307.55N 18.75E KBU33-6 1344.43 1330.77 31.70N 15.41E 177.3 290.36 -- Offset Wellbore Surve Tool Pro rams Well Wellbore ~ Survev Name _ MD(ftl Survey Tool _ __ _ Error Model __ KBU33-6 KBU33-6 GMS <0-7902'> 7902.00 Scientific KBU33-6 KBU33-6 MWD<0-8110> 8110.00 Navi Trak All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Planned G1 87.Oft 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 +II/~I®oY1r IINL..1i ~A~~sa e. .. ,, mob: ~_ ,, . ,~..~ .. ... _ ., .~„~~. ,. .., _ 1~~1 Fie Edit NC~~Ciles Table lroh ~;'r-ei;oara Urn:-~. inde~;~~ Help __~ ~~ ~ ~5 I rllEr~r? Dr 7~-~ Elfi-dh Dala ~ e~J[i~71r5 T~rarE_~ I~ 9in a-nl~~ E uf_~ Hr_; e~hriri I »~nT:~ ~~~~~ ~~~~ ~~ .S.E ~ 3Q~~ ~, ~ ®I ~~ ~J..~ ~..~..J_ 1 -Mart, h1G __ __- ~ R T'a'D ~-- -~-- t S _-r,ior~ ~ GePaull r _ pr~_iali~ed Nurtl~~ ~• ~ i Ea,~1 ~~~~'.~~ ~,zirni_irF~ ~~~~ I ~rtirrar~,~ rle ! t f J_.i~~ ~ - ' r ~ ~,l [~ I ~~~ CI ~~Ff ~_ _~~ 1 I I'Y I_iftFl ~i~ Ed..t `r t~ I r ~ Ll I f7~C f ,- S ~ Ef~, ~J ; ' ~ ~ I ~~ , ~~~,~~fr, ~ ~ ~ ~_ _.~ k ; k,~,~ _ _ __~_ _ ~ m..-1 ~ tr + i F 1 e .. .... I i _E ~~E _ _ E 27500 ` ~ 8295 76 3 489 6411.82~ 4682 45 N E 285 52 -~F ~ 1 7 ~ ......... ..................9720:94......................_OA00:.... ... .. ....................3:489 . .........._..........._ N 4682.45; ....,..,,.,.,, E 285.52 ~ ~1 ~ 1' -J ~~o e~_,~id~o E,~-~~~ , ,. ,,~;~e~i~~arF, ~ ~w.~,~ii r F~~i~~ rr~~~~~~E -~ ~, d,~,~r~_ __~ ~_ r,ao ~~ ,~~ - _ _ - ___ Fia!d ;- I~ r.al;~~!ic~~ ~~ Slo! ~ -~le~t . ~ P~~~q G~'~_irn r, FFId .-' Ir _t,ILti~-.r ~ ~I~~r, -: Fa Dare;;, ~]ah~fil P Plar~r~~d G1 ['~= i~~ ,-,~.ua ~U05 _~ F,r,~~~ran~ i; plr,' --~I _rr.. QUO -i '~ ~J s IFE s Marathon Oil Company Well Name: KBU 41-6 Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PRQJECT PLAN `xsE ~- __ `IFE ~~ ,_ Prepared For: MARATHON OIL COMPANY Well KBU 41-6 Kenai Peninsula, Alaska Prepared by: Tony Tykalsky Reviewed by: Mark Fairbanks Presented to: Will Tank September 20, 2005 ,IFE ^rf Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: Marathon Oil Company Well Name: KBU 41-6 Location: Kenai, Alaska. Enclosed is the recommended drilling fluid program for the KBU 41-6 Well to be drilled this year. The following is a brief synopsis of the program. Overview: KBU 41-6 is a development well targeting the Tyonek formation at the Kenai Gas Field. Flo-Pro fluid will be used for the intermediate and production intervals. After logging the production interval, the well will be completed with a 3-1/2" excape system cemented in place. Surface Interval: The surface interval will be drilled with the standard Gel/Gelex spud mud. No problems were noted in this interval while drilling 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 bridging material, Mix II should be added to the mud system prior to drilling the Sterling 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 be required. Completion: The cement will be displaced with 6% KCl brine for the completion phase of the program. Congor 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 11-8Y; KBU 11-8X; KBU 42-6 NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties required. IFE • • ~,i~ ~FE Marathon Oil Company Well Name: KBU 41-6 Location: Kenai, Alaska. EXECUTIVE SUMMARY Our overall goal is no spills and no incidents while providing fluids and solids -' ° -"'„ control services to Marathon Oil Company. ~.HSE: ,~._ Qur goal for KI3U 41-G is to remove drill solids from the mud system at a cost of [ass than $0.~4 per pound. This has been the average for 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 $24.'l7 per foot. We estimate the use of less that 5686 barrels to complete this well, not _~~ withstanding any un-anticipated losses to the formation. _~ ~~ 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. =~ 1FE • ~',~ • Marathon Oil Company Well Name: KBU 41-6 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 -1850' < $3.73 ft < 1780 bbls 1850 - < $30.40 ft < 3047 bbls 7274' 7274 - 9720' < $25.80 ft < 858 bbls Total Avg. Max. Project < $24.17 ft <5686 bbls < $0.24 Ib No Spills from Targets for Centrifuge Van Drilling Operation Interval IFE Fes: • • ~i.'~~ Marathon Oil Company - Well Name: KBU 41-6 _ Location: Kenai, Alaska. Project Summary Casing Hole' Casing Depth ND Mud Mud Sum Interval Size Size Program System Weight Days Mud Cost (in) {inj (ftj (ft) Solids Control (PP8) 13-3/8" 16" ;,;;,, 1850' 1652' GeUGelex Spud ~,-~ ;' , ~ Mud 8.6 - 9.4 5 $1.:0,806- 14`` ~ ~r~ Screens 150/180 v' mesh ~;' .,; Desilter Centrifuge. Van ~` 9-5/8" 12-1f4" 7274' 5412' Flo-Pra w/SafeCarb 90 - 7 $170,380 - Screens 180 - 210 < 9.~ mesh Desilter Centrifuge Van 3-1/2" 8-1/2" 9720' 7837 Flo Pro w/SafeCarb 9.0 5 $67,015 Screens 230 - 210 10.0~- mesh Desilter Centrifuge Van 3 1/2" 8-1/2" Completion 9720' 7837' 6% KCl 8.55 2 $5,600 - 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. ~~ IFE ~~ • • ~~+;,'~~ Marathon Oil Company Well Name: KBU 41-6 Location: Kenai, Alaska. Estimated Praduct ~Jsage Summary NROllL-CT M-I Bar surface Intermediate Producti~w C`on~plction'_ ~ ~~ °/~ of ~ ~ ~ , ~ ~ , Total Usages Total Cost 0 609 1030 0 1639 5.18 M-I Gel 356 0 0 0 356 1.18 Gelex 22 0 0 0 22 0.11 Soda Ash 9 15 9 0 33 0.21 Caustic Soda 9 30 9 0 48 0.69 Conqor 404 0 7 3 0 10 5.30 Sodium Meta Bisulfate 1 S 30 9 5 62 1.68 Bicarb 9 15 17 0 41 0.31 Congor 303 0 0 0 5 4 1.00 F1oVis 0 1.83 69 0 252 20.85 Desco CF 10 0 0 0 10 0.20 Polypac UL 9 122 34 0 165 10.86 KCl 0 1280 361 42 1683 8.89 Safecarb 0 914 258 0 1172 9.39 Lubetex 0 48 14 0 62 19.12 Mix II 0 112 0 0 112 1.18 EMI 920 0 0 8 0 8 3.08 Citric Acid 0 0 17 0 17 0.70 KlaGard 0 28 4 0 32 9.34 Defoam X 0 17 5 0 22 0.81 Engineer Service 5 7 5 2 19 ~~ IFE ~ • ~~.'~~ Marathon Oil Company Well Name: KBU 41-6 Location: Kenai, Alaska. C1lffset Well Information l~vell 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 FloPro (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 tiveight 8610 10.6 15 28 4.6 Gas - increase mud weight KBU 11-8Y 16" 498 8.65 11 16 17.0 Spud in 1550 9 9 16 8.8 Drlg to casing point, condition mud, short trip OK 1550 9.1 9 19 10.6 Run 8 cement csg 12.25" 1570 9.1 10 19 6.8 Drlg out, displace to new mud, drlg ahead 3774 9.1 9 17 7.0 Drill ahead 5033 9.3 13 15 7.8 Short trip, Ok drlg ahead 5820 9.45 17 23 5.8 TD Interval, add 3°!A Lubetex for torque 5820 9.55 19 22 5.8 Log well on wireline 5820 9.7 20 26 5.4 Conditian mud, run & cmt csg, lost partial returns 8.5" 5840 9.3 14 18 6.2 Drill out cmt, drlg ahead 7574 9.75 17 27 5.0 Drill ahead, add Lubetex & Etvll 920 for torque 8220 10 16 27 5.4 Drlg to TD, inc. PPG to 9.9 for gas 8220 10.5 17 28 5.8 Wireline well, RIH, increase ppg for gas 8220 10.8 17 26 5.2 Run excape assembly & cement same, displace with KCL brine IFE Eli ': • • L~~'F~ Marathon Oil Company Well Name: KBU 41-6 _ Location: Kenai, Alaska. t)ffset 'Well Information 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, lisp to F€oPro, drlg ahead, keep mud thin #ar 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 Drig to TD, filuid loss increasing to to bacterai4 contamination, POi-i #or logs 7659 10.2 11 14 9.1 Finish logging, run excape completion. KBU 42-6 16" 139 8.65 14 24 13.6 Spud in 1495 9.55 12 23 7.8 Drill ahead, wiper trip OK, ddg 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 surtace 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, Post returns pumped 3 LCM pills. stop losses, drlg ahead 6171 9.4 12 14 5.8 Drlg ahead, lost circulation, spot LGM pill 6176 9.1 10 14 7.4 Spot added LCM puts, losses as high as 100 8PH 6176 9 11 15 7.2 Stap #osses prior to running 9-518" casing 6176 9.2 20 13 7.4 Run & cement csg, no losses until end of cement job {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 11.05 21 25 4.4 Poh, run excape completion, cement same. ~~lFE ~~ • • ~~.'~~ Marathon Oil Company Well Name: KBU 41-6 _ 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. ~ DRILL SOLIDS -MBT -The MBT should be kept at less than 7.5 ppb in the intermediate and production intervals through aggressive use of solids equipment and dilution as needed. ~ MIXING CONDITIONS -Whenever possible all treatments to the mud system should be made as pre-mix additions. Polymers and KCI should first be mixed in fresh water in that order and then blended into the active system over one or two circulations as needed. ~ CORROSION - Congor 404 additions should be made daily when drilling with FloPro fluid in order to maintain a 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. '~ IFE 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 . • • A,~ Marathon Oil Company Well Name: KBU 41-6 Location: Kenai, Alaska. Interval Summary - l6" hole '0 -1850' Drilling Fluid System Gel/Gelex Spud Mud Key Products MI Gel / Gelex /Soda Ash /Caustic Soda / MI Bar / PolyPac Supreme UL /Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens -150 -180 mesh Potential Pralilems Lost circulation, coal sloughing, drill solids build-up, hole cleaning. IntervaLDrilling Fluid. Properties Depth 1~1nd Funnel Yield i~Pl Drill Interval ~'Veight Viscosity. Point Fluid Lays pH Solids (ft} (ppg) (dec./fit) (lb./100ftZ}, (mU30rnin} (%~} 0 - 1850' 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 - 1780 barrels. - Estimated haul off volume - 3680 barrels. IFE Eli' • • ~;'~~ Marathon Oil Company Well Name: KBU 41-6 _ Location: Kenai, Alaska. Interval Summary -12-1/4" hole 1850 - 7274' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / PolyPac Supreme UL / KCl / SafeCarb 10, 40, 250 / Mix II /MI Bar / Caustic Soda / Congor 404 /Sodium Meta Bisulfate K1aGard 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 1)ehth Nlud Plastic LSRV f1.PI DriII Interval Weight Viscosity 1 inin Fluid Lass NII3T Solids (ft) ~hA83 ~cp.} (eps) (mll~0min}: (°/,) 1850 - 7274' 9.0 - < 9.5 8 - 12 40,000+ 7 - 9 < 7.5 +/- 5% - Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed fluid forn~ula. Pre-heat makeup water with steam hoses as much as osp Bible. - After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test - As mud heats up, increase F1oVis concentration to 2 PPB and install 180 mesh shaker screens on end panel. - NOTE: Beware of whole mud losses to the Sterling A8 & Unuer BeluEa formations. Ensure adequate bridging material (30 PPB) SafeCarb + (5 - 10 PPB) Mix II is in the mud while drillinE 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 proper fluid roperties for that purpose. - Estimated volume usage for interval - 3047 barrels. - Estimated haul off volume - 4744 barrels. - Condition mud prior to running 9-518" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. '~ IFE ~~.,~~ Marathon Oil Company Well Name: KBU 41-6 _ Location: Kenai, Alaska. Fluid Formula -- l~-1/4" interval 12-1 /4" Interval from 1850 - 7274' Innut Descri tion KBU 41-6 Mud Wei ht ` 9.0 - 9.5 Preh drated Gel' No Wei ht Material Code SafeCarb Preh drated Gel Conc. Wei ht Material SG 2.8 1<CI Wt% 6 NOTE: Pre-heat makeup water with steam hoses as much as possible. Out ut -1 bbl Order of Products Concentration Volume `Product Addition Field, Ib Lab, m Field, bbl Lab, ml Usa' e 1 Water 298.70 298.70 0.853 298.70 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 Flovis 1.25 1.25 0.003 0.83 Viscosit 4 Pol ac Su reme UL 2.00 2.00 0.004 1.25 Fluid Loss Control 5 Caustic Soda 0.50 0.50 0.001 0.23 H Control 6 Potassium Chloride 19.07 19.07 0.023 7.98 Inhibition 7a SafeCarb 10 4.00 4.00 0.040 1.44 Brid in A ent 7b SafeCarb 40 12.00 12.00 0.012 4.32 Brid in A ent 7c SafeCarb 250 4.00 4.00 0.004 1.44 Brid in A ent 8 KlaGard 4.00 4.00 0.008 2.25 Inhibition Plan on addin 2.5 - 5 PPB Mix II to the muds stem rior to drillin into the Sterlin A8 sand +/- 4880' MD 9 Mix II 5.00 5.00 0.010 3.12 LCM If for ue becomes a roblem, or slidin is difficult, add 1 - 3% of the followin : 10 Lubetex 14.00 14.00 0.041 14.43 Lubrici If bit ballin becomes a roblem, add the followin 11 D-D CWT 1.00 1.00 0.003 1.00 Reduce BHA Balling ~ 399 I 399 I 1.000 I 350 I Mud Weight 9.500 Estimated Volume'Usage 3047 Barrels IFE ~y, • • ~~? ~~~ Marathon Oil Company Well Name: KBU 41-6 .. - Location: Kenai, Alaska. Interval Summary - 8-112" hole 7274 - 9720' Drilli~~g Fluid System Flo-Pro Fluid Key Products Flo-Vis ! Polypac Supreme UL / KCl / SafeCarb / MI Bar / Klagard Caustic Soda / Congor 404 /Sodium Meta Bisulfate /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 Dclrth 11~had Plastic LSRV API llrill Interval Weight Viscgsity 1 rnin Fh~id Loss ?~~T Solids (ft} (PAg? ~~cP•) (cps) (~nl/30min) (%} 7274 - 9720' 9.0 -10.0+ 10 -14 30,000+ 6 - 8 < 7.5 +/- 5% - Pre-treat drilling fluid with Bicarb and/or citric acid prior to drilling cement. Aggressively treat out cement contamination as soon as feasible. Build additional dilution volume to maintain proper specifications. - NOTE: Based on offset well history, mud weights 10.0 PPG or higher maY be required for wellbore stabili - NOTE: If metal-to-metal torque is a problem. after drllin~_out the 9-5/8" casing, 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 - 858 barrels. - Estimated haul off volume - 2304 barrels. - Condition mud prior to running 3-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. "IFE ~y, • • ~;'~~ Marathon Oil Company -' Well Name: KBU 41-6 Location: Kenai, Alaska. Dilution Formula - 8-1/2" Interval 8-/12" Interval from 7274 - 9720' ~.,.,~ ~+ Descri tion KBU 41-6 Mud Wei ht 9.0 - 10.0 Preh drated Gel No Wei ht Material Code MI BaR Preh `drated Gel Conc. Wei `ht Material SG 4.2 KCI Wt% 6 `Out ut -1'bb l Order of Products ` 'Concentration Volume Product. Addition Field, Ib Lab, m Field, bbl Lab, m1 Usa e 1 Water 325.19 325.19 0.929 325.19 2 Soda Ash 0.25 0.25 0.000 0.10 Reduce Hardness 3 FloVis Plus 2.00 2.00 0.005 1.34 Viscosit 4 Pol ac Su reme UL 2.00 2.00 0.004 1.33 Fluid Loss Control 5a SafeCarb 10 15.00 22.50 0.017 5.67 Brid in A ent 5b SafeCarb 40 5.00 7.50 0.006 1.89 Brid in A ent 6 Potassium Chloride 20.76 20.76 0.025 8.68 Inhibition 7 CONQOR 404 2.00 2.00 0.004 1.43 Corrosion Control 8 Caustic Soda 0.50 0.50 0.001 0.23 H Control 9 Sodium Meta Bisulfate 0.50 0.25 0.001 0.25 Ox en Scaven er 10 KlaGard 2.00 2.00 0.004 1.43 Inhibition If hi h for ue in incured while drillin out t he 9-5/8" cas in add 0.5 -1.0 % EMI 920 11 EMI 920 3.50 3.50 1.500 3.50 Metal to Metal Lub If slidin or hi h for ue becomes a roblem add 1 - 3% of the followin 12 Lubetex 7.00 7.00 0.021 7.00 Lubricit If sloughing coals become a roblem add 2 - 4 b of the followin 13 As hasol Su reme 2.00 2.00 0.004 1.33 Wellbore Stabilit Mix fluid in the order listed above. Total 380.1 380.1 Estimated VolumeUsa a 858 Barrels Calculated Mud Wei ht 9.050 Total Chloride 29600 =~ IFE • • ~~+;-'~~ Marathon Oil Company Well Name: KBU 41-6 Location: Kenai, Alaska. Interval Summary -- Com letion I'roceclures Corrosion Control Additive in Casing x Tubing Annulus Well KBU 41-6 Volumes: Tubing Volume 3-1~2" Tubing 84.56 barrels 3.50 x 2.992 x 9720 ft Annular Volume Casing x Tubii 446.12 barrels Open Hole x T 120.23 barrels Total Annular Volume 566.36 Tubing Volume 84.56 Total Hole Volume s5o.s2 9.625 x 8.681 @ 7274 ft M D 8.500 x 3.50 @ 9720 ft MD Treatment Procedures. After the 3-1/2" tubing is run and the drilling fluid is circulated and conditioned for the cement job, •culate an additional 450 barrels of drilling fluid. Add 1 drum of Congor 303A and 1 sack of Sodium Meta Bisulfate for each 90 barrels of drilling fluid imped (5 drums & 5 sacks total) After the 450 barrels of drilling fluid with treatment have been pumped downhole, begin the cement job. This procedure will place corrosion control in the 3-1 /2" x 9-5/8" annulus. '- IFE • • ~~:'~~ Marathon Oil Company ~_ Well Name: KBU 41-6 Location: Kenai, Alaska. I-ISE 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. '~ IFE ~ • a~~~'~~ Marathon Oil Company =_ Well Name: KBU 41-6 Location: Kenai, Alaska. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centrifuge solids van, insure all hoses and connections between the van and the rig are secure. =-1FE • • ~~~'~~ Marathon Oil Company Well Name: KBU 41-6 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health x~, , ~ ~~, ~~ Fl~mral~ilit ~ ,bttat o,; PPE M-I BAR Weighting Agent *~ :~~~ ~~~ E M-I GEL Viscosirycontrol ~*1 '° ~~±~°~ ~~ ~ E GELEX Bentonite Extender ~ fi E FLOVIS Viscosifier ~ ^ ~ ~~ ~ °N~ ~.~,~ E DUAL-FLO Modified Starch ~ .~ ~~ ~ ~ E POLYPAC Fluid Loss Reducer ~~ .~ ~ E HEC Loss Circulation Material ,' 1 ~ 1: ~ .~~ a~ ~~rt E Safe-Garb F,M,C Bridging and weighting agent ~.*~ ~ ro~ ~ °° ~ - E Nut Plug Loss Circulation Material *~ M-I Seal F, M, C Loss circulation Material *~ ~ ~~ ~ ~° F ~~ ~~ E Mix II FMC Loss circulation Material *~ ~ °' ~,~t~~ E:~a E DESCO CF Dispersant ~~ ~ ~ ~ s ~ ~* t,~ ~ s ~ . E SALT (Solar) Densifier 1 fl ~,~ ~~~ fi~ ~ E POTASSIUM CHLORIDE Shale Inhibitor ~1 ~! ~ '' ~°°~ati" ~ `r > °~ E CAUSTIC SODA Alkalinity control ~ ~ ,~~ ~ ~ ~ BORAX Inorganic Borate ~ ~~"~~(~ ~~ E SAPP Sodium Pyrophosphate *~ {~ ~~: ~ ,~ r~ E SODA ASH Alkalinity control ~ ~ _ ~ ~`~"~~~ ~a °~, ~ E SODIUM BICARBONATE Alkalinity control ~~ ~ ~ ~ ~~~ ~ ~ ~,~ E CITRIC ACID pH Adjuster ;~ ~ ~ ~ ~~, ~ ~^ ~~ ~ t ~~~ E BIOBAN BP-PLUS Biocide ~~ ~ ~~ ~, ~~~ °~ J GREEN CIDE 25G - Biocide ~~a~~N ~~ DEFOAM X - Defoamer 1 ~ ;~°,,,~~~~~~~e ~ G-SEAL Sized graphite LCM ~ ~ ~~,,~~,~~~~~~ ,~~ IoW E EMI 920 Lubricant ~ ~ ? ~~~ .1 LUBE TEX Lubricant 1 k ~ ~ ~,y~~ s~ ra ~ D-D CWT Detergent 2 ~~ ~~ ~~= ~ ~~ J Concor 404 Corrosion Inhibitor ~ ~, a~~ ~~ ~~° J SAFEKLEEN Drilling fluid additive ~ ~ ~ ~~~,:~~,~ ~ .,. ~ a~~ ~~ . ~;.Q ~ Asphasol Supreme Shale Inhibitor ~ ~ „~, ,,. ~ ~°~~~ ~ Sodium Meta Bisulfate Oxygen Scavenger ~ ~ ~t °~ ' '" ~ IFE • ~ e"-~~'F~ Marathon Oil Company Well Name: KBU 41-6 - Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARC3 RATfNGS 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 IFE • • ~~-' IFE Marathon Oil Company ~_ Well Name: KBU 41-6 Location: Kenai, Alaska. Cantacts 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 Bob Myles Warehouse Manager rmyles@miswaco.com 907 776-8722 907 252-4218 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, and/or utilization of any third party service. 'IFE ~ ~ TSN-R11W ~ -~ >...1--- + ~ `•~ UNiT ~_ 84UNL}ARY, .' `. + ecru aa-~ -~~' ~~. ~.~ L.. BelugalUpper Tyonek Compt~t~ar~ I 'r' f ~...i ~~ r•-' f{}RMATION c.s Boa id;'_ .AL.A`~1~..0. RE_ li!ra C ONFtDENTtAt KEIVAI FIELD ~8~ 4~-~ Lor~tro~n ~e~r~,L., ~m~ Nrl~naa ~~ ixraah~nri~kan7~'~t~E•li_iq~'~L:bu'?2-~_Inr fhll CUC9t VF P+'k[7 WELL K.B.U. 41-6 ASBUILT LOCATION ASP ZONE 4 NAD27 N: 2362054.63 E: 274916.45 LAT: 60°27'34.673" N LONG: 151 °14'49.031" W FEL = 994' FSL = 41' ELEV = 66.5' (MSL) SECTION 6, TOWNSHIP 4N RANGE 11W, SM AK KENAI GAS FIELD PAD 41-7 K.B.I.i. 11-8Y ~' WELL t~ELL.AR N: z3:~zos~r.II1 E:276205.°3 SECTION 6 r~,l K.8.U.33-6X K.B.U. 42-6 K.B.U. 11-8X N: 23n2053.94 N: 2362054.15 N: 23620 ,3.64 E: 275050.91 E ?_75105.24 E: 275155.II7 coUrROL PoINr z 2" ALrAP N = 2362228A5 E = 2752II5.63 ELEV. = 64.7.6 r-.. = (`~ ~' `' ' `"~~ f 994 FEL Ca1VGRETE 1fAULT K.B.U. 43-7X LV! PIPE GUARD N: 2362053.16 I r:== `_ E: 274996,71 i.~=._~ SECTION LINE 6 F - - - _ _ - ~ 41' FSL K.B.U. 24-6N ' - K --- ~ _ ftiET}iONAL 16 otA. svELL sELO .B.U.44-~ SKID N; 2303975.1& 16' DIA. `HELL SILO 7 E: 275073.31 N; 23619fi7.?_4 ~ , `mil ;^, ~ C) ~ ~` ! ~~\ E: 275191. t 7 K.B. U. 33-6 K.S.U. 42-7 K.B.U. 32-7 i&' Dirt. WELL SIL O 16' D!k. bVELL SILO 16' flEA, li`Ei_i_ SELO N: 23&1974.75 N: 2361975.39 N: 2361972.17 E: 274973.34 E:275G22.43 E: 275?3II.,90 -- ~' , \ SECTION 7 ''~-= T.U K 32~7N w . . 16' DIA.1njEL.L. sli_:~ ~' ? N: 2361920.50 -J I crNrr;cLS~c~INr 3 E:275232.;~5 Z ` 2° ALi;AP Q N = 2361955.33 g ~ E _- •75031.;`5 V ELEV. = 66.21 LLJ , 1 ~ ~ I - ~` K.U. 43-6X K.U. 43-6 K.S.U. 41-7 L^dEt.l- HOUSE 'G' Dit1. b~lE[..L >Il-O N; 2361808.84 I r~. -,,,. ,-,-,t n~. 17` x 17' PIPE GUARi:I E: 27520?.3Q { NOTES 1. BASIS OF COORDINATES IS U.S.C. R G.S. TRI STATION AUDRY IN A.S.P. ZONE 4. (NAD 27) AVERAGE CONVERGENCE OF POINTS SHOWN: 01°5'58". 2. AUDRY LOCATION: LAT: 60°30'50.559"N LONG: 151 ° 16'37.445"W NORTHING = 2,382,045.42 FASTING = 269,866.75 ~ITTr 1`^~ T PROJECT REVISION: 1 M lwl~ KENAI GAS FIELD PAD 41-7 °"TE 9,6'os O~ CO~L"SL\ 1 DRAWN BY: CRM ARATHON WELL K.B.U. 41-6 `~~'~ Rev ASBUILT SURFACE LOCATION DIAGRAM scALE: 1'=6a PROJECT NO. 0530' Consultin YOU ENGINEERING/MAPPING/SURVEYING/TESTING BOOK NO. 04-15,05 y G P P.O. BOX 468 SOLDOTNA, AK. 99669 LOCATION PV~cLane Testing VOICE: (907)283-4218 FAX: (907)283-3265 SHEET EMAIL: SAMCLANE~MCLANECG.COM S6 T4N R11 W SEWARD MERIDIAN, ALASKA '~ GF NORTH SCALE 0 60 120 ~ ) FEET • • Surface Use Plan for Kenai Beluga Unit, well KBU 41-6 Surface location: 41' FSL, 994' FEL, Sec. 6, T4N, R11W, S.M. 1} Existing Roads Existing roads which will be used for access to KBU 41-6 are shown on the attached map. Kenai, Alaska is the nearest town to the site and is also shown on the map. 2) Access Roads to be Constructed or Reconstructed No new roads will be required to access KBU 41-6. 3) Location of existing wells Well KBU 41-6 will be drilled on Kenai Gas Field (KGF) pad 41-7. A pad drawing is enclosed that shows existing wells and the proposed location of KBU 41-6. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the KGF pad 41-7 are shown on the enclosed pad drawing. A flowline will be installed from the KBU 41-6 wellhead to an existing line heater and separator. 5) Location of Water Supply A water supply well exists on the pad that KBU 41-6 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 Alf 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) A,nci!lary Facilities • A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. S & R will collect and transport sanitary wastes to their ADC approved disposal facility. No additional structures will be necessary. 9) Plans for reclamation of the surface KBU 41-6 will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of KBU 41-6 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: _ 9 ~z U ~~ J^ -, Name and Title: U'~C-f~ "~~~-- ~ ~T%~ Willard J. Tank, Advanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, TX 77253 (713) 296-3273 GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT r-----~ I i I I CENTRIF13Gq I I 19~1IT t I ;4'Xlfl' I I 1 1 I 1 ~ 1 1 I `'~ ! k 1 L~~J Ilf ~ 1 ~ 1 t 1 ~~~.~ ~ { 1 i 1 ~ i F--i ~ ! 1 11 1 I l 4 1{ t I ~ ~ ` ~ it 1 I q 1 ~ ~rli Ali; i ~ IcaaKr ~' x 12• 51J 9L A-600 PT 7S HP 75 IP 75 HP 6 X 3 6 X S 6 X 3 I1• SI• S' iH > , ~ s 75 FP 6X3 11' ~~ 11QT~i! x 1 w c j TJITA 3406 i I I 51d 9E. ~ t A-600 PT 1 I j DITA 3406 1 1 1 1 1 s~ AfiTA7dl Y ilr RL Marathon Oil Well KBU 41-6 Diverter 21 1/4" 2M Diverter -~ Knife Valve Diverter Spool r Marathon Oil Well KBU 41-6 BOP Stack Flow Nipple I Flow Line 13 5/8" 5M Annular _~ I ` ~ Preventer 13 5/8" 5M Double Ram Preventer Pipe Ram 2 1/16" 5M Blind Ram Check Valve 2 1116" 5M Manually Operated Valves ~LJ~--L_WJLI~--L~-~UJ Kill Choke 13 5/8" 5M Cross 135!8"5Mx135/8"5M Drilling Spool 2 3 3 1!8" 5M Manually Operated Valve _~JIJ~--~~-LIJ 1 3 1/8" 5M Hydraulically Operated Valve Bottom of mud cross must be 24-45" from ground level for Glacier 1 rig placement. 13 5/8" 5M Tubing Head Flange • 1 2 9/16" 1 OM Swaco Hydraulically Operated Choke To Gas Buster X °~°g X Marathon Oil Well KBU 41-6 Choke Manifold To Blooey Line X °~~ • Bleed off Line to Shakers x °°°g X X X °~~ III~~/Illllll^1 LJ~-' R~~LJ~ 3" 5M Valves X I 3 1/8" 5M Manually Adjustable Choke ~ From BOP Stack I ~ • ~ `. NATIONAL CITY BANK 3pchundeed ind i)n'liu) Ik~llar~ Ashl~nd.Ohio ~- -- - - -- u'000 1 19 1 2 70i~' ~:04 1 20 389 5~: 0183484~~' a • • TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME ~~~ ! ~~J~ 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 (pH) records, data and logs 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. (COmAanv 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 Cljody\transmittal_checklist WELL PERMIT CHECKLIST Field & Pool KENAI, UPPER TYONEK BELUGA GAS -44857 Well Name: KBU 41.6 Program DEV Well bore seg ^ PTD#:2051410 Company MARATHON OIL CO Initial ClasslType DEV 11-GAS GeoArea Unit On1Off Shore On Annular Disposal ^ Administration 1 Permitfee attached- - - - - - - - - - - - Yes - - - - - - - - - - - - - - - 2 Lease numberappropriake______________________________ ..._--__.Yes, -_____.._-___... -- - - - -- 3 Un(quewell-nameapdnumbe[_____________________________ _________Yes- -_------_--_ -------------------------------------------------------------- 4 Well located in a-definedpool- - - - - - - - Yes - - - - - - - - - - - - - 5 Well locatedp[operdistanGe-ftomdrillingunitboundary_______________ _________Yes_ ___.___-__.-_________._.__.._____.-_-.._-__--__..---_____._---__--_.- 6 Well located proper distance from other wells-___________________ _________Yes- ___----___________.__..-_---_.._ - - -- - - 7 Sufficient acreageayailableind_rillingunit-____-------------__ --._--__Yes_ ___.___________..__-.__--_-_._ ------------------------------------------ 8 If_deviated,is_wellboreplat_included-_---.__-_-_-__..-______ _________Yes- ___----_____-__-____ __..___-._.__.._-_-.___-__- ---------------------- 9 Operator only affected party. - - - - - - - - - - YeS ------------------------------------------- - - - 10 Operatorhas-appropriate-bond in force ----------------------- ---------Yes- --- ----- -------------------------- ----------------- --- ------- - ---- 11 Permit_eanbeissuedwithoutconservafionorder_----------------- --- -----Yes- ------------------------------------------------------------------- -- -- Appr Date 12 Pe[mit-can be issuedw~houtadministrative_appr_oyal________________ ___-.-__Yes- __----___---__________._.____._- -- - - - -- - RPC 912612005 13 Can permit be approved before 15-day wait Yes 14 Well located within area and strata authorized by Injectigp Orde[ # (put1O# in-comments)-(For_ NA- - - _ . _ . . . . . . . . . .. . . .. . . . . . . _ .. _ - - - _ . - _ . _ _ _ _ - 15 Allwells_within1l4_mileareaof[eyiewident[fled(Forsenricewellgnly)------ --------- NA-- --_------_-_--_____-...__._____-.__-_.._.___--___..__.-..___-____-..__.___ 16 Pre-produced injector_durationofpreproductionlessthag3months-(F4r_servicewellonly)--NA_- ---_,_---____--___________________-._.-__-.-__----__._________.__.-_ 17 ACMP.FindingofConsistency-hasbeenissued_forthisproject-_._____ _-_.---__NA-_ ____-__________________________________._----_.-_-.__-_.-__-.-_-__---. Engineering 18 Canduckor siring_p_ravided - - - - - - - - Yes - - 20" ~ 1$T. - - - - - - - - - - - - - - - 19 Surfacecasingprotectsall_known-USDWs_.__._.___._____.. __-...__Yes- __-_.._ ----_---_ --------------------------------------------------------- 20 CMT-vol adequate-io circul_ate-on conducto[& surf-csg _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _Yes _ _ - - - - _ Adequate excess. _ _ - _ - . _ . - - - _ _ . - _ - . _ -------------------------------------- 21 CMT_v_ol_ adequate_to tie-in long string tosurf csg- - - - - - N0 - - - - - - - - - - - - - 22 CMT willcoverallkno_wnproductivehodz9ns_____________________ _________Yes_ _-----___----_____.___-.___-_.._______..___--_._._.._.._.-__-__-__--_- 23 Casing designs adequate for C,T,B&.permafrost----------------- --.. ----Yes- ---------------------.-----------------------------------------.. _.-- 24 Adequate tankage-orreserye pit_______________ __________ __---..__Yes_ ____--GI_acierRig t.-___--____-,___--___-_______ ---------------------------- 25 Ifa-re-drill,has-a10-403forabandonmentbeen approved_____________ _________ NA_- ---___Newwell.__--_____--___--_-___--___---___--___-.___...__-_.-__.._-_._ 26 Adequatewellboreseparation.proposed--------------- -------- ---------Yes- ---------------------- ------------------ --------------- ---------- -- -- 27 If_divertertequired,doesitmeetregu_lotions------------------ ---------Yes- --------------------------------------------------------------------- Appr Date 28 Drillingfluid-programsehematic&equiplistadequate_______________ _________Yes_ ____.-Max MW-10,0_ppg.____-_______-._-__._-_-.__-_..-.-._.._,_._---____ WGA 9/2712005 29 BOPES,dotheymeetregulation----------------___---____ __-_-___Yes- --_______________.__.._-_____-__.__.-__..___-_--_..-_____.__..-_.__ 30 BOPE_pressratingapp[opriate;testko_(putpsigincomments)---_____. __._..-__Yes- _-_--Test to 2000psi._M$P1896psi___________________-_______-.____..___---__.-__ 31 Choke-manifold complies wlAPI-RP-53(May84)------------------- ---------Yes_ _.__-_--__.-_________. --------------------------------------------------- 32 Work willoccurwithoutoperationshutdown--___--__.------- -----_--Yes- --------------------------------------------------------------.-.-- --- 33 Is presenGe.of H2S gas_probable - - - - - - - - - N~ - No H2S inarea° - - - - - - - - - - - - - - 34 Mecha_nicalcgnditionofwellswithinAORverified(For_servicewellonly)___.. .-__._.-NA-- -----------_--_____--__-----____-__.__-_-.___--_---_..___._. Geology 35 Pe[mit-can be issuedwlohydrogen_sulfidemeasu[es_______________ ____.___Yes- -__--_..-______--__.-_____-__-____---__.-__-____-___.____-___-._- 36 Data-presentedon_potentialoverpressur_ezones__________________ _________ NA-- ___----______.______.-__._-___--___..---__-___.._____.__-..-___..__.__. Appr Date 37 Seismic analysisofshallowgaszones__________________.____ -.__.---. NA_„ ___- -__--_ RPC 9!26/2005 38 Seabed condition survey-(if off_-shore) . _ _ - - NA- - - - - - -- - - - - 39 _Contactnamelphoneforweeklyprogress-reports[exploratoryonly]----___- --_._---NA_- --___---___________________________________________________.___.__.-- Geologic Commissioner: Engineering c Date: ate ~ C ner ~ nommissioner: ~p~ ~ Date i O f- (' ill= I ~~ ~[~ •
