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Home My WebLink About205-0541. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: Cement Annulus, N2 Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 8,855 feet See Schematic feet true vertical 7,725 feet 4926 & 8700 feet Effective Depth measured 5,800 feet N/A feet true vertical 4,684 feet N/A feet Perforation depth Measured depth See Schematic feet True Vertical depth See Schematic feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 5,100' MD 4,031' TVD Packers and SSSV (type, measured and true vertical depth)N/A; N/A N/A; NA 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date: Contact Name: Contact Email: Authorized Title: Contact Phone: Chad Helgeson, Operations Engineer 323-359 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 0 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Noel Nocas, Operations Manager 907-564-5278 chelgeson@hilcorp.com 907-777-8405 N/A measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing Pressure 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf MD 0 Size 130' 0 00 0 600 360 measured TVD 9-5/8" 3-1/2" STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 205-054 50-133-20550-00-00 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Hilcorp Alaska, LLC N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: FEDA018142 Kenai / Sterling 4 Gas Kenai Beluga Unit (KBU) 22-06 Plugs Junk measured Length Production Liner 6,508' 8,816' Casing Structural 5,400' 7,707' 6,529' 8,837' 130'Conductor Surface Intermediate 20" 13-3/8" 109' 1,647' 3,909psi 10,530psi 3,060psi 3,450psi 5,750psi 10,160psi 1,668' 1,503' Burst Collapse 1,500psi 1,950psi p k ft t Fra O s 6. A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov By Grace Christianson at 8:47 am, Sep 15, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.09.14 14:00:25 - 08'00' Noel Nocas (4361) Rig Start Date End Date 6/29/23 8/15/23 06/29/2023 - Thursday PJSM and PTW SITP 18psi. RU YJ E-line Bleed well pressure to 0psi. Stab on lubricator. Pressure test to 250psi/2500psi - TEST GOOD. M/U 2.0" OD gun gamma and 3.5" CIBP (2.75"od). (CCL to plug 14.0ft) RIH. Correlate and set CIBP at 5,335ft. Tag plug - GOOD (plug tag witnessed by AOGCC inspector Bob Noble) POOH. Pumped ~1.25gallons (~1,000ft) of cement into each Excape control line until they pressured up to 1,500psi. M/U 2.5"OD x 25ft cement dump bailer. RIH, tag CIBP at 5,335ft, pick up and dump 13ft of cement. POOH Refill 2.5"OD x 25ft cement dump bailer.RIH and dump 13ft of cement. POOH Estimated TOC 5,309ft. M/U 2.0" OD gun gamma and 3.5" CIBP (2.75"OD). (CCL to plug 14.0ft) RIH. Correlate and set CIBP at 5,245ft. Good indication of plug set, but tools are detained. Work tools, try pumping and pressuring up on the well, no luck getting free. Attempt to pull out of the rope socket. Pulled up to 4k (the maximum recommended on the wire to not damage it) and was still detained. Wait for wire cutter from Pollard. Hold TGSM with YJ, Pollard, and Cruz to discuss the change of plan forward and risks involved. Well at 0psi Secure well with wireline valves, M/U and drop 1.85"OD Kinley cutter. Work cutter down for 1hr. Wire cut, POOH. ~3,450ft of 9/32 wire left in the well GR/CCL and Multistage setting tool left in well Kinley cutter was recovered on the pulled E-line. Secure well. RD YJ Eline Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 07/01/2023 - Saturday PJSM and PTW SITP 0psi. RU Pollard Slickline with both Slickline and Braided line WL valves. Pressure test lubricator to 250psi/2500psi - Test good. M/U and RIH with 3" GR /w baitsub /w inline Wirefinder (2.9" Spread) /w 3 Prong Wire Grab to 1132' SLM (1153' RKB) Set down High w/t get light overpull and unable to go down hole POOH OOH/w one Finger on Wirefinder Bent - Repair RIH/w Same to 1779' SLM (1800' RKB) Set down W/T get overpull at 1712' SLM after pulling out slack get 2 Good Jar licks after multiple pull ups and slip offs Come Free on 2nd Jar lick POOH to. RIH w 3" GR/Baitsub/w Inline wIrefinder/w center Spear (OAL 61" ) to 1783' SLM w/t many times getting overpulls but keep slipping off wire POOH OOH/w 7 Single strands of wire about 4 to 7" long RIH/w 3" GR /w Baitsub/w Inline Wirefinder/w 3 Prong Grab (OAL 63') to 1771' SLM w/t get pretty good bites start jar licks and Beat down between appear to Shear POOH. RIH/w 3" GS to 1739' SLM set down w/t latch w/t jar 4 times 1500 to 3000 come free POOH with 600lbs added weight On surface shut in WLV's start Clamping Eline - Standby for Yellow Jacket. TGSM with YJ and Pollard. Clamp E-line, feed it through the lubricator, and secure to E-line drum. Pull ~3450ft of E-line with full tool recovery (GR/CCL, Multistage setting tool w/o CIBP) No damage was observed to the E-line tool string Secure well. RD Pollard and YJ 07/02/2023 - Sunday PJSM and PTW SITP 0psi Perform MIT-T on tubing plug Pressures 0m/15m/30m - 2748psi/2727psi/2726psi 21psi drop in first 15min 1psi drop in the second 15min Test Good. RU Pollard SL Pressure test lubricator to 250psi/2500psi - Test good M/U and RIH with brush and 2.83"OD gauge ring. Tag plug at 5,245ft, POOH. M/U and RIH with brush and 2.50"OD magnet. Tag plug, POOH and recover 4 very small pieces of wire armor. RD Pollard SL and RU YJ E-line Pressure test lubricator to 250psi/2500psi - Test good M/U and RIH with centralized 1-11/16" OD CBL tool. Tag plug at 5245' and verify it was set on depth. Pull log. Bonded pipe up to ~5050FT. (could be drilling mud). M/U and RIH with 2.5"OD x 25ft cement dump bailer, tag plug at 5,245'. P/U and dump 13ft of cement Re-fill and RIH with 2.5"OD x 25ft cement dump bailer and dump 13ft of cement Estimated TOC 5,219ft. Secure well and lay down YJ Eline. Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 07/04/2023 - Tuesday PJSM and PTW SITP 0psi. R/U Halliburton cement. Pressure test cement lines to 250psi/3500psi. Establish circulation down tubing and up the IA. 2BBLS to establish circulation Mix cement, and verify density. Pump 80BBL of 15.3ppg cements down tubing and up the IA. Hold backpressure 4-500psi on the IA to prevent the cement from falling out. Drop wiper ball. Chase with 44.3BBL of fresh water to put the cement at 5100ft in the tubing. Final pressures T/IA 190psi/0psi Est TOC 3,850ft. Close in IA and pressure up tubing to 500psi, IA rose to 300psi. RD Halliburton cement and circulating iron. Secure well 07/03/2023 - Monday PJSM and PTW SITP 0psi. R/U YJ Eline M/U CCL, weight bars and 3.5" Jet cutter. MIT-T Test good (Witnessed by AOGCC inspector Bob Noble) Pressures T/IA/OA 0min 2755psi/0psi/5psi 15min 2740psi/0psi/5psi 30min 2738psi/0psi/5psi Pressure drop 1st 15min - 15psi Pressure drop 2nd 15min - 2psi. Stab on YJ Eline RIH with CCL and 3.5" jet cutter, correlate on depth tag TOC on plug at 5,219ft (26ft of cement) (Tag witnessed by AOGCC inspector Bob Noble). Pressure up tubing to 500psi Place jet cutter on depth and cut tubing at 5,100ft. No pressure response was seen on the IA. POOH Pressure up to 2500psi on tubing with no pressure response on the IA. R/D YJ Eline. R/U Hot oil truck. Pressure test lines to 5,000psi Pressure up tubing to 3,000psi and pressure broke over, circulation established. Pump 525BBLs of fresh water at 4.0BPM circulating out IA mud until returns were clean. Combo MIT T&IA to 2500psi. Saw pressure drop of ~1psi/second. Consult with engineer and plan to move forward with the cement job. RD Hot oil truck Secure well Haul 525BBL of drilling mud to G&I in the vac truck. Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 07/06/2023 - Thursday PJSM and PTW T/IA on slight vacuum;R/U YJ E-line M/U CCL and 2.75"OD Gauge ring/Junk Basket Pressure test lubricator to 250psi/2500psi - Test Good;RIH and Tag TOC at 4,343ft (757 ft high) POOH MU 1-11/16" CBL, RIH and tag at 4,350ft. Pull CBL, Top of Good cement at 4,120ft (195ft low) intermittent cement seen up to 3,730ft. POOH Secure well, RD YJ E-line;MIT-IA to 2000psi - Test good, chart in O:drive 0min - 2283psi 15min - 2226psi 30min - 2000psi Pressure drop of 57psi followed by 26psi 07/18/2023 - Tuesday Mobe Eq. to location. PJSM, PTW, Cont. mobe Eq. pull well house. Spot Eq. move in flowback & supply tank, fill supply tank w/water, run return lines& r/u choke skid. Setup function test BOPE, good, test BOPE 250/2500 AOGCC witness waived by Jim Regg, test blind sheer & pipe/slips good. Continue rig up install horse head to injector head, finish running circ lines. SDFN. 07/19/2023 - Wednesday Approved PTW, Held PJSM and discussed daily activities. SLB last data charts on pervious day BOP test due to possible software issues. Torqued up BOP's and flooded stack and eq. Tested BOPE as per Sundry 250 2500psi, chased leak on high test, found stack had air, purged system and sequential test was good. Stabbed pipe thru injector and M/u ext CT connector, pull tested connector to 25k. M/u riser and stab on injector head. Filled CT and tested pipe rams 250-2500psi good test. M/u C/o assembly, DFCV, BiDi Jar, Hydr disconnect, Circ sub, Motor and 2.75" rock bit. Stab on injector and PT break 2500psi. Found o-ring leak repaired and sequential test was good. Opened well and RIH ~80fpm with open choke. Wt checks ever 1500'. Tagged at 4429'ctm. Came on with pump @ 1.25bpm/CP 3200psi. Est parameters. Began washing drilling down f/4429' t/4480', returns at BU dirty water with cmt fines. Drilled stringers f/4490' t/4600' ROP @~100fph. F/2600' t/2625' drilling solid cement, ROP @~50fph. Circulated BU returns clean. Began POOH at 80fpm, at 4300', reel motor surged RIH to fix lose coil wraps and motor locked up pulling on injector head. SD and troubleshot, called and discuss issue with machinic POOH slowly at ~20fpm. Inspected bit all good, L/d eq. secured well and SDFN Mechanic will be out in the AM to troubleshot reel motor issues 07/20/2023 - Thursday PJSM and approved PTW. SLB mechanic onsite the replace reel motor. Could not get the gear sprocket off the drive motor. Mechanic took the motor to the machine shot to have it removed. Mechanic back on location and replace motor. Serviced Unit and eq. while mechanic on site, plan to resume wellwork in the AM. Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 07/24/2023 - Monday Approved PTW and PJSM. R/u SL, Rih w/ 2.75 G-ring to 4518' kb, w/t 4520' kb, pooh. Rih w/ 2.72 G-ring to 4524' kb, w/t fall through, rih to 4750' kb, set down, do not work tools, pull up to 4524' kb, work tight spot. Pooh. Rih w/ 2.75 G-ring to 4518' kb, w/t 4520' kb, keep getting stuck, pooh. Rih w/ 2.7.6 G-ring to 4519' kb, w/t 4521' kb, jar free, keep setting down @ 4519 and working to 4521'kb and jarring free. Pooh. Check tool. Rih w/ 2.85 Starbit to 4518' kb, w/t 4525' kb, pooh. Rih w/ 2.8 Star bit to 4525' kb, w/t 4529' kb, pooh. Rih w/ 2.74 Star bit to 4528' kb w/t 4530' kb, fall through to 4575' kb, pull back up to 4530' kb, work tight spot pooh. Rih w/ 2.85 Starbit to 4518' kb, w/t 4525' kb, w/t up and down Keep losing spangs, pooh. Rih w/ 2.8 Starbit to 4526' kb, w/t 4534' kb, w/t up and down to clean above. Pooh. w/ tools, lay down check tool string, re-head. 07/22/2023 - Saturday Held PJSM and approved PTW. P/u injector head and lubricator stabbed on well. R/u Nitrogen bottles and blow CT dry. R/d injector head, lubricator and hard lines. RDMO SLB CT unit and eq. Vac truck emptied return tank. MIRU JY E-line Unit, M/u CCL and 1-11/16" CBL tool, Stab on well and PT lubricator to 250-2500psi. Opened well and RIH tag 5,104'md. Log CBL to 3500'md. TOC 3730'. (see log in O. drive) POOH. L/d tools and lubricator. RDMO YJ EL. 07/23/2023 - Sunday Pollard SL crew on location, PJSM and approved PTW. Used the SL crane to move wellhouse on 41-7. MIRU SL. R/u on well with .160 wire. R/u return line to flowback tank. M/u 3-1/2" braided line brush, RIH tag 4518', w/t couldnt work passed. POOH, M/u 2.79" GR RIH tagged 4,518' w/t couldnt work passed. POOH. M/u 3-1/2" swab cups, Swabbed well 4,300', could not work cup passed 4518' due to cement on tbg walls. POOH. 07/21/2023- Friday Approved PTW and held PJSM, discussed daily activities. P/u injector and 20' of riser. M/u C/o assembly (2.75" rock bit).PT tool string to 3500psi-good. Stabbed on well PT 250-2500psi. Found flange leak on DSA. Tightened flange and the sequential test was good. Opened well and RIH ~80fpm with open choke. Wt checks ever 1500'. Tagged at 4625'md. Started pumping @ 1.25bpm/CP 3200psi. Est parameters. Began drilling out cement @ 4625'. ROP ~50fph, 1/1 returns with cement fines. Drilled out cement to 5,100'md. Stalled motor several time trying to work passed tbg cut at 5,100'. Notified OE decision made to POOH. Pumped Hi-vis sweep STS returns clean. POOH. L/d tools riser and injector head. M/u night cap secured well and SDFN. Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 07/25/2023 - Tuesday Approve PTW and held PJSM. R/u SL, Rih w/ 2.8 Star bit to 4530' kb, w/t 4532' kb, fall through to 4573' kb, pull up clean spot @ 4532' kb, Rih w/ 2.85 Star bit to 4518' kb, w/t 4527' kb, keep losing spangs, pooh. Rih w/ 1 3/4 KJ w/ 2.85 Star bit to 4525' kb, w/t 4534' kb, fall through to 4563' kb, w/t 4571' kb, pooh. check tool string. Rih w/ 2.8 Star bit to 4573' kb w/t 4575' kb fall through to 4629' kb wt 4640' kb, fall through to 4750' kb, pick up, clear out tight spots above, rih to 4830' kb w/t 4835' kb, pooh, check tool string. Rih w/ KJ w/ 2.85 Starbit to 4573' kb w/t fall to 4627' kb w/t fall to 4708' kb w/t fall to 4835' kb, w/t pooh, clean out tight spots between 4575-4835'kb. Rih w/ 2.8 Starbit to 4839' kb, w/t 4860' kb, pooh, check tool string. Rih w/ 2.75 Starbit to 4849' kb, w/t fall to 4858' kb, w/t lose spangs, cant get spangs back, pooh. Rih w/ 1 3/4 X3' stem, kj, 2.8 Starbit to 4860' kb, w/t 4892' kb, pooh. Rih w/ 2.25 X 3' DD Bailer to 4883' kb, w/t 4930' kb, pooh, ooh w/ 1 cup of 1" shards of cement. Rih w/ same to 4928' kb w/t 4929' kb, pooh, ooh w/ same. Ooh w/ tools, lay down for the night. Approved PTW and held PJSM. R/u SL, Rih w/ 2.5" X 3' DD Bailer to 4928' kb, w/t 4929' kb, pooh. Ooh empty, broken flapper.Rih w/ 2.25 X 3' DD Bailer to 4930' kb, w/t 4931' kb, pooh, ooh 3" of ground up cement and some chunks. Rih w/ 2.5 X 3' DD Bailer to 4930' kb, w/t fall to 4944' kb w/t fall to 4981' kb, w/t pooh, ooh same.Rih w/ 1 3/4 KJ w/ 2.8 Starbit to 4890' kb, w/t 4904' kb, fall through to 4980' kb, pooh. Rih w/ 2.5" X 3' DD Bailer to 4990' kb w/t 5008' kb, pooh, ooh 2" of large chunks of cement. Rih w/ same to 5008' kb, w/t 5009' kb, pooh. Ooh same. Rih w/ 2.25 X 3' DD Bailer to large chunks. Rih w/ same to 5030' kb, w/t 5080' kb, pooh, ooh w/ same.Rih w/ 2.5" X 2' DD Bailer to 5060' kb, w/t 5086' . Rih w/ KJ w/ 2.8 Star bit to 4989' kb, w/t 5050' kb, L/d tools and SDFN 07/27/2023 - Thursday Approved PTW and held PJSM. R/u SL, Rih w/ KJ w/ 2.85 Starbit to 4888' kb, w/t 4930' kb, fall through to 4998' kb, w/t 5018' kb, clean up spots above, still tight @ 4930' kb, pooh. Rih w/ 2.7 G-ring to 5028' kb, w/t 5032' kb, cant pass pooh. Rih w/ 2.78 G-ring to 4568' kb, w/t 4590' kb, pooh. Rih w/ 2.76 G-ring to 4588' kb, w/t fall to 4608' kb, w/t fall to 4874' kb, w/t fall to 4912' kb, w/t fall to 5018' kb, w/t 5019' kb, pooh. Rih w/ 2.78 G-ring to 4572' kb, w/t 4619' kb, fall through to 4885' kb, w/t fall to 4992' kb, w/t 4996' kb, pooh. Rih w/ 2.5 X 3' DD Bailer to 5088' kb, w/t 5089' kb, pooh. Ooh w/ several large chunks of cement. Rih w/ 1 3/4 Kj w/ 2.8 Starbit to 5050' kb, w/t 5086' kb,. Rih w/ 1 3/4 KJ w/ 2.85 Starbit to 4982' kb, w/t 5002' kb, fall to 5018' kb, w/t 5064' kb, clean up tight spots above, pooh. Ooh w/ tools, lay down. Switch to .125 wire. SDFN 07/26/2023 - Wednesday Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 SL arrived at KGF, Approve PTW and held PJSM. R/u on well. Rih w/ 2.25 X 9' DD Bailer to 5089' kb, w/t pooh, ooh w/ 6" of wet cement. Rih w/ 2.25 X 4' DD Bailer to 5090' kb w/t 5091' kb, pooh. Ooh w/ 6" of ground up cement. Rih w/ same Rih w/ same to 5092' kb, pooh, ooh w/ 2" of ground up cement. Rih w/ same (Rih slow looking for flat spots) to 5093' kb, w/t pooh, ooh w/ 2". Rih w/ same to 5094' kb, w/t, pooh, ooh w/ 4" of ground up/wet cement. Rih w/ 2.25 X 9' Pump Bailer (12' open) to 5094' kb, get stuck, jar free, pooh, ooh w/ 2" of wet cement, some chunks of cement. Rih w/ 2.5 X 4' DD Bailer to 5094' kb, w/t pooh. Ooh w/ 2" of wet cement/ ground up cement. Rih w/ 2.25" X 4' DD Bailer to 5094' kb, w/t 5095' kb, pooh. Ooh 2" of ground up cement. Rih w/ same to 5095' kb, w/t pooh. Ooh bottom is plugged up. Rih w/ same to 5096' bk w/t 5097' kb. Pooh. L/d tools secured well and SDFN 07/30/2023 - Sunday Approve PTW and held PJSM. Rih w/ 2.25 X 4' DD Bailer to 5097' kb, w/t pooh. Ooh w/ 4" of ground up cement. Rih w/ Rih w/ same to 5098' kb, w/t pooh. Ooh w/ 6" of ground up cement. Rih w/ same to 5099' kb w/t 5100' kb, pooh. Ooh w/ 3" of ground up cement. Rih w/ same to 5100' kb, w/t pooh, ooh w/ 4" of ground up cement. Rih w/ tandem Swab Mandrels w/ 3 v-cups each to 1200' kb, see fluid level (shouldnt see fluid) grab 200 pooh, get returns back into tank. Swab down to 1510' kb, let well sit for 45 min, rih tag has not moved. Check IA, on slight vaccum, swab well to 1630 to see if IA goes on vacuum, does not go on vacuum. MIT- IA Initial=2246psi 15mins=2223psi 30mins=2209psi Secured well SDFN 07/29/2023 - Saturday 07/28/2023- Friday Approved PTW and held PJSM. Rih w/ 2.25" X 3' DD Bailer to 5063' kb, w/t 5064' kb, pooh, ooh empty. Rih w/ 2.5" X 3' DD Bailer to 5063' kb, w/t 5064' kb, pooh, ooh w/ 2" of wet cement and several small chunks of cement. Rih w/ same to 5063' kb w/t 5066' kb fall to 5071' kb, w/t 5072' kb have to jar free, pooh, ooh w/ 2" of wet cement, ground up cement. Rih w/ same to 5073' kb, w/t 5075' kb, pooh. Ooh w/ 3" of ground up cement. Rih w/ same to 5076' kb w/t 5078' kb, pooh. Ooh w/ 2" of ground up cement. Rih w/ same to 5078' kb, w/t 5079' kb, pooh, ooh w/ 1" of ground up cement. Rih w/ 2.25" X3' DD Bailer to 5079' kb, w/t 5081' kb, pooh. Ooh 2' of ground up cement. Rih w/ 2.25 X 3' DD Bailer to 5086' kb, w/t 5087' kb, pooh. Ooh 2' of ground up cement. Rih w/ 2.5" X 3' DD Bailer to 5087'kb w/t 5088' kb, pooh, ooh Rih w/ 2.25 X 3' DD Bailer to 5088' kb w/t 5089' kb, pooh, ooh full ground up cement. L/d tools and Re-head secure well and SDFN Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 YJ ELine arrives, completes Permit & JSA MIRU, PT 250/2500H psi - Pass RIH w/ 1-11/16" GR/CCL tool. Tagged at 5096' logged to 4480'. POOH RIH w/ CCL & 2" x 15ft long cement dump bailer with 2 gals (5ft) TC @ 5,091'. RDMO. Wait on cement to swab 08/09/2023 - Wednesday PTW, R/U SL Lubricator pt 2500, Lay down lub. Secure well for night 08/10/2023 - Thursday PTW, PJSM, RIH tag fluid 3350' Made 15 swab runs. F/3350-4548 RIH w/ 2.25''x7' pump bailer to 5107'kb tag cement pooh 08/04/2023- Friday SL arrive on location, Conduct PJSM, Permit w/ Ops RU & PT to 2000 psi, good test. RIH w/ bailers and start bit, start at 5101' Make 11 runs and work 2.5" bailer to 5107' SDFN, will continue bailing tomorrow. 08/05/2023 - Saturday SL Arrives, completes JSA and permits RIH and cleanout well from 5106' to 5113' using 2.5" bailers & star bits. Rig down move to KBU 23-05. 08/06/2023 - Sunday 08/03/2023 - Thursday PJSM, PTW, Prep Location, move out PWL Eq. Spot Yellow Jacket E-line unit, R/U lubricator & tool string- 1 11/16" Wt bar, GR/CCL, re-boot computer, check tools good. Test Lubricator 500/2500 good, RIH t/ tag @ 5080.5', P/U 300' RIH tag same. POOH, discuss with engineering for plan forward. R/D e-line move off. Move in PWL, spot eq. & start rig-up.for bailing operations. SDFN Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 YJ move from 14-06Y onto KBU 22-06 MIRU, PT equipment to 3,000 psi SLB N2 unit RU and PT lines Start pressuring up well with N2 to push fluid away. YJ RU w/ GPT and RIH find fluid @ 3730ft w/ 1600 psi on well Pressure up well to 2790 psi. FL @ 4700'. Pressure up well to 2820 and monitored fluid depression. Confirmed fluid away, SD N2 pumping. waited 10 min, confirmed fluid was pushed away. POOH. RIH w/ 20' ox 2.5" cement dump bailer, fill with 4.5 gal of 15.8 cement. dump at 5,077' with 1200 psi on well. POOH and confirmed good dump. RIH w/ 2nd 20' x 2.5" cement dump bailer, filled with 4.5 gal of 15.8 cement. Dump at 5067'' with 1050 psi. TOC @ 5,052'. Final tubing pressure @ 1100 psi. SDFN 08/11/2023- Friday PTW, R/U Yellow jacket E-line, P/U 10', 2" 6 spf, 60 deg phasing perf gun, r/u on well, P/t 250/2500 good. RIH WHP 620psi, tag @ 5090' e-line measurement, pull correlation log send to engineering for correlation. Make 5' correction as per engineering, pull gun into position, CCL@5064.5', 10.5' ccl to top shot, placing shots @ 5075-5085' fire guns, good indication at surface guns fired. No initial change in pressure. Start pressure 620psi 5 min 660psi 10 min 675 15 min 680 30 min OOH, 690psi. Turn well to production to flow, without good results. RIH w/ GPT tool string finding fluid level @ 1735', tag bottom @ 5080.5', no temp change at perfs, POOH finding fluid level @ 1250'. Secure well, r/d e-line. 08/12/2023 - Saturday PTW, PJSM, R/U on well with 5' string shot, pt 250/2500 good. RIH place t/ ccl depth of 5021', 3.5' to string shot placing it accross 5025', fire shot, POOH, verify fired good RDMO. PTW, PJSM, MIRU SL, w/ 2.75GR, PT lubricator 250/2500 good. RIH see fluid level @740', tag KB depth 5067', POOH. M/U brush, RIH brush across plug setting point @ 5025', work several times over 20 min, 4980-5060' . POOH, secure well, RDMO. 08/13/2023 - Sunday Rig Start Date End Date 6/29/23 8/15/23 Daily Operations: Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 22-06 50-133-20550-00-00 205-054 08/14/2023 - Monday YJ ELine arrive, complete PTW and TGSM PU and RIH w/ GPT. Tag cement @ 5050.5' and saw no fluid in well with 1100 psi on tubing. RIH w/ 3.5" CIBP (Legacy Big Boy), confirm correlation with town, and set at 5025'. (change of plug depth confirmed with AOGCC). Eline tagged plug & logged tag. RIH w/ 2.5" x 20' cement bailer loaded with 4.5 gal of 15.8# cement, RIH and dump cement at 5025' RIH w 2.5" x 20' cement bailer loaded with 4.5 gal of 15.8# cement, RIH and dump cement at 5012'. Wait on cement Plan to perf in the morning. 08/15/2023 - Tuesday Approved PTW and PJSM. MIRU YJ EL unit.;P/u PCE and lubricator, M/u GPT tool. Stab on well and PT 2500psi.;\RIH w/GPT and tagged TOC @ 5001'. Confirmed no fluid in well. POOH;RIH W/ GR-CCL & 20' X 2 3/8" 5SPF HSC, SENT PASS TO TOWN CONFIRMED ON DEPTH. SITP 300psi, FIRED GUN @ 4938'-4958' LOST 150 0N WT INDICATOR , TBG PRESSURE INCREASED TO 460PSI, STARTED PULLING AND INSTANTLY STARTED PULLING WT WORKED FOR A WHILE AND NO MOVEMENT.;DROPPED KINLEY CUTTER WORKED LINE UNTIL CUTTER CUT, LEFT 75' OF WIRE ON TOP OF HEAD, TOP OF HEAD ~4926'. WELL FILE HAS FISH DIAGRAM. Tree crossing = 4-3/4" Otis 3-1/2" Top of Cement (CBL @ 5,150') Excape System Details - Ceramic flapper valves below each module as follows: - 6 Conventional flappers - No flappper at Module-1 Flappers MD (RKB): Module 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA FISH 1-11/16" X 3-1/2" Spinner 8,700' tagged on (7/2/2007) KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. TD 8,855' MD 7,725' TVD PBTD 5,800' MD 4,684' TVD Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 5,100' TVD 0' 4,031'' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Permit #: 205-054 API #: 50-133-20550-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: Longitude: Spud: 5/20/2005 TD: 6/3/2005 Rig Released: 6/9/2005 PA #: Perfs MD (RKB): (Sterling) MD TVD Ft Perf Date Comments B4-2 4,938'-4,958' 3,890'-3,907' 20' 08/15/23 Open B5.1 5,075'-5,085' 4,009'-4,019' 10' 08/11/23 Isolated B5A 5,285-5,290 4,198'-4,203' 5' 10/19/20 Isolated (Beluga) MD TVD Ft Perf Date Comments UB-1 5,930-5,955 4,809'-4,833' 25' 09/05/19 Isolated UB-3 6,013-6,023' 4,889'-4,899' 10' 09/04/19 Isolated UB-4B 6,130-6,135 5,003'-5,008' 5' 08/29/19 Isolated UB-5 6,166-6,186 5,039'-5,058' 11/10/16 Isolated UB-5A 6,197-6,217 5,069'-5,089' 11/10/16 Isolated UB-5B 6,228-6,248 5,100'-5,120' 11/10/16 Isolated Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 Isolated 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 Isolated (correlated to 7,031'-7,052' CH) Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Isolated Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 Isolated (Tyonek) MD TVD Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Isolated Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Isolated Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Isolated Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 Isolated Tagged fill @ 7851' MD (2/23/13) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 22-6 Kenai Peninsula Borough 5,285' - 8,685' 1.9º / 100' @ 300 ft 8/3/2005 D Ambruz Lease: State: Perf (TVD): Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,198' - 7,555' 1º 5º RKB:(AMSL)21' (AGL) 09-12-23 SCHEMATIC UB-5A / UB-5B UB-5 UB-4B UB-3 UB-1 B5A 9-5/8" Calc TOC @ 3925' CBL TOC @ 4,122' CIBP Depths: 5,025' w/ 25ft of cmt (8/14/23) 5,245' w/ 25ft of cmt (6/29/23)5,335' w/ 25ft of cmt (6/29/23) 5,800' (10/16/20) 6,105' w/ 5ft of cmt (9/5/19) 6,157' w/ 5ft of cmt (9/5/19)6,214' (8/26/19) 6,430' w/ 25ft of cmt (11/10/16)6,478' w/ 25ft cmt (11/1/16) Tbg cut @ 5100' 5.1 Eline Tool string top of fish 4926' w/ ~75' of wire B 4-2 1.25 gal cement in Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 08/24/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230824 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 14-6Y 50133205720000 207149 8/10/2023 YELLOW JACKET GPT/Plug/Perf KBU 14-6Y 50133205720000 207149 8/12/2023 YELLOW JACKET GPT/Plug/Perf KBU 14-6Y 50133205720000 207149 8/17/2023 YELLOW JACKET GPT/Plug/Perf KBU 22-06 50133205500000 205054 8/3/2023 YELLOW JACKET Gamma Ray KBU 22-06 50133205500000 205054 8/6/2023 YELLOW JACKET Gamma Ray KBU 22-06 50133205500000 205054 8/11/2023 YELLOW JACKET GPT/Plug/Perf MPU J-29A 50029236880100 221023 8/19/2023 READ Caliper Survey PBU S-42A 50029226620100 215055 8/11/2023 READ MAPP PBU PSI-09 50029230950000 202124 7/28/2023 HALLIBURTON WFL-TMD3D Please include current contact information if different from above. T37955 T37955 T37955 T37956 T37956 T37956 T37957 T37958 T37959 8/28/2023 YELLOWKBU 22-06 50133205500000 205054 8/3/2023 JACKET Gamma Ray YELLOWKBU 22-06 50133205500000 205054 8/6/2023 JACKET Gamma Ray YELLOWKBU 22-06 50133205500000 205054 8/11/2023 JACKET GPT/Plug/Perf Kayla Junke Digitally signed by Kayla Junke Date: 2023.08.28 15:49:42 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:McLellan, Bryan J (OGC) To:Chad Helgeson Cc:Donna Ambruz; Noel Nocas Subject:RE: KBU 22-06 PTD# 205-054 plug back Date:Monday, August 14, 2023 9:23:00 AM Chad, Hilcorp has approval to set the plug at 5025’ MD as described in your email below. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Chad Helgeson <chelgeson@hilcorp.com> Sent: Friday, August 11, 2023 3:12 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Donna Ambruz <dambruz@hilcorp.com>; Noel Nocas <Noel.Nocas@hilcorp.com> Subject: KBU 22-06 PTD# 205-054 plug back Bryan, We are working on the KBU 22-06 well, PTD# 205-054, and Sundry # 323-359, and currently completed step 33 (finished perforating the Sterling 5.1 sands 5075-5085). We are moving to our contingency plans for plugging and perforating the next zones up hole. The approved contingency plans were for a plug at ±5050’ for this zone. I would like to move the plug to 5025’ and then place 25ft of cement on the plug. This still meets the requirements of setting a plug within 50 ft of top perf, but wanted to be sure you were okay with this small change to the program of moving the plug up 25ft. This plug will isolate the Sterling 5.1 Pool. The top of the pool is 4,970’. The next set of perfs is at 4928’ in the next Pool. Let me know if you need any additional info or do not approve this change of depth for the plug. Attached is a current schematic on the well. Chad Helgeson Operations Engineer Kenai Asset Team 907-777-8405 - O 907-229-4824 - C 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 deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Tree crossing = 4-3/4" Otis 3-1/2" Top of Cement (CBL @ 5,150') Excape System Details - Ceramic flapper valves below each module as follows: - 6 Conventional flappers - No flappper at Module-1 Flappers MD (RKB): Module 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA FISH 1-11/16" X 3-1/2" Spinner 8,700' tagged on (7/2/2007) KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. TD 8,855' MD 7,725' TVD PBTD 5,800' MD 4,684' TVD Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Permit #: 205-054 API #: 50-133-20550-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: Longitude: Spud: 5/20/2005 TD: 6/3/2005 Rig Released: 6/9/2005 PA #: Perfs MD (RKB): (Sterling) MD TVD Ft Perf Date Comments B4-1 ±4,812'-4,872' ±3,784'-3,834' ±60' TBD If Necessary B4-2 ±4,928'-4,958' ±3,878'-3,907' ±30' TBD If Necessary B5.1 5,075'-5,085' 4,009'-4,019' 10' 8/11/23 PROPOSEDB5A 5,285’-5,290’ 4,198'-4,203' 5 10/19/20 Isolated (Beluga) MD TVD Ft Perf Date Comments UB-1 5,930’-5,955’ 4,809'-4,833' 25' 09/05/19 Isolated UB-3 6,013’-6,023' 4,889'-4,899' 10' 09/04/19 Isolated UB-4B 6,130-6,135’ 5,003'-5,008' 5' 08/29/19 Isolated UB-5 6,166’-6,186’ 5,039'-5,058' 11/10/16 Isolated UB-5A 6,197’-6,217’ 5,069'-5,089' 11/10/16 Isolated UB-5B 6,228-6,248’ 5,100'-5,120' 11/10/16 Isolated Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 Isolated 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 Isolated (correlated to 7,031'-7,052' CH) Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Isolated Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 Isolated (Tyonek) MD TVD Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Isolated Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Isolated Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Isolated Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 Isolated Tagged fill @ 7851' MD (2/23/13) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 22-6 Kenai Peninsula Borough 5,285' - 8,685' 1.9º / 100' @ 300 ft 8/3/2005 Chad Helgeson Lease: State: Perf (TVD): Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,198' - 7,555' 1º → 5º RKB:(AMSL)21' (AGL) 7-10-23 Current UB-5A / UB-5B UB-5 UB-4B UB-3 UB-1 B5A 9-5/8" Calc TOC @ 3925' CBL TOC @ 4,122' CIBP Depths:±5,025' w/ 25ft of cmt (TBD)5,245' w/ 25ft of cmt (6/29/23)5,335' w/ 25ft of cmt (6/29/23)5,800' (10/16/20) 6,105' w/ 5ft of cmt (9/5/19) 6,157' w/ 5ft of cmt (9/5/19)6,214' (8/26/19)6,430' w/ 25ft of cmt (11/10/16)6,478' w/ 25ft cmt (11/1/16) Tubing cut @ 5.1 Proposed plug @ 5025' Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/31/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230731 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 22-06 50133205500000 205055 7/22/2023 YELLOW JACKET SCBL KU 22-6X 50133205800000 208135 6/23/2023 HALLIBURTON EPX KU 22-6X 50133205800000 208135 6/23/2023 HALLIBURTON MFC MPU F-09 50029227730000 197104 7/22/2023 YELLOW JACKET PERF SRU 213-15 50133206520000 215100 7/20/2023 YELLOW JACKET GPT/PLUG/PERF Please include current contact information if different from above. T37902PTD:205-054 T37903 T37903 T37904 T37905 YELLOWKBU 22-06 50133205500000 205055 7/22/2023 SCBLJACKET Kayla Junke Digitally signed by Kayla Junke Date: 2023.08.01 10:13:43 -08'00' Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 07/11/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230711 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# KBU 22-06 50133205500000 205054 7/6/2023 YELLOW JACKET CBL KBU 22-06 50133205500000 205054 7/2/2023 YELLOW JACKET CBL/PERF KBU 33-06X 50133205290000 203183 6/14/2023 YELLOW JACKET GPT/PERF KBU 33-06X 50133205290000 203183 6/29/2023 YELLOW JACKET GPT/PERF KBU 33-06X 50133205290000 203183 6/13/2023 YELLOW JACKET PERF KU 12-17 50133205770000 208089 6/14/2023 YELLOW JACKET PERF MP F-89 50029232680000 205090 7/6/2023 READ Caliper Survey MP K-05 50029226700000 196068 5/30/2023 READ Caliper Survey MPU E-23 50029225700000 195094 6/23/2023 YELLOW JACKET CUT MPU L-43 50029231900000 203224 6/27/2023 YELLOW JACKET PERF PAXTON 12 50133207100000 223014 6/28/2023 YELLOW JACKET PERF Please include current contact information if different from above. T37830 T37830 T37831 T37831 T37831 T37832 T37833 T37834 T37835 T37836 T37837 YELLOWKBU 22-06 50133205500000 205054 7/6/2023 CBLJACKET YELLOWKBU 22-06 50133205500000 205054 7/2/2023 CBL/PERFJACKET Kayla Junke Digitally signed by Kayla Junke Date: 2023.07.11 14:54:56 -08'00' MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:6 Township:4N Range:11W Meridian:Seward Drilling Rig:N/A Rig Elevation:N/A Total Depth:8855 ft MD Lease No.:FEDA028142 Operator Rep:Suspend:P&A:X Conductor:20"O.D. Shoe@ 130 Feet Csg Cut@ Feet Surface:13 3/8"O.D. Shoe@ 1668 Feet Csg Cut@ Feet Intermediate:9 5/8"O.D. Shoe@ 6529 Feet Csg Cut@ Feet Production:3 1/2"O.D. Shoe@ 8837 Feet Csg Cut@ Feet Liner:O.D. Shoe@ Feet Csg Cut@ Feet Tubing:O.D. Tail@ Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Tubing Bridge plug 5335 ft 5334 ft 8.4 ppg Wireline tag Tubing Bridge plug 5246 ft 5245 ft 8.4 ppg Wireline tag Tubing Bridge plug 5245 ft 5219 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing 2755 2740 2738 IA 0 0 9 OA 5 5 5 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Plugging ops to isolate Sterling 5.2 gas pool. On 6/30/2023, I witnessed tags on top of 1st bridge plug @ 5334 ft MD and 2nd bridge plug @ 5245 ft MD. On 7/3/2023 I witnessed the tag of top of cement plug @ 5219 ft MD and a passing MIT-T. July 3, 2023 Bob Noble Well Bore Plug & Abandonment Kenai Beluga Unit 22-6 Hilcorp Alaska LLC PTD 2050540; Sundry 323-359 none Test Data: P Casing Removal: Karson Kozub Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): rev. 11-28-18 2023-0703_Plug_Verification_KBU_22-6_bn               1. Type of Request:Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: Cement Annulus, N2 2. Operator Name:4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address: Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number): 10. Field: Current Pools: 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,855'8,700' Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 10,530psi Liner Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments:Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng 10,160psi7,707'8,837' 130' 1,668' 6,529' Perforation Depth MD (ft): 8,816'3-1/2" 9-5/8"6,508' 20" 13-3/8" 109' 1,647' 5,750psi 3,060psi 3,450psi 130' 1,503' 5,400' Length Size Proposed Pools: TVD Burst PRESENT WELL CONDITION SUMMARY 7,725'5,800'4,684'~796 psi See Schematic MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 205-054 50-133-20550-00-00 Kenai Gas Sterling 5.2 Gas Sterling 5.1 or Pool 4 Gas CO 510B Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, Alaska 99503 Kenai Beluga Unit (KBU) 22-06 Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft):Tubing Size: 9.3# / L-80 8,837' July 5, 2023 N/A; N/A N/A; N/A See Schematic See Schematic 3-1/2" 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Chad Helgeson, Operations Engineer chelgeson@hilcorp.com 907-777-8405 Noel Nocas, Operations Manager 907-564-5278 m n P t 2 66 Form 10-403 Revised 10/2022 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov 323-359 By Grace Christianson at 2:31 pm, Jun 23, 2023 Digitally signed by Noel Nocas (4361) DN: cn=Noel Nocas (4361) Date: 2023.06.23 12:04:57 - 08'00' Noel Nocas (4361) BJM 6/28/23 MDG 6/26/2023 Variance to 20AAC25.112(c)(1)(E) approved to place bridge plug and 25' cement greater than 50' above perfs in Sterling 5.2 gas pool. The Sterling 5.2 perfs are currently isolated with a CIBP (without a cement cap) at 5800' and ~400' of fill. The new CIBP will be placed ~600' above the perfs at 5335' and capped with 25' of cement. Perform MITIA to at least 1500 psi within 30 days of returning well to production after adding perfs. 10-404 DSR-6/23/23 Pressure test Excape lines and fill with cement if possible before adding any new perfs or tubing punches. JLC 6/28/2023 06/28/23 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.06.28 19:31:41 -05'00' RBDMS JSB 062923 Well: KBU 22-06 Date: 6/21/23 PTD: 205-054 Well Name: KBU 22-06 API Number: 50-133-20550-00-00 Current Status: SI Gas Well Permit to Drill Number: 205-054 First Call Engineer: Chad Helgeson (907) 777-8405 (o) (907) 229-4824 (c) Second Call Engineer: Jake Flora (907) 777-8442 (o) (720) 988-5375 (c) Maximum Expected BHP: 1195 psi @ 3,985’ TVD Based on KBU 32-06 RFT data on 2/13/2017 Maximum Potential Surface Pressure: 796 psi @ 3,985’ TVD Using 0.1 psi/ft gradient 20 AAC 25.280(b)(4) Well Summary KBU 22-06 is an excape completion well drilled by Marathon in 2005. Hilcorp perforated the Beluga UB-5, the UB-5A and UB-5B in 2016, and the UB-1, UB 3 and UB 4B in 2019 without any success. The well was recompleted to the Sterling Pool 5.2 in 2020, where it successfully flowed until February of 2022, when it watered out. The goal of this project is to complete the abandonment of UpperTyonek/Beluga Pool by placing another plug and cement. Then abandon the Kenai Sterling Pool 5.2, cement the 3-1/2” x 9-5/8” annulus for access to perforating the Sterling Pool 5.1 and Pool 4 sands. These Sands will not be commingled. The well will be perforated in one Pool at a time. Notes Regarding Wellbore Condition x MIT-IA passed to 1500 psi on 9/30/2020 and on 10/23/2020 x 3-1/2” (2.75” OD) CIBP set at 5,800’ WLM 10/16/2020 x Current Open perforations from 5285-5290’ x Max deviation of 46 degrees at 2699’ MD / 2244’ TVD x CBL dated 6/17/2005 indicates a top of cement in the 3-1/2” by 9-5/8” annulus at 5150’ MD x No Bond Log on 9-5/8” Casing. Calculated TOC with 33% losses (full returns reported during job) is 3,925’ x SL bailed fill to 5,409’ on 6/12/23 Pool Tops in KBU 22-06 based on KU 21-6 reference well in CO 510B - Beluga/Upper Tyonek: 5833’ MD; 4715’ TVD - Pool 6: 5589’ MD; 4482’ TVD - Pool 5.2: 5265’ MD; 4180’ TVD - Pool 5.1: 4970’ MD; 3918’ TVD - Pool 4: 4812’ MD; 3784’ TVD - Pool 3: 4548’ MD; 3570’ TVD E-Line procedure 1. MIRU E-line and pressure control equipment, PT lubricator 250psi low / 2,500psi high. 2. RIH w/ CIBP and set at 5,335’. o Tag plug (notify AOGCC with 24hr notice to witness) Variance request of 20AAC25.112(c)(1)(E) - Hilcorp is requesting to set a plug with 25ft of cement greater than 50ft above the top of the perforated interval. (proposed depth is 600ft above the top perf in the Beluga/Upper Tyonek Pool). The proposed plug depth is at 5,335’ which places the cement across an interval with coal underclay isolation at 5,322’. These Sands will not be commingled. Top of fill @ 5409' MD. Bridge plug and cement will be placed above fill, below existing perfs and across confining interval. Variance approved. -bjm perforating the Sterling Pool 5.1 and Pool 4 sands. Well: KBU 22-06 Date: 6/21/23 PTD: 205-054 3. MU dump bailer and dump 25ft of cement on top of plug with TOC @ 5,310’. (This plug will be the Beluga/Sterling Pool isolation plug) o Note there was a plug set in 2020 per sundry #320-402, without cement o The well flowed 2 years and there is sand fill over plug 4. MU 3-1/2” CIBP 5. RIH and set 3-1/2” CIBP at ±5,250’ MD (within 50ft of the top perfs) a. Tag plug (notify AOGCC with 24hr notice to witness) b. Do not set plug in tubing collar c. Regulations require plug to be set within 50’ of perfs @ 5,285’ MD d. Pool Isolation plug for Sterling Pool 5.2 6. RIH and dump bail 25’ of cement on top of plug (est ToC ±5,225’ MD) 7. Load tubing with source/lease water lubricate & bleed o ~45bbl WBV (if well doesn’t start with a fluid level) 8. Run a new CBL to determine new TOC for cut 9. MIT-T to 2500 psi (no chart required- confirming plug holds) 10. MU and RIH with tubing cutter or punch 11. Holding at least 450psi on the tubing, cut/punch at ±5,125’ MD (or at a depth the new log does not show any cement) – See Clip of the existing bond log, attached o 9-5/8” x 3-1/2” Annulus is 10.6ppg drilling mud 12. Establish circulation from tubing to IA. o May need to work circulation both directions to break loose any settled drilling mud Contingency: if circulation can’t be established at least 2bpm contact OE. May have to move uphole and punch/cut again. Proposed Backup cut/punch depth = ±5,100’ MD. Second option for backup cut is 5,050’ (if 3rd option is necessary, proposed Pool 5.1 perfs will not be shot.). 13. Once circulation is established in both directions, swap well over to all source/lease water at max rate (>2bpm): o IA volume ~377bbls o Tubing volume ~45bbls o Minimum of at least 1 surface to surface volume pumped (425bbls minimum) o Pump additional water if returns aren’t clean o Preference is to take returns up the tubing 14. CMIT-TxIA to 2500psi (no chart required) 15. RDMO EL and pump truck 3-1/2” x 9-5/8” IA Cementing Procedure 16. RU cement truck, PT lines to 250psi low / 2,500psi high 17. Mix and pump 15.3 to 15.8ppg cement down the tubing, taking returns up the 3-1/2” x 9-5/8” IA o Manage IA back pressure to prevent the cement from running away down tubing 18. Planned TOC in IA is ±3,925’ MD. (±77bbls required) a. 0.0639 bbl/ft x 1,200ft = 77 bbls Well: KBU 22-06 Date: 6/21/23 PTD: 205-054 19. Displace per OE with ~44.5 bbls (use dart and cement head for dropping) drop dart/wiper ball down to tubing cut b. 0.0087 bbl/ft x 5,100ft = 44 bbls 20. SI well and IA while trapping pressure on the tubing (~425psi), ensure cement doesn’t utube 21. RDMO cementers 22. MIRU EL and pressure control equipment 23. PT lubricator to 250 psi Low / 2,500 psi High 24. RIH and tag TOC and complete CBL 25. RD EL 26. MIT-IA to 2000psi for 30 charted minutes 27. MIRU SL, PT PCE 250 psi Low / 2,500 psi High 28. Swab well down to 5,100’ 29. RDMO SL Contingency CT Procedure if cement tag is shallower than 5,100’ a. MIRU CTU, 24hr notice for BOP test b. Conduct BOP test to 250psi Low / 2500psi High c. If cement tag is shallower than 5,100’ Mill out cement to 5,100’ using lease water d. RIH and obtain dry tag of ToC with a nozzle and reverse out ~44 bbls of water e. Trap N2 pressure on tubing per OE recommendation for perforating f. RDMO CT E-Line Perf procedure 30. MIRU E-line and pressure control equipment 31. PT lubricator to 250psi low / 2,500 psi High 32. RIH and perforate Sterling Pool 5.1 sands per RE/Geo Pool Sand Perf Top (MD) Perf Bottom (MD) Perf Top (TVD) Perf Bottom (TVD) Total Footage (MD) Sterling 5.1 Sterling P5.1_B4 ±5,075’ ±5,095’ ±4,009’ ±4,026’ ±20' a. Proposed perfs also shown on the proposed schematic in red font. b. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. c. Use Gamma/CCL to correlate. d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. e. These sands are in the Kenai Sterling Gas Pool 5.1 per CO 510B. 33. Turn well over to operations and flow the well Contingency if Kenai Sterling Gas Pool 5.1 sand is not productive: Well: KBU 22-06 Date: 6/21/23 PTD: 205-054 a. MIRU N2 Pump and E-line with pressure control equipment b. PT lubricator and pump lines to 250psi low / 2,500 psi High c. MU CIBP with GPT tool. d. Pressure up with N2 and push water away, verifying depth of water with GPT (water must be deeper than 4970’) e. RIH and set 3-1/2” CIBP plug at ±5,050’ MD o Tag CIBP o Do not set plug across a collar f. RIH and dump bail 25’ of cement on top of plug (est ToC ±5,025’ MD) g. RIH and perforate Kenai Sterling Gas Pool 4 sands Pool Sand Perf Top (MD) Perf Bottom (MD) Perf Top (TVD) Perf Bottom (TVD) Total Footage (MD) Sterling 4 Sterling P4_B1 ±4,812’ ±4,872’ ±3,784’ ±3,834’ ±60' Sterling 4 Sterling P4_B2 ±4,928’ ±4,958’ ±3,882’ ±3,907’ ±30' i. Proposed perfs also shown on the proposed schematic in red font. ii. Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. iii. Use Gamma/CCL to correlate. iv. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals post shot. v. These sands are in the Kenai Sterling Gas Pool 4 per CO 510B. vi. If Sterling B1 sands are wet, zone will be tested in lengths that are patchable. vii. A wireline permanent patch will be installed across upper perfs. 34. Conduct SVS testing as required per regulations Post-Perf MIT-IA 35. Perform MIT-IA to 2000psi once job is complete and well has been brought online within 30 days. Attachments: 1. 3-1/2” x 9-5/8” CBL Clip – 6/17/05 2. Current schematic 3. Proposed Schematic 4. CT BOP Schematic (Fox) – If needed 5. Standard Well procedure – N2 Operations Well: KBU 22-06 Date: 6/21/23 PTD: 205-054 KBU 22-06 CBL Snip 4970-5280’ (6/17/05) Tree crossing = 4-3/4" Otis 3-1/2" Top of Cement (CBL @ 5,150') Excape System Details - Ceramic flapper valves below each module as follows: - 6 Conventional flappers - No flappper at Module-1 Flappers MD (RKB): Module 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA FISH 1-11/16" X 3-1/2" Spinner 8,700' tagged on (7/2/2007) KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. TD 8,855' MD 7,725' TVD PBTD 5,800' MD 4,684' TVD Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Permit #:205-054 API #:50-133-20550-00-00 Prop. Des:A - 028142 KB elevation:87' (21' AGL) WBS #: Latitude: Longitude: Spud:5/20/2005 TD:6/3/2005 Rig Released:6/9/2005 PA #: Perfs MD (RKB): (Beluga) MD TVD Ft Perf Date Comments B5A 5,285’-5,290’ 4,198'-4,203' 5 10/19/20 Open UB-1 5,930’-5,955’ 4,809'-4,833' 25' 09/05/19 Isolated UB-3 6,013’-6,023' 4,889'-4,899' 10' 09/04/19 Isolated UB-4B 6,130-6,135’ 5,003'-5,008' 5' 08/29/19 Isolated UB-5 6,166’-6,186’ 5,039'-5,058' 11/10/16 Isolated UB-5A 6,197’-6,217’ 5,069'-5,089' 11/10/16 Isolated UB-5B 6,228-6,248’ 5,100'-5,120' 11/10/16 Isolated Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 Isolated 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 Isolated (correlated to 7,031'-7,052' CH) Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Isolated Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 Isolated (Tyonek)MD TVD Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Isolated Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Isolated Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Isolated Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 Isolated Tagged fill @ 7851' MD (2/23/13) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 22-6 Kenai Peninsula Borough 5,285' - 8,685' 1.9º / 100' @ 300 ft 8/3/2005 Chad Helgeson Lease: State: Perf (TVD): Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,198' - 7,555' 1º ĺ 5º RKB:(AMSL)21' (AGL) 6-21-23 SCHEMATIC CIBP w/ 25' cement 6,478' CIBP w/ 25' cement 6,430' CIBP w/ 5' cement 6,105' 09/05/19 CIBP w/ 5' cement 6,157' 09/05/19 CIBP 6,214' 08/26/19 UB-5A / UB-5B UB-5 UB-4B UB-3 UB-1 B5A 9-5/8" Calc TOC @ 3925' CIBP @5,800' 10/16/20 Tag Sand @ 5409' on 6/12/23 Tree crossing = 4-3/4" Otis 3-1/2" Top of Cement (CBL @ 5,150') Excape System Details - Ceramic flapper valves below each module as follows: - 6 Conventional flappers - No flappper at Module-1 Flappers MD (RKB): Module 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA FISH 1-11/16" X 3-1/2" Spinner 8,700' tagged on (7/2/2007) KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. TD 8,855' MD 7,725' TVD PBTD 5,800' MD 4,684' TVD Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Permit #:205-054 API #:50-133-20550-00-00 Prop. Des:A - 028142 KB elevation:87' (21' AGL) WBS #: Latitude: Longitude: Spud:5/20/2005 TD:6/3/2005 Rig Released:6/9/2005 PA #: Perfs MD (RKB): (Sterling) MD TVD Ft Perf Date Comments B4-1 ±4,812'-4,872' ±3,784'-3,834' ±60' TBD If Necessary B4-2 ±4,928'-4,958' ±3,878'-3,907' ±30' TBD If Necessary B5.1 ±5,075'-5,095' ±4,009'-4,026' ±20' PROPOSED B5A 5,285’-5,290’ 4,198'-4,203' 5 10/19/20 Isolated (Beluga) MD TVD Ft Perf Date Comments UB-1 5,930’-5,955’ 4,809'-4,833' 25' 09/05/19 Isolated UB-3 6,013’-6,023' 4,889'-4,899' 10' 09/04/19 Isolated UB-4B 6,130-6,135’ 5,003'-5,008' 5' 08/29/19 Isolated UB-5 6,166’-6,186’ 5,039'-5,058' 11/10/16 Isolated UB-5A 6,197’-6,217’ 5,069'-5,089' 11/10/16 Isolated UB-5B 6,228-6,248’ 5,100'-5,120' 11/10/16 Isolated Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 Isolated 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 Isolated (correlated to 7,031'-7,052' CH) Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Isolated Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 Isolated (Tyonek)MD TVD Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Isolated Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 IsolatedModule 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Isolated Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 Isolated Tagged fill @ 7851' MD (2/23/13) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 22-6 Kenai Peninsula Borough 5,285' - 8,685' 1.9º / 100' @ 300 ft 8/3/2005 Chad Helgeson Lease: State: Perf (TVD): Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,198' - 7,555' 1º ĺ 5º RKB:(AMSL)21' (AGL) 6-19-23 PROPOSED UB-5A / UB-5B UB-5 UB-4B UB-3 UB-1 B5A 9-5/8" Calc TOC @ 3925'Proposed 3-1/2" TOC ±3950' CIBP Depths: ±5,250' w/ 25ft of cmt (TBD) ±5,335' w/ 25ft of cmt (TBD) 5,800' (10/16/20) 6,105' w/ 5ft of cmt (9/5/19) 6,157' w/ 5ft of cmt (9/5/19) 6,214' (8/26/19) 6,430' w/ 25ft of cmt (11/10/16) 6,478' w/ 25ft cmt (11/1/16) B4 (If Tubing punch @ ±5125' B5.1 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. Kyle Wiseman Hilcorp Alaska, LLC Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: Kyle.Wiseman@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/28/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20221128-1 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# CLU 13 50133206460000 214171 11/12/2022 Halliburton PERF CLU 05RD2 50133204740200 222092 11/11/2022 Halliburton PPROF KBU 22-06 50133205500000 205054 2/26/2022 Halliburton RMX KBU 22-06 50133205500000 205054 2/26/2022 Halliburton TMD3D KBU 33-06X 50133205290000 203183 2/28/2022 Halliburton RMX KBU 33-06X 50133205290000 203183 2/28/2022 Halliburton TMD3D KDU 4 50133201760000 169012 11/7/2022 Halliburton EPX KDU 4 50133201760000 169012 11/7/2022 Halliburton MFC24 KU 43-6RD 50133100910100 201231 11/8/2022 Halliburton EPX KU 43-6RD 50133100910100 201231 11/8/2022 Halliburton MFC24 Please include current contact information if different from above. By Meredith Guhl at 10:05 am, Nov 29, 2022 T37319 T37313 T37320 T37320 T37321 T37321 T37322 T37322 T37323 T37323 KBU 22-06 50133205500000 205054 2/26/2022 Halliburton RMX KBU 22-06 50133205500000 205054 2/26/2022 Halliburton TMD3D Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.11.29 11:15:51 -09'00' Kaitlyn Barcelona Hilcorp North Slope, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 564-4389 E-mail: kaitlyn.barcelona@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal Received By: Date: DATE: 4/07/2022 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 22-06 (PTD 205-054) TMD3D 2/26/2022 Please include current contact information if different from above. 205-054 T36451 Meredith Guhl Digitally signed by Meredith Guhl Date: 2022.04.08 08:29:10 -08'00' 2SHUDWLRQV $EDQGRQ 3OXJ3HUIRUDWLRQV )UDFWXUH6WLPXODWH 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Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: _____N2______ 2.Operator Name:4.Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD): 6105; 6157;Junk (MD): 8,855'8,700' Casing Collapse Structural Conductor 1,500psi Surface 1,950psi Intermediate 3,090psi Production 10,530psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Taylor Wellman 777-8449 Contact Name: Mike Quick Operations Manager Contact Email: Contact Phone: 777-8442 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng mquick@hilcorp.com 7,725'6,105'4,979'1269 psi 6214; 6430; 6478 N/A; N/A N/A; N/A Perforation Depth TVD (ft): Tubing Size: COMMISSION USE ONLY Authorized Name: Tubing Grade:Tubing MD (ft): See Attached Schematic STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA 028142 205-054 50-133-20550-00-00 Kenai Beluga Unit (KBU) 22-06 Kenai Gas Field - Sterling 5 Gas Pool Length Size C.O. 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY 9.3# / L-80 TVD Burst 8,837' 10,160psi MD 5,750psi 3,060psi 3,450psi 130' 1,503' 5,400' 130' 1,668' 7,707'3-1/2" 20" 13-3/8" 109' 9-5/8"6,508' 1,647' 8,837' Perforation Depth MD (ft): 6,529' See Attached Schematic 8,816' 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: October 9, 2020 3-1/2" Perforate Repair Wepair Well Exploratory Stratigraphic Development Service BOP TestMechanical Integrity Test Location Clearance No No Wellbore schematic Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:26 am, Sep 28, 2020 320-402 Digitally signed by Taylor Wellman DN: cn=Taylor Wellman, ou=Users Date: 2020.09.25 17:04:34 -08'00' Taylor Wellman X DSR-9/28/2020 _N2___Perforate New Pool DLB 09/28/2020 10-404 GAS Plug Perforations *MIT-IA to 1500 psi pre and post perforations (cement packer) gls 10/6/20Comm. 10/6/2020 dts 10/6/2020 JLC 10/6/2020 RBDMS HEW 11/2/2020 Well Prognosis Well: KBU 22-06 Date: 9-24-2020 Well Name: KBU 22-06 API Number: 50-133-20550-00 Current Status: Shut in Gas well Leg: N/A Estimated Start Date: 10/9/2020 Rig: N2 / E-line Reg. Approval Req’d? Yes Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-054 First Call Engineer: Michael Quick (907) 777-8442 (O) (907) 317-2969 (C) Second Call Engineer: Ted Kramer (907) 777-8420 (O) (985) 867-0665 (C) AFE Number: Maximum Expected BHP: 1700 psi @ 4,313’ TVD (Based on offset well BHP data) Max. Potential Surface Pressure: 1269 psi @ 4,313’ TVD (Based on expected BHP and gas gradient to surface (0.10psi/ft) Brief Well Summary KBU 22-06 is an “escape completion” well drilled by Marathon in 2005. Hilcorp perforated the Beluga UB-5, the UB-5A and UB-5B in 2016, and the UB-1, UB 3 and UB 4B in 2019. Well has been shut in since 2019. The purpose of this sundry is to return this well to production by adding perforations the Lower Sterling sand intervals. Work scope includes setting a 3-1/2” CIBP in the tubing above the UB-1 perforations, and perforating the Sterling B5A and B5B sands. Notes Regarding Wellbore Condition x 3-1/2” (2.75” OD) CIBP set at 6105’ WLM September 2019. x Open perforations from 5930’ to 5955’ and 6013’ to 6023’. x Max deviation of 45.8 degrees at 3076’ MD / 2510’ TVD. x CBL dated 6/17/2005 indicates a top of cement in the 3-1/2” by 9-5/8” annulus at 5150’ MD. Pre-Sundry Work 1. Pressure test (MIT-IA) 3-1/2” x 9-5/8” annulus to 1500 psi for 30 minutes. (TOC at 4077’ TVD x 0.25 psi/ft = 1020 psi pressure test, 1500 psi is minimum test pressure). Chart test. E-Line Procedure 1. MIRU E-line and pressure control equipment. PT lubricator to 3,000 psi High. 2. RIH with GPT tool to confirm fluid level. 3. Rig up field gas or Nitrogen and push fluid away to open perforations, push fluid level below 5880’ 4. PU and RIH with 3-1/2” tubing CIBP and set at +/-5880’. Leave 1020 psi on the well. Contingency: If nitrogen cannot push fluid away: a) MIRU Coil tubing unit. Pressure test BOP to 4,000 psi high, 250 psi low. b) RU Nitrogen. RIH W/ Coil and blow well dry with Nitrogen leaving 500 psi on well head. RDMO Nitrogen and CTU. 5. PU and RIH with 2-3/8” Perforating gun, 6 to 12 SPF, 60 degree phasing. Proposed Perforation Intervals: The purpose of this sundry is to return this well to production by adding perforations the Lower Sterling sand intervals. Work scope includes setting a 3-1/2” CIBP in the tubing above the UB-1 perforations, and perforating the Sterling B5A and B5B sands. pre MIT-IA Well Prognosis Well: KBU 22-06 Date: 9-24-2020 Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Reservoir Pressure P5_B5A ±5,260' ±5,330' 70' ±4,175' ±4,245' 1700 psi P5_B5B ±5,355' ±5,405' 50' ±4,263' ±4,313' 1700 psi a) Proposed perforations are also shown on the proposed schematic in red font. b) Final Perforation tie-in sheet will be provided in the field for exact perforation intervals. c) Correlate using Open Hole Correlation Log provided by Geologist. Send the correlation pass to the Operations Engineer, Reservoir Engineer, and Geologist for confirmation. d) Use Gamma/CCL to correlate. e) Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run at 5 min., 10 min. and 15 min intervals after firing gun. f) The listed Sands are governed by Conservation Order 510A. g) Sand intervals may be grouped or shot one at a time and flow tested to the system. If a sand makes water, then a plug or an isolation patch may be set prior to moving up to the next sand interval. 6. POOH. 7. RD E-line. 8. Turn well over to production to test. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Safety Concerns for N2 x Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. x Consider tank placement based on wind direction and current weather forecast (if venting Nitrogen during this job). x Ensure all crews are aware of stop work authority. Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. Coil Tubing BOP 4. Standard Well Procedure – N2 Operations 1700 psiP5_B5A ±5,260' ±5,330' 70' ±4,175' ±4,245' 1700 P5_B5B ±5,355' ±5,405' 50' ±4,263' ±4,313' (post perforation MIT-IA required ) Tree crossing = 4-3/4" Otis Top of Cement (CBL est.) on 3-1/2" @ 5,150' Excape System Details -Ceramic flapper valves below each module as follows: -6 Conventional flappers -No flappper at Module-1 Flappers MD (RKB): Module 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA FISH 1-11/16" X 3-1/2" Spinner 8,700' tagged on (7/2/2007) KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. TD 8,855' MD 7,725' TVD PBTD 6,105' MD 7,670' TVD Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Permit #:205-054 API #: 50-133-20550-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: Longitude: Spud: 5/20/2005 TD: 6/3/2005 Rig Released: 6/9/2005 PA #: Perfs MD (RKB): (Beluga)MD TVD Ft Perf Date UB-1 5,930’-5,955’ 4,809'-4,833' 25' 09/05/19 UB-3 6,013’-6,023' 4,889'-4,899' 10' 09/04/19 UB-4B 6,130-6,135’ 5,003'-5,008' 5' 08/29/19 UB-5 6,166’-6,186’ 5,039'-5,058' 11/10/16 UB-5A 6,197’-6,217’ 5,069'-5,089' 11/10/16 UB-5B 6,228-6,248’ 5,100'-5,120' 11/10/16 Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 (correlated to 7,031'-7,052' CH) Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 (Tyonek)MD TVD Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 Tagged fill @ 7851' MD (2/23/13) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 22-6 Kenai Peninsula Borough 5,930' -8,685' 1.9º / 100' @ 300 ft 8/3/2005 Donna Ambruz Lease: State: Perf (TVD): Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,809'-7,555' 1º ĺ 5º RKB:(AMSL )21' (AGL) 09-26-19 SCHEMATIC CIBP w/ 25' cement 6,478' CIBP w/ 25' cement 6,430' CIBP w/ 5' cement 6,105' 09/05/19 CIBP w/ 5' cement 6,157' 09/05/19 CIBP 6,214' 08/26/19 UB-5A / UB-5B UB-5 UB-4B UB-3 UB-1 Tree crossing = 4-3/4" Otis 3-1/2" Top of Cement (CBL @ 5,150' Excape System Details -Ceramic flapper valves below each module as follows: -6 Conventional flappers -No flappper at Module-1 Flappers MD (RKB): Module 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA FISH 1-11/16" X 3-1/2" Spinner 8,700' tagged on (7/2/2007) KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. TD 8,855' MD 7,725' TVD PBTD 6,105' MD 7,670' TVD Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' Surface Casing 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Permit #:205-054 API #: 50-133-20550-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: Longitude: Spud: 5/20/2005 TD: 6/3/2005 Rig Released: 6/9/2005 PA #: Perfs MD (RKB): (Beluga)MD TVD Ft Perf Date B5A 5,260’-5,330’ 4,175'-4,245' B5B 5,355’-5,405’ 4,263'-4,313' UB-1 5,930’-5,955’ 4,809'-4,833' 25' 09/05/19 UB-3 6,013’-6,023' 4,889'-4,899' 10' 09/04/19 UB-4B 6,130-6,135’ 5,003'-5,008' 5' 08/29/19 UB-5 6,166’-6,186’ 5,039'-5,058' 11/10/16 UB-5A 6,197’-6,217’ 5,069'-5,089' 11/10/16 UB-5B 6,228-6,248’ 5,100'-5,120' 11/10/16 Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 (correlated to 7,031'-7,052' CH) Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 (Tyonek)MD TVD Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Tagged fill @ 7851' MD (2/23/13) Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 22-6 Kenai Peninsula Borough 5,930' -8,685' 1.9º / 100' @ 300 ft 8/3/2005 M. Quick Lease: State: Perf (TVD): Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 4,809'-7,555' 1º ĺ 5º RKB:(AMSL )21' (AGL) 9-25-2020 PROPOSED SCHEMATIC CIBP w/ 25' cement 6,478' CIBP w/ 25' cement 6,430' CIBP w/ 5' cement 6,105' 09/05/19 CIBP w/ 5' cement 6,157' 09/05/19 CIBP 6,214' 08/26/19 UB-5A / UB-5B UB-5 UB-4B UB-3 UB-1 B5A B5B 9-5/8" Calc TOC @ 3925' 5260ft CIBP 5150 ft TOC 5405 ft 1668 ft MIT-IA 1500 PSI Pre/post perfs STANDARD WELL PROCEDURE NITROGEN OPERATIONS 12/08/2015 FINAL v1 Page 1 of 1 1.) MIRU Nitrogen Pumping Unit and Liquid Nitrogen Transport. 2.) Notify Pad Operator of upcoming Nitrogen operations. 3.) Perform Pre-Job Safety Meeting. Review Nitrogen vendor standard operating procedures and appropriate Safety Data Sheets (formerly MSDS). 4.) Document hazards and mitigation measures and confirm flow paths. Include review on asphyxiation caused by nitrogen displacing oxygen. Mitigation measures include appropriate routing of flowlines, adequate venting and atmospheric monitoring. 5.) Spot Pumping Unit and Transport. Confirm liquid N2 volumes in transport. 6.) Rig up lines from the Nitrogen Pumping Unit to the well and returns tank. Secure lines with whip checks. 7.) Place signs and placards warning of high pressure and nitrogen operations at areas where Nitrogen may accumulate or be released. 8.) Place pressure gauges downstream of liquid and nitrogen pumps to adequately measure tubing and casing pressures. 9.) Place pressure gauges upstream and downstream of any check valves. 10.) Wellsite Manager shall walk down valve alignments and ensure valve position is correct. 11.) Ensure portable 4-gas detection equipment is onsite, calibrated, and bump tested properly to detect LEL/H2S/CO2/O2 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures O2 levels. 12.) Pressure test lines upstream of well to approved sundry pressure or MPSP (Maximum Potential Surface Pressure), whichever is higher. Test lines downstream of well (from well to returns tank) to 1,500 psi. Perform visual inspection for any leaks. 13.) Bleed off test pressure and prepare for pumping nitrogen. 14.) Pump nitrogen at desired rate, monitoring rate (SCFM) and pressure (PSI). All nitrogen returns are to be routed to the returns tank. 15.) When final nitrogen volume has been achieved, isolate well from Nitrogen Pumping Unit and bleed down lines between well and Nitrogen Pumping Unit. 16.) Once you have confirmed lines are bled down, no trapped pressure exists, and no nitrogen has accumulated begin rig down of lines from the Nitrogen Pumping Unit. 17.) Finalize job log and discuss operations with Wellsite Manager. Document any lessons learned and confirm final rates/pressure/volumes of the job and remaining nitrogen in the transport. 18.) RDMO Nitrogen Pumping Unit and Liquid Nitrogen Transport. STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS SEP 3 0 201-9 1. Operations Abandon Plug Perforations Fracture Stimulate a Pull TubinLlg Operations shutdown p ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ erforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2. Operator Hilcorp Alaska, LLC 4. Well Class Before Work: 5. Permit to Drill Number: Name: Development Q Stratigraphic❑ Exploratory ❑ Service ❑ 205-054 3. Address: 3800 Centerpoint Dr, Suite 1400 Anchorage, 6. API Number: AK 99503 50-133-20550-00-00 7. Property Designation (Lease Number): 8. Well Name and Number: FEDA028142 Kenai Beluga Unit (KBU) 22-06 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Kenai Gas Field / Beluga - Up Tyonek Pools 11. Present Well Condition Summary: 6105;6157;6214; Total Depth measured 8,855 feet Plugs measured 6430;6478 feet true vertical 7,725 feet Junk measured 8,700 feet Effective Depth measured 6,105 feet Packer measured N/A feet true vertical 4,979 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060psi 1,500psi Surface 1,647' 13-3/8" 1,668' 1,503' 3,450psi 1,95opsi Intermediate 6,508' 9-5/8" 6,529' 5,400' 5,750psi 3,909psi Production 8,816' 3-1/2" 8,837' 7,707' 10,160psi 10,530psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.3# / L-80 8,837' MD 7,707' TVD Packers and SSSV (type, measured and true vertical depth) N/A; N/A N/A; NA 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:1 0 0 0 0 0 Subsequent to operation: 0 0 0 0 0 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.289) 15. Well Class after work: Daily Report of Well Operations Exploratory❑ Development 0 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16. Well Status after work: Oil Gas WDSPL Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 319-371 Authorized Name: Bo York 777-8345 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkrameR(Dhilcoro com Authorized Signature:/ ( Date: S ? b I `( Contact Phone: 777-8420 Form 10-404 Revised 4/2017 /t (�/r/ 7 /fiL /©S%I, RMS r f(' /DICT 0 7 2019 Submit Original Only Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number ]Start Start Date End Date KBU 22-06 E -Line 50-133-20550-00-00 205-054 9/5/19 Daily Operations: 08/26/2019 - Monday PTW, JSA and SIMOPS w/AKE-Line and SLB N2 Crew. Rig up hard lines and lubricator. PT lubricator and hard lines to 3000 psi. RIH w/GPT and find fluid at 600'. Start pressuring N2 into well at 1000 scf at 1,200 psi. Finally broke over at 1,400 psi and flat lined out at 1,000 psi. Found fluid level at 6,215'. Run correlation log and send to town. Town said to shift log down 12'. Shifted log 12' down.. RIH w /2.75" CIBP tie into GPT log. Run correlation and send to town. Told to shift log down 10'. Shift log and started logging up and plug hung up at 6,214'. Call town and decision was made after pulling up to safe pull a few times was set plug and then set another one in the morning. Set plug at 6,214' with 1,100 psi on tubing (just above bottom open perf zone. Got 2 more Zones that needs to be isolated. Picked up 20' and. went back down and tag plug. POOH. Tools look good. Rig down lubricator and secure well. Will be back at 9 am. 08/28/2019- Wednesday Sign in. Mobe to location. PTW JSA and SIMOPS with AKE-Line and SLB N2. PT hard lines and lubricator to 250 psi low and 3000 psi high. TP - 800 psi. RIH w/GPT and tie into SLB RST Log. Find fluid level at 6002'. Start pressuring N2 into well at 1,000 scf at 1,200 psi. Run correlation log and send to town. Push fluid back into perf zone at 6,166'. Town said we were on depth. POOH. RIH w/ 2.75" CIBP and tie into GPT. Run correlation log and send to town. Got ok to set plug at 6,162'. Set plug with 1,300 psi on tubing. Picked up 30' and went back down and tag plug. POOH. Good set. Pressured tubing up to 1,750 psi with N2. RIH w/ 2-1/2" x 10' dump bailer (loaded with 1.87 gals of 17 ppg cement and dump 5' of cement on top of plug at 6,162' . Est TOC at 6,157' and cement in place at 1700 hrs. POOH. Good dump. Rig down lubricator and secure well. Will perforate in the morning if cement is cured. The crew had to rig down wireline truck and take it to BCU 4RD because the unit out there broke down. There is another wireline crew out there so we don't lose the crew. Hopefully be back at 7 am. We have pumped 3,000 gal N2 total this well. 08/29/2019 -Thursday Sign in. Mobe to location. PTW and JSA. Rig up lubricator. Arm gun. PT lubricator to 250 psi low and 3000 psi high. TP - 1631 psi. RIH w/ 2-3/8" x 5' Razor HC, 5 spf, 60 deg phase and tie into GPT log. Run correlation log and send to town. Get ok to perf from 6,130' to 6,135'w/1,625 psi. Spotted and fired gun. After 5 min - 1,626 psi, 10 min - 1,622 psi and 15 min - 621 psi. POOH. All shots fired and gun was dry. Rig down equipment, turn well over to field and move to KBU 44-06. 08/31/2019 -Saturday PTW and JSA. Put well shed back on a well with crane. Mobe to location. PTW and JSA. Rig up lubricator. PT to 250 psi low and 3,000 psi high. TP - 0 psi. RIH w/GPT tool and tie into pert log. Tag fill at 6,128' (2' above top perf) and found fluid at 5,329'w/0 psi. Ran correlation logs and send to town. Decision was made to wait until we get everybody together on base. Will have plug and setting tool tomorrow and hopefully SLB N2 crew Monday. Will keep everybody updated. Rig down lubricator and secure well. Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 22-06 E -Line 1 50-133-20550-00-00 205-054 8/26/19 1 9/5/19 Daily Operations: 09/03/2019 -Tuesday Sign in. Mobe to location. PTW, JSA and SIMOPS w/AKE-Line and SLB N/2. Rig up hard lines and lubricator. PT hard lines and lubricator to 4,000 psi. TP - 700 psi. RIH w/GPT tool and tie into RST log. Tagged at 6,157' and fluid level at 5,015'. Start pressuring up tubing from 700 psi to 3,200 psi at 500 scf rate and pushed fluid into perfs at 6,130'. POOH. RIH w/ 2.75" CIBP and tie into RST log. Tubing showing 3,010 psi. Had SLB pressure up to 3,200 psi. Run correlation log and send to town. Had to shift 2' down. Spotted plug at 6,110' and set plug with 3,200 psi on tubing. Lost 120 lbs on wt indicator when set. Pick up 30' and go back down and tag plug. POOH and pressure still at 3200 psi and tools looked good. RIH w/ 2-1/2" x 10' dump bailer filled with 1.84 gals of 17 ppg cement. Dump cement on top of plug. CIP at 1805 hrs and est TOC at 6,105'. POOH. Good dump. TP 3,200 psi. Rig down lubricator. Secure well. Will be back at 0900 hrs in the morning to perf. Used approx. 1,300 gals of N2. 09/04/2019- Wednesday PTW and JSA. Put new rope socket on. PT to 250 psi low and 3,200 psi high. Blow well pressure down from 3,200 psi to 1,640 psi. RIH w/ 2-3/8" x 10' Razor HC, 5 spf, 60 deg phase and tie into Plug log. Run correlation log and send to town. Town changed to a different zone to pert. From UB -3A to UB -3. Correlation log was on depth. Spotted and fired gun from 6,013' to 6,023' with 1,637 psi on tubing. After 5 min - 1,636.8 psi, 10 min - 1,635 psi and after 15 min - 1,633.7 psi. POOH. All shots fired and gun was dry. Rig down lubricator and turn well over to field to bring well on. 09/05/2019 -Thursday PTW and JSA. Rig up lubricator. PT to 250 psi low and 3,000 psi high. TP - 700 psi. RIH w/ GPT tool and tie into perf log. Run correlation log and found fluid level at 6,008'w/700 psi on well. POOH. RIH w/ 2-3/8" x 25' Razor HC, 5 spf, 60 deg phase and tie into perf log. Run correlation log and send to town. Get ok to perf from 5,930' to 5,955'w/679.3 psi. Spotted and fired shot. After 5 min - 697 psi, 10 min - 706.5 psi and 15 min - 713 psi. POOH. All shots fired and gun was wet. Rig down lubricator and equipment. Turn well over to field and clean up work area. TP - 734 psi. U Hilcorp Alaska 205-064 50-133-20550,00-00 A - 028142 n: 8T (2T AGL) 5/20/2005 6/3/2005 9d: 6/912005 Tree crossing -4-3/4" Otis Top of Cement (CBL est.) on 3-112" @ 5,150' Ceramic flapper valves below each module as follows: 6 Conventional flappers No flappper at Module -1 Motlule 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA Tagged fill @ 7851' MD (2/23113) FISH 1-11/16" X 3=(712/2007) 00' tagged KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. CIBP w/ 5cement 6,105' 09/05/19 CIBP w/ V cement 6,157':l CIBP 6,214- 8/26/19 CIBP w/ 25' cement 6,430' CIBP w/ 25' cement 6,478' SCHEMATIC Conductor 20" K-55 133 ppf Too Bottom MD 0' 130' TVD 0' 130' Surface Casing 13-318" L-80 68 ppf BTC TOR Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface Intermediate Casing 9-5/8" L40 40 ppf BTC Tog Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd Tog Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Perfs MD (RKBt: ^_ I^ (Beluga) MD TVD Ft Perf Date UB -1 5,930'-5,955' 4,809'-4,833' 25' 09/05/19 i UB -3 6,013'-6,023' 4,889'-4,899' 10' 09/04/19 W r ^; UB -48 6,130-6,135' 5,003'-5,008' 5' 0829119 1• r UB -5 6,166'-6,186' 5,039'-5,058' 11/10/16 1 UB -5A 6,197'-6,217' 5,069'-5,089' 11/10/16 .N US -5B 6,228-6,248' 5,100'-5,120' 11/10116 ri '+ Module 7= 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 •^ 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 (correlated to 7,031'-7,052' CH) Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 r +: Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 (Tyonek) MD TVD Module = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 L^ Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 TD PBTD 8,855' MD F7,6700-. ,105' MD 7,725' TVD TV Well Name & Number: Kenai Beluga Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Count USA Perforations WD): 6,930' - 8,685' Perf TVD : ;Ane 4 809' - --55, Angle KOP & Depth: 1.9.1100' 300 ft Perfs: 10 - so Date Com leted: 8/3/2005 und Level: AMSL RKB: 21' AGLRevised b : Donna Ambruz ision Date: 09-26-19 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bo York Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga/Upper Tyonek Gas Pool, KBU 22-06 Permit to Drill Number: 205-054 Sundry Number: 319-371 Dear Mr. York: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 v -aogcc.alasko.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner DATED this S day of August, 2019. RBDMSk AUG 19 2019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 9n Aar. 75 9An ��fi� EL. E AUG 13 9U1g AOG CC 1. Type of Request: Abandon ❑ Plug Perforations Q Fracture Stimulate ❑ Repair Well ❑ Operations shutdown ❑ Suspend ❑ Perforate Q Other Stimulate ❑ Pull Tubing ❑ Change Approved Program ❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Hilcorp Alaska, LLC Exploratory ❑ Development Q Stndigraphic ❑ Service ❑ 205-054 3. Address: 3800 Centerpoint Drive, Suite 1400 6. API Number: Anchorage Alaska 99503 9 50-133-20550-00-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? CO 510a + ' Will planned perforations require a spacing exception? Yes El No No Kenai Beluga Unit (KBU) 22-06 9. Property Designation (Lease Number): 10. Field/Pool(s): FEDA028142 Kenai Gas Field / Beluga - Up Tyonek Pools 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8,855' 7,725' 8,800' 7,670' -1,607 psi N/A 8,700' Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060psi 1,500psi Surface 1,647' 13-3/8" 1,668' 1,503' 3,450psi 1,950psi Intermediate 6,508' 9-5/8" 6,529' 5,400' 5,750psi 3,090psi Production 8,816' 3-1/2" 8,837' 7,707' 10,160psi 10,530psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See Attached Schematic See Attached! 3-1/2" 9.3# / L-80 8,837 Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): N/A; N/A N/A; N/A 12. Attachments: Proposal Summary Q Wellbore schematic Q 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Strati ra hic g p ❑ Development Service ❑ 14. Estimated Date forjp 15. Well Status after proposed work: Commencing Operations: August3A, 20193 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ GAS WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Be York 777-8345 Contact Name: Taylor Nasse Authorized Title: O erations Manager Contact Email: tnasseC�Dhilcoro.com lxo�[� Contact Phone: 777-8354 �- 1 Authorized Signature: Date: 1 +T� COMMISSION SE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31q-3�� Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: RBDMS AUG 1 91019 Post Initial Injection MIT Raq'd? yes No ❑ ❑ U Spacing Exception Required? Yes ❑ No � Subsequent Form Required: I Q ' f e1� APPROD BY Approved by:Q COMMISSIONER THE COMMIS ION Date:Q orm 10-403 Rev sed 4/2017 Approved apiOdRIG fprR2�rC, L. the date of approval. 0r ",(q Submit Form and p, Attachments in Duplicate H Hilmrp Atoka. LU Well Prognosis Well: KBU 22-06 Date: 08/09/2019 Well Name: KBU 22-06 API Number: 50-133-20550-00 Current Status: Shut-in Gas Well Leg: N/A Estimated Start Date: August,23, 2019 Rig: N/A Reg. Approval Req'd? 403 P Date Reg. Approval Rec'vd: Upper Beluga Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-054 First Call Engineer: Taylor Nasse (907) 777-8354 (0) (907) 903-0341 (M) Second Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) AFE Number: 15 Upper Beluga UB -46 Maximum Expected BHP: —2,100 psi @ 4,936' TVD (Based on offset well data) Max. Potential Surface Pressure: —1,607 psi (0.10 psi/ft gas gradient) Brief Well Summary The KBU 22-06 was initially drilled and completed in 2005. It was initially completed w/ 3.5" casing as a multi- stage (racked Lower Beluga / Upper Tyonek completion. The well went down in late 2008 due to sand and both Marathon and Hilcorp have been unable to return the well to production in the original completed intervals (-2.0 Bscf of cum production). The UB -5, UB -5A, and UB -56 sands were added in 2016 but were unproductive. The purpose of this work/sundry is to plug back and add perforations in several sands in the Upper Beluga formation. ct35- Procedure: 1. MIRU E -line, PT lubricator to 2,000 psi Hi 250 Low. 2. RU with PT tool to determine fluid level. POOH a. Note: Prior to running PT tool, pressure up well with 800 psig gas to try to push fluid away. 3. MU 3-1/2" CIBP. RIH and set at ^'6,162'. POOH 4. MU Bailer and dump bail 5' of cement on top of plug. POOH. RD E -line. 5. RU Slickline. Swab fluid down to 6,150'. Confirm depth with Engineer prior to concluding swabbing operations. RD Slickline. Pressure well with methane to achieve desired underbalance. 6. RU E -line. RU perforating guns. 7. RIH and perforate the following intervals: Zone Sands Top (MD) Btm (MD) FT Upper Beluga UB -1X 5,865' 5,885' 20 Upper Beluga UB -1 5,915' 5,955' 40 Upper Beluga UB -2 5,955' 5,978' 23 Upper Beluga UB -3 6,010' 6,059' 49 Upper Beluga UB -3A 6,059' 6,074' 15 Upper Beluga UB -46 6,130' 6,150' 20 a. Bleed tubing pressure as require by Engineer. b. Proposed perfs shown on the proposed schematic in red font. c. Use Gamma/CCL/to correlate. Engineer to provide correlation log. d. Record tubing pressures before and after each perforating run. 8. POOH and RD E -line. 9. Turn well over to production. H Mkvey Alaska, LL, E -line Procedure (Contingency): If any zone produces sand and/or water. 10. MIRU E -line, PT lubricator to 2,000 psi Hi 250 Low. 11. RIH and set 3-1/2" CIBP. Set at depth specified by Engineer. 12. RU Slickline. Swab fluid down to depth approved by Engineer. 13. RIH with bailer assembly. Dump bail cement. POOH. 14. Continue with Step 6 above. Attachments: 1. Actual Schematic 2. Proposed Schematic Well Prognosis Well: KBU 22-06 Date: 08/09/2019 U Hilcorp Alaska 205.054 50-133-20550-00-00 A - 028142 L. 87' (21' AGL) 6/312005 gid: 6/9/2005 Tree crossing = 43/4" Otis Top of Cement (CBL est.) on 3-1 rt" @ 5,150' Excape System Details - Ceramic flapper valves below each module as follows: - 6 Conventional flappers - No flappper at Module -1 Flappers MD f111(61: Module 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA Tagged fill @ 7851' MD (2/23113) FISH 1-11/16" X 3-1/2" Spinner 8,700' tagged on (71212007) CIBP w/ 25' cement 6,430' 11/10/16 COP w/ 25' cement 6,478' 11/01/16 KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, UN, R11W, S.M. SCHEMATIC Intermediate Casino 9-518" LA0 40 ppf BTC Too Bottom MD 0' 6,529' TVD 0' 5,400' Cmt wl 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tall @ 13.5 ppg, Good circulation throughout job Production Tubina 3-1/2" LA0 9.3 ppf EUE 8rd Tog Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 aka Class G@ 15.8 ppg, LIL Good circulation throughout job (Beluga) MD TVD Ft Perf Date ?s , UB -5 6,166'-0,186' 5,039'-5,058' 11/10/16 UB -5A 6,197'-6,217' 5,069'-5,089' 11/10/16 +� n UB -5B 6,228-6,248' 5,100'-5,120' 11/10/16 �a .f Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 (correlated to 7,031'-7,052' CH) a '}' Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/D6/05 1 Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 (Tyonek) MD TVD Module = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 t uw Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,4501-7,460' 10' 08/05/05 b'. Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 b+ 61 TD PBTD 8,855' MD 8,800' MD 7,725' TVD 7,670' TVD Well Name & Number: Conductor - 13-318" L-80 68 ppf BTC 20" K-55 133 ppf SI TVD 0' 1,502' Ton Bottom 6,552' - 8,685' Type 1 cmt to surface MD 0' 130' 1.90/100' 300 ft Angle Perfs: TVD 0' 130' 8/3/2005 Intermediate Casino 9-518" LA0 40 ppf BTC Too Bottom MD 0' 6,529' TVD 0' 5,400' Cmt wl 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tall @ 13.5 ppg, Good circulation throughout job Production Tubina 3-1/2" LA0 9.3 ppf EUE 8rd Tog Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 aka Class G@ 15.8 ppg, LIL Good circulation throughout job (Beluga) MD TVD Ft Perf Date ?s , UB -5 6,166'-0,186' 5,039'-5,058' 11/10/16 UB -5A 6,197'-6,217' 5,069'-5,089' 11/10/16 +� n UB -5B 6,228-6,248' 5,100'-5,120' 11/10/16 �a .f Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 (correlated to 7,031'-7,052' CH) a '}' Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/D6/05 1 Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 (Tyonek) MD TVD Module = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 t uw Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,4501-7,460' 10' 08/05/05 b'. Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 b+ 61 TD PBTD 8,855' MD 8,800' MD 7,725' TVD 7,670' TVD Well Name & Number: Surface Casino - 13-318" L-80 68 ppf BTC �r ToBottom MD 0' 1,668' SI TVD 0' 1,502' I Count USA Con w/ 518 sks of 12.0 ppg, 6,552' - 8,685' Type 1 cmt to surface Intermediate Casino 9-518" LA0 40 ppf BTC Too Bottom MD 0' 6,529' TVD 0' 5,400' Cmt wl 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tall @ 13.5 ppg, Good circulation throughout job Production Tubina 3-1/2" LA0 9.3 ppf EUE 8rd Tog Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 aka Class G@ 15.8 ppg, LIL Good circulation throughout job (Beluga) MD TVD Ft Perf Date ?s , UB -5 6,166'-0,186' 5,039'-5,058' 11/10/16 UB -5A 6,197'-6,217' 5,069'-5,089' 11/10/16 +� n UB -5B 6,228-6,248' 5,100'-5,120' 11/10/16 �a .f Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2", 6spf = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 (correlated to 7,031'-7,052' CH) a '}' Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/D6/05 1 Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 (Tyonek) MD TVD Module = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 t uw Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,4501-7,460' 10' 08/05/05 b'. Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 b+ 61 TD PBTD 8,855' MD 8,800' MD 7,725' TVD 7,670' TVD Well Name & Number: Kenai Beluga Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska I I Count USA Perforations (MD): 6,552' - 8,685' Pert (TVD): 5,423' - 7,655' Angle CW KOP & Depth: 1.90/100' 300 ft Angle Perfs: 1e - 50 Date Completed: 8/3/2005 Ground Level: AMSL RKB: 21' AGL Revised b : Donna Ambruz Revision Date: 12/05/16 LT � Hilcorp Alaska Permit #: 205-054 API #: 50-133-20550-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: Longitude: Spud: 5/2012005 TD: 61312005 Rio Released: 6/912005 PA #: Tree crossing = 4-314" Otis Top of Cement (CBL est.) on 3-1/2" @ 5,150' Excaoe System Details - Ceramic flapper valves below each module as follows: - 6 Conventional flappers - No flappper at Module -1 Flappers MD (RKBI: Module 7 = 6,572' Module 6 = 7,704' Module 5 = 7,861' Module 4 = 8,433' Module 3 = 8,474' Module 2 = 8,599' Module 1 = NA Tagged fill @ 7851' MD (2123/13) FISH 1-11116"X 3-1/2" Spinner 8,700' tagged on (7/212007) KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. CIBP w/ 5' cement 6,162' Proposed CIBP w/ 25' cement 6,430' 11/10/16 CIBP w/ 25' cement 6,478' 11/01/16 UB -1 UB -2 UB -3 UB -3A UB4B UB -5 UB -5A UB -5B Module 7 = 2", 6spf = Module 6 = Module 5 = (Tyonek) Module 4 = Module 3 = Module 2 = Module 1 = TD PBTD 8,855' MD 8,800' MD 7,725' TVD 7,670' TVD PROPOSED SCHEMATIC Intermediate Casing 9-6/8" L-80 40 ppf BTC TOR Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & wl 266 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd im Bottom MD 0' 8,837' TVD 0' 7,707' Cod w/ 1,113 sks Class G @ 16.8 ppg, Good circulation throughout job MD Conductor Ft Pert Date 20" KS5 133 ppf 20' proposed LOR Bottom 40' proposed MD 0' 130' 23' proposed TVD 0' 130' 49' Surface Casing 13,3/8" L-80 68 ppf BTC TOP Bottom proposed MD 0' 1,668' 4,916'4,936' TVD 0' 1,502' proposed Cmt w/ 518 sks of 12.0 ppg, 5,039'-5,058' Type 1 cmt to surface 11/10/16 Intermediate Casing 9-6/8" L-80 40 ppf BTC TOR Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & wl 266 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job Production Tubing 3-1/2" L-80 9.3 ppf EUE 8rd im Bottom MD 0' 8,837' TVD 0' 7,707' Cod w/ 1,113 sks Class G @ 16.8 ppg, Good circulation throughout job MD TVD Ft Pert Date 5,865'-5,885' 4,659'-0,679' 20' proposed 5,915'-5,955' 4,707'-4,747' 40' proposed 5,955-5,978' 4,747'-0,769' 23' proposed 6,010'-6,059' 4,799'4,847' 49' proposed 6,059'-6,074' 4,947'4,862' 15' proposed 6,130-6,150' 4,916'4,936' 20' proposed 6,166'-6,186' 5,039'-5,058' 11/10/16 6,197'-6,217' 5,069'-5,089' 11/10/16 6,228-6,248' 5,100'-5,120' 11/10/16 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 (correlated to 7,031'-7,052' CH) 7,686-7,695' 6,555'-0,565' 10' 08/06/05 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 MD TVD 8,414'-8,424' 7,2847-7,294' 10' 08/06/05 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 Well Name & Number: Kenai Belu a Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borou h State: Alaska I I Countd USA Perforations (MD): 6-,5--52-' - 8,686' Pert (TVD): 5,423' - 7,555 - 555'An Angle le KOP & Depth: 1.90/100' A 300 ft Angle a Perfs: V - So Date Completed: 8/3/2005 Ground Level: AMSL RKB: 21' AGL Revised by: Donna Ambruz Revision Date: 12/05/16 14EtriFIVED STATE OF ALASKA ALARA OIL AND GAS CONSERVATION COMAION 1)EC 0 9 2016 REPORT OF SUNDRY WELL OPERATIONS . OGCC 1.Operations Abandon U Plug Perforations U Fracture Stimulate U Pull Tubing U Operations shutdown LJ Performed: Suspend ❑ Perforate Q Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ arforate New Pool ❑ Repair Well ❑ Re-enter Susp Well❑ Other: ❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development ❑✓ Exploratory ❑ 205-054 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic III Service ❑ 6.API Number: Anchorage,AK 99503 50-133-20550-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 Kenai Beluga Unit(KBU)22-06 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A Kenai Gas Field/Beluga-Up Tyonek Pools 11.Present Well Condition Summary: Total Depth measured 8,855 feet Plugs measured N/A feet true vertical 7,725 feet Junk measured 8,700 feet Effective Depth measured 8,800 feet Packer measured N/A feet true vertical 7,670 feet true vertical N/A feet Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060psi 1,500psi Surface 1,647' 13-3/8" 1,668' 1,503' 3,450psi 1,950psi Intermediate 6,508' 9-5/8" 6,529' 5,400' 5,750psi 3,909psi Production 8,816' 3-1/2" 8,837' 7,707' 10,160psi 10,530psi Liner Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic SCANNED MAR 3 0 21312, Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3#/L-80 8,837'MD 7,707'TVD Packers and SSSV(type,measured and true vertical depth) N/A;N/A N/A;NA 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 10 Subsequent to operation: 0 0 0 0 104 14.Attachments(required per 20 AAC 25.070,25.071,&25.283) 15.Well Class after work: Daily Report of Well Operations El Exploratory III Development 2 Service ❑ Stratigraphic ❑ Copies of Logs and Surveys Run ❑ 16.Well Status after work: Oil ❑ Gas Q WDSPL❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: 316-541 Contact Taylor Nasse-777-8354 Email tnasse(C7hilcorp.com Printed Name 6/./0„riv.iChhad Helgeson Title Operations Manager / Signature Phone 907-777-8405 Date I tic"/I Y'� Form 10-404 Revised 5/2015 < (2 --15-7‘, Submit Original Only RBDMSD0' DEC - 9 2916 • s • Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 22-06 E-Line 50-133-20550-00 205-054 11/1/16 11/10/16 Daily Operations: 11/01/2016-Tuesday Meet at office. PTW and JSA. Mobe to location and spot equipment. Rig up lubricator, PT to 250 psi low and 2,000 psi high. RIH with 2.75" CIBP, tie into SLB RST log dated 6-Dec-15. Run correlation log and send to town. Get ok to set log and 6,503'. Spot plug at 6,503' and fire setting tool. Lost 100#tool wt., pick up 30' and went back down and tagged plug. POOH. Good set.TP- 10 psi. RIH w/2-1/2" x 30' dump bailer filled with 6 gals cement and tag plug at 6,503'. Pick up and dump bail cement on top of plug. POOH. Good dump. RIH w/2-1/2" x 30' dump bailer filled with 3 gals cement (9 gals total) and dump on top of plug. 9 gals equals 25' cement on top of plug. POOH. Good dump.TOC est at 6,478'. Cement in place at 1430 hrs. Rig down lubricator, secure well and WOC. 11/07/2016- Monday PTW and JSA. Mobe to location and spot equipment. Rig up Pollard E-Line lub and P/T to 250 psi low and 2,000 psi high.TP-400 psi. Note: Pollard E-line has their own test pump now. RIH w/GPT tool and tie into SLB RST log. Found fluid level at 5,450'. Halliburton had swabbed well down to 6,285' 11-4-16.Tagged TOC at 6,478'. Halliburton had tagged TOC at 6,475' wlm KB. Ran GPT log from 6,478'to 5,300' and sent to town. POOH. Rig down Pollard Eline and wait on HLB slickline. Pressured tubing up to 700 psi from 400 psi. PTW and JSA. Rig up lubricator, PT 250 psi low and 2,000 psi high. Bleed pressure off well. Did not lose any pressure while holding the 700 psi on well. Bled pressure off well. RIH with tandem swab cups and tag fluid level at 5,321' WLM KB. Made 10 runs and swab from 5,321'to 6,295' WLM KB. We changed swab cups 3 times. RIH 2.75" blind box and tagged TOC at 6,470'.That is 8' higher than Pollard GPT tag. So that makes slickline FL at 6,303' correlated with Pollard GPT. We waited 30 min and splashed down on fluid level and it was same at 6,303'. Waited 30 more min and splashed down and gained 1'. POOH closed both masters and swab and will put the 300 psi on well in morning after talking about it. I think we should run GPT tool before adding pressure to make sure we are still dry and then put pressure on well while GPT tool is in hole to see if water comes in.Just a thought. 11/08/2016-Tuesday PTW and JSA. Mobe to location and spot equipment. Rig up Pollard E-Line lub and P/T to 250 psi low and 2,000 psi high.TP-0. RIH w/GPT tool and tie into Pollard GPT log dated 11-8-16. Found fluid level at 6,055'. 12 hrs earlier FL was 6,302'. Tag TOC at 6,478'. Run log and send to town. Performed three 1 hr fluid level tests and FL was rising between 5'to 7' per hour. Called town and discussed. Decided to run another plug. POOH. Waited on CIBP and cement. RIH with GPT tool and 2.75" OD CIBP and tie into GPT log. FL was 5,986'. Send to town and get ok to set at 6,460'. Spotted plug at 6,460' and set plug. Lost 150 lbs line wt when plug set. Pick up 30' and go back and tag plug. Log up and find FL at 5,980'. Waited 1/2 hr and FL was 5,976'. Called town and discussed. POOH. RIH w/2-1/2" x 30' dump bailer filled with cement and tag plug at 6,460'. Dumped cement. POOH good dump. RIH w/2-1/2" x3 0' dump bailer filled with cement and dump bailed on plug (25' cement 9.1 gals). Est TOC at 6,435'. Cement in place at 1900 hrs. Est FL-5,951'. Good dump. Rig down lubricator and secure well. WOC. • S Hilcorp Alaska, LLC Well Operations Summary Well Name Rig API Number Well Permit Number Start Date End Date KBU 22-06 E-Line 50-133-20550-00 205-054 11/1/16 11/10/16 Daily Operations: 11/10/2016-Thursday PTW and JSA. Rig SL lubricator up, PT to 250 psi low and 2,000 psi high. RIH with 2.75" blind box and found fluid level at 5,949' WLM KB and tag TOC at 6,430' WLM KB. Swab down to 6,340' making several runs. Waited 1 hour and went back down and tagged fluid level at 6,340'. POOH. Rig down slickline lubricator for standby. PTW and JSA. Rig up e-line lubricator up, PT to 250 psi low and 2,000 psi high. RIH w/2-3/8" x 20' Connex HC, 5 spf, 60 deg perf gun. Tag TOC at 6,435' and found FL at 6,340'. Ran correlation log and send to town. Get ok to perf from 6,228'to 6,248'. Pressured up tubing to 295 psi and spotted gun. Fired gun and pressure spiked to 300 psi and back to 295 psi. POOH. All shots fired. Gun was dry. RIH w/2-3/8" x 20' Connex HC, 5 spf, 60 deg perf gun.Tie into Pollard GPT tool dated 11-8-11. Send correlation to town and get ok to perf from 6,197' to 6,217'. Fired gun with 290 psi and did not lose any pressure. Gun was sticky pulling up for about 20'. POOH. All guns fired. Gun was dry. RIH w/2-3/8" x 20'Connex HC, 5 spf, 60 deg perf gun.Tie into Pollard GPT tool dated 11-8-11.Send correlation to town and get ok to perf from 6,166' to 6,186'. Fired gun with 280 psi on well and didn't gain any pressure. Tools were sticky for about 50' and then free up. POOH. Gun had mud in bull plug. Rig down lubricator and turn well over to field. • 0 ilKBU 22-6 SCHEMATIC Pad 14-6 Elilcorp Alaska 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. Conductor Permit#: 205-054 20" K-55 133 ppf API#: 50-133-20550-00-00Top Bottom Prop.Des: A-028142 MD 0' 130' KB elevation: 87' (21'AGL) ND 0' 130' WBS#: 1� Latitude: V' IL Surface Casing Longitude: 13-3/8" L-80 68 ppf BTC Spud: 5/20/2005 Top Bottom TD: 6/3/2005 MD 0' 1,668' Rig Released: 6/9/2005 ND 0' 1,502' PA#: , Cmt w/518 sks of 12.0 ppg, y ' Type 1 cmt to surface i tik ' Intermediate Casing °. ^, y; v 9-5/8" L-80 40 ppf BTC + Tree crossing=4-3/4"Otis * u' -I)R Bottom ,y MD 0' 6,529' °.raq-4;. ND 0' 5,400' Cmt w/313 sks of Class G Lead @ 12.5 ppg, Top of Cement .! &wl 256 sks of Class G Tail @ 13.5 ppg, (CBL est.)on 3-1/2"@ 5,150' Good circulation throughout job * Production Tubing Excape System Details l ""a 3-1/2" L-80 9.3 ppf EUE 8rd -Ceramic flapper valves below 1.0 Top Bottom CIBP w/25' each module as follows: MD 0' 8,837' -6 Conventional flappers cement 6,430' pp ND 0' 7,707' -No flappper at Module-1 11/10/16 - Cmt w/1,113 sks Class G @ 15.8 ppg, l- Good circulation throughout job Flappers MD(RKB): CIBP w/25' `' Module 7 = 6,572' cement 6,478' �; Module 6 = 7,704' 11/01/16 ES, y,- Perfs MD(RKBI: Module 5 = 7,861' (Beluga) MD ND Ft Perf Date Module 4 = 8,433' UB-5 6,166'-6,186' 5,039'-5,058' 11/10/16 Module 3 = 8,474' t UB-5A 6,197'-6,217' 5,069'-5,089' 11/10/16 Module 2 = 8,599' UB-5B 6,228-6,248' 5,100'-5,120' 11/10/16 Module 1 = NA Module 7= 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 7 t 2",6spf = 7,046-7,066'OH 5,915'-5,936' 21' 10/21/08 IM -11i (correlated to 7,031'-7,052'CH) Module 6 = 7,685'-7,695' 6,556-6,565' 10' 08/06/05 J f Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 nr (Tyonek) MD TVD Tagged fill @ 7851'MD (2/23/13) Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 ( ,,-, Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 7t Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 -Li Module 1 = 8,675'-8,685' 7,546-7,555' 10' 08/05/05 FISH -1 1-11/16"X 3-1/2"Spinner 8,700' • tagged on(7/2/2007) `r 1,*1 l ,. TD PBTD 8,855'MD 8,800' MD 7,725'TVD 7,670'TVD Well Name& Number: Kenai Beluga Unit 22-6 _ Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country USA Perforations (MD): 6,552' -8,685' Perf(TVD): 5,423' -7,555' Angle @ KOP & Depth: 1.9°/100' A 300 ft Angle @ Perfs: 1°-> 5° Date Completed: 8/3/2005 Ground Level: (AMSL) RKB: 21' (AGL) Revised by: Donna Ambruz Revision Date: 12/05/16 yoFT� • • ' g,1",\1y ,'6., THE STATE Alaska Oil and Gas m�' �-s=��='� (ALASKA Conservation Commission ti .,.,s � Ak kilt • c- ----*-�*-- --.---• 333 West Seventh Avenue , / GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 OFA S1°' Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson Operations Manager SCANNED LUv � Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Gas Field, Beluga—Upper Tyonek Pool, KBU 22-06 Permit to Drill Number: 205-054 Sundry Number: 316-541 Dear Mr. Helgeson: Enclosed is the approved application for sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Cathyr Foerster Chair DATED this 2 day of October, 2016. RBDMS liv Ut,I L 8 2016 S • RECEIVED STATE OF ALASKA OCT 1 9 2016 ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ROGCC 20 AAC 25.280 1.Type of Request: Abandon ❑ Plug Perforations • Fracture Stimulate ❑ Repair Well ❑ Operations shutdown❑ Suspend ❑ Perforate N' • Other Stimulate ❑ Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other: ❑ 2.Operator Name: Hilcorp Alaska,LLC 4.Current Well Class: 5.Permit to Drill Number. Exploratory ❑ Development Q • 205-054 ' 3.Address: 3800 Centerpoint Drive,Suite 1400 Stratigraphic ❑ Service ❑ 6.API Number. Anchorage,Alaska 99503 50-133-20550-00 • 7.If perforating: 8.Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? CO 510a Will planned perforations require a spacing exception? Yes ❑ No ❑Q Kenai Beluga Unit(KBU)22-06 9.Property Designation(Lease Number): 10.Field/Pool(s): FEDA028142 • Kenai Gas Field/Beluga-Up Tyonek Pools • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 8,855' • 7,725' ' 8,800' 7,670' 966 psi WA 8,700' Casing Length Size MD ND Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060psi 1,500psi Surface 1,647' 13-3/8" 1,668' 1,503' 3,450psi 1,950psi Intermediate 6,508' 9-5/8" 6,529' 5,400' 5,750psi 3,090psi Production 8,816' 3-1/2" 8,837' 7,707' 10,160psi 10.530psi Liner Perforation Depth MD(ft): Perforation Depth ND(ft): Tubing Size: Tubing Grade: Tubing MD(ft): See Attached Schematic See Attached Schematic 3-1/2" L-80 8,837 Packers and SSSV Type: Packers and SSSV MD(ft)and ND(ft): N/A;N/A N/A;N/A 12.Attachments: Proposal Summary Q 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: November 2,2016 OIL ❑ WINJ ❑ WDSPL 0 Suspended ❑ 16.Verbal Approval: Date: GAS ❑✓ - WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Taylor Nasse-777-8354 Email tnasse( hiicoro.com Printed Name Chad Helgeson Title Operations Manager Signature , 97‘"— Phone 907-777-8405 Date /0/17//1,, COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number. Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: Post Initial Injection MIT Req'd? Yes 0 No LI RBDMS Spacing Exception Required? Yes ❑ No ❑( Subsequent Form Required: k0 4D4 v IAA I ( 8 2O 16 t-S(= 1011_4. Itto DD APPROVED BY Approved by:C� �1,_ /3 9[,c COMMISSIONER THE COMMISSION�iDate:/ - — l� `�// OôRoje&fifi4ALl,d aal O (24 t1,6 Submit Form and Form 10-403 Revised 11/2015 for 12 months from the date of approval. ,/� �j�! Attachments in Duplicate • llS • Well Prognosis Well: KBU 22-06 • Hilcorp Alaska,LLC Date: 10/19/2016 Well Name: KBU 22-06 API Number: 50-133-20550-00 Current Status: Shut-in Gas Well Leg: N/A Estimated Start Date: November 2"d, 2016 Rig: N/A Reg.Approval Req'd? 403 Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 205-054 First Call Engineer: Taylor Nasse (907)777-8354(0) (907)903-0341 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907)229-4824(M) AFE Number: Maximum Expected BHP: —1,450 psi @ 4,836' ND (Based of off set well data) Max. Potential Surface Pressure: —966 psi (0.10 psi/ft gas gradient) Brief Well Summary The KBU 22-06 was initially drilled and completed in 2005. It was initially completed w/3.5" casing as a multi- stage fraced Lower Beluga/Upper Tyonek completion. The well went down in late 2008 due to sand and both . Marathon and Hilcorp have been unable to return the well to production in the original completed intervals (-2.0 Bscf of cum production). The purpose of this work/sundry is to plug back and add perforations in several sands in the Upper Beluga - formation. Procedure: 1. MIRU E-tine, PT lubricator to 2,000 psi Hi 250 Low. 2. RU with PT tool to determine fluid level. (On 12/3/15 fluid level was 1,000'). POOH 3. MU 3-1/2" CIBP. RIH and set at"'6,500'. POOH ..7.7 ZS` e c-+-xe r " 1 '`5 4. MU Bailer and dump bai"of cement on top of plug. POOH. RD E-line. 5. RU Slickline.Swab fluid down to"'6,300'. Confirm depth with Engineer prior to concluding swabbing operations. RD Slickline. Pressure well with methane to achieve desired underbalance. 6. RU E-line. RU perforating guns. 7. RIH and perforate the following intervals: Zone Sands Top(MD) Btm (MD) FT Upper Beluga UB-X1 5,867' 5,887' 20 Upper Beluga UB-1 5,900' 5,920' 20 Upper Beluga UB-2 5,934' 5,958' 24 Upper Beluga UB-5 6,166' 6,186' 20 Upper Beluga UB-5A 6,197' 6,217' 20 Upper Beluga UB-5B 6,228' 6,248' 20 a. Bleed tubing pressure as require by Engineer. b. Proposed perfs shown on the proposed schematic in red font. c. Use Gamma/CCL/to correlate. Engineer to provide coorelation log. d. Record tubing pressures before and after each perforating run. 8. POOH and RD E-line. 9. Turn well over to production. • • Well Prognosis Well: KBU 22-06 Hilwrp Alaska,LLC Date: 10/19/2016 E-line Procedure (Contingency):If any zone produces sand and/or water. 10. MIRU E-line, PT lubricator to 2,000 psi Hi 250 Low. 11. RIH and set 3-1/2" CIBP. Set at depth specificed by Engineer. 12. RU Slickline. Swab fluid down to depth approved by Engineer. 13. RIH with bailer assembly. Dump bail cement. POOH. 14. Continue with Step 6 above. Attachments: 1. Actual Schematic 2. Proposed Schematic . II • • KBU 22-6 Pad 14-6 SCHEMATIC Hulcorp Alaska 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. Conductor Permit#: 205-054 20" K-55 133 ppf API#: 50-133-20550-00-00 Top Bottom Prop.Des: A-028142 MD 0' 130' KB elevation: 87' (21'AGL) TVD 0' 130' WBS#: Latitude: Longitude: 13Surface-3/8"Casing L-80 68 ppf BTC Spud: 5/20/2005 Top Bottom TD: 6/3/2005 MD 0' 1,668' Rig Released: 6/9/2005 TVD 0' PA#: Cmt w/518 sks of 12.011;542: Type 1 cmt to surface 11, Y Intermediate Casing r 9-5/8" L-80 40 ppf BTC Tree crossing=4-3/4"Otis r Bottom al MD 0' 6,529' ND 0' 5,400' Cmt w/313 sks of Class G Lead @ 12.5 ppg, Top of Cement &w/256 sks of Class G Tail @ 13.5 ppg, (CBL est.)on 3-1/2"@ 5,150' 1 Good circulation throughout job Production Tubing Excape System Details ie,) 3-1/2" L-80 9.3 ppf EUE 8rd -Ceramic flapper valves belowTop Bottom lit each module as follows: MD 0' 8,837' -6 Conventional flappers ND 0' 7,707' No flappper at Module-1 , ..il Cmt w/1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Flappers MD(RKB): Module 7 = 6,572' Module 6 = 7,704' Perfs MD(RKBI: Module 5 = 7,861' + (Beluga) MD TVD Ft Perf Date Module 4 = 8,433' Module 7= 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 Module 3 = 8,474' *'/• 2",6spf = 7,045-7,066'OH 5,915'-5,936' 21' 10/21/08 Module 2 = 8,599' A (correlated to 7,031'-7,052'CH) Module 1 = NA - Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 ao Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 I 1 (Tyonek) MD TVD it ii, Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Tagged fill @ 7851'MD (2/23/13) Module 1 = 8,675-8,685' 7,545'-7,555' 10' 08/05/05 FISH 1-11/16"X 3-1/2"Spinner 8,700' i; tagged on(7/2/2007) '"a 4 ',I. TD PBTD 8,855'MD 8,800'MD 7,725'ND 7,670'TVD Well Name & Number: Kenai Beluga Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska _ Country: USA Perforations (MD): 6,552' -8,685' . Perf(TVD): 5,423' -7,555' Angle KOP & Depth: 1.9°/ 100' C? 300 ft Angle A Perfs: 1°-> 5° Date Completed: 8/3/2005 Ground Level: (AMSL) RKB: 21° (AGL) Revised by: Craig Rang ; Revision Date: 3/18/2010 r 0 1 a KBU 22-6 PROPOSED Pad 14-6 SCHEMATIC Hilcorp Alaska 482' FSL, 1,26T FWL, Sec. 6, T4N, R11W, S.M. Permit#: 205-054 Conductor" 20 K-55 133 ppf API#: 50-133-20550-00-00Top Bottom Prop.Des: A-028142 MD 0' 130' KB elevation: 87' (21'AGL) TVD 0' 130' WBS#: Latitude: Longitude: Surface Casing 13-3/8" L-80 68 ppf BTC Spud: 5/20/2005 Top Bottom TD: 6/3/2005 MD 0' 1,668' Rig Released: 6/9/2005 TVD 0' 1,502' PA#: * Cmt w/518 sks of 12.0 ppg, /1,„: t Type 1 cmt to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Tree crossing=4-3/4"Otis 112p Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/313 sks of Class G Lead @ 12.5 ppg, Top of Cement &w/256 sks of Class G Tail @ 13.5 ppg, (CBL est.)on 3-1/2"@ 5,150' Good circulation throughout job Production Tubing Excape System Details 3-1/2" L-80 9.3 ppf EUE 8rd -Ceramic flapper valves below * ' Top Bottom each module as follows: : MD 0' 8,837' -6 Conventional flappers • TVD 0' 7,707' No flappper at Module-1 ' Cmt w/1,113 sks Class G @ 15.8 ppg, Good circulation throughout job u r Flappers MD IRKB): •• Module 7 = 6,572' CIBP w/10' Module 6 = 7,704' ement-6,500' ' • T Perfs MD(RKB): Module 5 = 7,861' .. (Beluga) MD TVD Ft Perf Date Module 4 = 8,433' pri UB-X1 5,867'-5,887' 4,748'-4,767' Proposed Module 3 = 8,474' 4' UB-1 5,900'-5,920' 4,780'-4,799' Proposed Module 2 = 8,599' A UB-2 5,934-5,958' 4,815-4,836' Proposed Module 1 = NA +a'(R! UB-5 6,166'-6,186' 5,039'-5,058' Proposed UB-5A 6,197'-6,217' 5,069'-5,089' Proposed 0 UB-5B 6,228-6,248' 5,100'-5,120' Proposed 1 Module 7= 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2",6spf = 7,045-7,066'OH 5,915'-5,936' 21' 10/21/08 ',.. (correlated to 7,031'-7,052'CH) j Module 6 = 7,685-7,695' 6,555'-6,565' 10' 08/06/05 Tagged fill @ 7851'MD (2/23/13) I - Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 1 kAk (Tyonek) MD TVD Ili r., Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Module 3 = 8,455'-8,465' 7,325'-7,335' 10' 08/05/05 FISH I "•.. Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 1-11/16"X 3-1/2"Spinner 8,700' • T . Module 1 = 8,675'-8,685' 7,545'-7,555' 10' 08/05/05 tagged on(7/2/2007) . 1I 1l TD PBTD 8,855'MD 8,800'MD 7,725'ND 7,670'TVD Well Name& Number: Kenai Beluga Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country USA Perforations (MD): 6,552' -8,685' Perf(TVD): 5,423' -7,555' Angle (* KOP & Depth: 1.9°/ 100' (? 300 ft Angle @ Perfs:_ 1°-> 5° Date Completed: 8/3/2005 Ground Level: (AMSL) RKB: 21' (AGL) Revised by: J. Kaiser Revision Date: 10/17/2016 • Seth Nolan Hilcorp Alaska, LLC GeoTech 3800 Centerpoint Drive Anchorage, AK 99503 Tele: 907 777-8308 Frilriirp Alumka.IJ I Fax: 907 777-8510 E-mail: snolan@hilcorp.com DATA LOGGED 2 /rum K BENDER DATE 01/20/16 To: Alaska Oil & Gas Conservation Commission Makana Bender Natural Resource Technician II RECEIVED 333 W 7th Ave Ste 100 Anchorage, AK FEB 0 2 2016 99501 DATA TRANSMITTAL KBU 22-06 AOGCC KBU 22-06 Elog prints and digital data Prints: RST/PNL-GR-CCL CD1: digital Elog Data DLIS DATA 1/L9/20164:48 PM File folder LAS DATA 1/19/2416 4:48 PM File folder LOG DATA 1/19/20164:48 PM File folder SCANNED JUL2 82016 Please include current contact information if different from above. Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8337 Recerfry � Date: • • Marathon Alaska Production LLC Alaska Asset Team Marathon P.O. Box 1949 rnaRnTHON Alaska Production LLC Kenai,AK 99611 e Telephone 907/283-1371 Fax 907/283-1350 July 12, 2011 Guy Schwartz Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Field: Kenai Gas Field sCANE® Nov s 2016 Dear Mr. Schwartz, Submitted for your records is the Wellview cementing and frac information for KBU 11-8x well. Also included are Cement Bond Logs for: • KBU 11-7 • KBU 11-8x • KBU 11-8Y • KBU 22-6 7occ -bc9 • KBU 24-7x Please contact me at (907)283 -1371 if you have any questions or need additional information. Sincerely, °KileAru"ki- S a t Kevin J. Skiba Regulatory Compliance Representative Enclosures: Wellview Reports cc: Houston Well File 5 CBL logs Kenai Well File (2) KJS • Image Project Well History File Cover Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original fiile, may be scanned during a special rescan activity or are viewable by direct inspection of the file. Q ~ - Q ~ ~ Well History File Identifier Organizing (aone) ^ Two-sided III (I'III (I III II III ^ Rescan Needed III IIIIII II II III III RESCAN DIGITAL DATA OVERSIZED (Scannable) olor 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: I ~ ,~, ~j ~ /s/ Project Proofing III IIIIIIIIIII VIII BY: Maria Date: ~ ` ~ /s/ Scanning Preparation ~ x 30 = ~ + ~ =TOTAL PAGES~~ ~ ' ' Count does not include cover sheet ( ) BY: Maria Date: I I / °1 .~ 15 1 T /s/ 1 1' L I Production Scanning Stage 7 Page Count from Scanned File: _~~~ (Count does include co er sheet) Page Count Matches Number in Scanning Preparation: ~ YES NO BY: Maria Date: "~a~' Q ~ /s/ Stage 1 if NO in stage 1, page(s) discrepancies were found: YES NO BY: Maria Date: /s/ Scanning is complete at this point unless rescanning is required. If (II 1I II I II II I I III ReScanned III II'II) I{III V III BY: Maria Date: /s/ Comments about this file: Quality Checked 10!6!2005 Well History File Cover Page,doc M Marathon MARATHON Oil Company February 10, 2009 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 j ;~~'T~3~'t$50 3-1371 ,, F ~_ u~~~,~ ~ , Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field ~ ~ c~ ~ ~~~~ ~- Well: Kenai Beluga Unit 22-6 ~(, Dear Mr. Maunder: Attached for your records is the Report of Sundry Well Operations, 10-404, for KBU 22-6 well. Marathon attempted to isolate a water bearing zone utilizing polymer as a squeeze medium. We were unable to squeeze the intended volume of polymer into the perforations. 5.2 bbls, of the intended 25 bbls, were injected into the formation which later broke down and was carried to surface. An alternate plan to isolate the targeted zone is under development. A 10-403 will be submitted to proceed with this work upon finalization of the plan. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Engineering Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS ALA~OIL AND GAS CONSERVATIONOMMONJ,~ V REPORT OF SUNDRY WELL ~Ffl~~t~S di 0__n_.. ac •~ ~~~~~-' a /~~ r ~„ ,rq ,. ,~ a`''° 1. Operations Abandon Repair Well Plug Perforat dl ~~ tit z`fi+e3Si~iQther ~ Attempt to Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ ~~ Time Extension ^ plug perforations Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ 2. Operator Marathon Oil Company N 4. Well Class Before Work: 5. Permit to Drill Number: ame: Development ~ Exploratory^ 205-054' 3. Address: PO Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20550-00-00 - 7. KB Elevation (ft): 9. Well Name and Number: 87' - (21' AGL) Kenai Belu a Unit 22-6 8. Property Designation: 10. Field/Pool(s): A-028142 ~ Kenai Gas Field /Beluga & Tyonek Pools 11. Present Well Condition Summary: Total Depth measured 8,855' ~ feet Plugs (measured) N/A true vertical 7,725' feet Junk (measured) 8,700' Effective Depth measured $,800' - feet true vertical 7,870' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060 psi 1,500 psi Surface 1,647' 13-3/8" 1,668' 1,503' 3,450 psi 1,950 psi Intermediate 6,508' 9-5/8" 6,529' 5,400' 5,750 psi 3,090 psi Production 8,816' 3-1/2" 8,837' 7,707' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 6,552' - 8,685' True Vertical depth: 5,418' - 7,545' Tubing: (size, grade, and MD) Excape Tubing 3-1/2" L-80 8,837' Packers and SSSV (type and measured depth) N/A N/A tl ~ t O 12. Stimulation or cement squeeze summary: The work scope was directed at isolating the water bearing perforation Intervals treated (measured): zone of 7,045'-7,066' utilizing 25bblsof polymer in a squeeze operation. The formation was tight and only allowed 5.2bbls of the polymer to Treatment descriptions including volumes used and final pressure: enter the perforations. This volume was inadequate to successfully isolate the zone and the polymer broke down and failed. 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 19 0 77 Subsequent to operation: 0 0 - 0 4 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development 0 ~ Service [] Daily Report of Well Operations X 16. Well Status after work: Oil ^ Gas ~' WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 308-442 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technician Signature ~ ~ ~ ~ Phone (907) 283-1371 Date February 10, 2009 Form 10-404 Revised 04!2006 ~ a ~ ~ ~' ~ ~ ~d~~ ~j~/ `3 Submit Original Only M ~~~~ - operations Summary Report „,~T„D„ spj~ ~~~~ Well Name: KENAI BELUGA UNIT 22$ Daily Operations Report Date: 12xtix2008 Jab Category: R&M MAINTENANCE 2l H r Srmmary Ran and set Weatherford IBP at 7,113' MD SgrtTme EaaTme Drr 0 Cotle Actlr Cotle ops 51ada TrorbkCOOe Canmert 09:00 10:15 1.25 SAFETY MTG AF Held PJSM. Discussed Expro JSA and Weatherford JSA and assigned asks. Issue permit. 10:15 13:15 3.00 RURD ELEC AF Spot andf RU eline unit. Makeup, test and prime setting tool for 2-1 l8" Inflatable bride lu . 13:15 13:45 0.50 TEST EQIP AF Fill lubricator with 50150 and test to 2500 si. Bleed very slowly to protect IBP. 13:45 15:00 1.25 RUNPUL ELEC AF RIH 2-1 x8" IBP. 15:00 15:45 0.75 LOG CSG AF Correlate to CBL. Position IBP element at 7 113'. 15:45 16:00 0.25 SETREL PKR AF Set IBP. All indications are of a good set and release. 16:00 16:30 0.50 RUNPUL ELEC AF POH. 16:30 17:45 1 .25 RURD ELEC AF Rig down eline. Close permit. Sign out and leave location Report Date: 12;'18x2008 Job Category: R&M MAINTENANCE 2l H r srmmary RN Coil test BOP S~rtTme EraTrrie Drr o Coot Aca~ Cotle opa Stada TrorbkCOOe Canmert 07: DO 08:00 1 .00 SAFETY MTG AF PJSM; JSA for rigging up coil and testing BOP. Assign tasks. D8:00 10:00 2.00 RURD COIL AF Start up equip. 10:00 12:00 2.40 RURD COIL AF Sat containment and a ui ment.Mix 350 bbls. 6 % KCL 12:00 16:30 4.50 NUND ROPE AF Rig up treatment iron, pump suctions, methonal tank, gas buster.Offload BOP, Rig up hyd. Iines.Nipple up BOP, Function test BOP, run test bar. 16:30 1$:00 1 .50 TEST ROPE AF Break circ. Shell test lower tubing ram 260 psi 10 min.Shell test hiah, tubina rams 4400 si 10 min. All valves isolated, swab valve leaking. Bleed off pressure, extract test bar. Close blind rams, test low 415 psi 10 min., high est 4400 psi 10 min. Bleed off press., secure location, blind rams closed.BOP test WRness Waived b Jim Re 12M 702008 Report Date: 12M9x2008 Job Category: R&M MAINTENANCE <<i H r Srmmanx RIH'dVeatherford CT packer. Unable to pass top E?{CAPE module. Go to warm shutdown for night. st3rtTme EraTme Drr 0 Cotlt PiCUI COtl2 opr S7alaa TrorbkCOtle Canmert 07:OD 10:30 3.50 AITON EQIP AF Stand by to replace sick crewman. 1 D:30 11:30 1 .DO SAFETY MTG AF Hold PJSM. Issue permit. Discuss BJ JSA and JSA from ASRC. Assign asks. 11:30 16:30 5.00 RURD COIL Remove BOP cap function test BOP, Pull test to 20K, Make up tools, Pressure test tp 2500 psi, shell test low to 450 psi, shell test high to 2500 psi, fix leak, shell test high to 2500 psi, good, Displace methanol in coil with 6% KCL fluid, 16:30 16:45 0.25 RUNPUL COIL Open well, WHP 547 psi. 16:45 18:00 1.25 RUNPUL COIL RIH to 3500' c cle CT acker. 18:40 19:30 1.50 RUNPUL COIL RIH to to module at 6552' acker would not o thru.P00H.Up wt.=16000K 19:30 20:30 1.00 RUNPUL COIL POOH with packer.F16564' coil tubing measurement. 20:30 21 :OD 0.50 PULD PKR Remove Injection head, lay down packer, packer OD 2.81 would not go thru module. Send acker in and et OD turned down to 2.70 O . 21:00 21:30 0.50 RURD COIL Rig down coil and pump methenol thru coil, shut down for night, turn in permits. Report Date: 12x20,2008 Job Category: R&M MAINTENANCE oy H r Srmmary Safety meeting, discuss well, breakoff coil tools, get unit ready for standby, S~rtTme EraTm! Drr 0 COtl! F4CUI C opr SlaEra TrorbkCOOe Ccmmlrt 07:00 08:00 1.00 SAFETY MTG Safety meeting JSA, Start and warm up equip. 08:00 09:00 1 .00 SERVIC EQIP Standby for company rep. fuel equip. 09:00 10:00 1 .04 RURD COIL PJSM; Prep. to rack back injector head, break off coil tools, lay down lubrictor, chain flanged lub. stack, put injector in cradle, chain reel, install ni ht ca . 10:D0 11:00 1 .00 SECURE LL Secure location blow down suction lines. 11:00 11:30 0.50 SECURE LL Check fluids in pump, check stripper. OK www.peloton.com Report Printed: 2MOx2009 M ~~~~ t]perations Summary Report „~T„D,r s0i1 Cornp~~Y Well Name: KENAI BELUGA UNIT 22~ Daily Operations Report Date: 12~21C1008 Job Category: R&M MAINTENANCE 2l H r Srmmary RIH wlpacker inject 5.2 bbls, polymer. S6rtTme EitlTme Drr O Cods AoW Cade oFa Stalls Tro~bkCOde Canmert 07:00 08:00 1 .00 SAFETY MTG Safety Meeting JSA, Start and warm up equip. 08:00 09:30 1 .50 RURD COIL Pick up injector, make up riser. 09:30 10:00 0.50 PULD BHA Make up motor head asst'. and 2.70 CT Packer. Press. test tools low at 700 psi, Press. test high at 2500 psi Install injector hd. shell test 350 psi low, est 1500 si hi h. 10'00 10:30 U.50 CIRC CFLD Circ. methenal out of coil with 696 KCL. at 2500 psi,1 .5 BPM 10:30 11:30 1 .00 RUNPUL COIL RIH w! coil tubing to 5000' cycle packer OK. Up wt =13000# Dn wt.=4000# 11:30 12:15 0.75 RUNPUL COIL Tag inflatable packer at 7133' Coil tubing meas. 12:15 12:30 0.25 RUNPUL COIL with coil to 7000'. 12:30 12:45 0.25 SETREL PKR RIH to 7010' Set CT acker. 12:45 13:15 0.50 PUMP R Perform injection test, pumping .25 BPM=1780 psi 13:15 13:30 0.25 SETREL PKR Release packer POOH to 7000' Up wt.=15617# 13:30 14:30 1 .00 MI}{ PILL Mix 10 bbls.Maraseal as er Tiorco re . 14:30 15:00 0.50 PUMP LCM Displace 2bbls. 696 KCL and follow with 10 bbls. maraseal, within two bbls. from bottom of CT packer at 7010'. 15:00 16:00 1 .00 SQUEZE OTHR Set CT acker at 7010' Pull up to 25600# to energize packer start infecting, 2 bbls. water, at .35 BPM 1720 psi, then start injecting Maraseal at .20 BPM 1800 psi, with 3.2 bbls. away had to shut down pump, start hesitation squeeze from 3.2 bbls.Start pumping .20 BPM pressure to 1800 psi shut down 1 min. into pump, then 3 mins. to bleed off to 1000 psi, repeated 12 imes with 5.2 bbls. awa ressured u to 2000 si 1 min. to ressure u , 6 min. to bleed down to 1000 psi repeated two times. Pumped total of 5.2 bbls. Maraseal awa to erfs. 16:00 18:1 S 2.25 SETREL PKR Release CT packer POOH to 5010', pump 5 bbls. to clear polymer from bottom of coil, RIH 200', Circ. 25 bbls.to clear polymer fromm well, POOH dis lacin coil with methenal.U wt.=8392# 18:15 19:15 1.00 RURD COIL At surface with tools, close well in break down coil tools~CT Packer, acker in ood condition, rig down injector head, clean location, turn in work permits. Report Date: 12f2212008 Job Category: R&M MAINTENANCE ~t H r Srmmar~ RIH with 1 "JDC on 2 3/8 motor retrieve inflatable packer at 7133' SgrtTrne EtlTlne Der 0 Cotle ACiL Cotle ops Stabs TrorbleCOtle Canme~t 07:00 07:30 0.50 SAFETY MTG Safety Meeting JSA 07:30 08:30 1.00 RURD COIL Start and warm equip. 08:30 10:30 2.00 RUNPUL COIL Remove night cap on well head, Pick up injector and lubricator, Make up motor head asst'., 2 3J8 motor,1"JDC with 2.10 bell guide with drag eeth.Pressure test to 120U psi, Install injector head and riser, Shell test to 2000 si. 10:30 11:00 0.50 CIRC CFLD Circ. methanol from coil with 696 KCL. 11:00 13:00 2.00 RUNPUL COIL Open swab valve, RIH circ. KCL .25 BPM= 215 psi, Pull test coil at 3950', Up wt.=6000# Pump=.25 BPM 215psi, RIH circ. KCL to 7050', pull test, Up wt.=15000# Pum =.25 BPM 230 si. 13:00 13:30 0.50 SETREL PKR Shut down pum ,RIH to 7133'ta fish set down 2000# Latch onto inflatable packer, Up wt.=15000#, Pulled to 25000# to shear and release packer, wait 20 min. for packer to deflate. 13:30 15:45 2.25 RUNPUL COIL POOH with packer, without pump, at 80 ft. per min. Up wt.=17000# 15:45 16:1 S 0.50 PULD BHA Close swab valve, remove injector from well head, break down BHA, inflatable acker in ood sha a no llama e.: 16:15 16:45 U.50 CIRC CFLD Install injector hd. pump methanol thru coil displacing KCL, freeze protect lines. 16:45 17:15 0.50 RURD COIL Rig down injector hd. and riser set back in saddle, 17:15 18:00 0.75 RURD COIL Pick up tools and secure loation, service equip., shut down light plants and heaters, turn in work permits. Report Date: 72C23f2008 Job Category: R&M MAINTENANCE 2i Hr Srmmary RAJ, Coil 410psi WHP, RIH WI NOZZLE PUMP N2, www.peloton.com Report Printed: 2M012009 M ~~~~ operations Summary Report ,,~„~„ ~0i1 Cornp~nll Well Name: KENAI BELUGA UNIT 22~ SL3rt7me ErC7me Der 0 Cotl! ACW COOe ops Sfada Trorbk COdt Canme~t 07:00 08:00 1.00 SAFETY MTG Safety meeting and pre-job. 08:00 09:00 1 .00 RURD COIL Start equip. check injection hd. slings. Make up dimple on, and nozzle, nipple u in'. hd. towel) hd. set u to da shell test 400 si low 2000 si hi h. 09:00 10:30 1 .SO BLOWDN COIL Methanol return line frozen, 1312 psi on line, place heater trunk on line and haw out.Line still frozen, bleed off thru choke.Replace hard line. 10:30 11:30 1 .00 BLCNVDN COIL Displace methanol with N2. 11:30 14:00 2.50 RUNPUL COIL 0 en swab valve, RIH pum~n~ N2 ,700cfm 1640', 900 psi, 115 VN-IP/ 1200', 850' psi CTU,11 S WHP 03000', 940 psi CTU, 113 WHPi 4175', 1155 psi CTU, 166 WNP, Pull test from 4175'-4150'. Continue RIH, Start pumping at 1000 cfm. 48 bbls. recovered,16300', 1400 psi CTU,170 VN1P, 65 bbls. recovered, (8501', 1740 psi CTU, 237 WHP, Park coil for 10 min. 125 bbls.recovered total. 14:00 14:30 0.50 RUNPUL COIL POOH to 6500' ,1116 psi CTU, 159 WHP, 750 cfm. 14:30 16:00 1 .50 RUNPUL COIL RIH fA6500' to 8500',1100 psi CTU, 168 WHP, 195 bbls recovered total 1 fi~:00 17:00 1.00 RUNPUL COIL POOH to 5000' ,870 psi CTU, 137 tiMiP, 750 cfm 17:00 18:30 1 .50 RUNPUL COIL RIH f15000'to 8500' pumping 1000 cfm, 1100 psi CTU,168 WHP on bottom 10 min. 18:30 19:00 0.50 BLOWDN COIL On bottom circ. N2 8500' 1126 si CTU 143 WHP. 19:00 20:00 1 .00 RUNPUL COIL POOH 88500'-6000' Shut down N2. 20:00 21:1 S 1 .25 RUNPUL COIL POOH f/6000' without N2 well pressure bleeding down to 0 at surface __ when gat out of hole.Recovered total of 300 bbls. water. 21:15 22:00 0.75 RURD COIL Close swab and rig down coil unit for night, turn in work permits. Deity Operations Report Date: 121241200$ Job Category: R&M MAINTENANCE 2i H r Summary RIU, Coil 750 psi WNP, RIH WI NOZZLE PUMP N2, Total fluid back 183bb1s. St-rrtTme Erarme Drr o CaAe A~ctlr Cotle opa Sgda TrorbleCoOe Comment 07:00 08:00 1.00 SAFETY MTG Safety Meeting and JSA with BJ and 08:00 10:30 2.50 RURD COIL Start equip., inspect stripper element, rig up injector hd., prime up N2, start shell test, 400 psi low, 2000 psi high, no leaks, shell test complete.Open swab valve. 10:30 11:00 O.SO RUNPUL COIL Bleed off well, 750 psi on well head, RIH to 4000'. 11:00 12:00 1 .00 RUNPUL COIL Bring on N2 at 4225', 350 scf, RIH 40' min. 12:00 14:30 2.50 RUNPUL COIL Slight fluid and gas returns,6723', 1933psi CTU, 2 psi WNP, 7200' RIH with increasing fluid returns to surface, 1990 psi CTU, 85psi 1MiP,1 bbl min returns, 7700' 18SOpsi CTU, 3SOpsi WHP, 25 bbls.returned to surface.8500' 1550 si CTU 250 si WHP on bottom um in 500scfm N2. 14:30 15:00 0.50 RUNPUL COIL POOH to 6600' 1023psi CTU,165psi WHP, SOOscfm, 79 bbls. fluid back total 15:00 15:30 0.50 RUNPUL COIL RIH to 8500',1036psi CTU, 193psi WHP, 500 scfm, 99 bbls. fluid back otal.Weight check up wt.=20000# 15:30 17:00 1 .50 RUNPUL COIL POOH 1130psi CTU, 153psi WHP, 500 scfm, Up wt.=8110# Pull out 40' per min. 17:00 18:30 1 .50 RUNPUL COIL POOH to 5000" no fluid at surface, stop N2, WHP 90psi, 163 bbls. fluid total from well. 18:30 19:00 0.50 RURD COIL Shut swab valve, remove injector hd. set back in cradle. Pump methanol across tree. Report Date: 1212502008 Job Category: R&M MAINTENANCE 2i H r Srmmary RA,I, Coil 750 spi WNP, RIH W/ nozzle, pump N2,152 bbls. total water returned. SflrtTme E~tlTme Dlr O Catle Af.`tll Cotlt opa Stada Tro1bk000e Canme~t 07:00 08:40 1.00 SAFETY MTG Safety Meeting JSA with BJ Services and ASRC 06:00 09:00 1.00 RURD COIL Start and warm up equip. 09:00 09:30 0.50 RURD COIL Remove inject. hd. off cradle, check BHA, Install inject. hd. on well, Shell est 2000 si noleaks.Bleed off. 09:30 10:30 1 .00 RUNPUL COIL RIH, prime N2, RIH at 40fpm,pumping N2 at SOOscf,4200', 220psi CTU, 0 psi P, 4500', 375 CTU, 0 WHP, Up wt=750tt, 5350', SOOpsi CTU, 0 VVl-iP, www.peloton.com Report Printed: 2M012009 ~~~~ operations Summary Report s0~~ CornP~ryY Vtifell Name: KENAI BELUGA UNIT 225 SgrtTrrie ErGTme Drr 0 Cotle AuChl Cotle o~ Stada TrorbleCalt Canmert 10:30 11:30 1 .00 RUNPUL COIL Slow coil down to 40 FPM, slow N2 down to 350scf, stop and wait on returns at 6200', 154Dpsi CTU, 0 psi WHP, 11:30 13:15 1.75 RUNPUL COIL Start ettin returns back RIH frB200' to 8500' 1140 si CTU 200 si WHP 13:15 14:00 0.75 RUNPUL COIL Stop coil wI20 bbls. water returned, start POOH, fI8500', to 7450', 1100psi CTU, 165psi WHP, 14:00 15:00 1 .00 RUNPUL COIL RIH (/ 7450', 83 bbls. fluid back, 8500', 1180psi CTU, 165psi VNiP, pumping 500scf N2, Up wt.=24000#, 15:00 16:15 1 .25 RUNPUL COIL POOH ft 8500',1174psi CTU, 155psi WHPI 8430',1173psi CTU, 15lpsi WHPI 7500',1040psi CTU,150psi V4HP / 6800' 1015psi CTU, 130psi V~hiP 15800', 870psi CTU, 240psi WHP 15200', 850psi CTU, 175psi WHP 15150', 590psi CTU 176 si WHP. Shut dawn N2 no returns. 16:15 17:15 1 .00 RUNPUL COIL POOH wI coil to surface,,152 bbls. total returns. Pressure bled to zero 17:15 17:30 0.25 RURD COIL Rig down injector, secure location, turn in work permits. Daily Operations Report Date: 72I28I2008 Job Category: R&M MAIHTEHANCE 2i H r Srmmary RN coil 800 psi WHP ,RIH wlcoil blow down well, well flowing without water turn over to production. ST3rtTlne ErdTlne Drr 0 Cotle AC11! Catle opa St3ds TrorbkCOtle COmmert 07:00 08:00 1 .00 SAFETY MTG Hold safety meeting and JSA, warm up equip.. 08:00 10:00 2.00 RURD COIL Cheak well head press. 800 psi, install inject. hd., test had leak, bleed off remove injector hd., replace o-ring on injector hd., reinstall injector hd., shell est no leaks 2000 si bleed off well hd. 10:00 12:00 2.00 RUNPUL COIL RIH wI coil tubing, cool down N2, 200', Up wt =500K 13500' pull test up wt =6000K /Start pumping N2, 4100', 240psi CTU, 1 psi WNPI 5800', 1185psi CTU,116psi W'HP,N2 rate 500sfm, Getting returns..5 bbls min. l 7000' up wt.=15000K, 1100psi CTU, 140psi WHP, N2 rate 500 sfm. (8450' Tagged bottom 50' higher, 1380psi CTU, 62psi WHP 12:00 12:30 0.50 PUMP N2 Pum N2 for 30 min. on battorc~. At $450' 20 bbls. water back 12:30 13:00 0.50 RUNPUL COIL POOH to 7225', lOSpsi CTU, 115psi WHP, 13:00 13:30 0.50 RUNPUL COIL RIH to 8450', 100psi CTU, 68psi WHP, N2 rate SODsfm, 32 bbls. fluid back aal. 13:30 15:00 1 .50 RUNPUL COIL POOH fI 8450', 940psi CTU, 243psi WHP, POOH ,not getting water back to surface, 7529' 865psi CTU, 199psi V+MP 16450' 808psi CTU,195psi WNP, stop N2 POOH, 15:00 15:30 0.50 RUNPUL COIL Coil tubing at surface, close swab valve, open wing valve to production, well flowin to roduction header. 15:30 17:30 2.00 RURD COIL emove injector hd. bleed off lines, install night cap, secure location, turn in work permits.Move coil unit to KBU11-8Y Report Date: 1MOI2009 Job Category: R&M MAIHTEHANCE 2l H r Srmmary tv11RLl E xpra to run PT Survey. Fluid level ~ 2441' wlm. Set down 5' into top module( #7) perforations. Can't get below. SgrtTtne 6tlTme Drr O CoAe Af.Nll COOe ops Slada TrorbkCOtle Canmelt 09:00 10:00 1 .GO SAFETY MTG AF Obtain safe Work Permit. Hold PJSM. Discuss Expro JSA. Discuss alarms, muster area, emergency reponse. Discuss specific job tasks and overall ob~ective for toda s 'ob. 10:00 12:18 2.30 RURD ELEC AF Spot equipment. MU lubricator. Carry 10' section of lubricator to WH. MU remainder of lubricator) BOP'sl toolstring wICCLlpressure temperature gauges. Carry lubricator to WH. . 12:18 14:33 2.25 RUNPUL ELEC AF RIH wl PT au es to 6551' , 5' into Module 7 perfs Set down. Work tools. Can NOT aet below. Fluid level ~ 2441 elm. Call and discuss w/Ken W. POOH. 14:33 16:03 1.50 RURD ELEC AF OOH. Gau a readin 88 sia and 42 de rees and fallin RD E line unit. 16:03 16:18 0.25 SECURE LL AF Secure well head and loc. Turn in permit. Sign out Report Date: 1M4I2009 Job Category: R&M MAINTENA NCE ~l Hr Srmmary MIRU Pollard to dump bail sand bridge. Tag up on damaged casing (~ 6541' KB.-top module( #7) perforations. Fluid level ~ 2400' wlm. ops St3rtTme EeGTme Drr 0 Cotle AC1L Cone Stalls TrorbleC06e Canmert 08:00 08:45 0.75 SAFETY MTG AF Hold PJSM. Discussed Pollard JSA and assigned tasks. Issued permit. 08:45 09:00 0.25 PREP LOC AF Sand location and work area. Clear and sand entrances to well house. www.peloton.com Report Printed: 2MOI2009 -, ~~~~ - operations Summary Report ~~ ~0~~ ~~~~ Well Name: KENAI BELUGA UNIT 22~ S6rtTlne E~tlTlne Dir 0 COOe ACW Cotle oPs S1aCra Tro~bleCOae Canme~t 09:00 09:15 0.25 RURD SLIK AF RU slickline unit. PU 2" DD Bailer with chisle bottom. Test Lubricator to 2000 psi. Test good 09:15 10:30 1 .25 RUNPUL SLIK AF RIH(1) 2" DD Bailer to 6541' KBm Work tools. POOH. OOH. Recover cup of water. No sand. 10:30 11:30 1 .00 RUNPUL SLIK AF RIH (2)wJ 2.25" Bailer. Tag fill ~ 6541' KB. Work tools. Sticky. Tap down once. Have to jar out. POOH. OOH. Bailer MT. No sand. 11:30 12:36 1 .10 RUNPUL SLIK AF RIH(3) 2.0" LIB. Tag c~D 6544' KB. Tap down twice. POOH. OOH. Edges of LIB rolled up. NO marks on face. NO indication of sand. 12:36 13:12 0.60 RUNPUL SLIK AF RIH(4) 2.7" LIB. Tag ~ 6536' KB. (8' higher) POOH. OOH. Edges of LIB rolled u ward sli htl NO marks on face. 13:12 14:12 1 .00 RURD SLIK AF RD slick line unit. LD tool string. LD lubricator. Install tree and PTest. Test good. 14:12 14:27 0.25 SECURE LL AF Secure well. www.peloton.com Report Printed: 2M0J2009 Permit #: 205-054 API #: 50-133-20550-00-00 Prop. Des: A - 028142 KB elevation: 87' (21' AGL) wBS #: Latitude: 5/20/2005 6/3/2005 ~d: 6/9/2005 Tree crossing = 4-3/4" Otis Top of Cement (CBL est.) on 3-1/2" @ 5,150' ~cBU 22-s Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11 W, S.M. Tag fill @ 6557' on 1/9/09 - Ceramic flapper valves below each module as follows: Flappers MD (RKB): Module 7 = 6,566' Module 6 = 7,707' Module 5 = 7,867' Module 4 = 8,445' Module 3 = 8,484' Module 2 = 8,610' Module 1 = NA ~~: >~ i. a i% ,~ ~. FISH R`~ -•'7 1-11/16" X 3-1/2" Spinner 8,700' MA~TMOM Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' Surface Casing 13-318" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt wl 518 sks of 12.0 ppg, Type 1 cmt to surface 9-518" L-80 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, 8 w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' ND 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job Perfs MD (RKB): (Beluga) MD TVD (Beluga) Ft Perf Date Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2" - 6spf gun = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 (correlated to) 7,031'-7,052' CH Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 (Tyonek) M D Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Module 3 = 8,455'-8,465' 7,325'- 7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Module 1 = 8,675'-8,685' 7,545'- 7,555' 10' 08/05/05 tagged on (7/2/2007) TD PBTD 8,855' MD 8,800' MD 7,725' TVD 7,670' TVD Well Name & Number: Kenai Beluga Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,552' - 8,685' (TVD): 5,423' - 7,555' Angle/Perfs: - 1° Angle @ KOP and Depth: -3.5°I 100' from 300'to 1,600' MD Dated Completed: 8/3/2005 Completion Fluid: 6% KCL Revised By: Kevin Skiba Last Revison Date: 2/10/2009 • • ~+ t.ttrSta~T 0~ ~ ~ 333 W. 7th AVENUE, SUITE 100 C0~~7ERQAii01` CQ~IIS5I~~ ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907)276-7542 Ken Walsh Senior Production Engineer Marathon Oil Company f, ~~ ~~~~ ~ ~f 200 PO Box 1949 r Dsr y Kenai AK 996 1 1-1 949 ~tiJr '7 Re: Kenai Gas Field, U. Tyonek/Beluga Gas, Kenai Beluga Unit 22-6 Sundry Number: 308-442 Dear Mr. Walsh: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. Chair DATED this ~ day of December, 2008 Encl. ~Zb ~ - ,~ ~ ~' l2 • STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS ~n aar ~~ gun 1. Type of Requesf: Abandon^ Suspend ^ Operational shutdown^ Perforate ^ Waiver^ Other^ Alter casing^ Repair well ^ Plug Perforations^/ - Stimulate ^ Time Extension [~ Change approved program ~ Pult Tubing ^ Perforate New Pool ^ Re-enter Suspended Well [~ 2.Operator Name: Marathon Oil Com an 4. Cureent Weli Class: 5. Perrnit to Dril! Number: p y Development ^ Exploratory ^ 205-~54 - 3 Addr ~ . ess: pp Box 1949 Stratigraphic ^ Service ^ 6. API Number. Kenai Alaska, 99611-1949 50-133-20550-00-00- 7. If pertordting, closest approach in pools} opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ^ Na ~ Kenai Beluga Unit 22-6 9. Property Designation: 10. KB Elevation (ft}: 11. Field/Pool(s}: ~r~~~ ~ ~\uS~ ~o_S A-028142 ~ 8T (21' KB) ~ Kenai Gas Field / B Tyone 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft}: Plugs (measured): Junk (measured}: 8,855' - 7,725' - 8,800' _ 7,670' - N/A 8,700' Casing Length Size MD TVD Burst Collapse structural Conductor 109' 20" 130' 130' 3,060 psi 1,500 psi Surface 1,647' 13-318" 1,668' 1,503' 3,450 Psi 1,950 psi Intermediate 6,508' 9-5/8" 6,529' 5,400' 5,750 psi 3,090 psi Production 8,816' 3-1/2" 8,837' 7,707' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft}: Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft}: 6,552' - 8,685' 5,418' - 7,545' 3-1/2" L-80 8,g37~ Packers and SSSV Type: Packers and SSSV MD (ft): NIA N1A 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ^ Exploratory ^ Development Q - Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: December 15, 2008 ^ Oil ^ Gas Q ~ Plugged ^ Abandoned 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. 1 hereby certify that the foregoing is true and coreect to the best of my knowledge. Contact Kevin Skiba (807) 283-1371 Printed Name Ken D. Walsh Titie Senior Production Engineer Signature $ Phone Date (907) 283-1311 December 5, 2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ~~ ~ '' '~~'~ Plug Integrity ^ BOP Test `~. Mechanical Integrity Test Location Clearance ^ Other. ~~Q ~S~ ~~ ~~ C ~~ Ci~S p ~Y~,~~ SubsequentFonnRequired: ~~~ APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 12 ip ~~~~~ Form 10-403 Revised 06/2006 ~ K ~ ~ ~ ~ ~ ~ ~;~~~ '' ~'~ ~~~~ ~ ~~~~ Submit in Dupligte • arathan MARATHON ~~I C:o-mpany December 5, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7tn Ave Anchorage, Alaska 99501 Reference: 10-403 Application of Sundry Approvals Field: Kenai Gas Field Well: Kenai Beluga Unit 22-6 Dear Mr. Maunder: • Marathon Oil Company Alaska Asset Team P.o. l3ax 1sa9 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Attached for your records is the10-403 Application of Sundry Approvals for KBU 22-6 well. Marathon is requesting permission to isolate the 7,045' - 7,066' zone utilizing a polymer squeeze. This zone has been allowing water to infiltrate the wellbore since it was perforated in October of this year. All flow has since stopped as of November 30rn Plans are to isolate the water bearing zone and jet the fluids out to reinitiate gas flow. Please contact me at (907) 283-1.371 if you have any questions or need additional information. Sincerely, ~~ Kevin J. Skiba Engineering Technician Enclosures: 10-403 Application of Sundry Approvals cc: Houston Well File Well Schematic Kenai Well File Isolation Procedure KJS KDW • • M MARATHON December 5, 2008 Marathon Oil Company Alaska Asset Team KBU 22-6 Procedure to: Shut off Water with Polymer Squeeze WBS # W0.08.19141.EXP Objective: Permanently abandon a single wet Beluga interval that was conventionally perforated on October 20, 2008. This Excape~ well was making 1.5 MMscfd prior to perforating the interval, 7045'-7066' MD. This water productive interval will be permanently shut off by squeezing a polyacrylamide polymer into the near wellbore region over the twenty-one foot perforated length. Current status: Well is currently dead with a fluid level recorded by Expro on 10/31/2008 at roughly 1625' from surface with ashut-in surface pressure of 200 psig and a static BHP of 2750 psig at 8400' MD. Procedure• 1. Haul Tanks and Rental Equipment to Location. Make arrangements with ASRC to lay liner and berm around flowback equipment. Deliver diesel fueled man-lift, two light towers, and MOFO to location. Deliver MOC flowback tank, gas buster, and 2" SK choke skid to location. Deliver clean Rain-for-Rent fluid tank and fill with 500 bbls of 6% KCL water. Deliver 50/50 methanol water tank to location. Make arrangements for electrician and crane truck to remove well house. 2. Run GR. MIRU Expro Wireline to run inflatable bridge plug. Hold PJSM. MU a 2.80" GR or swage and pull into the lubricator. Take lubricator to wellhead and pressure test to 2000 psi with 50/50 methanol water. RIH with 2.80" GR or swage past 7600' MD to tag PBTD at or near 8700' MD. POOH and LD GR. Set Inflatable Bridge Plug to Change out Tree. Hold PJSM. PU 2.125" max running OD Weatherford/BOT inflatable bridge plug and setting tool. Pull tools into lubricator. Note: While pressure testing the lubricator, be sure and pressure up and bleed off pressure slowly. This will help prevent a possible premature set in the lubricator. Take lubricator to wellhead and pressure test to 2000 psi with 50/50 methanol water. Be very careful RIH and set center of inflatable bridge plug at 7116' MD (50' below the bottom wet perforation at 7066' MD). Do not tag the inflatable bridge plug to verify setting depth. POOH and LD setting tool. RDMO Expro Wireline. KBU 22-6 Polymer Squeeze Wet Beluga Perf Interval • 4. MIRU Coiled Tubing Unit. Hold PJSM. MIRU ASRC 40 or 45-ton Crane, BJ Services coiled tubing unit with 1-3/4" coiled tubing work string, nitrogen unit, and fluid pump. Hold PJSM. Install BJ 4-1/16" SK flow cross on 4-1/2" Otis connection on top of swab valve. RU MOC flow back iron to allow circulation of fluids from the flow cross, through the choke skid, to the gas buster and flow-back tank. Have ASRC crane PU CT BOP's and flange to flow cross. Pressure test BOP's with 50/50 methanol water to 250 psi/4500 psi. Function test BOP accumulator. Submit required BOP Test Report to AOGCC. Stab coil tubing in injector assembly. Pickup the injector head and lubricator with crane. Coiled tubing volume is 27 bbls. Notify AOGCC .Tames Reg @ 907-793-1236 (24 or loner) prior to CT BOP Test 5. MU the following Weatherford CT packer assembly: Equipment OD ID Length Bull Nose Guide, 2.500" 0.64" 0.57' X-Over (1-1/2 MT Box x 1.8 Acme Pin), 2.220" 1.000" 0.60' PT Dual Flapper Check Valve, 2.375" 1.000" 1.17' X-Over (1-1/2 CS Pin x 1-1/2 MT Pin), 2.500" 1.300" 0.50' Tension Set CT Packer, 2.810" 1.380" 4.6' Set Down Unloader, 2.500" 1.380" 3.06' X-Over (1-1/2 MT Box x 1-1/2 CS Pin), 2.170" 1.000" 0.45' MHA with 3/8"Ball Disconnect, 2.375" 0.664" 2.30' With Coiled Tubing Connector, Max OD Min ID Total Length 13.25' Pull test connector to 15K lbs. MU injector head and lubricator on top of BOP's. Shell test BOP and lubricator to 4500 psi with methanol water. Displace methanol to tank with 6% KCL water. 6. RIH, Spot Polymer in CT, and Set CT Tension Packer. Hold PJSM. Open well and RIH pumping 6% KCL water at minimum rate to fill the well. Stop at about 6,500' MD (above all perforations) and function test packer set using J-latch assembly on CT packer. Wash down and lightly tai (no more than 1000# slackoff weight) the top of the Weatherford inflatable bridge plug at about 7,110' MD. PUH exactly 100' with coiled tubing. Mix 36 bbls of Tiorco "MaraSeal" polyacrylamide polymer with fresh water. Tiorco representatives to provide polymer hydration unit to deliver product to BJ Services fluid pumper. Pump 25 bbls of the MaraSeal polymer into coiled tubing to spot it to within 2 bbls of the CT packer. Set the middle of CT Packer element at 7,010' MD. 7. Permanently Isolate Perf Interval, 7045'-7066' MD, with MaraSeal Polymer. Pump the remaining 16 bbls of MaraSeal polymer into the coiled tubing and displace KBU 22-6 Polymer Squeeze Wet Beluga Perf Interval • polymer into the perfs with 25 bbls of 6% KCL water leaving 2 bbls of polymer in the coiled tubing. Ensure that polymer squeeze pressure is below frac pressure. Assuming a frac gradient of 0.75 psi/ft at 5920'TVD and a fluid gradient of 0.45 psi/ft, the maximum surface treating pressure should be kept below 1775 psi. Release the CT packer by slacking off weight to close the Unloader. PUH pumping 6% KCL water at sufficient rate to string/disperse the remaining 2 bbls of polymer out in the 3-1/2" casing before. the coiled tubing has reached the upper-most set of ExcapeTM perfs at 6,552'-6,562' MD. POOH and LD CT Packer. 8. Pull Inflatable Bridge Plug. Hold PJSM. MU a 1" pump-through JDC pulling tool and bell guide to catch a 1" fishing neck on the inflatable BP to the Weatherford MHA and double flapper/check assembly on the BJ Services coiled tubing. Pull fishing BHA into lubricator and take to wellhead. Pressure test lubricator to 2000 psi with 50/50 methanol water. RIH and circulate down with KCL water to the inflatable BP. Latch up on inflatable BP. Set down to equalize and then pickup to shear release BP. Allow tool to relax and contract for about 30 minutes before attempting to POOH. POOH and LD fishing tools and inflatable BP. State condition of the inflatable BP in the WellView report. 9. ,Jet Well Dry with Nitrogen. Hold PJSM. Cool down nitrogen unit and pressure test lines and check valve to 250/4500 psi with methanol or KCL water. Bleed off pressure and displace water to storage or flowback tank as appropriate with nitrogen. Take initial fluid tank straps. RIH jetting well in with nitrogen per BJ Services jetting procedure. POOH with coiled tubing. RDMO BJ Services Coiled Tubing Equipment. 10. Release all unnecessary Rental Equipment and Clean up Location. Complete Well Handover Form and review with Production #1 Operator. 11. Produce well to sales. CONTACTS Ken Walsh: 907-283-1311 (w) Scott Szalkowski: 907-394-3060 (c) Lyndon Ibele: 907-565-3042 (w) Sharad Yadev: 907-748-2819 (c) KGF Operators: 907-283-1305 713-296-3390 (w) 713- 301-9834 (c) 713-296-3689 (w) 512-731-3369 (c) KBU 22-6 Polymer Squeeze Wet Beluga Perf Interval 205-054 50-133-20550-00-00 A - 028142 ~: 87' (21' AGL) 5/20/2005 6/3/2005 'd: 6/9/2005 Tree crossing = 4-3/4" Otis Top of Cement (CBL est.) on 3-1/2" Cc? 5,150' '~CBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11 W, S.M. u - Ceramic flapper valves below each module as follows: Module 7 = 6,566' Module 6 = 7,707' Module 5 = 7,867' Module 4 = 8,445' Module 3 = 8,484' Module 2 = 8,610' Module 1 = NA 1-11/16" X 3-1/2" Spinner 8,700' tagged on (7/2/2007) TD PBTD 8,855' MD 8,800' MD 7,725' TVD 7,670' TVD Tag fill @ 8,513' on 10/31/08 Well Name & Number: Kenai Beluga Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,552' - 8,685' (TVD): 5,423' - 7,555' Angle/Perfs: Angle ~ KOP and Depth: Dated Completed: 8/3/2005 Completion Fluid: 6% KCL Revised By: Mickey Mullin Last Revison Date: 11/10/2008 Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' 13-3/8" L-80 66 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface Intermediate Casino 9-5/8" L-60 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' ND 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job MD (Beluga) TVD (Beluga) Ft Perf Date Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2" - 6spf gun = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 correlated to 7,031'-7,052' CH Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 MD (Tyonek) Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Module 3 = 8,455'-8,465' 7,325'- 7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Module 1 = 8,675'-8,685' 7,545'- 7,555' 10' 08/05/05 M Marathon MARATHON Oil Company November 5, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 22-6 Dear Mr. Maunder: Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~: k r ... ~„H 6 ~.1 ~ tf ~l~c',. ~ ~°,_ .., ~_~~ a 4e a~~~ Attached for your records is the10-404 Report of Sundry Well Operations for KBU 22-6 well. This report covers the work performed to add twenty-one feet of perforations to the Beluga formation. All work performed was completed under Sundry 308-357. KBU 22-6 is presently flowing at 1450 mcf at 115 psi. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ,~ w ~~ Kevin J. Skiba Engineering Technician ~~~% ~G~~ ~~ :~ ZQQ~ Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Operations Summary Kenai Well File Current Well Schematic KJS KM - J~+G STATE OF ALASKA ~~~ 08 ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS ``~ , ~, ~, . 1. Operations Abandon Repair Well Plug Perforations Stimulate ' ~ `' er ~ Pertormed: Alter Casing ^ Pull Tubing^ Perforate New Pool ^ ,, Waiver^ Time Extension^ `~ Change Approved Program ^ Operat. Shutdown^ Perforate ^~ ' Re-enter Suspended Well^ 2. Operator Marathon Oil Company Name 4. Well Class Before Work: 5. Permit to Drill Number: ; Development ^~ Exploratory^ 205-054 3. Address: PO Box 1949 Stratigraphic ^ Service^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20550-00-00 ' 7. KB Elevation (ft): 9. Well Name and Number: 87' (21' KB) ~ Kenai Belu a Unit 22-6 8. Property Designation: 10. Field/Pool(s): A-028142 ~ Kenai Gas Field /Beluga 8- Tyonek Pools 11. Present WeII Condition Summary: Total Depth measured 8,855' ~ feet Plugs (measured) N/A true vertical 7,725' .feet Junk (measured) 8,700' Effective Depth measured $,$p0' ~ feet true vertical 7,870' ` feet Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060 psi 1,500 psi Surface 1,647' 13-3/8" 1,668' 1,503' 3,450 psi 1,950 psi Intermediate 6,508' 9-5/8" 6,529' 5,400' 5,750 psi 3,090 psi Production 8,816' 3-1/2" 8,837' 7,707' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 6,552' - 8,685' True Vertical depth: 5,418' - 7,545' Tubing: (size, grade, and MD) Excape Tubing 3-1/2" L-80 8,837' Packers .and SSSV (type and measured depth) N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,361 21 0 117 Subsequent to operation: 0 1,450 19 0 115 14. Attachments: 15. Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ^~ ~ Service ^ Daily Report of Well Operations X 16. Well Status after work: Oil ^ Gas ~ ~ WAG ^ GINJ ^ WINJ ^ WDSPL ^ 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 308-357 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Engineering Technician Signature _~~ ~ `~' Phone (907) 283-1371 Date November 5, 2008 Form 10-404 Revised 04/2006 ~ 3 { ,~ ~ ~ ~ ~ p ~ Submit Original Only ~ ~ ~~~~ Marathon iJperations Summary Report ~T,~, ;0i1 ~~~~ Well Name: KENAI BELUGA UNIT 22~ www.peloton.com Report Printed: 10!23!2008 50-133-20550-00-00 A - 028142 on: 87' (21' AGL) 5/20/2005 61312005 ~d: 6/9/2005 Tree crossing = 4-314" Otis Top of Cement (CBL est.) on 3-1/2" @ 5,150' KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. MARATHON ` Conductor 20" K-55 133 ppf ' Top Bottom ' MD 0' 130' TVD 0' 130' 13-318" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt wl 518 sks of 12.0 ppg, Type 1 cmt to surface 9-518" L-80 40 ppf BTC Top Bottom MD 0' 6,529' TVD 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, 8 wl 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job - Ceramic flapper valves below each module as follows: Module 7 = 6,566' Module 6 = 7,707' Module 5 = 7,867' Module 4 = 8,445' Module 3 = 8,484' Module 2 = 8,610' Module 1 = NA FISH 1-11/16" X 3-1/2" Spinner 8,700' / ~~' ~ ~' '~ tagged on (71212007) ` ± 4 a TD PBTD 8,855' MD 8,800' MD 7,725' TVD 7,670' TVD Excaae System Details - 7 Excape modules placed - Red contol line fire modules 2-7 -Green control line fires Module 1 Perfs MD IRKBI: MD (Beluga) TVD (Beluga) Ft Perf Date Module 7 = 6,552'-6,562' 5,423'-5,432' 10' 08/06/05 2" - 6spf gun = 7,045'-7,066' OH 5,915'-5,936' 21' 10/21/08 correlated to 7,031'-7,052' CH Module 6 = 7,685'-7,695' 6,555'-6,565' 10' 08/06/05 Module 5 = 7,842'-7,852' 6,712'-6,722' 10' 08/06/05 MD (Tyonek) Module 4 = 8,414'-8,424' 7,284'-7,294' 10' 08/06/05 Module 3 = 8,455'-8,465' 7,325'- 7,335' 10' 08/05/05 Module 2 = 8,580'-8,590' 7,450'-7,460' 10' 08/05/05 Module 1 = 8,675'-8,685' 7,545'- 7,555' 10' 08/05/05 Well Name & Number: Kenai Beluga Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,552' - 8,685' (TVD): 5,423' - 7,555' Angle/Perfs: Angle @ KOP and Depth: Dated Completed: 8/3/2005 Completion Fluid: 6% KCL Revised By: Nancy Henry Last Revison Date: 11/3/2008 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' TVD 0' 7,707' Cmt wl 1,113 sks Class G ~ 15.8 ppg, Good circulation throughout job CJ ,~`~ ~~ ~ ~~ 4 NPd` ALASiSA OIL A1~TD GA5 COI~TSERQA7'IO~T CO1rII~IIS5IOl~T • SARAH PAL/N, GOVERNOR 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Kyle Miranda Production Engineer Marathon Oil Company PO Box 1949 `~~~~'~~~1~~d ' .t'' 4 ,~ ~~~~ Kenai AK 99611-1949 ~~~ ~~ Re: Kenai Gas Field, Upper 1~onek/Beluga Gas Pool, KBU 22-6 Sundry Number: 308-357 Dear Mr. Miranda: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Scamount, Jr. Chair '~- DATED this ~ day of October, 2008 Encl. M Marathon MARATHON Oil Company October 1, 2008 Mr. Tom Maunder Alaska Oil & Gas Conservation Commission 333 W 7t" Ave Anchorage, Alaska 99501 Reference: 10-403 Application of Sundry Approvals Field: Kenai Gas Field Well: Kenai Beluga Unit 22-6 Dear Mr. Maunder: C Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1377 Fax 907/283-1350 Attached for your records is the10-403 Application of Sundry Approvals for KBU 22-6 well. Marathon proposes to enhance gas production by adding 21' of perforations to the Beluga formation. The proposed operation will be performed during one perforating gun run: MD TVD ft 7,045' - 7,066' 5,915' - 5,936' 21 Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, y ~~ Kevin J. Skiba Engineering Technician Enclosures: 10-403 Application of Sundry Approvals cc: Houston Well File Well Schematic Kenai Well File Perforation Procedure KJS KM STATE OF ALASKA ALA OIL AND GAS CONSERVATION COM ION APPLICATION FOR SUNDRY APPROVALS ~n nnr ~~ ~Rn ~~ /~.~~D~ V ~o ~~ 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown^ Perforate ^~ - Waiver ^ Other ^ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: Marathon OII Con1 an p y 4. Current Well Class: 5. Permit to Drill Number: Development ^ ~ Exploratory ^ 205-054 - 3. Address: p0 Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20550-00-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Y ^ ~ Kenai Beluga Unit 22-6 Spacing Exception Required? es No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): A 028142 87' (21' KB) Kenai Gas Field /Beluga & Tyonek Pools 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 8855' - 7725' ~ 8800' - 7670' - N/A 8,700' Casing Length Size MD TVD Burst Collapse Structural Conductor 109' 20" 130' 130' 3,060 psi 1,500 psi Surface 1,647' 13-3/8" 1,668' 1,503' 3,450 psi 1,950 psi Intermediate 6,508' 9-5/8" 6,529' 5,400' 5,750 psi 3,090 psi Production 8,816' 3-1/2" 8,837' 7,707' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6,552' - 8,685' 5,418' - 7,545' 3-1/2" L-80 8,837' Packers and SSSV Type: Packers and SSSV MD (ft): N/A N/A 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program Q BOP Sketch ^ Exploratory ^ Development ^~ - Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: October 27, 2008 Oil ^ Gas Q- Plugged ^ Abandoned ^ 17. Verba! Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kyle Mir da Title Production Engineer Signature ~ Phone (907) 394-8271 Date October 1, 2008 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: Subsequent Form Required: t~t~ ~j APPROVED BY r /' ( Approved by: ® Y COMMISSIONER THE COMMISSION Date: / / b ~+ Form 10-403 Revised 06/2006 G ~ i ~" ~ ~ ~ _.__ ~.~~-~~~~~AL Submit in Duplicate ~ ! M September 18, 2008 MARATHON Marathon Oil Corporation Field: Kenai Beluga Unit WBS: Not requested yet Pad: 14-6 KBU 22-6 Well Status: 1.404 MMcf/d @ 116 psi (SCADA 9-17-08) and 21 BWPD (TOW 9-17-08). Objective: Perforate one Beluga sand. Depth and surface pressure to fire guns: 7045' - 7066' (21' net, 20' gun, single run) - 1310 psi Guns to be used: 2-3/8" RTG (Retrievable Tubing Gun) guns loaded 4 SPF 60 degree-phased with TAG-2375-402NTX charges and PX-1 firing head. API target performance: 0.27" entrance hole and 19.21" penetration. Max gun swell in air: 2.575" OD. Procedure• a) Remove well house. b) MI diesel man-lift. c) MIRU Expro E-line service with full lubricator, pump-in sub, flow tubes, and pressure control equipment. d) Hold PJSM. e) PT lubricator to 2000 psi (MPSP+) with KCL H2O or methanol, weather dependent. f) RIH with dummy guns to minimum depth needed for CCL correlation. POOH GR. 2. a) RIH w/ 20' of guns (type shown above, 20' gun, single run). b) Correlate Expro CBL/GR/CCL log depth to open-hole logs. c) SI well long enough to obtain 1310 psi WHP (underbalanced at 40% DD). d) Pull up into position and shoot 7045' - 7066' (OH). Leave well shut in for 15 minutes while POOH. Observe and note pressure build rate over 15 minutes. Open well to flow while continuing to POOH. e) LD spent perf gun and lubricator. RD Expro. Return well to production. Flow test. 3. Produce well to sales. CONTACTS Ken Walsh: 907-283-1311 (w) Jennifer Enos: 713-296-3319 (w) 907-394-3060 (c) 713- 408-3583 (c) Lyndon Ibele: 907-565-3042 (w) Clyde Scott: 713-296-2336 (w) 907-748-2819 (c) KGF Operators: 907-283-1305 • Perf MD Perf ND Formation Bottom Bottom Pressure' 7066 5936 2511 *MFT pressure 40% dd Formation Surface Pressure to Pressure f'ra J~:; ~~ ;~rJAM calc; temp 1507 1312 128 • KBU 22-6 Add perfs - MD Dammeyer 10/1/2008 10:16:45 AM 50-133-20550-00-00 A - 028142 ~: 8T (21' AGL) 5/20/2005 6/3/2005 ~d: 6/9/2005 Tree crossing = 4-3/4" Otis ~ KBU 22-6 Pad 14-6 482' FSL, 1,267' FWL, Sec. 6, T4N, R11W, S.M. Top of Cement (CBL est.) on 3-1/2" @ 5,150' M ~uw-TxoM Conductor 20" K-55 133 ppf Top Bottom MD 0' 130' TVD 0' 130' Surface Casino 13-3/8" L-80 68 ppf BTC Top Bottom MD 0' 1,668' TVD 0' 1,502' Cmt w/ 518 sks of 12.0 ppg, Type 1 cmt to surface 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,529' ND 0' 5,400' Cmt w/ 313 sks of Class G Lead @ 12.5 ppg, & w/ 256 sks of Class G Tail @ 13.5 ppg, Good circulation throughout job - Ceramic flapper valves below each module as follows: Module 7 = 6,566' Module 6 = 7,707' Module 5 = 7,867' Module 4 = 8,445' Module 3 = 8,484' Module 2 = 8,610' Module 1 = NA FISH ~` '~` 1-11/16" X 3-1 /2" Spinner 8,700' *~ '* tagged on (7/2/2007) ' TD PBTD 8,855' MD 8,800' MD 7,725' TVD 7,670' TVD :cape modules placed contol line fires modules 2-7 n control line fires Module 1 e 7 = 6,552'-6,562' (Beluga) e 6 = 7,685'-7,695' (Beluga) e 5 = 7,842'-7,852' (Beluga) e 4 = 8,414'-8,424' (Tyonek) e 3 = 8,455'-8,465' (Tyonek) e 2 = 8,580'-8,590' (Tyonek) e 1 = 8,675'-8,685' (Tyonek) Well Name & Number: Kenai Beluga Unit 22-6 Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,552' - 8,685' (TVD): 5,423' - 7,555' Angle/Perfs: Angle @ KOP and Depth: Dated Completed: 8/3/2005 Completion Fluid: 6% KCL Prepared By: Kevin Skiba Last Revison Date: 10/1/2008 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,837' TVD 0' 7,707' Cmt w/ 1,113 sks Class G @ 15.8 ppg, Good circulation throughout job • ~!~` ~x_: ~: yr,.,~- _ -g ~. ,~ ~~ ~ .. ~` ~ ,. `., '~, F:\LaserFicheiCvrPgs_InsertslRticrofilm Marker.doc 3 ~ ~.~ ~~ DATA SUBMITTAL COMPLIANCE REPORT 10/25/2007 Permit to Drill 2050540 Well Name/No. KENAI BELUGA UNIT 22-06 Operator MARATHON OIL CO MD 8855 TVD 7725 Completion Date 8/3/2005 Completion Status 1-GAS Current Status 1-GAS REQUIRED INFORMATION Mud Log No DATA INFORMATION Types Electric or Other Logs Run: RES, NEU, DEN, Sonic, Caliper, MFT Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name - -_-_ y ___-_ _ D C Las 15177 'Induction/Resistivit Well Cores/Samples Information: Name Interval Start Stop API No. 50-133-20550-00-00 UIC N ~ Samples No Directional Survey Yes ~.--°'"~ (data taken from Logs Portion of Master Well Data Maint Interval Log Log Run OH / Scale Media No Start Stop CH Received Comments 2999 8888 Open 3/28/2007 GR, SP, Poro, Dens, Sonic, MUDLOG las & pdf, Well Report, Dir Survey Sample Set Sent Received Number Comments ADDITIONAL INFORMATION Well Cored? Y Daily History Received? °~~/ N Chips Received? `~ `T7'I~t"- Formation Tops N Analysis ~L1~4-~~ Received? Comments: Compliance Reviewed By: _ Date: __.~ ~~~} ~~"-- ~>~ M Marathon MARATHON Oil Company March 26, 2007 Alaska Oil & Gas Conservation Commission Attn: Howard Okland 333 W. 7~' Avenue Suite 100 Alaska Asset Team Northern Business Unit P.O. Box 3128 Houston, TX 77253 Telephone 713-296-3597 Fax 713-499-4469 FEDERAL EXPRESS Anchorage, AK 99501 RE: Marathon KBU #22-06 -API 50-133-20550-00 ~( CONFIDENTIAL Dear Mr. Okland: Enclosed is one CD containing confidential digital well data for the above referenced well, as described on the attached CD Contents document. Please indicate your receipt of this data by signing below and returning one copy to my attention at the letterhead address or fax to 713-499-4469. Thank you, Courtney McElmoyl Enclosures D Received by: M,, Date: ~,~ `"'~ ~ ~ C~ 7 KBU 22-06 API 50-133-20550-00 CD CONTENTS Confidential Operations Summary: ®KBU 22-6 Operatiais Summary.xls Directional Data: KBU22-6 EOWR.pdf ~kbu22 6_dir_sur.dat f~ KBU22-6 Survey.txt Wireline Data: ®FINAL_KBU 22-6_complete.dpk FINAL_KBU 22-6~lotted.dpk ukbu22-6 MAIN PASS.Ias final_KBU22-6_MFT_2-4complete.dpk - ~final_KBU 22-6_MFT_2-4plotted.dpk ®Final_khu22-6_mftl.dpk 'C~FINALKBU22-6MFT_SUMMARY TABLE.csv Mudlog Data: L"J KBU 22-6.1as ~` KBU22 6 DD,pdf , `KBU22-6_ML_MD.pdf ±_ Y.BU22-6_ML_TVD.pdf ®KBU22-6 dbf ~~..- .~.'. .__. ®KBU22.6_SCL,DBF ®KBU22-6 TVD.DBF ®kbu22-6r. d6F ®kbu22-6. hdr ®KBU22-6.mdx KBU22-6_SCL.MDX KBU22-6_TVD.mdx ®kbu22-6r.mdx Well Report KBU 22-6.doc KBU 22-6 Remarks dat As-built Plat in PDF format. • M Marathon MARATHON. OII COI11pc1n~/ October 18, 2005 Winton Aubert Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Reference: Completion Report 10-407 for permit 205-054 Field: Kenai Gas Field /Beluga / Tyonek Well: KBU 22-6 Dear Mr. Aubert, Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 ~~~ ~ ~ ~. r , . ~~~ ~, ~ ~~0~ Enclosed please find the Well Completion Report with associated attachments for Kenai Beluga Unit well 22-6. 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. Should you require further information, I can be reached at 713-232-9347 / 713-296- 2730, or by a-mail at JRThompson@MarathonOil.com. Sincerely, ~ / ~' James R. Thompson Sr. Completions Engineer Enclosures: Completion Report Directional Survey Operations Summary Wellbore Diagram STATE OF ALASKA ALAS IL AND GAS CONSERVATION COMMI ~.I~~VED pC~ ~ 1 20Q5 WELL COMPLETION OR RECOMPLETION REPORT ~~Q~,~cans.Commiss+~ 1a. Well Status: Oil^ GasO Plugged Abandoned^ 2oAAC 2s.1os GINJ^ WINJ^ WDSPL^ No. of Completions Suspended^ VJAG^ zoAAC 2s.11o Other 1b. Well Class: Af~C~EQCB~ Development Q Exp oratory Service ^ StratigraphicTest^ 2. Operator Name: Marathon Oil Company 5. Date Comp., Susp., or Aband.: 12. Permit to Drill Number: 205-054 3. Address: P. O. Box 3128, Houston, TX 77253 6. Date Spudded: May 20, 2005 13. API Number: 50-133-20550 4a. Location of Well (Governmental Section): Surface: 482' FSL, 1267' FWL, Sec 6. T4N, R11W, S.M. 7. Date TD Reached: June 9, 2005 14. Well Name and Number: Kenai Beluga Unit 22-6 Top of Productive Horizon: 3,461' FSL, 2,533' FWL, Sec. 6, T4N, R11W, S.M. 8. KB Elevation (ft): 87' 15. Field/Pool(s): Kenai Gas Field Total Depth: 3,461' FSL, 2,537' FWL, Sec. 6, T4N, R11W, S.M. 9. Plug Back Depth(MD+ND): 8800' / 7670' Beluga/UpperTyonek Pool 4b. Location of Well (State Base Plane Coordinates): Surface: x- 272,189.59 y- 2,362,527.30 Zone- 4 10. Total Depth (MD + ND): 8855' / 7725' 16. Property Designation: A-028142 TPI: x- 273512.84 y- 2365481.24 Zone- 4 Total Depth: x- 273516.15 y- 2365481.49 Zone- 4 11. Depth Where SSSV Set: N/A 17. Land Use Permit: NA 18. Directional Survey: Yes ~ No 19. Water Depth, if Offshore N/A feet MSL : 20. Thickness of Permafrost: NA 21. Logs Run: Resistivity, Neutron, Density, Sonic, Caliper, MFT 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" 133 K-55 0 130' 0 130' Driven NA NA 13 3/8" 68 L-80 0 1668' 0 1503' 16" 518 sks Class G NA 9 5/8" 40 L-80 0 6529' 0 5400' 12 1/4" 569 sks Class G NA 3 1/2" 9.3 L-80 0 8837' 0 7707' 8 1/2" 1113 sks Class G 95,000 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) 8675-8685; 8580-8590;8455-8465; 8414-8424; 7842-7852; 768 3 1/2" 8837' N/A 7695;6552-6562 ND (RKB) 7545-7555; 7450-7460; 7325-7335; 7284-7294; 6712-6722; 6555- 6565; 5423-5433 25. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED Module 1:8675-8685' Frac: 21754 Ibs prop (Ottawa & Flex sand) Module 2: 8580-8590' Frac: 38406 Ibs prop (Ottawa & Flex Sand) Module 3: 8455-8465' Frac: 11041 Ibs prop (Ottawa & Flex Sand) Module 4: 8414-8424' Frac: 26943 Ibs prop (Ottawa 8~ Flex Sand) Module 5: 7842-7852' Frac: 27113 Ibs prop (Ottawa & Flex Sand) Module 6: 7685-7695' Frac: 23371 Ibs prop (Ottawa & Flex Sand) Module 7: 6552-6562' Frac: 30874 Ibs prop (Ottawa & Flex Sand) 26. PRODUCTION TEST Date First Production: August 9, 2005 Method of Operation (Flowing, gas lift, etc.): FlOwin Date of Test: 8/13/2005 Hours Tested: 24 Production for Test Period Oil-Bbl: NA Gas-MCF: 2600 Water-Bbl: 226 Choke Size: Open Gas-Oil Ratio: NA Flow Tubing Press. ggp Casing Press: 0 Calculated 24-Hour Rate ~ Oil-Bbl: NA Gas-MCF: 2600 Water-Bbl: 226 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'. ---- °- GGIN~t~'"?I~~ ; None ~-~ .I~~ ,~ ~ ~r ~Q~rJ KBU 22-6 Alaska_Cmpl_10-407.x16 CONTINUED ON REVERSE 10/1812005 3:40 PM 28. GEOLOGIC MARKERS 29. FORMATION TESTS NAME MD TVD Include and briefly summ est results. List intervals tested, and attach detailed supporting data as necessary. If no tests were conducted, state "None". Middle Beluga 6520 5391 Zone Top MD Top TVD Pressure Tyonek 8386 7256 Beluga M1 6540 5411 2310 Beluga L8 7680 6550 2822 Beluga L9 7841 6711 3108 Tyonek 72-8 8420 7290 2115 Tyonek 73-1 8458 7328 3361 Tyopnek 73-1 8584 7454 3614 Tyonek 75-8 8680 7550 2883 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: ~ Q Phone:713-296-2730 Date: 10/18/2005 J INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item 1a: Classification of Service wells: Gas Injection, Water Injection, Water-Alternating-Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b: TPI (Top of Producing Interval). Item 8: The Kelly Bushing elevation in feet above mean low low water. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 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". Form 10-407 Revised 12/2003 KBU 22-6 Alaska_Cmpl_10-407.x1s 10/18/2005 3:45 PM • KBU 22-6 Directional Survey . Report Date: 23-Jun-2005 _ - _- .__ -- -- Client Marathon Oil Company i ~ _ -- - - - f ~ l _ 1 Field ~ Kenai Gas Field _ _- ' _ _ SWcture /Slot Pad 14-6 /Slot #KBU22 - _ ~ - - Well: KBU22-6 - _ _ - __ ~ _ __ -- I- _- - _ Borehole: KBU22-6 -- I Well ath Name I MWD <0-8855 > ~ y _ Gnd Coordmate S stem: I Alaska Sfate Plane, Zone 4 _ -~ _ __+ I __ _ r - -_ _ - - _ -- ~ I _ Location LaULong: N60 27 38.8152, W 151 15 43.5803 _ i, i - -_ - _ __ _- r ~ _ i- _ - -- Location Grid N/E Y/X: 2362527.3000 ft, 272189.5900 ft _ _ Grid Convergence Angle: -1.10 deg T ~ I - __ , _ `- ~ ~-- --- -- Grid Scale Factor 0.999960 ', y _ P _ - _ _ - _ ---- - _ - - -- --- - Surve /DLS Com utation Method: I Minimum Curvature _ 23.08 deg A 1 h - _ __ - i- Vertical Section Origin: O.OON, 0.00E ' _~ - --_ - __ ~ -. !...----. -- --._.. --- -- - -- --- ---Y - ---- --- .. - J B -- - - - - 9 ( veI ] ~ _ __ _ __ _ _ - - _-- - -- - - -e mean sea le - _ + __ ___ TVD Reference Elevation: i RK Datum #2 87.0 ft abov - Sea Bed /Ground Level Elevation: 0.00 ft to mean sea level I, Magnetic Declination. 19.99 deg ~ ~, __ ._ _ r _ - - - Total Field Strength: '.55369.45 ' i Magnetic Dip: 73 34 deg 1 -- ' - - - De cl i p L ' ~ ~ _ _ _ r -~- - - - - - --- -- - netic Declination Model I BGS Global Geoma netic Model 1945.0 _ g _ g [ 2005.0] ~ North Reference True I ~ I ~ ~ I Total Corr Mag North to True North: 19.99 deg ~ 1 , - _. _ Local Coordinates Referenced To: lot .._ __- --- _._.... __- T- _..___-.- _ -- - _ - - - --- ~ d - ~ _ _ I Gn Coordinates Geographic Coordinates --+ - - MD Inc ~_ Azi TVD ND SS ( ) - VS N/-S E/-W DLS Northing Easting Latitude Longitude ( _ - -- Comment (ft) (deg) (deg) (ft) (ft) (ft) (ft) (ft) -- (deg/100ft) a _ (ft) (ft) 0.00 0.00 0.00 0.00 -87.00 0.00 0.00 0.00 0.00 2362527.30 272189.59 N60 27 38.8152 W151 15 43 5803 __ ; ~ ___ 1 20.OOOin 130 1 0.13 294.30 130.00 43.00 0.00 0.06 -0.14 0.10 2362527.36 272189.45 j N60 27 38.8158 W 151 15 43.5831 Conductor 195 0.201 294.30 195.00 108.00 0.01 0.14 -0.31 0.10 2362527.45 272189.28 ~ N60 27 38.8166 W 151 15 43.5865 255 -- _0.70 338.10 __ 255.00 168.00 __ 0.27 0.52 _ -0.54 0.95 2362527.83 272189.06 _N602738.8203 W1511543.5912 _____ 316 2.50 4.10 315.97 228.97 1.79 2.20 -0.59 3.11 2362529.51 272189.05 N60 27 38.8368 W 151 15 43.5920 ~ 375 ------ 6.30 11.80 374.79 - 287.79 6.1 B ----- _ 6.65 0.17 ----- 6.50 2362533.95 272189.89 -- N60 27 38.8807 W 151 15 43.5770 _ - 436 7.40 12.601 _ _ 435.35 348.35 13.33 13.76 _ 1.72 1.81 __ 2362541.02 272191.58 N60 27 38.9507 W 151 15 43.5460 496 8.20 14.10 494.80 407.80 21.36 21.68 3.62 1.37 2 362548.90 272193.63 N60 27 39.0286 W151 15 43.5081 I _ ___ 556 9.10 17.30 554.11 467.11 _ 30.31 30.36 ~ _ 6.08 _ __ 1.70 _ _ 2362557.53 272196.25 N60 27 39.1141 W151 15 43.4592 ~ _ 618 10.20 ___ 21.60 ___ 615.24 528.24 40.67 _40.14 ~ __ ___ 9.55 2.12 2362567.25 272199.91 N60 27 39.2105 W 151 15 43.3898 ~ _ 678 11.40 23.80 674.17 587.17 51.91 50.51 13.90 2.11 2362577.53 272204.46 N60 27 39.3126 W151 15 43.3031 739 - 13 20 26 00 733 77 646 77 64 90 62 28 19 39 --- -- 05 3 2362589 20 272210 17 N60 27 39 4285 W151 15 43 1937 . . . . . . . . . . . . 801 15.50 28.20 793.83 706.83 80.22 75.95 26.41 3.81 2362602.73 272217.45 N60 27 39.5631 W151 15 43.0537 865 18.40, 28.30 855.04 768.04 98.80 92.38 35.24 4.53 2362618.99 272226.59 N60 27 39.7250 W151 15 42.8776 927 21.60 27.40 913.30 826.30 119.93 111.13 45.13 5.18 2362637.54 272236.84 N60 27 39.9096 W 151 15 42.6803 990 23.90 __ ___ r 25.60 971.39 884.39 144.25 _ 132.94 _ 55.98 3.81 _ 2362659.14 272248.11 N602740.1244 W151 1542.4639__ _ __ __ 1053 __ 26.80 24.10 1028.32 941.32 171.20 157.42 _ 67.30 4.71 2362683.40 272259.89 I N60 27 40.3654 W_151 15 42.2382 1116 29.60 _ 24.70 ~ 1083.84 996.84 200.96 _ 184.53 79.61 4.47 2362710.26 272272.71 N60 27 40.6324 W t 51 15 41.9929 __ _ 1179 32.70 27.30 1137.75 1050.75 233.50 213.79 93.92 5.36 2362739.24 272287.58 N60 27 40.9206 W 151 15 41.7075 1241 35.90 _ 28.90 1188.96 1101.96 268.29 244.60 110.39 5.36 2362769.73 272304.64 N60 27 41.2240 W 151 15 41.3790 __ __ _ _ 1303 39.30 29.10 1238.08 1151.08 305.91 277.68 128.73 __ _ 5.49 __ 2362802.45 272323.61 N60 27 41.5497 W 151 15 41.0133 1365 42.20 27.70 1285.04 1198.04 346.21 313.28 147.96 4.90 2362837.67 272343.52 N60 27 41.9003 W 15_1 15 40.629_7__ _ _ __ 1429 43.90 _ 26.10 1331.81 1244.81 389.79 352.24 167.72 3.16 __ _ 2362876.25 272364.02 N60 27 42.2840 W 151 15 40.2357 1493 43.80 - _ 25.20 1377.97 1290.97 434.09 _ 392.21 186.91 0.99 2362915.84 272383.97 N60 27 42.6776 W151 15 39.8530 1555 -- 44.30 24.20 - 1422.53 1335.53 477.18 431.37 -- 204.92 1.38 2362954.65 272402.73 N_60 27 43.0633 W 151 15 39.4938 1616 _ 45.80 _ 22.80 1465.62 1378.62 520.34 470.96 222.13 _ 2.95 __ 2362993.90 272420.69 N60 27 43.4532 W151 15 39.1506 -- ~ 13 3/bin 1668 44.27 23.28 1502.37 1415.37 557.13 504.82 236.52 3.01 2363027.47 272435.73 _ N60 27 43.7866 W151 15 38.8635 Casing 1691 _ __ 43.60 23.50 t 518.93 1431.93 _ _ 573.09 519.47 __ ~ ~ 242.86 3.01 2363042.00 272442.35 N60 27 43.9308 W 151 15 38.7371 1753 41.90 24.60 1564.46 1477.46 615.17 557.90 260.00 2.99 2363080.09 272460.22 N60 27 44.3093 W 151 15 38.3952 1816 41.40 22.80 1611.53 1524.53 657.03 596.23 _ _ 276.83 2.06 2363118.09 272477.79 N60 27 44.6868 W 151 15 38.0596_ _ ___ 1879 44.00 22.10 1657.83 1570.83 699.75 _ 635.72 293.14 4.20 __ __ 2363157.25 272494.85 N60 27 45.0756 W151 t5 37.7343 1943 42.80 22.10 1704.33 1617.33 743.72 676.46 309.68 1.88 2363197.67 272512.17 N60 27 45.4769 W151 15 37_.4044___ _ _ 2006 42.40 22.50 1750.70 _ 1663.70 786.35 _ 715.91 325.86 ______ 0.77 _ 2363236.81 272529.10 N60 27 45.8654 W151 15 37.0817 2069 45.20 23.30 1796.17 1709.17 829.95 756.07 342.84 4.53 2363276.63 272546.84 N60 27 46.2609 W 151 15 36.7431 ~ 2132 45.20 _ 22.70 1840.56 1753.56 _ 874.66 797.22 _ 360.30 0.68 2363317.44 272565.09 ~ N60 27 46.6661 W 151 15 36.3948 2195 _ 44.70 22.90 1885.15 1798.15 919.17 638.25 __ _ 377.55 0.82 2363358.13 272583.12 N60 27 47.0702 W 151 15 36.0508 2258 _ 44.40 21.90 _ 1930.05 1843.05 963.36 879.11 _ _ 394.39 1.21 2363398.66 272600.74 N60 27 47.4726 W 151 15 35.7149 2322 _ 43.90 21.40 1975.97 1888.97 _ _ 1007.92 ~ 920.55 j - -- 410.84 0.95 2363439.76 272617.98 N60 27 47.8806 W 151 15 35.3868 2385; 44.00 21.80 _ _ 2021.32 1934.32 1051.63 961.20 426.94 0.47 2363480.10 272634.85 N60 27 48.2809 W151 15 35.0658 _ 2448 44.70 _ 22.80 2066.37 _ 1979.37 1095.66 1001.94 443.65 1.57 2363520.51 272652.34 N60 27 48.6822 W 151 15 34.7325 2510 _ 44.30 23.00 __ 2110.60 2023.60 1139.12 1041.97 __ _ _ 460.5 16 0.68 2363560.21 272670.01 _ _ _ N60 27 49.0764 W 151 15 34.3952 -_ _ 2574 44.60 22.60 2156.28' _ 2069.28 1183.94 1083.291 _ 477.931 ___ 0.64 2363601.19 272688.17 N60 27 49.4833 W 151 1534.0488 2699 46.10 22.50 _ 2244.13 2157.13 ~ _ 1272.86 1165.42 _ 512.03' 1.20 2363682.64 272723.83 N60 27 50.2920 W 151 15 33.3686 2825 45.00 22.60 j 2332.36 2245.36 1362.80 1248.48 546.52 i 0.87 - r 2363765.03 272759.91 ---- 101 W 151 t 5 32.6807 X60 27 51.1 _ 2952 44.10 _ 22.70 2422.87 _ _ __ 2335.87 I __ 1451.89 13_30.711 580.83 0.71 ; 2363846.58 272795.79 ;. _ N60 27 51.9198 W 151 15 31.9963 __ 3076 45.80 22.30 ii 2510 62 2423.62 1539.49 1411.64 614 35 __ 1.39 2363926.85 272830 85 I N60 27 52.7168 W 151 15 31 3277 3202 45.50 22.50 2598 70 2511.70 1629.58 1494.94 648 68 0.26 2364009.47 272866 77 N60 27 53.5371 W 151 15 30 6429 3328 43.30 22.90 2688 72 2601.72 _ 1717.73 1576.27 _ 682 70 1.76 2364090.13 272902 34 N60 27 54.3380 W151 15 29 9644 3457 45.70 23.30 2780.72 2693.72 1808.14 1 1659.43 718.17 1.87 2364172.59 272939.40 N60 27 55.1569 W 151 15 29 2568 i _ _ 3581 45.10 23.30 2867.79 2780.79 1896.43 1740.52 ~ 753.10 0.48 2364252.99 272975.87 N60 27 55.9555 W 151 15 28 5601 KBU 22-6 1 of 2 10/20/2005 1:32 PM KBU 22-6 Directional Survey . 3706 43.10 ~ ~ 1820.32 787 71 1.61 2364332.11 273012.00 ; N60 27 56.7413 W 151 15 27.8697 38331 44.20 23.00 3049 44 2962.44 I ~ -- 2071 07 I 19 00.83 822 38~ 0.93 2364411.94 273048.21 ; N60 27 57.5342 W151 15 27.1781 44.90 ' 2 .40; 313781 3050.81 _ _ 1981.37 855 24 1.07 2158.01 --- ~ - - - 2364491.83 273082 60 N60 27 58 3273 W 151 15 26.5227 - - 4082 44.40 , 2 .80 _ _ _ 2063.05 887 57 I 0 46 x2364572.87 273116 50 i - N 957206 1316 W 151 15 25.8776 ~ ~--~-- -- 4208 44 40 ~ , ? 3316.76 22.10 336113 ~ 1 T _3229.76 2144.82 2334.00 ~ 920 53 0 17 i ~ 23 .30 ~ _ 2364653 99 273151 O t 2364693.67 273168 34 N60 27 59 9368 W 151 15 25.2202 -_ N60 28 0 3308 W 151 15 24.8896 4333' - _ 43 I 0 23.40 ~ 38 - 9 2364733.42 273186 25 N60 28 0 7256 W151 15 24.5477 -- 4396 42.10 _.. ~ _- 23.80 3452.87 1 3365.87 0 971.361 2 2463.67 2264. ~~, 2364772 28 273204 11 N60 28 1 1115 W 151 15 24.2062 '. _ - 44601 40.20 - 23.80 j 3501.05 , 3414.06 + -- -- t_._.- - 2505.76 2302.63 988.35 i 2.971 r - - 2364810.47 273221.84 - .-.-- - N60 28 1.4910 W 151 15 23.8672 4523 ~ 38 10 23.60 ~ 3549.91 3462.91 ~ 2545 55 . 2339.05 1004 34 3 34 2364846.58 273238.52 , N60 28 1.8496 W 151 15 23 5482 _ 45851 37 10 - - - 23.00' 3599.03 3512.031 -* - 2583 38; 2373.79 1019 30 1 72 - - - 2364881.02 273254.15 j --- N60 28 2.1917 W 151 15 23.2497 ~-- - ~ - 4650 36.20 - 22.50 3651.18 3564.18 - r - -- 2622 17 ; 2409.57 1034.31 ' 1.46 _ 2364916.51 273269.84 I N60 28 2.5441 W 151 15 22.9503 47121 35.301 22.20: 3701.50 3614.50 ~ 2658.39: 2443.08 1048 08' 1.4812364949.74 273284.25 ~, N60 478282 0 W 151 15 22.6755 4776!. 34.00' 21.70 3754.141 3667.141 2694.77 2476.82 1061 69'. 2.08'.2364983.22 273298.50 , N60 28 3.2063 W 151 15 22.4041 2120 3806 651 3719 65 2729.58 2509.23 1074.42 1.49 2365015 37 273311.85 N60 28 3 5254 W 151 15 22.1500 4903 i 32 20; 21.70 3860.53 3773 53 2764.09' 2541.3? 1087.05 1 47 :2365047.26 273325.09 N60 28 3 8419 W 151 15 21.8982 ' - 3826.40 j - _ 2796.471 2571 47 1099.00 _-- 2 26;.2365077.13 273337.62 ~' N60 28 4.1384 W 151 15 21 6597 ~. 5027 29 90; 22.30 3966.90 3879.90 ! 2827.80 ~ 2600.53 1110 70' 1 56' 2365105.96 273349.88 ~, N60 28 4.4245 W 151 15 21 4262 5090 28.00 ~': 23.60 40 22.031 3935 03' ~ 2858.29 2628.61 1122.59' 3.18 2365133.81 273362.29 1 N60 28 4.7011 W 151 15 21.1891 5152 26 20' . 24.50 4077.22 ~ 2886.52 i 2654.41 1134 09 2 98 ~ 2365159.37 273374.29 --- N60 28 4 9551 W 151 15 20.9597 ' - 1 0 -- - --- f - +- - - - ~~ ~ _-~- 5215 2430 : 25.30 4134.19 404 .19 2913.38, 2678.78 1145.40, 3 06:2365183.53 273386.06 N60 28 5.1951 W151 15 20.7341 5278 23 t 0 _ 25.10 4191.88 4104.88' 2938.69 2701.70 1156 18 ~ 1 91 2365206.23 273397.28 N60 28 5.4207 W 151 15 20.5189 ~ ~ --~ -- __-. 2365228.07 273407.84 1, I .._. -._ _.... N60 28 5.6378 W 151 15 20 3166 5404 I 21.50 t _. 23.30 4308 49 4221.50 2986.38 ~ 2745.191 1175.79 126 2365249.33 273417.72 N60 2 85 48 90 W 151 15 20 1278 __.. - -- { -r - ~ --- - ---- 5468 20.60 23.00 ~ 4368.22 4281.22 3009.37_ 2766.3 1184.82 1.42 2365270.29 273427.16 N60 28 6.0571 W 151 15 19 9475 L 4427.39 4340.39 3031.02 2786.29 ~ 1193.18 1.62 2365290.10 273435.89 N60 28 6.2538 W 151 15 19.7807 ', 5594 18.70 - 22.60' 4486.90 4399.90 3051.69 2805.39 1201.09 1.43 2365309.03 273444.17 _ - N60286.4418 W151 1519.6230 r 5657 18.10 21.50 4546.68 4459.68 3071.57 2823.821 1208.56 1.10 2365327.32 273451.99 N60 28 6.6233 W151 15 19.4740 ~ _ 5720 16 80 22.10. 4606.78 4519.78 3090.45 2841.36 1215.57 1_ 2.081 2365344.72 273459.33 N60 28 6.7961 W151 15 19.3341 5784 15.90 23.20 j 4668.19 4581.19 3108.47 2857.9 9 52221 0 - 1.49 2365361.21 273466.58 N60 28 6.9598 W 151 15 19.1957 - -1------ 5847 __- 15.60 24.10 4728.82 __.- 4641.82 3125.57 - 2873.65] - 1229.36 - 0.61 ---- 2365376.74 273473.74 N60 28 7.1141 W151 15 19.0589 1 _-.. 15.60 _ 1 .60 4789.50 4 0 3142.511 _ - 2 1 1236.21 ---- 0.21 2365392.10 273480.89 - N60 28 7.2667 W 151 15 18 9222 _ - ' ~ ~ 0 1242.78 ~ ~-~~-- 0.65 ~ 2365407.07 273487 74 ----- N60 28 7.4153 W 151 15 18 7912 ' - T -~. - -- - 034 ~ 14.201 24.60 -- 4909.25 4822.25 3174.70 ~ 29 18.62 1249.17 1.69 2365421.32 273494.41 N60 28 7.5569 W 151 15 18.6637 _ 60971 __ _ 11.50 T30 4970.66 4883.66 __ 3188.711 2931.46 _ _ 1254.77 4.36 2365434.05 273500.25 N60 28 7.6833 W 151 1518.5519 __ ~l 5032.66 4945.66 3199.84 2941.92 1258.63 4.33 2365444.43 273504.31 N60 28 7.7863 W 151 15 18 4750 6223 8.70 13.40 5095.00 5008.00 3208.85 2950.67 1261.08 2.13 2365453.13 273506.93 N60 28 7.8725 W 151 15_18 4260 1 ~~ 6 --- 6.10 ~ 12.10 5157.55 - - 5070.55 3216.30 2958.05 1262.76 2.55 2365460.48 273508.75 N60 28 7.9451 W 151 15 18.3925 -- ----- 6349 5.00 9.10' 5220.25 5133.25 3222.25 - 2964.03 1263.90 --- - 1.81 2365466.44 273510.00 N60 28 8.0041 W151 15 18.3699 I 6475 -- - 4.70 - 10.60 5345.80 - - - 5258.80 3232.62 2974.53 _ - , 1265.71 0.26 -- --- 2365476.90 273512.02 - - N60288.1074 W151 1518.3336 --- -- ~ ~ 9 5/bin 6528 4.87 8.7511 5398.611 5311.61 3236.92 2978.881 1266.45 0.43 2365481.24 273512.84 N60 28 8.1503 W151 15 18.3188 Casing 6569 5.00 7.40 ~ 5439.461 5352.46 3240.32 2982.37 i 1266.95 j 0.43 2365484.72 273513.41 N60 28 8.1847 W151 15 18.3089 ~ _ 6694 _ 3.30 _ ~ _ __20.40 ~ 5564.13 5477.13 3249.16 _ __ 2991.15' 1268.91 ' 1.55 2365493.45 273515.53 __ N60 28 8.2711 W 151 15 18.2699 _ ! _ -- 6822 1.20 1 28.50'1 5692 03 5605.03 3254.18 2995.78 } 1270.83 1.66 2365498.05 273517.54 N60 28 8.3167 W 151 15 18.2315 6947 ___ 1.20 30.70 i 5817.00 5730.00 3256.78 2998.0 5 1272.12 0.04 2365500.30 273518.88 N60 28 8.3391 _W 151 15 18.2057 7072 110 1 19.70 ] 5941.97 5854.97 3259.27 _ 3000.31 1273.19 _ 0.19 2365502.53 273519.99 N60 28 8.3613 W 151 15 18.1843 ~ 7198 __ 0.80 _ __ _ 2 80 90 6067.97 5980.97 32 95 60 3000.68 1273.18 1.50 2365502.90 273519.98 _ -_ N60 28 8.3650 W151 15 18.1846 7324 0.80 219.10 6193.95 6106.95 3257.88 2999.23 1272.20 0.11 2365501.47 273518.97 N60 28 8.3507 W 151 15 18.2042 7450 0.80 206.60 6319.94 6232.94 3256.16 2997.76 1271.25 0.14 2365500.02 273518.00 N60 28 8.3362 W 151 15 18.2231 7577 0.70 221.20 ~ 6446.93 6359.93 3254.54 2996.38 1270.34 0.17 2365498.66 273517.06 N60 28 8.3227 W 151 15 18.2412 7699 0.50 218.10 6568.93 6481.93 3253.32 2995.40 1269.52 0.17 2365497.69 273516.23 N60 28 8.3130 W151 15 18.2576 7828 0.80 218.70 6697.92 6610.92 3251.91 _ 2994.26 1268.61 0.23 2365496.57 273515.29 N60 28 8.3017 W151 15 18.2757 --- 7954 0.70 - 187.70 6823.91 6736.91 3250.32 2992.80 1267.96 0.33 273514.61 2365495.13 N60 28 8.2875 W151 15 182888 8078 1 00 __ 185 70 6947 89 6860 89 3248 55 2990 98 1267 75 0 24 _ _ 2365493 31 273514 37 2695 W151 15 18.2929 ~ N60 28 8 _ . . . - -- . . . - . . . . _ _ . - - 8206 0.90 1 182.00 7075.88 0 6988.88 3246.55 2988.86 1267.60 0.09 2365491.19 273514.18 N60 28 8.2486 W151 15.18.2958__ 8332 _ 0.90 _ 1 186.1 7201.86 _ 7114.86 3244.68 2986.89 __ 1267.46 0.05 2365489.22 273514.01 N60 28 8.2292 W151 15 18.2986 8456 0.80 176.501 7325.85 7238.85 3242.97 2985.06 1267.41 0.14 2365487.39 273513.92 N60 28 8.2111 W151 15 18.2996 8585 0.80 _ 168.70 7454.83 7367.83 3241.43 298328 1267.64 0.08 2365485.61 273514.12 N60 28 8.1936 W 151 15 18 2950 _ ___ _ ~ 8646 1.00 148.90 7515.83 7428.83 3240.76 2982.40 1268.00 0.60 2365484.73 273514.46 N60 28 8.1850 W151 15 18 2879 8773 __ 1.00 152.40 7642.81 7555.81 3239.4 it 2980.47 1269.09 0.05 _ 2365482.77 273515.51 N60 28 8.1660 W 151 15 18 2662 ; _ _ 1 ~ Projection to ' TD, 3 1/tin 8855 1.00 152.40 7724.79 - ---- 7637.79 3238.50 2979.20 1 1269.75 0.00 2365481.49 273516.15 N60 28 8.1535 W 151 15 18.2530 Liner --- - 1 - ~ - ---- _ . _ --- ' I KBU 22-6 2 of 2 10/20/2005 1:32 PM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Name: Event Date Event Report Date _From - To ~' 5/17/2005 Event 5/17/2005 00:00 - 06:00 5/18/2005 06:00 - 12:00 12:00 - 18:00 18:00 - 00:00 00:00 - 06:00 5/19/2005 06:00 - 12:00 12:00 - 18:00 18:00 - 00:00 00:00 - 04:00 04:00 - 06:00 5/20/2005 06:00 - 12:00 12:00 - 16:00 16:00 - 00:00 00:00 - 06:00 5/21 /2005 06:00 - 07:00 KENAI BELUGA UNIT 22-6 KENAI BELUGA UNIT 22-6 Hours ~ Code Code Phase ~- ~ - -~ _ 6.00 ~ RURD_ RIG_ ~ RDMO 6.00 RURD_ RIG_ MIRU 6.00 RURD_ RIG_ MIRU 6.00 RURD_ RIG_ MIRU 6.00 RURD_ RIG_ MIRU 6.00 RURD_ RIG_ MIRU 6.00 RURD_ RIG_ MIRU 6.00 RURD_ EOIP MIRU 4.00 RURD_ EOIP MIRU 2.00 NUND BOPE MIRU 6.00 NUND BOPE MIRU 4.00 NUND BOPE MIRU 8.00 RURD_ EOIP MIRU 6.00 RURD_ EOIP MIRU 1.00 TEST_ BOPE SURDRL 07:00 - 12:00 5.00 RURD_ EOIP SURDRL 12:00 - 16:00 4.00 RURD_ EOIP SURDRL 16:00 - 19:00 3.00 PULD_ DP_ SURDRL Page 1 of 9 ~ Spud Date: 5/20/2005 ___ __ Event Type --/-- Objective SideTrack- --/ - Description of Operations - -- - ___- ORIGINAL DRILLING --/-- Development-Gas OH --/-- Accept::rig from rig maintenance ~ OO:OOhrs 05/17/2005. PJSM. Install new fall arrest on crown. Install derrick climber counter weight. R/D water line and secure for move. Install new jacks and ramp locks on shaker. R/D handrails on pits and pump room. Install clamps on mud pump hydraulic line. Prep boiler house and generator house for move. OH --/-- PJSM prior to rig move. Load out and move generator house, boiler house, pump and pit room. R/D camp and prep welding shop. Load matting boards on trailers. Load out and move carrier, change house, and camp. PJSM. Set sub, mud boat, carrier, pump and pit rooms, generator house, boiler house, water tank, hanson tank, cuttings tank, MI centrifudge van, cement silo. Raise sub. Suck pits together. Prep derrick f/raising. R/U camp. Install rails on roofs. Run service and electrical lines. Lay water lines. PJSM for crane lifts. Set and R/U diesel tank, derrick house, out riggers, front windwalls, dog house and choke house. Raise derrick, unload trailers, set convex. Finish loading trailers at NS#1. PJSM prior to crane work. Crane in stairs, flowline, panic line, wind walls, back landing and gas buster. Pull wires. R/U drillers console and boot up PLC. Install teflon on shakers and R/U dresser sleeves. Prep derrick to scope up. OH --/-- PJSM:Telescope derrick up. R/U service lines and communication. R/U U-tube and choke lines to gas buster, Install float in trip tank and pump. Remove worn hyd hoses on #1 pump. Hook up guide wires. PJSM:Install trip tank and cellar grating. Cylinder socks, R/U beaver slide, Catwalk, Conex stairs, M/U lower derrick mud and cmt lines. Set in epoch office, #3 mud pump complex, R/U mud lines, Electric and service lines, Carrier exhaust, Unload trailers, Change out worn hydraulic hoses on #1 mud pump. PJSM:Make final cut on 20" conductor pipe, Install starter head and test seals to 1200 psi. for 10 min. Install hydraulic pulsation dampner on #2 mud pump, Fill carrier hydraulic reservoir. Repair MI van and Epoch power cords, R/U welding shop, Choke hose and shuck, Derrick cylinder socks. PJSM:CIean sand out of pits and pump room. Change out nipple on #1 pump swab, R/U mud manifold on rig floor. Spot', dsiverter stack acid orientate. Mount oiler for bridge crane and plumb oiler for same. PJSM: Nipple up diverter stack OH --/-- PJSM: N/U Diveter bell nipple, flow line, low torque, bleeder trip,!'tank lines, knife valve, and koomey lines, clean sand out of pits; install top drive control panel, Trouble shoot plc problem, fix wiring problem. PJSM:N/U diverter line and anchor down, turnbuckles, trip tank flowline, 2" Hi Psi drain valve on 20". Power up accumalator and function test annular and knive valve. PJSM:R/U geolograph and geronimo lines. Monkey board, purge hydraulic`systems on mud pumps and carrier, mix spud mud, unload and-stage top drive equipment, PJSM: R/U top drive torque tube, R/U baker and MI trailers. PJSM: Install turnbuckles and adjust torque tube, Inspect tugger lines and anchors, P/U and hang top drive install slide, install drive line on #2 motor to Benison while prepare for diverter test with AOGCC. OH --l-- PJSM: Function test diverter, Witnessed by Lew Grimaldi with AOGC. Accept rig for well Ca? 0600 hrs. 5/20/2005 PJSM:Change out continental valve on top drive, Install actuator and IBOP valve,Function test mud pumps, Set pipe racks. mix spud mud PJSM: Rig up tongs, Spinners, Slips, and Miscellaneous rotary tools, Set mouse hole, Test pumps to 1000 psi. Rack 5"drill pipe, check crown-0-matic, PJSM:Pick up make up and stand back 30 stds. of 5" drill pipe • • Printed: 10/20/2005 11:30:36 AM Marathon Oil Company Operations Summary Report -Per Weli Legal Well Name: KENAI BELUGA UNIT 22-6 Common Well Name: KENAI BELUGA UNIT 22-6 -- Event Date Event ' Sul_, Report Date .From - To __ _ ! Hours .Code _ !Code phase 19:00 - 20:30 1.50 PULD_ BHA_ SURDRL 20:30 - 22:00 1.50 CLNOU CSG_ SURDRL 22:00 - 22:30 0.50 DRILL_ ROT_ SURDRL 22:30 - 23:00 0.50 CIRC_ MUD SURDRL 23:00 - 02:00 3.00 PULD_ BHA_ SURDRL 02:00 - 06:00 4.00 DRILL_ ROT_ SURDRL 5/22/2005 06:00 - 01:30 19.50 DRILL_ ROT_ SURDRL 01:30 - 02:30 1.00 CIRC_ MUD_ SURDRL 02:30 - 04:30 2.00 TRIP_ WIPR SURDRL 04:30 - 05:00 0.50 CLEAN_ RIG_ SURDRL 05:00 - 06:00 1.00 TRIP_ WIPR SURDRL 5/23/2005 06:00 - 08:00 2.00 CIRC_ MUD_ SURDRL 08:00 - 10:00 2.00 TRIP_ DP_ SURDRL 10:00 - 12:00 2.00 PULD_ BHA_ SURDRL 12:00 - 14:00 2.00 RURD_ CSG_ SURCSG 14:00 - 19:00 5.00 RUN CSG SURCSG 19:00 - 20:30 1.50 RURD_ CSG_ SURCSG 20:30 - 22:00 1.50 TRIP_ ?EOIP SURCSG 22:00 - 23:00 1.00 CIRC_ MUD SURCSG 23:00 - 03:30 4.50 PUMP_ CMT_ SURCSG 03:30 - 05:00 1.50 TRIP_ DP_ SURCSG 05;00 - 06:00 1.00 CLEAN_ RIG_ SURCSG 5/24/2005 06:00 - 08:00 2.00 NUND BOPE SURCSG 08:00 - 09:00 1.00 CUT_ CSG_ SURCSG 09:00 - 13:30 4.50 NUND BOPE SURCSG 13:30 - 15:00 1.50 NUND BOPE SURCSG 15:00 - 17:30 2.501 NUND WLHD SURCSG 17:30 - 23:00 5.50 NUND BOPE SURCSG 23;00 - 00:00 1.00 TEST_ BOPS SURCSG 00:00 - 04:30 4.50 TEST BOPE SURCSG 04:30 - 05:30 1.00 RURD_ OTHR SURCSG 05:30 - 06:00 0.50 TEST_ CSG_ SURCSG 5/25/2005 06:00 - 07:00 1.00 RURD_ OTHR SURCSG 07;00 - 15:00 8.00 PULD_ DP_ SURCSG 15:00 - 18:00 3.00 PULD_ BHA_ SURCSG Event Type --I--'Objective SideTrack -, -- Description of Operations Page 2 of 9 Spud Date: 5/20/2005 PJSM: Pick up 16" Bit and Bha. Spud well ~ 2030 hrs, 05/20/2005, Tag ~ 35' Clean out 20" to 130' Drill 16" hole F/130'to i83' (ART=..4hrs.) Circ wellbore clean PJSM:POH to Motor and M/U MWD and orientate. same ' Drill ahead 16" hole drdntl F/183' to 285'. ART= 0 AST= 2.1 hrs OH --/-- Drill ahead 16" hole drentl F/185' to 1680'. ART= 2.9hrs AST=9.6hrs. No gain, loss, drag, torque (Circ 40 bbl. hi-vis sweep 75% increase in solids returns. C~ 1550') Circ 40 bbl.Hi-Vis sweep around (30% increase in solids) PJSM: POOH to 20" shoe. No drag or torque. SLM. No correction. Clean rig floor PJSM, TIH. No do drag, no gain /loss. OH --/-- Circ 40 bbl. Hi-Vis sweep, Check well, mix and pump slug PJSM: POOH to Bha #1 PJSM: Lay down and stand back Bha #1 PJSM:Rig up 13 3/8" csg. tools. PJSM, Commence RIH 13 3/8 68# L-80 csg, total 38 jts. Thread lock shoe track (Shoe, 1 jt, float collar), check floats. Shoe 1668 ft, float collar 1624 ft. No do drag /gain /loss /fill. Correct displacement. Break circ, no pkf, 100% returns. R/D Weatherford csg tools MU stab in Adapter and Centralizer. RIH on 5" DP inner string sting into stab in float collar, set full wt of string C~ 1624'. Circ @ 307 gpm; 500 psi. annulus X 2 PJSM:Rig BJ and Rig pumped 40 bbl.Mud Clean II Preflush. Pump 2 bbl H2o, test liries 2000 psi Mix /pump 518 sks (229 bbls) type 1, 12ppg, cmt. Cmt to surface. Displace with 2 bbls H2o, 21.9 bbls mud. Approx 30 bbls cmt returns to surface Check floats, sting out, equalize 5 bbls slurry. Pull 5 sts DP, drop wiper plug, pump same through stinger. Trace cmt returns, csg clean. 100% returns entire job. No loss /gain. PJSM, POH 5" DP inner string, lay do tools Clean rig floor, prepare for nipple do diverter. OH --/-- PJSM:Nipple down diverter lines & pick up. Make rough cut on 13 3/8" PJSM: Set out diverter and 20" head. PJSM:Remove single ram preventer from bop stack PJSM: Make final cut on 13 3/8" and Install Multi-Bowl wellhead and tested by Vetco Reps to 1650 psi. for 15 min. good test. PJSM:Nipple up BOP's PJSM: M/U BOP test equipment PJSM: Test all bop and manifold equipment to 250/2000 psi. test witnessed by Tim Lawlor with BLM and Lew Grimmaldi with AOGCC. PJSM: Pull test plug, set wear bushing and rig down test equipment. Test csg to 2000 psi. / 30 min, test successful. OH --/-- PJSM: Rig up Drill pipe equipment, PJSM:P/U 5" Drill pipe and std back in derrick drift same. PJSM:M/U Bha #2 and test MWD CJ • Printed: 10/20!2005 11:30:36 AM Marathon OiI Company Operations Summary Report -Per Well Legal Well Common W Event Date Report Date __ Name: ell Name: ~ Event From - Td ~ - KE KE ~ Hours __ NAI BEL NAI BEL Code UGA U UGA U ' SuIJ I Code NIT 22-6 NIT 22-6 Phase ~ 18:00 - 19:30 1.50 PULD_ DP_ SURCSG 19:30 - 21:30 2.00 DRILL_ CMT_ SURCSG 21:30 - 22:00 0.50 DRILL_ ROT_ SURCSG 22:00 - 00:00 2.00 CIRC_ MUD_ SURCSG 00:00 - 00:30 0.50 TEST_ LOT_ SURCSG 00:30 - 02:00 1.50 REPAIR RIG_ INi DRL 02:00 - 06:00 4.00 DRILL - ROT - IN1 DRL 5/26/2005 06:00 - 05:30 23.50 DRILL_ ROT_ IN1 DRL 05:30 - 06:00 0.50 CIRC_. MUD_ IN1 DRL 5/27/2005 06:00 - 06:30 0.50 CIRC MUD_ IN1 DRL '~ 06:30 - 09:00 2.50 TRIP_ WIPR IN1 DRL 09:00 - 10:30 1.50 SLPCUT DLIN IN1 DRL 10:30 - 11:00 0.50 SERVIC EOIP INIDRL 11:00-12:00 1.00 SERVIC RIG_ INi DRL 12:00 - 12:30 0.50 SAFETY MTG IN1 DRL ~ 12:30 - 13:30 1.00 TRIP_ 'WIPR IN1 DRL 13:30 - 05:30 16.00 DRILL_ ROT_ IN1 DRL 05:30 - 06:00 0.50 TRIP_ DP, IN1 DRL 5/28/2005 06:00 - 07:30 1.50 MIX_ LCM_ IN1 DRL 07:30 - 08:30 1.00 TRIP_ DP_ IN1 DRL 08:30 - 13:00 4.50 MIX_ LCM_ IN1 DRL 13:00-13:30 0.50 TRIP_ DP_ INIDRL 13:30 - 22:30 9.00 DRILL_ ROT_ IN1 DRL 22:30-00:00 1.50 CIRC_ MUD_ INIDRL 00:00 - 04:30 4.50 DRILL_ ROT_ IN1 DRL 04:30 - 05:00 0.50 SERVIC RIG_ IN1 DRL 05:00 - 06:00 1.00 DRILL_ ROT_ IN1 DRL 5/29/2005 06:00 - 13:00 7.00 DRILL_ ROT_ IN1 DRL 13:00- 16:00 3.OO WORK LPIPE INIDRL 16:00 - 18:00 ~ 2.00 PUMP LCM_ IN1 DRL Page 3 of 9 Spud Date: 5/20/2005 Event Type -!-- Objective SideTrack- --~-- Description of Operations PJSM: RIH picking up single jts. drill pipe to 1604' PJSM:Drill cmt and stab in float collar and shoe and clean out open hole F/1604' to 1680' (Cmt very firm, app. 20' of hard cmt on top of stab in collar.) Drill 12 1/4" hole F/1680' to 1700' (ART=.25hrs) PJSM:Circ and change over wellbore fluids to 9.0 ppg. flo-pro mud PJSM:PuII into shoe, Perform LOT. 578 psi.leak off 9.0 ppg mud, 1509' TVD=16.37ppg EMW. PJSM: Chg out motor on shale shaker PJSM: Drill ahead 12 1/4" hole drentl F/1700' to 2066 ft ART = 1.45 hrs, AST = 1.1 hrs OH --/-- Drilll ahead 12 1/4" hole drentl F/2066' to 4017' (ART=11.4hrsAST=3.9hrs} No drag, gain, loss, torque. Ran Hi-Vis sweeps ~ 500' Intervals. Approx 10% cuttings increase with sweeps. Circ Hi-Vis sweep for wiper trip X4017' OH --/-- Circ Hi-Vis sweep ~ 401 T for wiper trip PJSM: Wiper trip out of hole to csg shoe 1668' (No Drag ,Torque, gain, loss. PJSM:Cut and slip drilling line PJSM: Adjust brake rollers on desks PJSM:Service r Weekly safety meeting, all crews /personnel PJSM:Wiper TIH`(No gain, loss, torque, drag, No fill) Drill ahead 12 1/4" hole drentl F401T to 4929'. ART=5.4 hrs AST=4 hrs Lost partial returns C~ 4929' (POOH 5- stds.) for LCM pill. Initial loss 30 bph, increasing to 150 bph. OH --/-- Mlx 100 ppb LCM pill. spot 50 bbl. LCM pill consist of 35 ppb. Safecarb 40, 35 ppb Safecarb 250, 30 ppb MIX 11 Med. Spot pill at 60 spm, note partial returns at 40 bbls away. Observe well, fluid column drop approx 5 bph. POOH 6 Stda above pill to 4330' Circ with full returns and build volume, continue adding safecarb 250, and MIX 11 fine to active system for seepage. Initial 100 spm, ramp to 300 spm. Cont Circ ECD down force on pill. 100% returns. PJSM:TIH to 4929' Drill ahead 12 1/4" hole drentl F/4929' to 5338' at reduced pump rate (230 spm / 1060 psi.) (AST=3.2 hrs ART=2.8 hrs) No loss, gain, high torque, no drag Circ drill cuttings gas before making connection Max units 1212. Drill ahead 12 1/4" hole drentl F/5338' to 5528' at reduced pump rate 230 spm / 1060 psi. ART=1.25 hrs AST=1.2 hrs PJSM:Adjust hydraulics on Top Drive Drill ahead 12 1/4" hole drentl F/5528' to 5591'. ART=.3 hrs AST=.6 hrs OH --/-- Drill ahead 12 1/4" hole drentl F/5591' to 5840'. ART=1.24 hrs AST=4.5 hrs Lose partial returns, 5 bph increasing to 50 bph in 2 hrs. Slow to 60 spm, no loss, stop pump, flow check, no loss. Stop drlg, Circ /work pipe. Cont Circ at 60 spm / 116 gpm / 575 psi. Entry added later to account for problems mentioned during time period from 06:00 to 16:00: "Lose partial returns, 5 bph` increasing to 5Q bph in 2 hrs. Slow to 60 spm, no loss, stop pump, flow check, no loss. Stop drlg, circ /work pipe. Cont circ at 60 spm / 116` fpm / 575 psi." Mix and pump LCM pill,35 ppb Safecarb 40+35 ppb Safecarb 250+20 ppb Mix 11, full returns established at lower flow rate Stage pumps up"to 400 gpm, no loss, encounter loss at 450 gpm • r Printed: 10/20/2005 11:30:36 AM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Name: Event Date Event Report Date 'From - To 16:00 - 18:00 18:00 - 06:00 Page 4 of`9 KENAI BELUGA UNIT 22-6 KENAI BELUGA UNIT 22-6 _ Spud Date: 5/20/2005 pub TEvent Type --;-- Objective H~.urs ~ Code Code Phase SideTraok- --/-- Description of Operations 2.00 PUMP_ LCM_ IN1 DRL 12.00 DRILL_ ROT_ INIDRL 5/30/2005 06:00 - 15:30 9.50 DRILL_ ROT_ IN1 DRL 15:30 - 17:30 2.00 CIRC_ MUD_ IN1 DRL 17:30 - 21:30 4.00 TRIP_ WIPR IN1 DRL 21:30 - 22:30 1.00 SERVIC RIG_ IN1 DRL 22:30 - 23:00 0.50 PULD_ DP_ IN1 DRL 23:00-03:00 4.00 TRIP_ WIPR INIDRL 03:00 - 05:30 2.50 CIRC_ MUD_ IN1 DRL 05:30 - 06:00 0.50 TRIP_ DP_ IN1 DRL 5/31/2005 06:00 - 12:00 6.00 TRIP DP INIDRL 12:00 - 15:00 3.00 PULD_ BHA IN1 DRL 15:00 - 15:30 0.50 RURD_ CSG_ INICSG 15:30-17:30 2.00 TEST_ ROPE INICSG 17:30 - 18:00 0.50 RURD_ EOIP INICSG 18:00 - 22:00 4.00 RURD_ CSG_ INICSG I 22:00 - 23:30 1.50 RUN_ CSG_ INICSG 23:30 - 06:00 6.50 RUN_ CSG_ IN1 CSG 6/1/2005 06:00 - 08:30 2.50 RUN_ CSG_ INICSG 08:30 - 09:30 1.00 RURD_ CMT_ INICSG 09:30 - 12:00 2.50 PUMP_ CMT_ INICSG 12:00-13:00 1.00 PULD_ EOIP INICSG 13:00 - 14:00 1.00 TEST_ EQIP INICSG 14:00-16:00 2.00 PULD_ EQIP INICSG 16:00 - 16:30 0.50 SETREL PLUG 1N1 CSG 16:30 - 20:30 4.00 TEST_ ROPE IN1 CSG 20:30 - 21:00 0.50 TEST_ PLUG IN1 CSG 21:00 - 22:00 1.00 TEST_ CSG_ IN1 CSG 22:00 - 00:00 2.00 RURD_ EOIP IN1 CSG 00:00 - 01:00 1.00 SERVIC RIG_ IN1 CSG 01:00 - 02:30 1.50 PULD_ DP_ IN1 CSG Return to 400 gpm. Drill ahead 12 1/4" hole drentl F/5840' to 6178' (ART=1.9 hrs AST=5.9 hrs) Maintain LCM in system, ramp up to 500 gpm, no loss. OH --/-- Drill ahead 12 1/4" hole drentl F/6178' to 6535'. ART=3.Ohrs AST=3.6hrs Circ and condition mud ,Pump hi-vis sweep, Flow check, pump slug. Sweep as caliper volume = 9.2 bbls excess. PJSM:Wiper trip,POOH to 13 3/8" csg. shoe 1668' (No abnormal drag, torque, loss, gain,) Service rig ' PJSM:L/D 10 jts.°Drillpipe contaminated with Cmt from Surface csg. cmt job. PJSM:Wiper TIH, (No noticeable fill , no loss, no gain,) one bridge at 6445' washed through with no problems) Circ Hi-Vis Sweep and condition mud for csg. Running centrifuge. (No loss, gain, torque, drag. 500 gpm, 1200 psi. PJSM: POOH (SLM) OH --/-- PJSM:POOH to Bha. (Spot 50 bbl. LCM pills at each of two stations 5840' and 4930' consist of 35 ppb. safe carb 40, 35 ppb safe carb250, 10 ppb. Mix 11 Medium. (SLM Drill Pipe) PJSM: Lay down`Bha #2 PJSM: Rig up stabbing board PJSM:PuII wear bushing run test plug. C/O top rams 9 5/8" . Test door seals to 250/2000 psi. M/U 13 9/16" X 9 5/8" hanger assy to 9 5/8" landing jt. Make test run and verify hanger landed . L/D hanger assy. PJSM: R/U to run 9 5/8" csg. rig bails, elevators, adjust torque tube, M/U low torque valve on swedge, load centralizers on floor. PJSM: MU shoe track /thread lock same. PJSM: Commence run Jts. 9 5/8" 40# L80 BTC Csg. (Shoe, 2 jts csg, float collar), check floats, Break circ at 4100', correct dsplcmnt, No losses, gains, down drag normal. Slow go, approx 1.5 fps due to possible losses. 5235 ft at 0600 hrs. OH --/-- RIH with total of 157 jts. 9 5/8" 40# L80 BTC .Circ last 2- Jts. down Install 9 5/8" csg. hanger. Shoe set ~ 6529.44' PJSM: Rig up BJ and rig down Weatherford csg tools. PJSM:Pump 5- bbl. water, Test lines to 4000 psi. Drop bottom plug, Pump 30 bbls. MCS-4D Spacer 10 ppg. Pump 119 bbls, 313 sxs. Lead cmt(G+0.2% CD-32+0.5% FL-52+2.2% SMS+ .25 11 s/sx Celloflake+ 1 ghs FP-6L))12.5ppg. 2.1 yield. 11.94 gals water per sx. Follow with 97 bb1.256 sxs Tail CMT(G+15%BA-56+0.5% EC-1 +0.5%SMS+0.1 ASA-301+2%CaCL2+1 gphs FP-6L (13.5ppg.1.91 yield, 9.56 gals water per sx. Drop top plug and put in place with 10 bbls. water+479 bbs. mud slow rate last 10 bbl. ~ 468 bbl. and Bump plug from 760 pumping psi to 1500 psi. check floats (ok) Got back 2-bbls. when checking floats good circulation throughout job. CIP C~ 1200 hrs. 5/31/2005. PJSM: UD Landing jt and wash out stack PJSM Install 9 5!8" Packoff and test to 5000 psi F/15 min. (OK) PJSM:CIear rig'ffoor, C/O rams, PJSM:Set test Plug, M/U test tools. PJSM: Pressure test all BOP equipment to 250/2000 psi. Witness waived by Jim Regg W/ AOGC PJSM: Pull test plug and set wear bushing. PJSM:Test csg to 2000 psi. F/30 Min. (Good Test) PJSM:Adjust top drive torque tube Service rig PJSM:Rack and strap drill pipe • L' Printed: 10/20/2005 11:30:36 AM Marathon Oil Company Operations Summary Report -Per Well Page 5 of 9 Legal Well Common W Event Date Report Dafe Name: ell Name: Event ~ From - To KE KE Hours NAI BEL NAI BEL - ! Code UGA U UGA U Sub '~ Code NIT 22-6 NIT 22-6 - Phase Spud Date: 5/20/2005 _ _ !Event Type --/-- Objective I SideTr~ck- -- -- Description of Operations 02:30 - 04:30 2.00 PULD_ BHA_ IN1 CSG PJSM:M/U Bha #3 04:30 - 06:00 1.50 PULD_ DP_ IN1 CSG PJSM: P/U 5" Drill pipe from walk. New pipe m/u twice. 6/2/2005 06:00 - 07:00 1.00 PULD_ DP_ INICSG OH --/-- P/U and RIH W/ 5" DP(P/U total 66jnts). 07:00 - 09:00 2.00 TRIP_ DP_ INICSG RIH W/5" DP from derrick and tag ~ 6438'. 09:00 - 11:00 2.00 DRILL_ CMT_ INICSG Drill FC, shoe tract and shoe to 6529'. Clean old hole to 6535'. 11:00 - 11:30 0.50 DRILL_ ROT_ INICSG Drill 8.5" hole F/6535' to 6555'. 11:30 - 12:00 0.50 CIRC_ MUD_ INICSG Circ. clean for LOT. 12:00 - 12:30 0.50 TEST_ LOT_ IN1 CSG Perform LOT to i5.5PPG EMW(9.7MW and 1650psi) 12:30 - 06:00 17.50 DRILL_ ROT_ PR1 DRL Dir drill and survey F/6555' to 7435'(ART=7.7hrs AST=3.9hrs)(increased lubtext F/2.5% to 4.0% Before UP225K, DN90K, ROT135,T016-18K After UP180K, DN115K, ROT135K TQ13-15K, pumped high vis sweep@7193'). 6/3/2005 06:00 - 07:00 1.00 DRILL_ ROT_ PR1 DRL OH --/-- Dir drill and survey F/7435' to 7508'. lincrease lubtex to 5% Before Up 200K, DN 110K, ROT 147K, TQ 19K, After UP195K, DN 110K, ROT 145K, TO 14K). (ART=4.2hrs AST=O). 07:00 - 07:30 .0.50 CIRC_ MUD_ PR1 DRL High torque. Circ. clean and let lubtex circ. around. 07:30 - 12:00 4.50 DRILL_ ROT_ PR1 DRL Drill F/7508' to 7761'. Due to high torque increased Lubtex to 6% X7508' Before UP 195K, DN 110K, ROT 145K TO 14K After UP 193K, DN 115K, ROT 145K, TO 13.5K. 12:00 - 13:30 1.50 CIRC_ MUD_ PR1 DRL Circ. clean(CBUX2, 425gpm, 1450psi, 65RPM). Check flow. 13:30 - 15:30 2.00 TRIP_ WIPR PRIDRL POOH to CSG shoe tight~7454', 7412',7403', 7351', 7207', 7118', B/R 7126'-7071', tight C~ 6913', 6908', 6726, 6703', 6684', 6608', 6603', 6600' B/R 6600' to 6562'. 15:30 - 16:00 0.50 SERVIC RIG_ PRi DRL Service the rig. 17:00 - 18:00 1.00 TRIP_ WIPR PR1 DRL RIH. to 7761'. No noticeable fill or excessive drag Trip gas 85 units. 18:00 - 06:00 12.00 DRILL_ ROT_ PRi DRL Dir drill and survey F/7761' to 8490'. Added lubtex to bring con. back to 6% decreased torque F/18K to 16.5K, ART=8.9hrs AST=O. 6/4/2005 06:00 - 09:00 3.00 DRILL_ ROT_ PRi DRL OH --/-- Dir drill and survey F/8490' to 8655'(ART=2.3 AST=Ohrs). 09:00 - 09:30 0.50 CIRC_ .MUD_ PR1 DRL Circ. clean while wait on geology to confirm TD. 09:30 - 14:30 5.00 DRILL_ ROT_ PRi DRL Drill F/8655' to 8855'(ART=4.Ohrs AST=Ohrs). 14:30 - 16:30 2.00 CIRC_ MUD_ PRi DRL Circ. clean(CBUX2). 16:30 - 20:00 3.50 TRIP_ WIPR PR1 DRL POOH to 8540`: Pump Dry job. Cont. POOH F/8655' to 6529' 9-5/8" csg shoe. Several tight intervals from 8200' to 6700' used top drive fo'back ream intervals ~ 7505' and 7384'. 20:00 - 20:30 0.50 SERVIC RIG_ PRIDRL Service Rig 20:30 - 21:30 1.00 TRIP_ WIPR PR1 DRL TIH, Wash & Ream F/ 8830' to 8855'(App. 15' Fill). 21:30 - 00:30 3.00 CIRC_ MUD_ PR1 DRL Circ Hi-Vic Sweep solids increased app. 50 % . Bottoms up returns from wiper trip were very heavy with solids. 3200 Max gas units. 00:30 - 06:00 5.50 TRIP_ DP_ PR1 DRL PJSM: Monitor well, Pump Dry Job, Drop 2.875 rabbit, POOH (SLM). 6/5/2005 06:00 - 07:30 1.50 TRIP_ BHA_ PR1 DRL OH --/-- Rack back HWDP. L/D directional tools and bit. 07:30 - 08:00 0.50 LOG_ OH_ PR1 EVL PJSM prior to logging operations. R/U Precision Logging for conventional E/L Quad combo run. 08:00 - 14:30 6.50 LOG_ OH_ PRi EVL Run Precision Quad combo F/8850' to 3000'. PJSM prior to R/D. R/D EL tools. 14:30 - 16:00 1.50 PULD_ BHA_ PR1 EVL L/D 5" HWDP and jars. 16:00 - 19:30 3.50 TRIP_ DP_ PR1 EVL PJSM:TIH W/5" DP and Muleshoe to 6528'. 19:30 - 21:00 1.50 SLPCUT DLIN PR1 EVL PJSM:SIip and cut drilling line and adjust desks brakes. 21:00 - 00:30 3.50 TRIP_ DP_ PR1 EVL PJSM:TIH W/ 5"DP and Muleshoe to 8832'(P/U 23jnts 5" DP). 00:30 - 04:00 3.50 CIRC_ MUD_ PR1 EVL PJSM: Circ wellbore clean of influx (Max gas units 4250, circ on choke) and wait on RFT station report. 04:00 - 04:30 0.50 TRIP_ DP_ PR1 EVL PJSM:Monitor well, POOH W/Drill pipe to 7943'. • • Printed: 10/20/2005 11:30:36 AM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Nam_ e: Event Date Event Report Date From - To 04:30 - 05:00 05:00 - 06:00 6/6/2005 06:00 - 11:00 11:00 - 12:00 12:00 - 16:00 16:00 - 16:30 16:30 - 20:00 20:00 - 21:00 6/5/2005 Event 21:00 - 22:00 22:00 - 01:30 01:30 - 06:00 6/7/2005 06:00 - 07:00 07:00 - 10:30 10:30 - 13:00 13:00 - 21:00 21:00 - 21:30 21:30 - 22:00 22:00 - 02:00 02:00 - 06:00 KENAI BELUGA UNIT 22-6 KENAI BELUGA UNIT 22-6 Hours Code Sub Phase ~ Event Type --/-- Objective Code SideTrack- -- -- Description of Operations 0.50 SAFETY MTG_ PR1 EVL 1.00 LOG OH_ PR1 EVL 5.00 LOG_ OH_ PRi EVL 1.00 TRIP_ DP_ PR1 EVL 4.00 LOG_ OH_ PR1 EVL 0.50 TRIP_ DP_ PR1 EVL 3.50 LOG_ OH_ PR1 EVL 1.00 KURD EOIP PRIEVL 1.00 TRIP, DP_ PRICSG 3.50 CIRC_ MUD_ PRICSG 4.50 TRIP_ DP_ PRICSG 1.00 PULD_ BHA_ PRi CSG 3.50 TRIP DP_ PRi CSG 2.50 CIRC_ MUD_ PRICSG 8.00 PULD_ DP_ PRi CSG 0.50 PULD_ BHA_ PRi CSG 0.50 RUNPU WBSH PRICSG 4.00 RURD_ CSG_ PR1 CSG 4.00 RUN CSG PRi CSG 6/8/2005 06:00 - 14:30 8.50 RUN._ CSG_ PRICSG 14:30 - 15:00 0.50 CIRC_ MUD_ PRICSG 15:00 - 19:00 4.00 RUN_ GSG_ PRICSG 19:00 - 20:30 1.50 CIRC MUD PRICSG 20:30 - 21:00 0.50 RURD_ ELEC PRi CSG 21:00 - 00:30 3.50 LOG_ CSG_ PRICSG 00:30 - 01:00 0.50 KURD CMT PRi CSG 01:00 - 04:00 ~ 3.00 ~ PUMP_~ CMT_ ~ PRi CSG 04:00 - 05:00 1.00 RURD_ CMT_ PRi CSG 05:00 - 06:00 1.00 WAITON CMT_ PR1 CSG 6/9/2005 06:00 - 12:00 6.00 WAITON CMT_ PRi CSG 12:00 - 13:00 1.00 NUND BOPE PRICSG 13:00 - 14:00 1.00 NUND BOPE PRi CSG 14:00 - 15:30 1.50 NUND TREE PR1 CSG 15:30 - 17:00 1.50 NUND BOPE PR1 CSG Page 6 of'9 Spud Date: 5/20/2005 PJSM:Safety meeting with Precision logging on running RFT's. R/U Precision Logging and RIH with RFT tool OH --/-- Run CRFT. R/D E/L packoff. POOH to 7377'. PJSM. R/U E/L. Run CRFT. R/D E/L packoff. POOH w/DP to 6500'. R/U Precision E/L packoff. Run CRFT. R/D Precision energy services logging equipment. Rig turned to completion ~ 2100 hrs. 6/5/2005 ORIGINAL COMPLETION --/-- Development -Gas PJSM:TIH, F/ 6529' to 8834' (No loss, gain, torque, drag) 180 up, 125 dn, 150 rt, Tq 10- 12K PJSM: Cir out wellbore influx through choke. Max gas units 3850. Continue to Circ and raise mud wt to 10.6 ppg. PJSM:Monitor well, Pump dry job, POOH. OH --/-- PJSM:M/U 8.5" bit. P/U 5" HWDP and Jars. RIH w/5" DP(tag 15' of fill). Circ. clean. CBUX3, 500gpm, 1790psi, 60RPM, large amount of clay across shakers, 700units Trip gas. PJSM:FIow Check prior to UD DP. Pump dry job. POOH and UD DP(Hole in good condition). PJSM: UD Bha. PJSM: Pull wear bushing. PJSM:Rig up csg'tools to run 3 1/2" Excape module completion. PJSM:Run 3 1/2" 9.3#/ft. L-80 8rd EUE Modified csg. Excape module completion. Floats checked after making up shoe tract jts(Depth 1800' joint 49 of 271 C~06:OOhrs). OH --/-- Cont to Run 3 1/2" 9.3#/ft. L-80 8rd EUE Modified csg Excape completion(PJSM w/crew coming on at noon). Circ. at CSG shoe(188gpm, 700psi). Cont. to run 3 t/2" 9.3# L-80 8rd EUE Modified csg Excape completion to 8830' (Total of 271 jts, UP 110K, DN 65K ). PJSM:R/U and Circ @ 303 gpm, 1860 psi(Pump carbide ,and Safe carb 250 sweep, Both indicated near gauge hole, 91 Units max gas bottoms up). PJSM: R/U Expro EL. PJSM: Run GR correlation log. R/D Expro (set shoe ~ 8837', FC ~ 8801'). PJSM: R/U BJ cement head. Circ and spot 400 bbl mud w/conquor 303 corrosion inhibitor (309 gpm, 1860 psi, Mix 100 bbl 6 %KCL brine in vac truck). PJSM: Pump 5 bbl. water ahead. Test BJ lines to 3500 psi. Mix and pump 40 bbls. 11.0 ppg MCS-4 spacer, Mix and pump 1113 sxs class "G" cement with 1.2% BA-56+.5%EC-1+.1% R-3+.2%CD-32+ lghs FP-6L, Yield 228 bbl. 15.8 ppg. slurry. Shut down and Drop plug. Displace with 77 bbl KCL, Displacing psi. 1800 psi Bump plug to 2640 psi. Hold for 1-min Check floats, (Held) CIP ~ 0400 hrs. 6/8/2005, 100 % Returns through out job(Reciprocated with 8' strokes during cement job). R/D BJ cement head. While WOC: flush lines, prep to N/D BOP and empty pits OH --/-- While WOC: Prep to N/D BOP. Clean pits. PJSM prior to N/D BOP. N/D BOP. Set 3 1/2" X 13 5/8" slips w/95K. Make rough cut on 3 1/2" CSG. UD cut joint. Set out BOP from sub. Make final cut and dress(22.13' RKB). Set 3 1/2"X13 5/8" packoff. N/U 13 5/8" X 3 t/6" 10,000 psi X-mas tree. ~~ s Printed: 10/20/2005 11:30:36 AM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: KENAI BELUGA UNIT 22-6 Common Well Name: KENAI BELUGA UNIT 22-6 i Event Date Event Sub ~ j Report Date From - To Hours Code I Cody Phase 17:00 - 18:00 1.00 TEST_ TREE PR1 CSG 18:00 - 00:00 6.00 RURD_ RIG_ RDMO 00:00 - 06:00 6.00 RURD RIG RDMO 6/10/2005 06:00 - 12:00 6.00 RURD RIG RDMO 6/15/2005 Event 6/18/2005 10:00 - 10:15 0.25 SAFETY MTG CMPSTM 10:15 - 10:30 0.25 SAFETY MTG_ CMPSTM 10:30 - 11:00 0.50 RURD_ ELEC CMPSTM 11:00 - 11:15 0.25 PULD_ LOG_ CMPSTM 11:15 - 15:15 4.00 LOG_ CSG_ CMPSTM 15:15 - 16:00 0.75 RURD_ ELEC CMPSTM ,7/27/2005 06:00 - 15:00 9.00 RURD STIM CMPSTM 15:00 - 21:00 6.00 RURD_ STIM CMPSTM 7/28/2005 06:00 - 21:00 15.00 KURD STIM CMPSTM 7/29/2005 06:00 - 21:00 15.00 RURD_ STIM CMPSTM 7/30/2005 06:00 - 21:00 15.00 KURD STIM CMPSTM 8/2/2005 06:00 - 21:00 15.00 KURD STIM CMPSTM 8/3/2005 06:00 - 12:00 6.00 RURD_ STIM CMPSTM 12:00 - 12:30 0.50 PERF_ CSG_ CMPSTM 12:30 - 13:00 0.50 PERF_ CSG_ CMPSTM 13:00 - 18:30 5.50 RURD_ STIM CMPSTM 8/4/2005 06:00 - 18:30 12.50 RURD_ STIM CMPSTM 18:30 - 20:30 2.00 KURD SLIK CMPSTM 20:30 - 22:00 1.50 RURD_ STIM CMPSTM 8/5/2005 06:00 - 11:30 5.50 RURD_ STIM CMPSTM 11:30 - 12:00 0.50 SAFETY MTG_ CMPSTM 12:00 - 13:00 1.00 TEST EOIP CMPSTM Page 7 of 9 Spud Date: 5/20/2005 EventType-l-- Objective SideTrack- --,-- Description of Operations Test tree void to 5000psi/10min. Run and set TWC, Test tree to 10000psi/10min. Pull TWC and set BPV. PJSM: R/D & Move out pump #3, R/D manifold, bleeder ,low troque & Kill lines, Choke hose, Bails and elevators, Pickle pump #1 and #2, R/D Top drive service lines, remove slide, Set Top drive in rack & L/D. Remove turnbuckles, unhang Torque tube, R/D Geolograph line, dresser sleeve, pop off lines, Choke lines to poorboy , R/D Service lines, Pull wires Load Trailers. PJSM:R/D Gas buster,Torque tube, monkey board, Scope down derrick, load floats with iscellaneous items, R/D Rig. OH --/-- PJSM prior to rig move. R/D and pull all electrical lines. R/D w/crane choke house, stairs, landings, flow line, ODS outriggers, back wind walls. Load out generator, boiler house, water, hanson tank and diesel tank. L/D Derrick. Rig released from KBU 22-6 ~ 12:OOhrs 6-9-2005. ORIGINAL COMPLETION --/-- Development -Gas OH --/-- Arrive on location, sign in, obtain work permit, PJSM Spot equipment, complete JSA, hold safety meeting RU wireline truck.. PU CBL tool and"memory pressure tool RIH w/ CBL and memeory PT tools. Log free pipe 4200'-4000'. Log repeat pass and main pass from PBTD 8740' to TOC (TOC-5145'). POOH. RD, turn in work permit, and depart. OH --/-- Start laying liner for frac and flowback tanks. Haul 6 frac tanks to location and spot same for frac water and flowback tank. Start hauling water to location and begin filling frac tanks. OH --/-- Continue hauling water to frac tanks and lining location. Spotted MOC tank and gas buster and flowback iron and valves. OH --/-- Continued filling frac tanks with water, Started spotting flowback lines and berming up liner. OH --/-- Finished hauling water to frac tanks. Continued lining location and bermining same. Spotted sand kings and blew sand. OH --/-- Mixed up 6% KCL in frac tanks. Spotted frac trucks and frac van. Continued making up flowback iron. Spot CT Unit and equipment OH --/-- Continued laying out frac lines, flowback lines. RU Expro control lines to wellhead and pressure tested Green line to 5000 psi. Opened up green firling line. Pressured up to 3300 psig and fired Module one gun perforating 8675 - 8685'. Good indication of guns firing. Finished RU of CT Unit and continued finalizing line hook up and valve requirements while waiting on Well test equipment. OH --/-- Continued to finalize flowback and frac line and equipment layout. Well Test crews arrived on location. Arranaged for safety orientation for 2 crew members. Discussed well test equipment layout with lead well tester and BJ field service supervisor. Spotted well test'equipment and started to layout testing lines. SDFN. OH --/-- Re spbt;vent flare stack and well test equipment. RU Well testing equipment. Hold PJSM with oll Frac rrelated personnel. Pressure test frac lines to 9500 psig. Good test. Pressure test flowback iron to well testers choke manifold to 4500 psig. Good test. • • Printed: 10/20/2005 11:30:36 AM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Name: Event Date Event Report Date From - To 13:00 - 14:00 14:00 - 14:30 14:30 - 15:15 15:15 - 15:30 KENAI BELUGA UNIT 22-6 KENAI BELUGA UNIT 22-6 Hours ~ Code Code Phase 1.00 PUMP` FRAC CMPSTM 0.50 PUMP_ FRAC CMPSTM 0.75 ~ PUMP_ FRAC CMPSTM 0.251 PUMP_ I FRAC I CMPSTM 15:30 - 16:00 0.50 FLOW_ CHEK CMPSTM 16:00 - 18:00 2.00 RURD_ STIM CMPSTM 18:00 - 20:30 2.50 RURD_ COIL CMPSTM 20:30 - 01:30 5.00 CLNOU CSG CMPSTM 01:30 - 02:00 0.50 CLNOU CSG_ CMPSTM 02:00 - 04:00 2.00 RUNPUL COIL CMPSTM 8/6/2005 06:00 - 07:00 1.00 RURD_ STIM CMPSTM 07:00 - 07:30 0.50 SAFETY MTG_ CMPSTM 07:30 - 08:00 0.50 WAITON OTHR CMPSTM 08:00 - 08:30 0.50 ~ PUMP FRAC ~ CMPSTM 08:30 - 09:00 ~ 0.50 ~ PUMP_ FRAC CMPSTM 09:00 - 09:30 ~ 0.50 ~ PUMP_ FRAC ~ CMPSTM 09:30 - 10:00 ~ 0.501 PUMP FRAC CMPSTM Page 8 of 9 Spud Date: 5/20/2005 Event Type --l-- Objective SideTrack- -- -- Description of Operations Perform injection test into module 1 perfs at 8675-8685. ISIP = 2580 psig. F.G. = 0.79 psi/ft. Gel up fluid for frac job. Frac mod 1 perfs w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 6020 psi. Ramp 2.0 - 8.0 ppa. Place 21754 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 258 bbl. Tagged w/ ProTechnics CFT 1100 chemical tracer and field tracer AUM 02 (cumm. load = 258 bbls) (Strap chemical tanks post frac) Perforate Module 2 from 8580-8590' with +/- 3450 psig on red line. Frac mod 2 perfs w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 5600 psi. Ramp 2.0 - 8.0 ppa. Place 38406 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 266 bbl. Tagged w/ ProTechnics CFT 1200 chemical tracer (cumm. load = 524 bbls) (Strap chemical tanks post frac) Perforate Module 3 from 8455-8465' with +/- 4350 psig on red line. Frac mod 3 perfs w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 9500 psi. Ramp 2.0 - 6.0 ppa. Pressures indicated high pert friction. Screened out with 5.3 ppg proppant on perfs during ram from 4 to 6 ppg. Shut down pumps and bled pressure off to flowback tank rapidly. Well bled to 0 psig with no flow. Pressure back up on module 3 perfs to 9000 psig. No success. Bled pressure off to flowback tanks and monitored well for flow. Placed 11041 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 198 bbl. Tagged w/ ProTechnics CFT 1400 chemical tracer (cummr, load = 722 bbls) (Strap chemical tanks post frac) Monitor well for flow. Well dead. Call Coil Tubing crew. RD frac equipment and clean up blender etc. •_ Mix 6% KCL for CT operations and RU coil tubing injector head with washout assembly. Pressure test injector connection. RIH with CT pumping 0.25 bpm to 5600'. WHP = 0 psig (open choke). Increase pumps to 1.5 bpm adn continue RIH. Ciculate out frac sand and flex sand. Tag Module 3 flapper at 8476' CTM. CBU POOH with CT. Shut in well. RD injector head. secure location for night. OH --/-- Arrive on location and start up and warm up frac trucks. Inspect well location Hold PJSM. Discuss high pressure frac operations, spills, slips trips and falls, and near misses. Review Module 4 frac design with 6% KCL in tubing versus crosslinked pad. Adjusted pad volume and slurry stages per GOHFER redesign. Perforate Module 4 from 8414-8424' with +/- 5400 psig on red line. Frac mod 4 perfs w/ BJ Lightning_V_1800 wtr based system at 15 BPM at max TP = 4950 psi. Ramp 2.0 - 8.0 ppa. Place 26943 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 245 bbl. Tagged w/ ProTechnics CFT 1500 chemical tracer and field tracer AUM 01 (cumm. load= 967 bbls) (Strap Chemical tanks post frac) Perforate Module 5 from 7842-7852' with +/- 6685 psig on red line. Frac mod 5 perts w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 5500 psi. Ramp 2.0 - 8.0 ppa. Place 2711`3 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot' Load = 205 bbl. Tagged w/ ProTechnics CFT 1600 chemical tracer (cumm. load = 1172 bbls) (Strap chemical tanks post frac) Perforate Module 6 from 7685-7695' with +/- 7350 psig on red line. Frac mod 6 perfs w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 4950 psi. Ramp 2.0 - 8.0 ppa. Place 23371 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 210 bbl. Tagged w/ ProTechnics CFT 1900 chemical tracer (cumm. load = 1382 bbls) (Strap chemical tanks post frac) Perforate Module 7 from 6552-6562' with +/- 9800 psig on red line. Frac mpd 7 perts w/ BJ Lightning_V_1600 wtr based system at 15 BPM at max TP = 3700 psi. Ramp 2.0 - 8.0 ppa. Place 30874 Ibs prop (87.5 % 20/40 Ottawa & 12.5% 12/20 Flex Sand). Tot Load = 231 bbl. Tagged w/ ProTechnics CFT 2000 chemical tracer (cumm. load = 1613 bbls) (Strap chemical tanks post frac) • CJ Printed: 10/20/2005 11:30:36 AM Marathon Oil Company Operations Summary Report -Per Well Legal Well Name: Common Well Name: Event Date Event Report Date From- To ~ 10:00 - 11:00 11:00 - 12:15 12:15 - 15:00 15:00 - 15:30 15:30 - 16:30 16:30 - 21:30 21:30 - 22:15 22:15 - 23:30 23:30 - 01:00 KENAI BELUGA UNIT 22-6 KENAI BELUGA UNIT 22-6 ~ Sub ~ Hours ~ Code .Code 1.00 RURD_ STIM 1.25 RURD_ COIL 2.75 RUNPU COIL Phase CMPSTM CMPSTM CMPSTM 0.50 RUNPUL COIL CMPSTM 1.00 JET N2_ CMPSTM 5.00 JET_ N2_ CMPSTM 10.50 RURDU~ COILK CMPSTM 01:50 - 06:00 4.17 FLOW_ TEST CMPSTM 8/7/2005 06:00 - 06:00 24.00 FLOW TEST CMPSTM 8/8/2005 06:00 - 06:00 24.00 FLOW TEST CMPSTM 8/9/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM 8/10/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM 8/11/2005 06:00 - 06:00 24.00 FLOW TEST CMPSTM 8/12/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM 8/13/2005 06:00 - 06:00 24.00 FLOW_ TEST CMPSTM 8/14/2005 06:00 - 10:30 4.50 FLOW_ TEST CMPSTM 10:30 - 06:00 19.50 RURD_ OTHR CMPSTM 8/16/2005 08:00 - 18:00 10.00 9/25/2005 07:00 - 07:30 0.50 SAFETY MTG_ PRDTST 07:30 - 08:30 1.00 RURD_ SLIK PRDTST 08:30 - 09:20 0.83 DRIFT_ TBG_ PRDTST 09:20 - 10:30 1.17 LOG CSG_ PRDTST 10:30 - 11:15 0.75 RURD_ SLIK PRDTST 11:15 - 11:30 0.25 CLEAN_ LOC_ PRDTST Event Type --/-- Objective SideTrack- --/-- Description of Operations Pale 9 of 9 Spud Date: 5/20/2005 Hold RD safety meeting. RD frac lines and clean up blender and frac equipment Hold PJSM. RU injector head and washout nozzle assembly. Stab injector head and pressure test same. RIH with CT washout assembly circulating at 0.25 bpm. RIH to 6500' CTM and increase circulating rate to 1.5 bpm. RIH attempting to locate and break excape module flappers. Did not see Module 7, 6, 5 flappers. Tag Module 4 flapper at 8440' CTM and break with 2000 Ibs set down. RIH and tag module 3 flapper at 8479' CTM and break with 1800 Ibs set down. RIH and tag module 2 flapper at 8605' CTM and break with 4000 Ibs set down. Momentarily lost returns after breaking module 2 flapper. Regained circulation. RIH to PETS of 8785' CTM. CBU Start pumping Nitrogen at 400 scfm and decrease fluid rate to 0.75 bpm. Get Nitorgen around and to surface. Increase Nitrogen to 750 scfm and shut down fluid pump. Jet well in from 8670 'CTM. POOH slowly to 7650' CTM. Decrease Nitrogen to min rate of +/= 400 scfm. Monitor well for indications of gas flow. RIH to below perfs to 8670' CTM and jet from below perfs. No indication of well coming in. POOH to 7650' CTM. Shut down Nitrogen and monitor well. Total fluid recovery = 383 bbls. Monitor well for flow. FTP = 365-380 psig. Started getting gas to surface. POOH with CT. FTP went from 380 to 450 psig while POOH. Line well flow through tree flowline. Close tree swab valve. Blow down CT. Rd Injector head and secure CT unit for night. FTP = 500 psig. Cumm frac load recovery = +/- 438 bbls Monitor well production. Well unloading fluid from 3300 BPD peak rate to 700 - 1200 bpd current rate. FTP = 540 psig. Cumm load recovery = 792 bbls or 49% of 1613 bbl total frac load. OH --/-- Continued unloading well. FTP = 620 psig. BW PD = +/-400 to 500. Traces of frac and flex sand along with very fine formation fines. OH --/-- Continued flow testing well. Well now flowing at FTP = 960 psig. Gas = 3.1 mmcfd, BW PD = +/-384 on an open choke flowing into LP sales gas system. Cumm water recovered = +/- 1643 (102% frac load) OH --/-- Continued to flow test well. FTP = 950 psig, 3.2 mmcfd, 192 bwpd. Well riding LP sales system pressure. OH --/-- Continued testing well. FTP=930 psig, 3.06 mmcfd, 202 bwpd. Cum fluid recovered = 2292 bbls (frac load = 1613 bbls) OH --/-- Continued flow testing well. FTP = 920 psig, 3.15 mmcfd, 403 bwpd. Well unloaded slug of water with fair amount of fromaton fines. Cumm water recovered = 2533 bbls (frac load = 1613 bbls) OH --/-- Flow test well. FTP = 970 psig, 2.7 mmcfd, 221 bwpd at 0600 hrs 8/12/05 OH --/-- Flow test well. FTP = 970 psig, 2.7 mmcfd, 187 bwpd at 0600 hrs 8-13-05 OH --/-- Flow test well with well testers to 1030 hrs 8/13/05. Well flowing 2.6 mmcfd, FTP = 960 psig, 226 bwpd. RD well testers. Final DIMS report OH --/-- Break down flow back equipment, vent stack layed down with crane, pickup liner and misc around the well head. Empty liquids from tanks. OH --/-- Hold safety and procedure meeting in office. Rig up slickline unit to flowing well. Drift tubing with 1-11/16" x 20' dummy gun. Tight spots at 6552' KB and 7845' KB, beat down several times. Tag at 8703' KB. RIH w/ Core Lab logging tool to 4800' KB. Had to work down to 6222' KB. Hung up and had to hit several OJ hits to come free. POOH w/o spinner on tool. Fish in hole -3.5" x 1-11/16" RD equipment. Clean up location and depart. • • Printed: 10/20/2005 11:30:36 AM • Marathon Oil Company Page 1 of 2 WeII Summary Report Legal Name: KENAI BELU GA UNIT 22-6 Common Name: KENAI BELU GA UNIT 22-6 Well Location Country: USA API #: 50133205500000 Well ID: 205-054 State/Prov: ALASKA County: Kenai Borough Location: 6- 4-N 11-W 1 Field Name: KENAI Block: Slot No: Platform: License No: License Date: Licensee: Spud Date/Time:5/20/2005 - 00:00 P&A Date: Surface /Bottom Hole Coordinates Surface Location Bottom Hole Loc ation Latitude: 60.46078 Longitude: -151.26211 Distance North/(-)South: -482.00 (ft) (ft) Distance East/(-)West: -1,267.00 (ft) (ft) Measured From: Section 6, T4N, R11 W, S.M. Reference Elevations Permanent Datum: KELLY BUSHING Datum Elev: 87.00 (ft) Kelly Bushing: 87.00 (ft) Water TMD: (ft) Ground Level/Mudline:66.00 (ft) Measured Depth: (ft) Casing Flange: (ft) Date Measured: TVD: (ft) Tubing Hanger: (ft) Date Measured: Plugback TMD: (ft) KB to Datum: (ft) Fill: (ft) KB to GL/Mudline: 21.0 (ft} / (ft) Deviated Well: Y Operator /Well Information Operator: MARATHON OIL COMPANY Region: ALASKA REGION Division: AR District: Well Type: DRY GAS Status: Geological Play: Authorized TVD: 7,525 (ft) Authorized TMD: 8,653 (ft) Event Summary __ - Event Type Objective. Start Bete End Date __ Auth. Cost ~ ~ Last Ee,t. Unspecified 9/27/2005 ----~ -- ORIGINAL DRILLING Development-Gas 5/17/2005 5,641,300 5/12/2005 ORIGINAL COMPLETION Development -Gas 6/5/2005 5,641,300 4/15/2005 ORIGINAL COMPLETION Development -Gas 6/15/2005 Hole Section - ST i Pilot Size Top M~ No. ii Hole (in) (tt) ~ - - Bottom MD ! Top TVD ~ Bottom TVD ~ Plan MD (ft) (ft) (ft) (ft) - ~ Plan TVD (ft) - Start Date End Date OH i N 20.000 21.0 130.0 5/17/2005 5/20/2005 OH N 16.000 130.0 1,680.0 5/20/2005 5/24/2005 Printed: 10/20/2005 1:17:53 PM • • Marathon Oil Company Page 2 of 2 Well Summary Report Legal Name: KENAI BELUGA UNIT 22-6 Common Name: KENAI BELUGA UNIT 22-6 Hole Section ST Pilot Size No. Hoie (in) Top MD Bottom MD Top TVD E3ottom TVD Plan MD eft) ~ {ft) (ft) (ft) (ft) Plan TVD Start (ft) Date End Date OH N 12.250 1,680.0 6,535.0 5/24/2005 6/1/2005 OH N 8.500 6,535.0 8,855.0 6/1/2005 6/4/2005 Printed: 10/20/2005 1:17:53 PM • -GL: 21.00' -THF: 21.70' 482' FSL, 1267' FWL, Sec. 6, T4N, R11 W, S.M. TOC on 3-1/2" (CBL est.) - 5150' KBU 22-6 • M ~wewTMOM Drive Pipe: 20", 133 ppf, K-55 to 130' Int. Casino: 9-518", 40 ppf, L-80, BTC @ 6529' Cmt w/ 313 sx of class G lead at 12.5 ppg followed by 256 sx of class G tail at 13.5 ppg. Good circulation throughout job. Prod. Tubing: 3-1/2", 9.3 ppf, L-80, EUE 8rd with 6.25" OD control line protectors to 8837' Cmt w/ 1113 sx of class G at 15.8 ppg. Good circulation throughout job. - 7 Excape modules placed - Green control line fires Module 1 - Red contol line fires modules 2-7 Module 1 -8675-8685' (Tyonek) Module 2 - 8580-8590' (Tyonek) Module 3 -8455-8465' (Tyonek) Module 4 - 8414-8424' (Tyonek) Module 5 - 7842-7852' (Beluga) Module 6 - 7685-7695' (Beluga) Module 7 - 6552-6562' (Beluga) Surface Casino: 13-3/8", 68 ppf, L-80, BTC ~ 1668' Cmt w/ 518 sx. of type 1 cemtn at 12.0 ppg. Cement to surtace. Well Name 8 Number: KBU 22~ Lease: Kenai Gas Field Cou or Parish: Kenai State/Prov. Alaska Country: USA Perforations (MD) (TVD) Angle/Perfs Angle @ KOP and Depth BHP: BHT: Completi on Fluid: 6°r6 KCL Dated Completed: 8/3/2005 Prepan3d J. R. Thompson Last Revison Date: 7/28/2005 10/20/2005 7:42 AM TD - 8855' PBTD - 8800' KBU 22-6 • Subject: ILBU 22-6 From: "Ln~s, Jennifer S." <jenos(~~?mal-athonoil.com> Date: 7 hu, 16 .Iun ?UU~ (i~:: ~ti31 -0500 ~ ~,~ ~ ~,~ ~ . ~~ Tu: titctc ~~li~m~iin5~~~iadmin.,tatc.~il..us- C(': "l~h~m~p;un. Jir7~" ~_jrtho~l~a>>c~n~~i nr~rath~muil.c~~m-~ Steve, I left a message on your-voice mail yesterday but want to go ahead and follow up with an email. I understand from Ken Walsh that there is some confusion on the name of our most recent well in Kenai Gas Field. The well is a Beluga well and should be named Kenai Beluga Unit 22-6 (per the permit application). Hope this helps. If you have any other questions, please let us know. T will be in the office this week, but in contact sporadically from June 20 - July 6. I have cc'd Jim Thompson on this note, so if you can't reach me, you can try him. Thanks, Jennifer Enos Geologist Alaska Asset Team Marathon Oil Co. 713-296-3319 i enoscmarathonoi 1 . com ~L'~ ~ 1w.+-+-t.~,. ~l« ~ .~; ~~ 1 of 1 6/16(2005 6:25 AM I`~~ ~ FRANK H. MURKOW5Kl GOVERNOR . ~~ ~Q~~ Willard J. Tank Advanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, Texas 77253 Re: Kenai KBU 22-6 Marathon Oil Company Permit No: 205-054 C011T5E Surface Location: 482' FSL, 1267' FWL, SEC. 6, T4N, Rl 1 W, SM Bottomhole Location: 3457' FSL, 2538' FWL, SEC. 6, T4N, Rl 1 W, SM Dear Mr. Tank: Enclosed is the approved application for permit to drill the above referenced development well. This permit to drill does not exempt you from obtaining additional permits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 2. Alaska Administrative Code unless the Commission to comply with an applicable provision of AS 31 Administrative Code, or a Commission order, or th result in the revocation or suspension of the permit. hours notice for a representative of the Commission Commission's petroleum field inspector at (907) 659, S/ DATED this day of April, 2005 0! taa~[sal~iA OII, A1~TD ~`iA-5i 333 W. 7"' AVENUE, SUITE 100 RQA~IOIQ COl-II~II55IO1Q ~ ANCHORAGE, ALASKA 99501-3539 PHONE (907} 279-1433 FAX j907) 276.7542 specifically authorizes a variance. .05, Title 20, Chapter 25 of the of the Failure Alaska e terms and conditions of this permit may Please provide at least twenty-four (24) to~'tness any required test. Contact the cc: Department of Fish & Game, Habitat Section w!o encl. Department of Environmental Conservation wlo encl. • ~ M Marathon MARATHON Oil Company March 28, 2005 John Norman Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West 7th Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Kenai Gas Field Well: KBU 22-6 ~ 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 development well in the Beluga 1 Upper Tyonek Pool in the Kenai Gas Field. ~No completion is desired in the Sterling pool. ~' Please note that Marathon is requesting a waiver for 20 ACC 25.035 {e) (1) (b) requiring a two pipe ram stack. The request is specified on page 12 of the attached drilling prognosis. If you require further information, I can be reached at 713-296-3273 or by a-mail at wjtankC marathonoil.com. Sincerely, ~~~~ Willard J. Tank Advanced Senior Drifting Engineer Enclosures STATE OF ALASKA AL KA OIL AND GAS CONSERVATION CONi"~SSION ,; PERMIT TO DRILL 20 AAC 25.005 Ir~~~- ~ ~31 ~ Lc~oS ~~I V L..D t;a ~ 2 4 2005 1a. Type of Work: Drill ~ Redrill Re-entry (] ib. Current Wei! Class: Exploratory Development Oil Multiple Zong Stratigraphic Test ~ Service ~ Dev I °~ ~IiQJ 2. Operator Name: Marathon Oil Company 5. Bond: B{anket ~ Single Well Bond No. 5194234 11. W~il{~~~ Number: KBU 22-6 3. Address: P.O. Box 3128, Houston, TX 77253 6. Proposed Depth: MD: 8,653 TVD: 7,525 12. Field/Pool(s): Kenai Gas Field 4a. Location of Well (Governmental Section): Surface: 482' FSL, 1,267 FWL, Sec. 6, T4N, R11W, S.M. ` 7. Property Designation: A-028142 Beluga /Upper Tyonek Pool Top of Productive Horizon: 3,457 FSL, 2,538' FWL, Sec. 6, T4N, R11 W, S.M. 8. Land Use Permit: 13. Approximate Spud Date: April 4, 200 ,~ ~'' Total Depth: 3,457' FSL, 2,538` FWL, Sec. 6, T4N, R11 W, S.M. ~ 9. Acres in Property: 2,560 14. Distance to Nearest Property: 2,130 ft 4b. Location of Well (State Base Plane Coordinates): Surface: x - 272,189.59 y - 2,362,527.30 Zone - 4 10. KB Elevation (Height above GL): (21' AGL) 87 feet 15. Distance to Nearest Well V/ithin Pool: 1,320 ft. to KBU 33-6 i 16. Deviated wells: Kickoff depth: 150 feet Maximum Hole Angle: 44.66 degrees 17. Maximum Anticipated Pressures in psig (see 20 .035) Downhole: 3,522 Surface: ;821 18. Casing Program: Size Specifications Setting Depth Top Bottom Quantity of Cement c.f. or sacks Hole C g Weight Grade Coupling Length MD TVD MD TVD (including stage data) Driven 2 133 K-55 PE 109' 0' 0' 139' .130' i 6" 13 3/8" 68 L-80 BTC 1,628' 0' 0' 1,649' 1,500' 519 sacks 12 114" 9 5/8" 40 L-80 BTC 6,47T 0' 0' 6,498' 5,370' 607 sacks f 8 112" 3 i/2" 9.3 L-80 EUE 8,632' 0' 0' 8,653' , 7,525' 1,000 sacks - 19. PRESENT WELL CONDITfON SUMMARY (To be completed for Redrill and Re-Entry O perations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (tt}: Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD ND Structural Conductor Surface intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (tt): 20. Attachments: Filing Fee ~ BOP Sketch ~ Drilling Program ~ Time v. Depth Plot Shallow Hazard Analysis Property Piat ~ Diverter Sketch Q Seabed Report ~ Drilling Fluid Program Q 20 AAC 25.050 requirements 21. Verbal Approval: Commission Representative: Date 22. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Printed Name Willard J. Tank Title Advanced Senior Drilling Engineer Signature Rhone 713-296-3273 Date March 28, 2005 Commission Use Only Permit to Drill API Number: Number: Zp~- ~ j 50- ~~3- ~0~..!'!J Permit Approval Date: See cover letter for other requirements. Conditions of approval Sa les r quired Yes ~ No ~ Mud log required Yes ® No H , r sulfide measures Yes ~ No ~ Directional survey required Yes ~ No other: T ~ ~-G 'L ~ O a 1~ s if APPROVED BY Approv r•-} ~ (~ ~ i^ MMISSION Date: / Form 10-401 Revised 0612004 Submit inDuplicate • • / ~ MARATHON MARATHON OIL COMPANY DRILLING PROGRAM Kenai Gas Field KBU 22-6 Original 3/24105 Originator: W.J. Tank Drilling Superintendent: P.K. Berga North America Drilling Manager: B.J. Roy Page 1 of 14 • • Table of Contents General Well Data ...................................................................................................................................................................3 Geologic Program Summary ...................................................................................................................................................3 Summary of Potential Drilling Hazards ....................................................................................................................................4 Formation Evaluation Summary ..............................................................................................................................................4 Drilling Program Summary ......................................................................................................................................................5 Casing Program .......................................................................................................................................................................6 Casing Design .........................................................................................................................................................................6 Maximum Anticipated Surface Pressure .................................................................................................................................6 BOPE Program ........................................................................................................................................................................8 Wellhead Equipment Summary ..............................................................................................................................................9 Directional Program Summary .............................................................................................................................................. ..9 Directional Surveying Summary ............................................................................................................................................ 10 Drilling Fluid Program Summary ........................................................................................................................................... 10 Drilling Fluid Specifications .................................................................................................................................................... 11 Solids Control Equipment ...................................................................................................................................................... 11 Cement Program Summary ................................................................................................................................................... 12 Regulatory Waivers and Special Procedures ........................................................................................................................ 12 Bit Summary .......................................................................................................................................................................... 13 Hydraulics Summary ............................................................................................................................................................. 13 Formation Integrity Test Procedure ....................................................................................................................................... 14 Page 2 of 14 • • General Well Data Weil Name KBU 22-6 Lease/License Surface Location 482' FS ,26T FW L, Sec. 6, T4N, R11 W, S.M. WBS Code DD.04.11123.CAP.DRL Slot/Pad Pad 1 - Field Kenai Gas Field Spud Date 4/4/05 (est.) KB Eiev. 87 ~ .County/Province Kenai Peninsula APF No. Ground Level Etev. 66 State /Country Alaska Well Cass Development Perm. Datum KB Totai MD 8,653' Rig Contractor Glacier Drilling Water Depth N/A Totat TVD 7,525' Rig Name #1 Water Protection Depth Comments: Geologic Program Summary Formation MD -RKB: (ft) TVD -RKB (ft) Pore Pressure (psi) Pore Pressure {p } U Possible Fluid Content Sterling A-8 (Not a Prod Target) 4,548 3,570 0.8 - 6.5 Sandstone Gas /Water Beluga (Not a Prod Target) 5,852 4,730 1.5 - 7.3 Sandstone Gas Middle Beluga (Primary Target) 6,513 5,385 3.8 - 8. Sandstone Gas Tyonek (Secondary Target) 8,425 7,297 5.8 - .0 Sandstone Gas Comments: Surface Location Coordinates from LeaseBlock lines 482' FSL, 1,267 FWL, Sec. 6, T4N, R11W, S.M. Latitude 60° 2T 38.815" N Longitude 151 ° 15' 43.580" W UTM North (Y) 2,362,527.30' UTM East (x) 272,189.59' :Tolerance Horizontal Depth Displacement (ft) MD TVD +NI-S +E/-W 7oVerance Directional Target (ft) (ft} Location m {X) (ft) Middle Beluga 6,513 5,385 3,457' FSL, 2,538' FWL, Sec. 6, T4N, R11 W, S.M. 2,975 1,271 Circle 250' radius TD J 8,653 7,525 3,457' FSL, 2,538' FWL, Sec. 6, T4N, R11 W, S.M. 2,975 1,271 Circle 250' radius Comments: Page 3 of 14 • Summary of Potential Drilling Hazards Hazard Event Discussion Lost Circulation in Low Pressure Sterling and Belu a sands Control losses by using sufficiently sized LCM. Comments: Potential Hazards Statement To comp{y 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 H2S is anticipated. ~ Gas sands will be encountered from +!- 4,548 MD (3,570' TVD) to total depth of the well. These sands will run from highly depleted to slightly above normal pressure. Lost circulation and differential sticking are potential hazards in some of the Sterling and Beluga sands. The Flo-Pro mud system that will be used to drill the well will help reduce these risks and lost circulation materials will be on location. Weighting material will available on location for proper well control.. Formation Evaluation Summary Interval LWD Electric Logs Mud Logs Surface None None None 0' -1,649' MD Intermediate None None Basic with GCA, shale density, temperature in and out, 1,649' - 6,498' MD sample collection (10' samples). Production None Reeves Quad Combo with pressures Basic with GCA, shale density, temperature in and out, 6,498' - 8,653' MD through pipe. Pull GR-Neutron to surtace sample collection (10' samples). inside casing. Completion N/A GR, CCL N/A Coring Requirements: None Comments: Page 4 of 14 • • Drilling Program Summary CONDUCTOR: 1. Drive 20" conductor to +/-100 ft. RKB. 2. Move in and rig up rotary drilling rig. 3. Install starting head 20" SLC x 21 1/4", 2M flanged. ` 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and 16" diverter line. " 5. Function test diverter and diverter valve. SURFACE: 1. Drill a 16" hole to 1,649' MD (1,500' TVD) per the directional plan. / 2. RIH with 13 3/8" casing and hang off in the elevators. Make up stab-in sub and centralizer on 5" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 13 3/8" casing. Sting out, shear out drill pipe wiper plug, and circulate drill pipe clean. TOOH with inner string. 3. Cut off 13 3/8" casing. ND diverter. 4. Install 13 3!8" slip lock connection X 13 5/8" 5M flanged multibowl wellhead./~' 5. NU 13 5/8" 5M BOP'S. Test BOP'S and choke manifold to 250/2,000 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. j 3. Drill 12 1!4" directional hole to 6,498' MD (5,370' TVD) as per directional program, short tripping as necessary (1,000' or 24 hours, but can be extended depending on hole conditions). 4. At TD circulate hole clean. Make wiper trip. TOOH. 5. Change out variable pipe rams with 9 5!8" casing rams. Run test plug and test casing rams to 2,000 psi. , 6. Run and cement 9 518" 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 1S2" bit. CBU. 2. Test shoe to leak off. Estimated EMW 13.0 ppg. ~ 3. Drill a $ 1/2" hole to 8,653' MD (7,525' 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 logging company. Run open hole logs as per plan. RD logging company. 6. TIH w/ 8 1/2" bit to TD for wiper trip. TOOH to 9 5/8" shoe and circulate until log evaluation is complete for picking EXCAPE modules. After picks are made, trip to TD and circulate clean. TOOH and laydown BHA and drill pipe. Pull wear bushing. 7. RU and run 3 i/2" EXCAPE casing string. RU logging company to correlate EXCAPE modules to open hole logs. RD logging company. j 8. Cement 3 112" casing while reciprocating. Bump plug with 500 psi over displacement pressure. WOC. 9. PU 3 112" 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 13 518" 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 arig. Page 5 of 14 Casing Program MD (ft) Connection APi Ratings. Casing ~ Makeup r. ~ °'~', = ~ 4 Size Weight f O. D. Torque Hole Size m o (in) Top Bottom (Ibs/ft) Grade Type (in) (ft-lbs) (in) V ~ 133/8 Surface 1,649 68 L-80 BTC 14.375 N/A* 16 5,020 2,260 1,545 9 5/8 Surface 6,498 40 L-80 BTC 10.625 N/A * 12 1/4 5,750 3,090 979 31/2 Surface 8,653 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 Size (in) Weight {lb/ft) Grade Setting Depth (TVD) Mud Wt When Set (Ib/gai) Frac. Grad (Ib/gal) Form Press (ib/gal) Maximum Surface Pressure (Psi) (~ ~ o U ,~ 13318 68 L-80 1,500 9.4 15.0 8. 0 3.12 2.43 3.85 9 5/8 40 L-80 5,370 9.5 13.0 1,821 1.58 1.02 2.60 31/2 9.3 L-80 7,525 10.0 15.0 9.0 1,821 1.16 2.17 1.60 Comments: Maximum Anticipated Surface Pressure Casing Size (in) Setting Depth TVD (ft) MAWP * (psi) MASP ** (psi) Mud/Gas Ratio 133/8 1,500 3,428 0 30/70 9 5!8 5,370 3,997 1,821 30/70 3 112 7,525 6,916 1,821 30!70 MAWP =Maximum allowable working pressure *" MASP =Maximum anticipated surface pressure Comments: MASP !MAWP CALCULATIONS: Surface casing: 13 3l8" (1.649' MD. 1.500' TVDI MASPtrac = ((Fracture gradient at shoe + S.F.) x .052 x TVDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPtrac = (15.0 ppg + 0.5 ppg) x .052 x 1,500' - {.1 psilft x 1,500') MASPtrac = 1,209 psi - 150 psi MASPtrac = 1,059 psi. Page 6 of 14 • • MASPbnp = BHPopB~ node ra -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnp = (1.5 ppg x .052 x 5,370') - (0.3 x 9.5 ppg x .052 x 5,370') - (0.7 x 0.1 psilft x 5,370') MASPbnp = 419 psi - 796 psi - 376 psi MASPbnp = 0 psi MASP =MASPbnp = 0 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,020) - (9.4 - 8.3) x .052 x 1,500' MAWP = 3,514 psi - 86 psi = 3,428 psi Intermediate casing: 9 5!8" !6.498' MD. 5.370' TVD) MASPr~o = ((Fracture gradient at shoe + S.F.) x .052 x TVDsn~) -Hydrostatic pressure of gas column at the shoe. MASPr~ac = (13.0 ppg + 0.5 ppg) x .052 x 5,370' - (.1 psilft x 5,370') MASPr,~~ = 3,770 psi - 537 psi MASPr~ = 3,233 psi. MASPbnp = BHP„ nasea -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnp = (9.0 ppg x .052 x 7,525') - (0.3 x 10.0 ppg x .052 x 7,525') - (0.7 x 0.1 psilft x 7,525') MASPb,,p = 3,522 psi -1,174 psi - 527 psi MASPbnp = 1,821 psi MASP =MASPbnp = 1,821 psi MAWP = (0.7 x Casing Burst) - (Mud Wt. -Backup Fluid Wt.) x .052 x TVD MAWP = (0.7 x 5,750) - (9.5 - 9.4) x .052 x 5,370' MAWP = 4,025 psi - 28 psi = 3,997 psi Production casing: 3 1!2" (8.653' MD. 7.525' TVD) MASPr~ _{(Fracture gradient at shoe + S.F.) x .052 x TVDsnoe) -Hydrostatic pressure of gas column at the shoe. MASPr~a~ _ (15.0 ppg + 0.5 ppg) x .052 x 7,525' - (.1 psilft x 7,525') MASPr~~ = 6,065 psi - 753 psi MASPt~ = 5,312 psi. MASPbnp = BHPop~ meta -Hydrostatic pressure of mud portion -Hydrostatic pressure of gas portion MASPbnp = (9.0 ppg x .052 x 7,525') - (0.3 x 10.0 ppg x .052 x 7,525') - (0.7 x 0.1 psilft x 7,525') MASPbnp = 3,522 psi -1,174 psi - 527 psi MASPbnp = 1,821 psi MASP =MASPbnp = 1,821 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 7,525' MAWP = 7,112 psi - 196 psi = 6,916 psi Page 7 of 14 • BOPE Program • Casing Test Test Casing Test Fluid Pressure. Size MAWP MASP Press Density BOPS Lawltiigh Casing (in) (psi) (psi) (psi) {Ib/gag Size & Rating (psi) (1) 13-518" 5M annular (1) 13-518" 5M pipe ram Surtace 13 3/8 3,428 0 2,000 9.4 (1) 13 5l8" 5M blind ram 25012,000 (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets {1) 13-5/8" 5M annular {1) 13-5l8" 5M pipe ram Intermediate 9 518 3,997 1,821 2,000 9.5 (1) 13 5/8" 5M blind ram 250/2,000 (1) 13-5l8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram Production 3 112 6,916 1,821 2,000 10.0 (1) 13 518" 5M blind ram 25012,000 (1) 13-5/8" 5M drilling spool with 3-1l8" 5M outlets Comments: Blowout Preventers 1 The blowout preventer stack will consist of a 13-518" x 5000 psi annular preventer, a 13-5f8" x 5000 psi double gate ram type preventer with blind rams in the2bottom and pipe rams in the top and a 13-518" x 5000 psi drilling spool {mud cross) with 3-118" x 5000 psi outlets. The choke manifold will be rated 3-1f8" 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 Surtace mud system. Both sensors will contain readouts convenient to the drillers console. Casing Test Pressures Casing test pressures are based on the lesser of (1) MASP, or (2) 70% of rated burst pressure of the casing adjusted for the mud weight used during the test less a 8.3 ppg back-up unless otherwise noted. Page 8 of 14 • Wellhead Eauipment Summary Component Description Casing Hamper Type Casing Head 13-518" 3M X 13-3/8" Slip Loc W! 2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL7, 13 5/8" x 9 5/8" Fluted PR 1 Mandrel Tubing Head 13-5/8" 3M Studded Bottom X 13-5l8" 5M Flg Top, WJ 2, 2-1/16" 5M Studded Outlets, 13 5f8" x 3 112" Manual U,AA,PSLI,PR1 Slip Adapter Flange 13-5/8" 5M X 3-118" 5M W/Seal Pocket and 3" H BPV Threads Comments: Control lines and electric cable for the EXCAPE system will be routed through the tubing head side outlet. Directional Program Summary Build Tum Coordinates .Sec. No. Description MD {ft} TVD (ft) Rate (°/i00') Rate (°/100') Dogleg. (°/100') Inclination (deg) Azimuth (deg) +NJ-S {ft), +EJ-W {ft)" VS (ft) 1 Tie On 0 0 0 0 0 0 23.14 0 0 0 2 KOP 150.00 150.00 0 0 0 0 23.14 0 0 0 3 Build up Section 3.00 0 ~ 3.00 23.14 4 End of Build 1,638.52 1,492.40 3.00 0 3.00 44.66 23.14 507.01 216.65 551.36 5 Hold Section 0 0 0 44.66 23.14 6 End of Hold 4,280.22 3,371.40 0 0 0 44.66 23.14 2,214.40 946.22 2,408.09 7 Drop Section -2.00 0 2.00 23.14 8 End of Drop to the Target 6,513.15 5,385.00 -2.00 0 2.00 0.00 23.14 2,974.92 1,271.20 3,235.13 9 TD 8,653.15 7,525.00 0 0 0 0.00 23.14 2,974.92 1,271.20 3,235.13 Comments: Vertical section calculated from a reference azimuth of 23.14° taken from surface location to bottom hole location. Potential Well Interference: Well Distance (ft) Depth (MD) KU 13-6 53.25 Surface KBU 31-7 80.74 164 KU 14X-6 138.02 Surface KU 31-7 155.95 Surface KBU 24-6 166.94 150 KBU 23X-6 190.17 Surface No serious interference exists. See attached directional plan and anticollision analysis for more details. Page 9 of 14 C_ O O PJ N_ L d C N 2 H Directional Surveying Summary C_ O O O + L C O Z L 7 O • Interval MWD Survey Magnetic Multishot Gyro Multishot Comments 0 - 1,649' X 1,649' - 6,498' X 6,498' - 8,653' X Comments: Drilling Fluid Program Summary Interva l - ND I Minimum Inventory From To Density Gel (ft) (ft) (Ib/gal) Fluid Description Additives Viscosifier Barite Gel, Gelex, Soda Ash, Caustic, Barite, 0 1,500 8.6 - 9.4 Gel / Gelex Spud Mud Polypac Supreme UL, Sodium Meta Bisulfate Flo-Vis, Polypac Supreme UL, KCI, 1,500 5,370 9.0 - 9.5 6% Flo-Pro w/ Safecarb SafeCarb F&M, Barite, Caustic, Conqor 404, Sodium Meta Bisulfate Flo-Vis, Polypac Supreme UL, KCI, 5,370 7,525 9.0 - 0.0 % 6% Flo-Pro w/ Safecarb SafeCarb F&M, Barite, Caustic, Conqor 404, ~~ Sodium Meta Bisulfate Comments: See mud prognosis for details. The mud system from the intermediate section will be utilized in the production hole section instead of building a new mud for that section. Sized CaCOs (SafeCarb) will be used to control leakoff. Page 10 of 14 Vertical Section at 23.14° [2300WinJ i West(-)/East(+) [t000fUin] / • • Drillina Fluid Specifications Interval = TVD LSRV From.. (ft) To (ft) Density (Ib/gaf) Vis (seclgt) 1 min (1b.I100ft~) PV (cP) YP (Ib/100 ftz) Fluid loss (cc) pH Drill Solids {~,) 0 1,500 8.6 - 9.4 60 - 100 N/A 25 - 35 NC - 12 +/- 9.5 < 7.5 1,500 5,370 9.0 - 9.5 40,000 + 8 - 12 7 - 9 +/- 9.5 +/- 5 5,370 7,525 9.0 - 10.0 30,000 + 10 - 14 6 - 8 +/- 9.5 +1- 5 Comments: As a standard practice for long string completions, the drilling mud that will remain above the top of cement on the 3 Yz" 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 0 rn L ~ ~ ~ C ~ m ~ N N _ L N N ~ N ~ ~ N Interval ~ ~ ~ ~ v U V N Comments 0 - 8,653' MD X X X X Closed Loop System, Full Containment Item Equipment Spec cations (quantity, design type, brand, model, flow capacity, etc) Shaker 2 -Derrick Model 2E48-90F-3TA Desander NfA Desilter 1 -Derrick Model 0522 Mud Cleaner N/A Centrifuge 2 - MI/Swaco units Cuttings Dryer NJA Cuttings Injection Marathon G&I Facility Zero Discharge N!A Comments: The solids control equipment will consist of two flowline cleaners, a desilter, and the MI centrifuge van. Included will be equipment to de-water the underflow from the mud processing equipment to allow for disposal of the cuttings and solids by slurrification and injection into the disposal well at the KGF. Page 11 of 14 • • Cement Program Summary De pth Gauge Top of Cement ~n Casing Size (in) MD (ft) TVD (ft) Hole Size (in} MD (ft) TVD (ft) Ann Vol To TOC (~I Slurry Vol (~ WOC Time (hrs) Hole Excess (%) 13 3/8 1,649 1,500 16 0 0 745 1,302 8 75 9 5!8 6,498 5,370 12 114 4,000 ~ 3,172 782 1,208 8 50 31/2 8,653 7,525 81/2 5,900 ~ 4,777 920 1,170 N/A 35 Mix Water Compressive Casing Size Density Qty .Yield Slurry Vol TOC MD Qty WL FN! Strength ~) (in) Slurry Cement Description (Iblgal) (sx) (fts/sx) (ft3) (ft) (gaUsx) Type (cc) (%o) 8 hr 24 hr 133!8 Tai! Type I Cement 12.0 519 2.51 1,302 0 11.28 Fresh 812 0 196 818 4ead Class "G" 12.5 335 2.10 704 4,000 11.92 Fresh 273 769 9 518 Tail Class "G" 13.5 272 1.85 504 5,498 9.31 Fresh 0 0 208 981 3 1l2 Tail Class "G" 15.8 1,000 1.17 1,170 5,900 4.97 Fresh 24 0 226 2,632 Comments: See cement prognosis for details and spacer specifications. Regulatory Waivers and Special Procedures AOGCC Regulation 20 ACC 25.035 (e) (1) (b) Requirement for 2 pipe rams, one blind ram, and one annular for a API 5K or above BOP stack. Marathon is requesting a waiver from the above regulation for KBU 22-6. We are requesting that the BOP stack be configured with one pipe ram instead of two, due to rig height restrictions in the running of the 3 1/2" production casing. The height restriction involves having rig crew members routing control line and electrical line through one of the tubing head outlets after the 3 1/2" casing is cemented and the BOP stack is picked up. This is prior to setting the casing on slips and cutting the casing sticking up. These lines control firing of the perforating guns and the monitoring of downhole pressure and temperature in our EXCAPE completion system. Similar waivers have been requested for EXCAPE completion wells in the Kenai Gas Field and were granted. No problems were encountered while doing this operation on any of the wells. Also due to MASP below 2,000 psi, only a 3,000 psi BOP stack would be required for this work if it was economic to change out BOP stacks for this well. If a 3,000 psi BOP stack was used then no waiver would be necessary. Utilizing the 13 5/8" 5M stack currently found on the Glacier Drilling #1 rig is more than sufficient for pressures to be encountered. , p WCt,~V ~/ t~~CGSS ~t rvt ~~ Page 12 of 14 • Bit Summary • Interva l - MD TYP® Recommended Estimated From ft) To (ft} Size {in} Manufacturer Model No. IADC WOB (ki ) RPM Rotating Houra ROP ft/hr 0 1,649 16 Christensen MX-1 115 1 - 4 80 - 350 1,649 6,498 12 114 Christensen HCM406 M333 Up to 50 Motor 6,498 8,653 8 1!2 Christensen HCM605 M323 Up to 25 Motor Comments: If a second bit is necessary for the 12'1<" hole a MX-C3 (IADC 137) should be used to finish this section. Back up bits for the 8'/s" 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 gp°l° W P 95% eff Max Rate Hole Sections Used Qty Make Model (in} (in) (psi) (gal/stroke} (spm/gpm) 5 8 2,597 2.04 125 / 255 Surface 3 National Oil A600PT 5 8 2,597 2.04 1251255 Intermediate Well 5 8 2,597 2.04 1251255 Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Hole Standpipe Min Nozz{e Depth-MD Size Pump Rata Pressure AV ECD Size (ft) (in) ( m) (si) (fpm) (Ib/gal) (32"s) Remarks 3 -18's 0 - 1, 649 16 650+ 1,500 69 1-15 1,649 - 6,498 12 1!4 662 2,000 130 6 -13's Actual Data from CLU 8 (~ 6,722' MD) 6,498- 8,653 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'/a", and 8'I2" holes were calculated using 5"drillpipe. 5" drillpipe should be used to drill all hole sections to maximize hole cleaning, while minimizing stand pipe pressure. Page 13 of 14 • • Formation Integrity 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 i!2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Page 14 of 14 • • Marathon Oil Well KBU 22-6 Diverter Flow line 21 il4" 2M Diverter ~~ 16" Automatic Knife Valve ~~ Diverter Spool ~• t 16" Diverter Line ,' Marathon Oil Well KBU 22-6 BOP Stack 13 5/8" 5M Annular Preventer ~-~ 13 5/8" 5M Gross s ~ Marathon Oil Weil KBU 22-6 Choke Manifold To Gas Buster To Blooey Line Bleed off Line to Shakers U • Surface Use Plan for Kenai Beluga Unit, well KBU 22-6 Surface location: Anticipated at 482' FSL, 1,267' FWL, Sec. 6, T4N, R11 W, S.M. 1) Existing Roads Existing roads which will be used for access to KBU 22-6 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 22-6. 3) Location of existing wells Well KBU 22-6 will be drilled on Kenai Gas Field (KGF) pad 14-6. A pad drawing is enclosed that shows existing wells and the proposed location of KBU 22-6. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the KGF pad 14-6 are shown on the enclosed pad drawing. A flowline will be installed from the KBU 22-6 wellhead to an new line heater and existing separator. 5) Location of Water Supply A water supply well exists on the pad that KBU 22-6 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) Ancillary Facilities A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose. Bottled water wil{ 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) Ptans for reclamation of the surface KBU 22-6 will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of KBU 22-6 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 CIRI Native Corporation. 11) Operator's Representative and Certification I hereby certify that I, or persons under my direct supervision, have inspected the proposed drill site and access route; that I am familiar with the conditions that currently exist; that the statements made in this plan are, to the best of my knowledge, true and correct; and that the work associated with operations proposed herein will be performed by Marathon Oil Company and its contractors and subcontractors in conformity with this plan and the terms and conditions under which it is approved. This statement is subject to the provisions of 18 U.S.C. 1001 for the filing of a false statement. Date: `~ ~ ~ ~ Name and Title: F» ~ ~ /~`1/~- Willard J. Tank, dvanced Senior Drilling Engineer Marathon Oil Company P.O. Box 3128 Houston, TX 77253 (713) 296-3273 I I I CVIe- ~I~ t i I I SECTION 6 --~. '{~~~-~ '°~" /K B U FUTURE WELL -" -- - - - ~~"`~'''`~t'?.t;? ~~~ Y~z,s~~,e~~~.~7s . . . 18" CONDUCTOR PIPE ' ' PROPOSED K F G ~ '~' - L K.B.U. 22-6 -fit, ~» ~,,;:,~ ~` _~! ,f,,. ~ ` DIA. WELL CELLAR 8 ASP ZONE 4 NAD27 . . . PAD 14-6 K B U 21-6 1s" ONDUCTOR PIPE t 2U .. dS.; r.;1 tt~~-a ~~' j~~ ~~ ._~~ ~t= ' N: 2362537.28 . . . ASP ZONE 4 NAD27 D1A. WELL CELLAR i i - - _, E: 271988.97 N: 2362530.204 ASP ZONE 4 NAD27 LAT: 60°27'38.876" N E: 272129.169 N: 2362527.30 LONG: 151°15'47.584" W LAT: 60°27'38.832" N E: 272189.59 FWL = 1066' LONG: 151 °15'44.786" W LAT: 60°27'38.815" N FSL = 490' FWL = 1207' LONG: 151 °15'43.580" W ELEV = 66.16' (MSL) FSL = 485' FWL = 1267' SECTION 6, ELEV = 65.97' {MSL} FSL = 482' TOWNSHIP 4N SECTION 6, ELEV = 66.0' (MSL) / RANGE 11 W, SM AK TOWNSHIP 4N SECTION 6, RANGE 11 W, SM AK TOWNSHIP 4N ~' - J 207' FWL K RANGE 11W,~MAK .G.F. 14-6 p K.B.U. 21-6 ' 1267 FWL K.G.F. 14-6 K.B.U. 22-6 I I KENAI GAS FIELD « PAD 14-6 z _~_ . ,--_~ { / ' ' ~J U 1f3.0 X'~s.u ;F k!:_E: ' ' SftE1~ ~4i1 GUA~L P A L I K~t.l, Z1-.~ 3 G ~ 51~~; Ul X='~~~~,(ik~,~1 1 6 12 1 7 SECTION LINE r r- C7 CV (,~ Y ~ Y J i m --~ I i Y ILL' ~ ~ '~ ~ ~, i~ ~~~ t~ ..._...Jry ...._ ~ ~;~ N ~~" tV m Y 3 1 --; ---~ l`~ u`~ x tdE_t... i-~Ol1SF ~~~ , X=2?2,122.2G Y-2, 382, 3~ I. 1 I Y'-2,362, 305„`iEi NOTES 1. BASIS OF COORDINATES IS U.S.C. 8 G.S. TRI STATION AUDRY IN A.S.P. ZONE 4. (NAD 27) AVERAGE CONVERGENCE OF POINTS SHOWN: 01°5'58". 2. AUDRY LOCATION: LAT: 60°30'50.559"N LONG 151°16'37.445"W NORTHING = 2,382,045.42 FASTING = 269,86675 ' f - T • ~^~ T PROJECT M lo-MJ~AALK~C>co~V^11~,1~ ARATHON AIWA RBC~ION K.E3.lJ. 24-6 v~~~~ ~ ~~i~usL X=2 72, ` k3~. ~9 Y~ 2,~~2,354.C?4 NORTH SCALE 0 60 120 FEET REVISION: 1 KENAI GAS FIELD PAD 14-6 WELL K.B.U. 22-6 DATE: 3/24/05 AND FUTURE WELL ASBUILT SURFACE DRAWN BY: DME LOCATION DIAGRAM SCALE: 1"=60' PROJECT NO. 0530 Consultin GfOU ENGINEERING/MAPPING/SURVEYING/TESTING BOOK NO. 04-15 9 P P.O. BOX 468 SOLDOTNA, AK. 99669 LOCATION McLane esting vDIGE: Iso~>z83-4z,e FAX: (907)283-3265 S6 T4N R11W SEWARD MERIDIAN, ALASKA SHEEt 'I OF EMAIL: SAMCLANE@MGLANECG.COM • ~ , ~„" ro~ NORTH I ~. p'Ipeliae _~ _ ~ -~ °~ ~~~ I ~. _.. .--- ~_. - . _ ~ Gravll4 `~I alp., WNl ~ i 1 ~ i .~ Pad_,33-30 ~~=_ i~ ,, ~ ~• _~ r ' ~ ;,Poppy Lan ~'cotiP Yj~ ' ~ PHvat~Roed - _ i ~~ .iF // _ ~z3~ooo0 I~_. r J~ ~ ~ r, _, ~ I~ Y, /f iEEi i i `" t . ~: , __`: _ .-z~-" Pad 43-32 ~ h~~,r, L.aldirl~ ti~ '° _ I Pad 3 4 .3 1 ~ _ _~Gas wells Stnps } KENAI CiAS FIELD ~ i~ + .I ~ . III 6 ~ 4 ~ li ravel ri ~ ' M ~ `Padl 14-8 =- _--- - - ~° :i ow ,n _~: ~. ~~~ Pad-33-1~ . ~ ~' ;~s Wells r ~, i_, I i -- Pad 41 -7 Pad 14-4 1'` ~, ~~ Projectr Location T ~ v ~y I„ L.~ •~ 12 ~ 8 9 ,, 4 ~ 1 1 ~ PrivstsGRoad ~~ i• .: p , . a Pad 41-18 _~ 1 ~ 2 c j Lane ~ z c' I ' ~-^ •-- ~ 14 COOK INLET 1 P~1~44-18 1 ~ '~ ~'` ;-~`3 z I ~ I Abandoned ~' - ~~ - ~ ~:~~~"r ~ _ .~ Gn ~ ~ ~ ,..~R~ StdP .~ ~ 'i~, ~~ ~ _ ,,, o _ - Landit~ .~ .--..c K. ..~ ..- _ ~-1 I ~~2:1 21t F-~ ~22r1 ..- (,_ AS t Kanai Unit BouRdar ~ ~ ~' - '~ . • Ka1i[onsky ~ y , L 'i _ i• !~. ~ - r' - _ I 1 ~ • ~' - t ~ l 25' • ~ 25 ~ 30 ~ .~ 2gl ~ X'. ~ t e ~ 6 G{ • ` • . i >.. ~ ~ p r r ~~ . ~' ~~'`~U ~'„y~/^~ - Rejleetx»E a ';. f 3 '~~ 35 i~ 31 32 e:: Lake ~ I 4,-.. .- r ~iKasilof Rivor -. i ~ '~. ' •~, ~---- ,fit--7- ~; ~'~ j , t x:.n ] N. ~- ..T /1i ~' ~ ~ I • 2 -1 1. 6 .. ,5 d .:fir 3 ._- 2 t`q n99 _ (f ; r~~n , `~~ ll l~1 F ~ m Tandi~, I V 1, !2 r__... _ Strip ,, ._ .. , Source Map: U363, 1951 Kenai, Alaska B-4, 1:83,360 SCALE 1.63360 l f: 1 l t. M4, ~. /Y./1 ~/Ir1n Rf!'YI x0011 !i000 li'%10 ifYl0:1 '1000 rEEI s ;. . .1 I 1 1 •, NIIOMErERS i.-T't l'Ti i i i i._ .. -... _- Marathon Oil Company Kenai Gas Field Area Map u map„I:I;r ~i ca Alap p+g l • BelugalUpp~er Tyanek ~. C am{~latfnn • .+ ~.•' ~'S 111-R "I ~ VII ~•~ UNIT ~_ BOUNDARY. .~ 1~. t + ~.~. s ~~. ~.~ Keu ax•s ~ L~~ ~~ ~. ,, ~~ ~~ ~ ~' + i!~ Cl ~ i L .~ ~ ~~ ~...._.y ~~r + `~ ~~ .~ ~r ~~ r~ FZ?R1tA'AT1t3N c•~ ioa- t~ i a r r,~iLE r~i~F.arri~ ~r•a ~~~ ~ ~ 1~~r.~'.ar•rr ~L_~~h:.RRE~_ i~_~ra G ONFtDENT1At KENAI FIELD K8U ZZ-6 Lor~tian ~r~,~n,' ~+~as n ~freahenfi.ken~i5beluq~tikGu~'2-+~_loc.th 1t'1 GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT °o -aoo N I U p N m N 400 800 1200 1600 2000 2400 ~ 2800 ... t 3200 a+ Q d Q 3600 R V 4000 ~ 4400 L V 4800 5200 5600 6000 6400 6800 7200 7600 8000 ~ w MARATHON Oil Company LOCBtiOn: Kenai Peninsula, Alaska(Imported) $IOt: Slot #KBU22-6 INTEQ Field: Kenai Gas Field Well: KBU22-6 MARATHON InStallatiOn: Pad 14-6 Wellbofe: KBU22-6 Vers#1 RKB E-evation: KOP 6.00 12.00 DLS: 3.00 deg/1 24.00 30.00 36.00 ~, 42.00 13 318" Casing Pt~ EOC 7' WELL PROFILE DATA Point MD Inc Azi ND North East deg/100ft V. Sect Tie on 0.00 0.00 23.14 0.00 0.00 0.00 0.00 0.00 OOft KOP 150.00 0.00 23.14 150.00 0.00 0.00 0.00 0.00 End of Build 1638.62 44.66 23.14 1492.40 507.01 216.65 3.00 551.36 End of Hold 4280.22 44.66 23.14 3371.40 2214.40 946.22 0.00 2408.09 Target KBU22-6 Top Mid 6513.15 0.00 23.14 5385.00 2974.92 1271.20 2.00 3235.13 T.D. & Target KBU22-6 T 8653.15 0.00 0.00 7525.00 2974.92 1271.20 0.00 $ 3235.13 Begin Drop 40.66 36.66 DLS: 2.00 deg/100ft 28.66 24.66 20.66 16.66 12.66 8.66 4.66 Targqet-Mid Beluga -EOD ~ ~ 0.66 g 518" Casing Pt. KBlJZ2-6 Top Middle Beluga TD - 3 112" Casing Pt ~' ~" KBU22-6 TD -400 -0 400 800 1200 1600 2000 2400 2800 3200 3600 Scale 1 cm = 200 ft Vertical Section (feet) -> Azimuth 23.14 with reference 0.00 N, 0.00 E from Slot #KBU22-6 Created by : Planner Date plotted : 22-Feb-2005 Plot reference is KBU2 -6 Vers#1. Ref wellpath is KBU22-6 Vers#1. Coordinates are in feet reference Slot #KBU22-6. True Vertical Depths are reference Rig Datum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 87.00 ft. Plot North is aligned to TRUE North. 3600 3400 3200 3000 2800 2600 2400 2200 2000 A ~ 1800 ..~ tt,, 1600 O Z 1400 1200 1000 800 600 400 ~ 200 0 0 I~ 0 U -200 ~`~ MARATHON Oil Company INTEQ Location: Kenai Peninsula, Alaska(Imported) SIOt: Slot #KBU22-6 FiBld: Kenai Gas Field Well: KBU22-6 Installation: Pad fa-s Wellbore: KBU22-s vers#1 MARATHON ~: Planner I: 22-Feb-2005 2- a 1. '-6 Vers#1. t reference siot #KBUZZ-s. ~re reference Rig Datum. reference Rig Datum. a level: 87.00 ft. i TRUE North. -200 0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400 Scale 1 cm = 100 ft East (feet) -> MARATHON Oil Company,Slot #KBU22-6 Pad 14-6, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska(Imported) • PROPOSAL LISTING Page 1 Wellbore: KBU22-6 Vers#1 Wellpath: KBU22-6 Vers#1 Date Printed: 22-Feb-2005 ~~~ INTEQ Weltbare -- - Name. Created LasfRevised -{ KBU22-6 Vers#1 22-Feb-2005 22-Feb-2005 I f) _ ____ _ _ ___ i LNam® - - _ __ ~ Government ID v ~ _ ~ LastRevised _ _ KBU22-6 22-Feb-2005 i,~, ~taffation __ re Eastina Northing Coord Svstem Name North Alic~nm~nt _ 14-6 270993.1910 2361975.0460 ~ AK-4 on NORTH AMERICAN DATUM 1927 datur~ True »R~d --- -- ----- - -1 ~®. -.. C:~~N.... Af...~ll.:.,... !`..nil C..c.4n... kl~mn 1Jnrfh Alinnmunt _ ___-_-T , ~ _. _ -..-.._ _ .. __-. ~ _ _ Created By- - - - - Comments - - - - - - - - - - All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and TVD's are from Rig (Datum #1 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 23.14 degrees Bottom hole distance is 3235.13 Feet on azimuth 23.14 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated C: MARATHON Oil Company,Slot #KBU22-6 Pad 14-6, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska(Imported) • PROPOSAL LISTING Page 2 Wellbore: KBU22-6 Vers#1 Wellpath: KBU22-6 Vers#1 Date Printed: 22-Feb-2005 ~/~ INTEQ Weil ath 'R e ort MD[ft) Inc[deg)' Azi[deg] ND(ftJ Vertical Depth SS North[ftJ East[ft] Station Position(Grid North Station Position(Grid East Dogleg [deg/10 Oft Vertical Section(f t _ Station Comment 0.00 0.00 23.14 0.00 -87.00 O.OON 0.00E 2362527.12 272189.08 0.00 0.00 Tie on 100.00 0.00 23.14 100.00 13.00 O.OON 0.00E 2362527.12 272189.08 0.00 0.00 150.00 0.00 23.14 150.00 63.00 O.OON 0.00E 2362527.12 272189.08 0.00 0.00 KOP 2DS Kick off Point 250.00 3.00 23.14 249.95 162.95 2.41N 1.03E 2362529.51 272190.16 3.00 2.62 350.00 6.00 23.14 349.63 262.63 9.62N 4.11E 2362536.66 272193.38 3.00 10.46 450.00 9.00 23.14 448.77 361.77 21.62N 9.24E 2362548.56 272198.73 3.00 23.51 550.00 12.00 23.14 547.08 460.08 38.38N 16.40E 2362565.17 272206.21 3.00 41.74 650.00 15.00 23.14 644.31 557.31 59.84N 25.57E 2362586.46 272215.79 3.00 65.08 750.00 18.00 23.14 740.18 653.18 85.96N 36.73E 2362612.35 272227.45 3.00 93.48 850.00 21.00 23.14 834.43 747.43 116.65N 49.84E 2362642.79 272241.15 3.00 126.85 950.00 24.00 23.14 926.81 839.81 151.84N 64.88E 2362677.68 272256.86 3.00 165.12 1050.00 27.00 23.14 1017.06 930.06 191.42N 81.79E 2362716.93 272274.53 3.00 208.16 1150.00 30.00 23.14 1104.93 1017.93 235.29N 100.54E 2362760.43 272294.11 3.00 255.87 1250.00 33.00 23.14 1190.18 1103.18 283.33N 121.07E 2362808.07 272315.55 3.00 308.12 1350.00 36.00 23.14 1272.59 1185.59 335.41N 143.32E 2362859.71 272338.80 3.00 364.75 1450.00 39.00 23.14 1351.91 1264.91 391.39N 167.24E 2362915.21 272363.79 3.00 425.62 1550.00 42.00 23.14 1427.94 1340.95 451.10N 192.76E 2362974.42 272390.44 3.00 490.56 1638.62 44.66 23.14 1492.40 1405.40 507.01N 216.65E 2363029.86 272415.40 3.00 551.36 EOC End of Build 1649.30 44.66 23.14 1500.00 1413.00 513.92N 219.60E 2363036.71 272418.48 0.00 558.87 13 3i8" Casin Pt. 13 3/bin Casin 1700.00 44.66 23.14 1536.06 1449.06 546.69N 233.60E 2363069.21 272433.11 0.00 594.50 1800.00 44.66 23.14 1607.19 1520.19 611.32N 261.22E 2363133.30 272461.96 0.00 664.79 1900.00 44.66 23.14 1678.33 1591.33 675.96N 288.84E 2363197.39 272490.81 0.00 735.08 2000.00 44.66 23.14 1749.46 1662.46 740.59N 316.46E 2363261.48 272519.66 0.00 805.37 2100.00 44.66 23.14 1820.59 1733.59 805.22N 344.08E 2363325.57 272548.51 0.00 875.66 2200.00 44.66 23.14 1891.72 1804.72 869.86N 371.69E 2363389.66 272577.36 0.00 945.94 2300.00 44.6 23.14 1962.85 1875.85 934.49N 399.31E 2363453.75 272606.21 0.00 1016.23 2400.00 44.66 23.14 2033.98 1946.98 999.13N 426.93E 2363517.84 272635.06 0.00 1086.52 2500.00 44.66 23.14 2105.11 2018.11 1063.76N 454.55E 2363581.93 272663.92 0.00 1156.81 2600.00 44.66 23.14 2176.24 2089.24 1128.40N 482.17E 2363646.02 272692.77 0.00 1227.10 2700.00 44.66 23.14 2247.37 _ 2160.37 1193.03N 509.79E 2363710.11 272721.62 0.00 1297.38 2800.00 44.66 23.14 2318.50 2231.50 1257.67N 537.41E 2363774.20 272750.47 0.00 1367.67 2900.00 44.66 23.14 2389.63 2302.63 1322.30N 565.02E 2363838.29 272779.32 0.00 1437.96 3000.00 44.66 23.14 2460.76 2373.77 1386.93N 592.64E 2363902.38 272808.17 0.00 1508.25 3100.00 44.66 23.14 2 31.90 2444.90 1451.57N 620.26E 2363966.47 272837.02 0.00 1578.54 3200.00 44.66 23.14 2603.03 2516.03 1516.20N 647.88E 2364030.56 272865.87 0.00 1648.82 3300.00 44.66 23.14 2674.16 2587.16 15 0.84N 675.50E 2364094.65 272894.72 0.00 1719.11 3400.00 44.66 23.14 2745.29 2658.29 1645.47N 703.12E 236415 .74 272923.57 0.00 1789.40 350 .00 44.66 23.14 2816.42 2729.42 1710.11 N 730.74E 2364222.83 272952.43 0.00 1859.69 3600.00 44.66 23.14 2887.55 2800.55 1774.74N 758.36E 2364286.92 272981.28 0.00 1929.98 3700.00 44.66 23.14 2958.68 2871.68 1839.38N 785.97E 2364351.02 273010.13 0.00 2000.26 380 .00 44.66 23.14 3029.81 2942.81 1904.01 N 813.59E 2364415.11 273038.98 0.00 2070.55 3900.00 44.66 23.14 3100.94 3013.94 1968.64N 841.21E 2364479.20 273067.83 0.00 2140.84 4000.00 44.66 23.14 3172.07 3085.07 2033.28N 868.83E 2364543.29 273096.68 0.00 2211.13 4100.00 44.66 23.14 3243.20 3156.21 2097.91 N 896.45E 2364607.38 273125.53 0.00 2281.42 4200.00 44.66 23.14 3314.34 3227.34 2162.55N 924.07E 2364671.47 273154.38 0.00 2351.70 4280.22 44.66 23.14 3371.40 3284.40 2214.40N 946.22E 2364722.88 273177.53 0.00 2408.09 Be in Dro End of Hold 4380.22 42.66 23.14 3443.74 3356.74 2277.88N 973.35E 2364785.83 273205.86 2.00 2477.12 4480.22 40.66 23.14 3518.45 3431.45 2339.OON 999.47E 2364846.43 273233.14 2.00 2543.59 4580.22 38.66 23.14 3595.43 3508.43 2397.68N 1024.54E 2364904.62 273259.34 2.00 2607.41 4680.22 36.66 23.14 3674.59 3587.59 2453.86N 1048.55E 2364960.33 273284.42 2.00 2668.50 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Datum #1 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 23.14 degrees Bottom hole distance is 3235.13 Feet on azimuth 23.14 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON Oil Company,Slot #KBU22-6 Pad 14-6, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska(Imported) ;7 PROPOSAL LISTING Page 3 Wellbore: KBU22-6 Vers#1 Wellpath: KBU22-6 Vers#1 Date Printed: 22-Feb-2005 . 74~f,~` ~~ INTEQ Weil ath R e ort - - MD[ftl ` i0c[~9l Azi[deg] 'TVD[ft] Vertical Depth SS North[ft] East[ftj Station Position(Grid North Station. Position(Grid East Dogleg [degfl0 Oft Vertical Section[f t Station Comment 4780.22 34.66 23.14 3755.84 3668.84 2507.46N 1071.45E 2365013.48 273308.34 2.00 2726.79 4880.22 32.66 23.14 3839.07 3752.07 2558.43N 1093.23E 2365064.02 273331.09 2.00 2782.21 4980.22 30.66 23.14 3924.19 3837.19 2606.69N 1113.85E 2365111.87 273352.63 2.00 2834.69 5080.22 28.66 23.14 4011.08 3924.08 2652.19N 1133.29E 2365156.99 273372.94 2.00 2884.17 5180.22 26.66 23.14 4099.65 4012.65 2694.87N 1151.53E 2365199.31 273392.00 2.00 2930.59 5280.22 24.66 23.14 4189.78 4102.78 2734.69N 1168.55E 2365238.80 273409.77 2.00 2973.89 5380.22 22.66 23.14 4281.38 4194.38 2771.59N 1184.31E 2365275.38 273426.24 2.00 3014.02 5480.22 20.66 23.14 4374.31 4287.31 2805.53N 1198.81E 2365309.04 273441.39 2.00 3050.92 5580.22 18.66 23.14 4468.48 4361.48 2836.46N 1212.03E 2365339.71 273455.20 2.00 3084.56 5680.22 16.66 23.14 4563.76 4476.76 2864.35N 1223.95E 2365367.37 273467.65 2.00 3114.90 5780.22 14.66 23.14 4660.05 4573.04 2889.17N 1234.56E 2365391.98 273478.73 2.00 3141.88 5880.22 12.66 23.14 4757.21 4670.21 2910.88N 1243.83E 2365413.51 273488.42 2.00 3165.50 5980.22 10.66 23.14 4855.14 4768.14 2929.47N 1251.77E 2365431.93 273496.71 2.00 3185.70 6080.22 8.66 23.14 4953.72 4866.72 2944.89N 1258.37E 2365447.23 273503.60 2.00 3202.48 6180.22 6.66 23.14 5052.82 4965.82 2957.15N 1263.60E 2365459.38 273509.07 2.00 3215.81 6280.22 4.66 23.14 5152.33 5065.33 2966.21 N 1267.48E 2365468.37 273513.12 2.00 3225.67 6380.22 2.66 23.14 5252.12 5165.12 2972.08N 1269.98E 2365474.19 273515.73 2.00 3232.05 6480.22 0.66 23.14 5352.08 5265.08 2974.74N 1271.12E 2365476.83 273516.92 2.00 3234.94 6498.15 0.30 23.14 5370.00 5283.00 2974.88N 1271.18E 2365476.96 273516.98 2.00 3235.09 9 5/8" Casin Pt. 9 5/bin Casin 6513.15 0.00 23.14 5385.00 5298.00 2974.92N 1271.19E 2365477.00 273517.00 2.00 3235.13 Target-Mid Beluga -EOD, KBU22-6 Top Middle Belu a S/C Kick off Point 6600.00 0.00 23.14 5471.85 5384.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 67 0.00 0.00 23.14 5571.85 5484.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 6800.00 0.00 23.14 5671.85 5584.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 6900.00 0.00 23.14 5771.85 5684.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7000.00 0.00 23.14 5871.85 5784.85 2974.92N 1271.19E 2365477.00 _ 273517.00 0.00 3235.13 7100.00 0.00 23.14 5971.85 5884.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7200.00 0.00 23.14 6071.85 5984.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7300.00 0.00 23.14 6171.85 6084.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7400.00 0.00 23.14 6271.85 6184.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7500.00 0.00 23.14 6371.85 6284.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7600.00 0.00 23.14 6471.85 6384.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7700.00 0.00 23.14 6571.85 6484.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7800.00 0.00 23.14 6671.85 6584.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 7900.00 0.00 23.14 6771.85 6684.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 8000.00 0.00 23.14 6871.85 6784.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 6100.00 0.00 23.14 6971.85 6884.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 8200.00 0.00 23.14 7071.85 6984.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 8300.00 0.00 23.14 7171.85 7084.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 8400.00 0.00 23.14 7271.85 7184.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 8500.00 0.00 23.14 7371.85 7284.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 8600.00 0.00 23.14 7471.85 7384.85 2974.92N 1271.19E 2365477.00 273517.00 0.00 3235.13 8653.15 0.00 0.00 7525.00 7438.00 2974.92N 1271.19E 2365477.00 _ 273517.00 0.00 3235.13 TD - 3 112" Casing Pt, KBU22-6 TD, 3 ~ 1/tin Casin End of Turn All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Datum #1 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 23.14 degrees Bottom hole distance is 3235.13 Feet on azimuth 23.14 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated MARATHON Oil Company,Slot #KBU22-fi Pad 14-6, MARATHON Kenai Gas Field,Kenai Peninsula, Alaska(Imported) PROPOSAL LISTING Page 4 Wellbore: KBU22-6 Vers#1 Wellpath: KBU22-6 Vers#1 Date Printed: 22-Feb-2005 ~.^ INTEQ comme --- - nts MDjft TVD ft Eas ft North ft -- Comment 150.00 1638.62 150.00 1492.40 0.00E 216.65E O.OON KOP 507.01 N EOC 1649.30 1500.00 219.60E 513.92N 13 3/8" Casin Pt. 4280.22 3371.40 946.22E 2214.40N Be in Dro 6498.15 5370.00 1271.18E 2974.88N 9 5/8" Casin Pt. 6513.15 5385.00 1271.19E 2974.92N Tar et-Mid Belu a -EOD 8653.15 7525.00 1271.19E 2974.92N TD- 31/2" C_asingPt_______ Hoie Sections ~ Diameter Start Start Start Start End End End EndinEast[ftj Wellbore i finl MDfftl TVDtftI Northfftl Eastfftt MDfftt TVDfft1 Northfftl ~ , _ __ __ _ _i rf'_~cinnc - - -- - - -Name Top ft Top TVD ft Top North ft Top ast ft Shce M ft Shoe TVD ft Shoe North ft Shoe a t -- Wellbore- 13 3/bin Casin 0.00 0.00 O.OON 0.00E 1649.30 1500.00 513.92N 219.60E KBU22-6 Vers#1 9 5/bin Casin 1649.30 1500.00 513.92N 219.60E 6498.15 5370.00 2974.88N 1271.18E KBU22-6 Vers#1 3 1/tin Casin 6498.15 5370.00 2974.88N 1271.1E 8653.15 7525.00 2974.92N 1271.19E KBU22-6 Vers#1 All data is in Feet unless otherwise stated Coordinates are from Slot MD's are from Rig and ND's are from Rig (Datum #1 87.Oft above mean sea level ) Vertical Section is from O.OON 0.00E on azimuth 23.14 degrees Bottom hole distance is 3235.13 Feet on azimuth 23.14 degrees from Wellhead Calculation method uses Minimum Curvature method Prepared by Baker Hughes Incorporated ~ ~ _ MARATHON Oil Company ~~•• LoCatiOn: Kenai Peninsula, Naska(Imported) SIOt: Slot MK8U22.6 Field: KenaiGaaFleld wail: Keuzz~ MARATHON ~~~ INTEQ Installation: Pad fay Wellbore: Keuzz~ vera#1 reeled by : tanner _ Date plotted : 22-Feb-2005 Plot reference is KBU22-6 Vers#1. 640 `D ro ~ Ref wellpath is KBU22-6 Vers#f . N NN Coordinates are in feet reference Slot #KBU22-6. m m True Vertical Depths are reference Rig Datum. y ~ Measured Depths are reference Rig Datum. 600 1600 Rig Datum: Datum #1 3200 Rig Datum to mean sea level: 87.00 K. Plot North is aligned to TRUE North. 560 . 3100 520 480 3000 440 2900 1400 400 360 2800 1300 320 ~O ~.1 /~ 2700 1200 7400 y 280 ~ 7300 `~ 2600 7200 C 240 1100 7100 Z 7000 200 2500 1000 6900 6800 160 6700 ~ 2400 900 6600 120 w 6500 ~ 1200 6400 800 ~~ ~~1 6300 ' 2300 2 80 700 - ~0~.1 .1100 600 1900 40 1000• .2200 1800 500 900 400 1700 0 2100 800 • 1600 oOq-6 600 1500 3400 -40 2000 1400 3300 o ~ 200 3200 N ~ 1300 3100 3040 -80 1900 200 ~ ,~J31 12 2900 U ~ 1 10400 ~eli37y KgU24 6> ~ 120 ~ 1500 ~ Y -120 -80 -40 -0 40 80 120 160 200 240 280 320 360 400 440 480 Scale 1 cm = 20 ft East (feet) -> ~ ~ MARATHON Oil Company .... _-_ M ~~~~ location: Kenai Fanlnsula, Alaaka(Imported) Slot: slot #Keuzz~ Field: KanalGasFleld weu: KBUZZ~ MARATHON INTEQ Installation- Padu-s weubore: Keuzz•svaraxf 'I 4400 L T O Ref wellpath Is KBU22-6 Vers#1. Coordinates are in feet reference Slot#KBU22-6. ~~/2 1 ~s True Vertical Depths are reference Rig Datum. 4200 - 4000 ,6 4600 4800 KU21-6 ~ 8600 ~ 9000 - 9400 ~KDU5l Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 87.00 K. Plot North is aligned to TRUE North. 3800 3600 3400 3200 i KBUZZ-s 3000 i 4800 2800 4400 A 4200 .-. 4000 ~ 2600 w 3800 ... ~ 2400 3600 KTU43-6X ~ _ Z ~ 8600 2200 KU43- 8200 2000 KBU23X-6~ 3200 KTU43-6X 7800 - 6400 7 '46 06 7 0 400 6000 3000 7200 1800 - Ksu3s-s 4d,(~p0 g$' 5600 00 74 7000 5400 ~ 2800 '. KBU33-6X 66 6200 1600 5200 - 5000 2600 580 00 74 4800 6600 . 5400 ~ ' 1400 4600 y~ 6000 5000 24 00 400 5600 4400 4600 1200 4200 2200 KTUZa-sH 5200 440 ~ . 5000 420 x 4000 ~ 1000 - 2000 4800 40 0 3800 0 4600 3800 I~ 800 3600 1800 4400. 3600 U L r rq <p ry TG? 9 'fB ~ ~ G 600 - j Jer ~ ~ti w ~~s ~ (/1 Y b~ -200 -0 200 400 600 i 800 1000 1200 1400 1600 i 1800 2000 2200 2400 2600 2800 Scale 1 cm =100 ft East (feet) -> w ~ _ MARATHON Oil Company •~•^ LOCatIOn: Kenai Peninsula, Alaska(Imported) $IOt: Slot #KBU22-6 E4AKER '~~ Field: Kenai Gas Field Well: KBU22-6 Installation: Pad 1as Wellbore: KBU22-s vers#1 INTEQ 350 340 330 300 290 280 270 260 250 240 Kv13-6 TRUE NORTH 0 10 20 30 ~o~ ~ ~ P~ N "k~ ryp~ M I~ C J Jam' J ~ JJ ~ Y ~~ m Y .t Normal Plane Travelling Cylinder -Feet All depths shown are Measured depths on Reference Well M MARATHON Created by : Planner Date plotted : 22-Feb-2005 Plot reference is KBU22-6 Vers#1. Ref wellpath is KBU22-6 Vers#1. Coordinates are in feet reference Slot #KBU22-6 True Vertical Depths are reference Rig Dalum. Measured Depths are reference Rig Datum. Rig Datum: Datum #1 Rig Datum to mean sea level: 87.00 ft. Plot North is aligned to TRUE North. 60 70 80 90 100 110 120 MARATHON O[I Company CLEARANCE LISTING Page 1 ~t~~ KBU22-6 Vers#1, KBU22-6 Vers#1 Date Printed: 22-Feb-2005 Slot #KBU22-ti, Pad 14-6 Kenai Gas Field, Kenai Peninsula, , MARATHON IN~ EQ Alaska(Imported) 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 Name Created Last Revised KBU22-6 Vers#1 - - - _ ---- _ _ 22-Feb-2005 - _ - __ __ _ 22-Feb-2005__ - - _ r ~~~ ,~- -- - - - _ - - _ _ . ~ _r_ _ Name. Government ID _ ~ast Revised KBU22-6 _ _ 22-Feb-2005 -Name. Grid Northinn-Grid Eastirxt Latitude Longitude North _ ,East J ns~€a~~~an ~~, _ _~ Na Eastin No in cord S stem Name N Alignment _ Pad 14-6 270993.191 2361975.046 AK-4 on NORTH AMERICAN DATUM 1927 datu True - --- --- 'Fiefd ______ __ _ Name ~Easting ~ Northing ~Coord System Name North Alionment iC'la~ry.~~tan _~t~tnm~rri -- - - Offset WeHName ,Offset Wetlbore ~ Offset 51ot Offset Structure Minimum Distance ft MD[ft] Diverging From[ft] Ellipse Separation ft Ellipse MD[ft] Clearance Factor Clearance MD[ft] KU13-6 KU13-6 slot #KU 13-6 Pad 14-6 53.25 0.00 0.00 KBU31-7 KBU31-7Rd slot #KBU 31-7 Pad 14-6 80.74 164.0 164.0 KBU31-7 KBU31-7 slot #KBU 31-7 Pad 14-6 80.7 164.0 164.0 KU14X-6 KU14X-6 slot #KDU 8 Pad 14-6 138.0 0.00 0.00 KU 31-7 KU 31-7 slot #KU 31-7 Pad 14-6 155.9 0.00 0.00 KBU24-6 KBU24-6 Slot# KBU24-6 Pad 14-6 166.9 150.0 150.0 KBU23X-6 KBU23X-6 slot #KBU 23X-6 Pad 14-6 190.1 0.00 0.00 _ KBU 23-7 KBU 23-7 Slot #KBU 23-7 Pad 14-6 229.5 ___ 164.0 164.0 KU21-7 KU21-7 slot #KU 21-7 Pad 14-6 283.6 2.00 2.00 _ KDU-1 KDU-1 slot #KDU 1 Pad 14-6 359.0 _ 150.0 150.0 _ _ KU 14-6 KU 14-6 slot #KU 14-6 Pad 14-6 383.31 150.0 150.0 J All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 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 KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Slot #KBU22-6, Pad 14-6 G~ea~ce SI:~m~rl Offset WeIINam KU43-12 • CLEARANCE LISTING Page 2 Date Printed: 22-Feb-2005 Kenai Gas Fiefd, Kenai Peninsula, Alaska(Imported) Offset Offset Offsef Minimum MD[ft] Diverging Ellipse Ellipse Clearan e Wellbore Sbt Structure Distance From[ft] Separation MD[ft] Factor ft ft KU43-12 slot #KU Pad 14-6 427.2 0.00 0.00 43-12 All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 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 INTEQ ce (Clearance j j MD(ft] - ~- i MARATHON Oil Company KBU22-li Vers#1, KBU22-6 Vers#1 MARATHQN Slot #KBU22-6, Pad 14-6 Iea[r~i~t~ Qsta i CLEARANCE LISTING Page 3 Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, Alaska(lmported) Reference MD[ftj_ Reference- TVp[ft] Reference North[ftj Reference East[ftj Offset Welt Offset. MD[ftj - Offset TVD[ft] Offset North[ftj Offset East[ftj - Rngie From Approach (Separation Highside Distance [ft] d ft 0.00 0.00 O.OON 0.00E KU 31-7 0.00 0.00 146.51 53.43 160. 155.9 0.00 0.00 O.OON 0.00E KU 31-7 0.00 0.00 146.51 53.43 160. 155.9 100.0 100.0 O.OON 0.00E KU 31-7 99.84 99.84 146.48 53.68 159.9 156.01 150.0 150.0 O.OON 0.00E KU 31-7 149.8 149.8 146.44 53.93 159.8 156.0 250.0 249.9 2.41N 1.03E KU 31-7 250.21 _ 250.21 146.16 54.58 137.0 157.9 350.0 349.6 9.62N 4.11E KU 31-7 349.9 349.9 145.74 55.24 138. 163.5 450.0 448.7 21.62N 9.24E KU 31-7 449.3 449.2 145.11 56.49 140.7 173.3 550.0 547.0 38.38N 16.40 KU 31-7 549.6 549.5 143.70 58.77 143.3 186.9 650.0 644.31 59.84N 25.57 KU 31-7 649.9 649.7 140.78 63.01 145.6 204.1 750.0 740.1 5.96N 36.73 KU 31-7 750.1 749.6 136.28 69.40 147.6 224.8 850.0 834.4 116.65 49.84 KU 31-7 852.0 850.81 129.36 79.63 149.0 248.3 950.0 926.81 151.84 64.88 KU 31-7 953.0 950.2 120.25 94.18 149. 274.6 1050.0 1017.0 191.42 81.79 KU 31-7 1054.1 1049.1 109.12 112.00 149.8 303.7 1150.0 1104.9 235.29 100.54 KU 31-7 1154.8 1146.9 95.73 131.85 149.9 335.1 1250.0 1190.1 283.33 121.07 KU 31-7 1253.7 1242.3 80.82 153.80 149.9 369.3 1350.0 1272.5 335.41 143.32 KU 31-7 1351.0 1335.0 64.66 178.34 149. 406.4 1450.0 1351.91 391.39 167.24 KU 31-7 1444.1 1422.7 48.34 204.70 149. 446.9 1550.0 1427.9 451.10 192.76 KU 31-7 1531.5 1504.9 33.17 230.53 148. 491.8 1638.6 1492.4 507.01N 216.65 KU 31-7 1623.6 1590.1 15.88 260.70 148. 533.7 1700.0 1536.0 546.9 233.60 KU 31-7 1683.4 1644.6 3.61S 282.05 148. 563.0 1800.0 1607.1 611.32 261.22 KU 31-7 1772.11 1724.9 15.23N 314.59 148. 609.9 1900.0 1678.3 675.96 288.84 KU 31-7 1859.2 1803.9 33.64N 346.50 148. 657.0 2000.0 1749.4 740.59 316.46 KU 31-7 1946.0 _ 1882.7 51.77N 378.11 148.2 704.2 2100.0 1820.5 805.22 344.08 KU 31-7 2034.6 1963.2 70.21N 410.25 148.1 751.6 2200.0 1891.7 869.86 371.69 KU 31-7 2109.4 2031.2 85.61N 437.37 148.1 799.2 2300.0 1962.8 934.49 399.31 KU 31-7 2176.0 2091.8 97.60N 461.90 148.1 849.0 2400.0 2033.9 999.13 426.93 KU 31-7 2230.1 2141.3 105.69N 482.26 148.1 901.5 2500.0 2105.11 1063.76 454.55 KU 31-7 2290.9 2197.1 112.97N 505.48 148. 956.5 --- --- _ _ ~~t ~'ettbor_e_rve~r Tool _Prc~rarns KU 31-7 ~ KU 31-7 ~ MWD <0-5790') JVtY IWI G.Ii Vi iY _ ISCWSA MWD Basic MWD -ISCWSA - 28 All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 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 ~.^ INTEQ Closest Ellipse ~ ~ MARATHQN • MARATHON Oil Company KBU22-6 Vers#1, KBU22-6 Vers#1 Slot #KBU22-6, Pad 14-6 • CLEARANCE LISTING Page 4 ~~, Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, INTEQ Alaska(Imported) Reference MD[tt} Reference ND[ftJ Reference North[ft] Reference East[ft] OffsefWeB Offset MD[ftJ Offset TVD[ft] Offset North[ftJ iffset East[ftJ Angle ~Cbsest ~Eitipse From Approach ,Separation Highside Distance ' [ftl d ft 0.00 0.00 O.OON 0.00E KU43-12 1.23 -1.77 308.85 295.24 -136.3 427.2 100.0 100.0 O.OON 0.00E KU43-12 97.14 94.14 309.62 295.59 -136.3 428.1 150.0 150.0 O.OON 0.00E KU43-12 144.1 141.1 310.55 296.02 -136.4 429.1 250.0 249.9 2.41 N 1.03E KU43-12 236.8 233.7 313.43 297.37 -159.7 434.81 350.0 349.6 9.62N 4.11E KU43-12 328.7 325.51 317.68 299.35 -160.1 446.9 450.0 448.7 21.62N 9.24E KU43-12 398.8 395.3 323.11 302.04 -160.5 467. 550.0 547.0 38.38N 16.40 KU43-12 479.2 475. 332.09 307.42 -161.0 497.2 650.0 644.31 59.84N 25.57 KU43-12 558.7 553.5 342.80 314.68 -161.5 534.91 750.0 740.1 85.96N 36.73 KU43-12 626.4 619.9 354.32 320.76 -162.1 579.7 850.0 834.4 116.65 49.84 KU43-12 683.3 675.1 366.98 325.95 -162.6 632.8 950.0 926.81 151.84 64.88 KU43-12 744.9 734.5 382.40 332.18 -163.2 692.8 1050.0 1017.0 191.42 81.79 KU43-12 804.0 790. 398.44 338.66 -163.7 758.8 1150.0 1104.9 235.29 100.54 KU43-12 _ 859.1 843.2 414.57 345.17 -164.0 830.3 1250.0 1190.1 283.33 121.07 KU43-12 901.6 883.3 427.69 350.47 -164.0 906.6 1350.0 1272.5 335.41 143.32 KU43-12 945.5 924.5 441.93 356.25 -163.9 987.4 ~~t W~~t~ore ~xa~r~e~V Tcxal MD1ftl SurvewTool` ~ I Error Model All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Datum #1 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 Oil Company ~~ KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Stot #KBU22-6, Pad 14-6 • CLEARANCE LISTING Page 5 ~t~ Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, INTEQ Alaska(Imported) ~ ..Reference MD[ft] Reference TVD[ft} Reference North[R] Reference East[ftj Offset Well Offset MD[ft) Offset TVD[ft] Offset ' North[ftj Offset East[ft] ~ ~ Closest Angle From Approach Higttside Distance de ft - Ellipse Separation [ft[ 0.00 0.00 O.OON 0.00E KBU24-6 0.10 0.10 166.71 11.60 -176.0 167.11 100.0 100.0 O.OON 0.00E KBU24-6 100.31 100.31 166.62 11.80 -175.9 167.0 150.0 150.0 O.OON 0.00E KBU24-6 150.31 150.3 166.51 12.04 -175.9 166.9 250.0 249.9 2.41N 1.03E KBU24-6 250.4 250.4 166.18 12.75 161. 169.1 350.0 349.6 9.62N 4.11E KBU24-6 350.1 350.1 165.69 13.83 162. 176.2 450.0 448.7 21.62N 9.24E KBU24-6 448.71 448.6 165.31 15.27 164. 188.5 550.0 547.0 38.38N 16.40 KBU24-6 546.2 546.2 165.24 17.04 165. 206.3 650.0 644.31 59.84N 25.57 KBU24-6 643.01 642.9 165.35 19.17 167.7 229.6 750.0 740.1 85.96N 36.73 KBU24-6 738.7 738.6 165.37 21.70 169.4 . 2 8.0 850.0 834.4 116.65 49.84 KBU24-6 833.0 832.9 165.21 24.64 171.1 291. 950.0 926.81 151.84 64.88 KBU24-6 926.4 926.2 164.87 27.21 172.4 329.8 1050.0 1017.0 191.42 81.79 KBU24-6 101 6.6 1016.4 164.44 29.13 173. 372.7 1150.0 1104.9 235.29 100.54 _ KBU24-6 1103.7 1103.51 164.04 31.21 174.4 420.5 1250.0 1190.1 283.33 121.07 KBU24-6 1188.0 1187.7 163.67 33.55 175.2 473.0 1350.0 1272.5 335.41 143:32 __ KBU24-6 1269.5 1269.2 163.35 36.13 175. 530.0 1450.0 1351.91 391.39 167.24 KBU24-6 1350.0 1349.7 163.01 38.24 176. 591.2 1550.0 1427.9 451.10N 192.76 KBU24-6 1430.0 1429.7 162.60 39.24 176. 656.0 1638.6 1492.4 507.01 216.65 _ KBU24-6 1499.0 1498.6 162.04 39.25 176. 716.3 1700.0 1536.0 546.69N 233.60 KBU24-6 1545.2 1544.8 161.73 38.93 177.1 759.0 180 .0 1607.1 611.32 261.22 KBU24-6 1629.1 1628.81 160.59 37.56 177.3 828.0 1 00.0 1678.3 675.96 288.84 KBU24-6 1715.7 1715.3 158.48 34.88 177.4 895.8 2000.0 1749.4 740.59 316.46 KBU24-6 1807.6 1807.01 155.41 30.13 177.4 962.4 ;offset 1AI+~tF~a~re S,urwey Too_I_P_ Well Wellbore Surv N me KBU24-6 KBU24-6 MWD <0-7500> __ _ ~ ~ x ISCWSA MWD All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Datum #1 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 Basic MWD -ISCWSA - 28 MARATHON Oil Company KBU22-6 Vers#1, KBU22-6 Vers#1 MARATNpN Slot #KBU22-6, Pad 14-6 CLEARANCE LISTING Page 6 Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, Alaska(Imported) ~^ INTEQ Reference 'MD[ft] Reference TVD[fij Reference. North[ft] Reference East[ft] .Offset Well Offset MD[ft] Offset TVD[ft] Offset North[ft] Offset East[ft] Angle From Highstde d Gosest ~ Approach Distance ft Ellipse j Separation. [ft] 0.00 0.00 O.OON 0.00E KBU 23-7 0.47 0.47 158.72 166.88 -133.6 230.3 100.0 100.0 O.OON 0.00E KBU 23-7 101.4 101.4 158.61 166.53 -133.6 229.9 150.0 150.0 O.OON 0.00E KBU 23-7 152.0 152.0 158.51 166.16 -133.7 229.6 164.0 164.0 0.05N 0.02E KBU 23-7 166.1 166.1 158.48 166.00 -156.8 229.5 250.0 249.9 2.41 N 1.03E KBU 23-7 253.5 253.51 156.35 164.59 -157.3 230.8 350.0 349.6 9.62N 4.11E KBU 23-7 355.2 355.2 157.69 162.44 -158.2 236.1 450.0 448.7 21.62N 9.24E KBU 23-7 455.3 455.31 156.93 159.62 -159.6 245. 550.0 547.0 38.38N 16.40 KBU 23-7 554.4 554.2 156.24 156.45 -161.3 260.3 650.0 644.31 59.84N 25.57 KB 23-7 654.0 653.8 155.30 152.69 -163.1 279.5 750.0 740.1 85.96N 36.73 KBU 23-7 753.3 753.0 154.01 148.41 -165.0 303.3 850.0 834.4 116.65N 49.84 KBU 23-7 848.8 848.4 152.37 143.86 -166.7 331.8 950.0 926.81 151.84 64.88 KBU 23-7 936.2 935.6 150.63 141.01 -168.0 365.9 1050.0 1017.0 191.42 81.79 KBU 23-7 1026.5 1026.0 149.24 139.26 -169.1 406.1 1150.0 1104.9 235.29 100.54 KBU 23-7 1109.21 1108.6 148.22 138.85 -169.9 452.11 1250.0 1190.1 283.33 121.07 KBU 23-7 1194.8 1194.2 147.28 139.08 -170.5 503.1 1350.0 1272.5 335.41 143.32 KBU 23-7 1276.1 1275.6 146.43 139.35 -171.1 558.6 1450.0 1351.91 391.39 167.24 KBU 23-7 1348.6 1348.0 146.58 139.20 -171.6 619.1 1550.0 1427.9 451.10 192.76 KBU 23-7 1417.5 1417.0 147.69 138.82 -172.1 684.5 1638.6 1492.4 507.01 216.65 KBU 23-7 1472.4 1471.9 149.12 138.55 -172.4 746.3 1700.0 1536.0 546.69 233.60 KBU 23-7 1507.4 1506.8 150.51 138.19 -172.8 790.6 1800.0 1607.1 611.32 261.22 KBU 23-7 1553.6 1552.91 153.62 137.34 -173.4 864.2 1900.0 1678.3 675.96 288.84 KBU 23-7 1599.4 1598.4 158.22 136.09 -174.1 939.5 .~.+ All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 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 --- -- ~ 'rrw MQ41eL _ _ .-I • MARATHON Oil Company I~ KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Slot #KBU22-fi, Pad 14-6 1~~~e ~~ta CLEARANCE LISTING Page 7 Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, Alaska(Imported) itv'1~~ Reference 'MD[ftj` Reference TVD[ftj Reference . North[ft] Reference . East[ft[ Offset Well Offset MD[ftJ Offset ND[ftj Offset North[ft] Offset' East[ftj Angle Closest i Ellipse FromApproach Separation Highside 'Distance [ft] ft 0.00 0.00 O.OON 0.00E KBU23X-6 5.47 -0.53 176.53 70.73 -158.2 190.1 100.0 100.0 O.OON 0.00E KBU23X-6 104.01 98.01 177.03 71.05 -158.1 190.7 150.0 150.0 O.OON 0.00E KBU23X-6 154.01 148.0 177.47 71.3 -158.1 191.2 250.0 249.9 2.41N 1.03E KBU23X-6 254.4 248.4 178.29 71.90 178. 194.8 350.0 349.6 9.62N 4.11E KBU23X-6 353.7 347.7 178.87 72.55 179. 203.4 450.0 448.7 21.62N 9.24 KBU23X-6 453.0 447.0 179.54 73.36 179. 217.4 550.0 547.0 38.38N 16.40 KBU23X-6 551.7 545.7 180.02 74.07 179.3 236.4 650.0 644.31 59.84N 25.57 KBU23X-6 649.0 643.0 180.42 74.45 179.4 260.2 750.0 740.1 85.96N 36.73 KBU23X-6 744.9 738.9 180.78 74.78 179. 289.11 850.0 834.4 116.65 49.84 KBU23X-6 839.6 833.61 180.93 75.16 179. 322.7 950.0 926.81 151.84 64.88 KBU23X-6 931.6 925.6 181.09 75.41 179. 361.2 1050.0 1017.0 191.42 81.79 KBU23X-6 1021.1 1015.1 181.39 75.75 179. 404.7 1150.0 1104.9 235.29 100.54 KBU23X-6 1110.2 1104.2 181.63 75.93 179.8 452.7 1250.0 1190.1 283.33 121.07 KBU23X-6 1195.8 1189.8 181.76 75.90 179. 505.0 1350.0 1272.5 335.41 143.32 KBU23X-6 1290.9 1284.9 180.62 75.75 179. 560.7 1450.0 1351.9 391.39 167.24 KBU23X-6 1391.5 _ 1385.3 176.66 74.90 179.9 618.41 1550.0 1427.9 451.10 192.76 KBU23X-6 ,1505.81 1499.3 167.95 72.97 -179.9 677. 1638.6 1492.4 507,01 216.65 KBU23X-6 ,1616.1 1608.61 153.36 7 .14 -179.6 729.2 1700.0 1536.0 546.69 233.60 KBU23X-6 1707.0 1697.8 136.73 66.16 -179.4 763.61 1800.0 1607.1 611.32 _ 261.22 _ KBU23X-6 1855.7 1841.8 101.31 55.67 -179.1 814.4 1900.0 1678.3 675.96 288.84 KBU23X-6 2010.5 1988.1 52.29 42.85 -178.6 858.1 2000.0 1749.4 740.59 316.46 KBU23X-6 2156.4 2122.0 3.71N 28.16 -178.1 894.7 2100.0 1820.5 805.22 344.08 KBU23X-6 2292.9 2244.1 62.81N 13.29 -177.6 926.4 2200.0 18 1.7 869.86 371:69 KBU23X-6 2397.9 2336.7 110.92N 1.29 -177.2 955.5 2300.0 1962.8 9 4.49 399.31 KBU23X-6 2487.0 2415.2 151.70N .64E -176.8 984.9 l'~t V1`II~t~re Su~rev Toc~ Prot~rwa~ns All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 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 Oil Company KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Slot #KBU22-6, Pad 14-6 - -- - -- - - - - - -- ---- ('.~.~ar~e~ 11a CLEARANCE LISTING Page 8 ~/~ Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, INTEQ Alaska(Imported) r. . Reference MD[ftJ Reference TVD[ftJ Reference North[ftJ Reference East[ft] Offset Well Offset MD[ft] Offset TVD[ft} Offset North[it) Offset ~ Angle East[ftJ ~ From Highskie d ~ Closest Approach Distance ft I Eclipse Separation [ft] ~ 0.00 0.00 O.OON 0.00E KBU31-7 8.05 0.05 73.48 34.33 155.0 81.10 100.0 100.0 O.OON 0.00E KBU31-7 108.2 100.2 73.39 34.18 155.0 80.9 150.0 150.0 O.OON 0.00E KBU31-7 158.4 150.4 73.26 34.04 155.1 80.7 164.0 164.0 0.05N 0.02E KBU31-7 172.4 164.4 73.19 33.99 132. 80.74 250.0 249.9 2.41N 1.03E KBU31-7 258.5 250.5 72.86 33.42 133. 61.9 350.0 349.6 9.62N 4.11E KBU31-7 358.2 350.2 72.75 31.85 138.1 6.9 450.0 448.7 21.62N 9.24E KBU31-7 457.3 449.3 72.20 31.02 143. 96.3 550.0 547.0 38.38N 16.40 KBU31-7 5 5.6 547.5 71.84 30.12 149. 111.0 650.0 644.31 59.84N 25.57 KBU31-7 652.4 644.4 71.55 29.19 154. 131.4 750.0 740.1 85.96N 36.73 KBU31-7 748.0 739.9 71.57 28.35 159.0 1 7.7 850.0 834.4 116.65 49.84 KBU31-7 842.3 834.31 71.61 27.83 162.4 189. 950.0 926.81 151.84 64,88 KBU31-7 933.5 925. 71.61 27.78 165.0 226.51 1050.0 1017.0 191.42 81.79 _ KBU31-7 1021.1 1013.1 72.60 28.56 166. 269.3 1150.0 1104.9 235.29 100.54 KBU31-7 1103.7 1095.61 75.16 31.06 167. 318.2 1250.0 1190.1 283.33 121.07 KBU31-7 1192.1 1183.71 78.66 36.99 167. 371.6 1350.0 1272.5 335.41 143.32 KBU31-7 1292.1 1283.0 80.78 48.01 167.6 427.1 1450.0 1351.9 391.39 167.24 KBU31-7 1366.9 1357.2 81.32 57.88 167. 485.2 1550.0 1427.9 451.10 192.76 KBU31-7 1432.3 1422.01 83.04 66.65 166.7 548.8 1638.6 1492.4 507.01 216.65 KBU31-7 1482.1 1471.2 85.70 73.50 166.2 610.1 1700.0 1536.0 546.69 233.60 KBU31-7 1516.6 1505.3 88.29 78.29 166.3 654.41 1800.0 1607.1 611.32 261.22 KBU31-7 1566.3 1554.4 93.03 84.78 166. 728.0 1900.0 1678.3 675.96 288.84 KBU31-7 1617.1 1604.4 99.01 90.92 166. 803.2 2000.0 1749.4 740.59 316.46 KBU31-7 1680.4 1666.5 107.23 99.61 166. 879.0 2100.0 1820.5 805.22 344.08 KBU31-7 1733.3 1718.2 114.61 108.09 166.4 955.11 -- ,t :Well I W~sllh~rw I Sslrvav NamA ~AADrftt TSUryeY 70!Ot ErfOr fVfrJdel KBU31-7 ~ KBU31-7Rd ~ MWD <5814-7575> ISCWSA MWD Basic MWD -ISCWSA - 28 All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Datum #1 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 KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Siot #KBU22-ti, Pad 14-6 f'~ Eta ~- CLEARANCE LISTING Page 9 ~~~ Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, INTEQ Alaska(Imported) Reference MD[ftj Reference ND[ftj Reference North[ft] Reference East[ft] Offset: Well Offset MD[ftj Offset ND[ft] Offset North[ftj Offset ~ast[ftJ ' Angle From liighstde Closest Approiach Distance ft Ellipse Separation tftj 0.00 0.00 O.OON 0.00E KBU31-7 8.05 0.05 73.48 34.33 155. 81.1 100.0 100.0 O.OON 0.00E KBU31-7 108.2 100.2 73.39 34.18 155. 80.96 150.0 150.0 O.OON 0.00E KB 31-7 158.4 150.4 73.26 34.04 155.1 80.78 164.0 164.0 0.05N 0.02E KBU31-7 172.4 164.4 73.19 33.99 132.0 80.74 250.0 249.9 2.41N 1.03E KBU31-7 258.5 250.5 72.86 33.42 133.6 81.9 350.0 349.6 9.62N 4.11E KBU31-7 358.2 350.2 72.75 31.85 138.1 86.9 450.0 448.7 21.62N 9.24E KBU31-7 457.3 449.3 72.20 31.02 143. 96.3 550.0 547.0 38.38N 16.40 KBU31-7 555.6 547.5 71.4 30.12 149.2 111.0 650.0 644.31 59.84N 25.57 KBU31-7 652.4 644.4 71.55 29.1 154. 131.4 750.0 740.1 85.96N 36.73 KBU31-7 748.0 739.9 71.57 28.35 159.0 157.7 850.0 834.4 116.65 49.84 KBU31-7 842.3 834.31 71.61 27.8 162.4 189. 950.0 926.81 151.84 64.88 KBU31-7 933.5 925. 71.61 27.78 165. 226.51 1050.0 1017.0 191.42 81.79 KBU31-7 1021.1 1013.1 72.60 28.56 166. 269.3 1150.0 1104.9 235.29 100.54 KBU31-7 1103.7 1095.61 75.16 31.06 167.7 318.2 1250.0 1190.1 283.33 121.07 KBU31-7 1192.1 1183.71 78.66 36.99 167. 371.6 1350.0 1272.5 335.41 143.32 KBU31-7 1292.1 1283.0 80.78 48.01 167.6 427.1 1450.0 1351.91 391.39 167.24 KBU31-7 1366.9 1357.2 81.32 57.88 167. 485.2 1550.0 1427.9 451.10 192.76 KBU31-7 14 2.3 1422.01 83.04 66.65 166.7 548.8 1638.6 1492.4 507.01 216.65 KBU31-7 1482.1 1471.2 85.70 73.50 166.2 610.1 1700.0 1536.0 546.69 233.60 KBU31-7 1516.6 1505.3 88.29 78.29 166. 654.41 1800.0 1607.1 611.32 261.22 KBU31-7 1566.3 1554.4 93.03 84.78 166.4 728.0 1900.0 1678.3 675.96 288.84 KBU31-7 1617.1 1604.4 .99.01 90.92 166. 803.2 2000.0 1749.4 740.59 316.46 KBU31-7 1680.4 1666.5 107.23 99.61 166. 879.0 2100.0 1820.5 805.22N 344.08 KBU31-7 1733.3 1718.2 114.61 108.09 166.4 955.11 „_..c~ ~._ ~-.._ Mods1 ~ _ ~ All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 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 KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Slot #KBU22-6, Pad 14-6 CLEARANCE LISTING Page 10 ~~~ Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, jNTEQ Alaska(Imported) ~~~~ ~a Reference MD[ft] :Reference TVD[ftJ Reference North[ftJ Reference East[ft] Offset Well Offset MD[ft] Offset ND[ft] Offset . North[ftJ Offset East[ft] Angte From Highside Closest ! HNipse Approach 5eparahon . Distance [ftJ ft 0.00 0.00 O.OON 0.00E KDU-1 9.00 0.00 71.88 351.79 -101.6 359.0 100.0 100.0 O.OON 0.00E KDU-1 109.0 100.0 71.88 351.79 -101.6 359.0 150.0 150.0 O.OON 0.00E KDU-1 159.0 150.0 71.88 351.79 -101.6 359.0 250.0 249.9 2.41N 1.03E KDU-1 258.9 249.9 71.88 351.79 -125.0 360.5 350.0 349.6 9.62N 4.11E KDU-1 3 8.6 349.6 71.88 351.79 -125.9 3 5.11 450.0 448.7 21.62N 9.24E KDU-1 457.7 448.7 71.88 351.79 -127.3 372.9 550.0 547.0 38.38N 16.40 KDU-1 556.0 547.0 71.88 351.79 -129.2 384.3 650.0 644.31 59.84N 25.57 KDU-1 653.31 644.31 71.88 351.79 -131.4 399.6 750.0 740.1 85.96N 36.73 KDU-1 749.1 740.1 71.88 351.79 -133.8 419.3 850.0 834.4 116.65 49.84 KDU-1 843.4 834.4 71.88 351.79 -136.3 443.6 950.0 926.81 151.84 64.88 KDU-1 935.81 926.81 71.88 351.79 -138.8 472.9 1050.0 1017.0 191.42 81.79 KDU-1 1026.0 1017.0 71.88 351.79 -141.2 507.2 1150.0 1104.9 235.29 100.54 KDU-1 1113.9 1104.9 71.88 351.79 -143.5 546.7 1250.0 1190.1 283.33 121.07 KDU-1 1199.1 1190.1 71.88 351.79 -145.5 591.41 1350.0 1272.5 335.41 143.32 KDU-1 1281.5 1272.5 71.88 351.79 -147.3 641.11 14 0.0 1351.91 391.39 167.24 KDU-1 1360.9 1351.9 71.88 351.79 -148.9 695.7 1550.0 1427.9 451.10 192.76 KDU-1 1436.9 1427.9 71.88 351.79 -150.2 755.01 638.6 1492.4 507.01 216.65 KD -1 1501.4 1492.4 71.88 351.79 -151.2 811.31 1700.0 1536.0 546.69 233.60 KDU-1 1545.0 1536.0 71.88 351.79 -152.5 851.6 1800.0 1607.1 611.32 261.22 KDU-1 1616.1 1607.1 71.88 351,79 -154.5 917.9 1900.0 1678.3 675.96 28 .84 KDU-1 1687.3 1678.3 71.88 351.79 -156.2 984.71 All data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 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 O[I Company KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Slot #KBU22-6, Pad 14-ti CLEARANCE LISTING Page 11 ~t~ Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, INTEQ Alaska(Imported) -r~, ~~,~ ~~~ - ~.~. ~ ~ ,: Reference MD[ftJ Reference ND[ft] Reference North[ft] Reference East[ftJ Offset Well Offset MD[ftj Offset TVD[ftl Offset North[ft] Offset East[ftj .Angle ~ From Hiphstde d ICoosest Approach Distance 8 EAipse Separation [ftJ _ 0.00 0.00 O.OON 0.00 KU14X-6 7.98 -0.02 58.53 124.99 -115.1 138.0 _ 100.0 100.0 O.OON 0.00E KU14X-6 107.8 __ 99.89 58.74 124.93 -115.2 138.0 150.0 150.0 O.OON 0.00E KU14X-6 157.8 149.8 58.89 124.91 -115.2 138.1 250.0 249.9 2.41N 1.03E KU14X-6 257.7 249.7 59.07 124.94 -139.1 140.1 350.0 349.6 9.62N 4.11E _ KU14X-6 357.4 349.4 59.06 125.11 -141.0 146.3 450.0 448.7 21.62N 9.24E KU14X-6 456.3 448.3 58.97 125.41 -143.7 156.9 550.0 547.0 38.38N 16.40 KU14X-6 554.41 546.41 58.89 125.74 -146.9 172.2 650. 644.31 59.84N 25.57 KU14X-6 651.5 643.5 58.96 126.15 -150.3 192.7 750.0 740.1 85.96N 36.73 KU14X-6 747.11 739.1 59.08 126.59 -15 .6 218.4 850.0 834.4 116.65 49.84 KU14X-6 841.2 833.2 59.25 127.06 -156.5 249.4 950.0 926.81 151.84 64.88 KU14X-6 933.2 925.2 59.44 127.59 -159.1 285.81 1050.0 1017.0 191.42 81.79 KU14X-6 1023.6 1015.5 59.64 128.07 -161.3 327.2 1150.0 1104.9 235.29 100.54 _ KU14X-6 1112.2 1104.1 59.86 128.38 -16 .2 373.5 1250.0 1190.1 283.33 121.07 KU14X-6 1197.3 1189.3 60.09 128.37 -164.8 424.4 1350.0 1272.5 335.41 143.32 KU14X-6 _ 1280.6 1272.6 60.33 128.00 -166.1 479.8 1450.0 1351.9 391.39 167.24 KU14X-6 1360.3 1352.3 60.63 127.45 -167.3 539.5 1550.0 1427.9 451.10 192.76 KU14X-6 1436.0 _ 1428.0 61.00 126.80 -168.2 603.6 1638.6 1492.4 507.01 216.65 KU14X-6 15 0.01 _ 1491.9 61.38 126.18 -168.9 663.7 1700. 1536.0 546.69 233.60 KU14X-6 1543.5 1535.5 61.71 125.67 -169.6 7 6.5 1800.0 1607.1 611.32 261.22 KU14X-6 1613.3 1605.3 62.27 124.87 -170.6 776.4 1900.0 1678.3 675.96 288.84 KU14X-6 1684.2 1676.1 62.90 124.12 -171.5 846.4 2000.0 1749.4 740.59N 316.46 KU14X-6 1753.0 1744.9 6 .52 123.61 -172.2 916.6 2100.0 1820.5 805.22 344.08 KU14X-6 1821.5 1813.4 64.16 123.26 -172.8 987.0 Y ~= r t 1~'let6t~e SurV~ ° foot ~~a >~axns - - - - -- - __ ~ ~s~ Wett Welibore Surve Nam MDR Surve Too rr~ ei KU14X-6 KU14X-6 GMS <0-9500> 9500.0 Level Rotor G ro Standard KU14X-6 U14X-6 _ MSS <977 -10225> 10225.0 Photomech nicai Ma netic Standard Aii data is in Feet unless otherwise stated Coordinates are from Slot and ND's are from Rig (Datum #1 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 KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Slot #KBU22-6, Pad 14.6 CLEARANCE LISTING Page 12 ~~' Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, ~,,I,EQ Alaska(Imported) ~ t Reference MD[ft] Reference ND[ftJ Reference North[rtJ Reference East[ft] Offset Welt ^ Offset MD[ftJ Offset ND[ft] Offset North[ftJ Offset ~ East[ftJ Angfe ~ Closest I Ellipse Frorn Approach ~ Separation Htghside Distance [ft] ft 0.00 0.00 O.OON 0.00E KU13-6 6.99 -0.01 50.82 15.90 162. 53.2 100.0 100.0 O.OON 0.00E KU13-6 106.9 99.95 50.74 16.31 162. 53.2 150.0 150.0 O.OON 0.00E KU13-6 156.9 149.9 50.65 16.75 161.7 53. 250.0 249.9 2.41N 1.03E KU13-6 257.0 249.9 50.33 17.99 139. 55.4 350.0 349.6 9.62N 4.11E _ KU13-6 358.6 351.5 48.45 19.12 142. 60.0 450.0 448.7 21.62N 9.24E KU13-6 460.2 453.0 43.82 17.64 149. 66.1 50.0 547.0 38.38N 16.40 KU13-6 561.4 553.9 36.12 13.64 159. 74.8 650.0 644.31 59.84N 25.57 KU13-6 660.9 652.5 25.80 6.35E 169.4 88.16 750.0 740.1 85.96N 36.73 KU13-6 762.2 752.3 11.08 3.89 179.6 105.8 850.0 834.4 116.65 49.84 KU13-6 860.2 847.8 7.08N 16.04 -171.9 128.5 950.0 926.81 151.84 64.88 KU13-6 958.0 942.6 27.15N 28.81 -165.6 156.7 1050.0 1017.0 191.42 81.79 KU13-6 1055.4 1036.2 50.28N 42.27 -160.7 188.8 1150.0 1104.9 235.29 100.54 KU13-6 1153.6 1129.2 78.O6N 57.29 -156.4 224.11 1250.0 1190.1 283.33 121.07 KU13-6 1251.8 1220.6 110.34N 73.22 -152.7 261.9 1350.0 1272.5 335.41 143.32 KU13-6 1347.2 1307. 145.50 89.41 -149.4 302.4 1450.0 1351.91 391.39 167.24 KU13-6 1443.4 1394.1 184.26N 106.73 -146.6 346.0 1550.0 1427.9 451.10 192.76 _ KU13-6 1538.0 1476.8 226.33N 124.97 -143.9 392.2 1638.6 1492.4 507.01 216.65 KU13-6 1616.4 1543.9 263.65 140.83 -141.7 435.51 1700.0 1536.0 546.69 233.60 KU13-6 1669.5 1589.2 289.18N 151.66 -141.1 466.4 1800.0 1607.1 611.32 261.22 KU13-6 1755.9 1662.8 330.93N 169.39 -140.2 516.8 1900.0 1678.3 675.96 288.84 KU13-6 1843.8 1737.4 373.66N 187.51 -139.4 567.2 2000.0 1749.4 740.59 316.46 KU13-6 1932.9 1812.9 417.21N 205.68 -138.7 617.4 2100.0 1820.5 805.22 344.08 KU 13-6 2020.7 1887.4 460.31 N 223.23 -138.2 667.2 2200.0 1891.7 869.86 371.69 KU13-6 2107.0 1960.7 502.54N 240.29 -137.7 717.0 2300.0 1962.8 934.49 399.31 KU13-6 2190.3 2031.5 543.15N 256.90 -137.3 767.1 2400.0 2033.9 999.13 426.93 KU13-6 2274.3 2102.8 584.16N 274.02 -137.0 817.4 2500.0 2105.11 1063.76 454.55 KU13-6 2360.7 2176.1 626.39N 291.81 -136.6 867.9 2600.0 2176.2 1128.40 482.17 KU13-6 2450. 2251.7 670.14N 310.05 -136.3 918.31 2700.0 2247.3 1193.03 509.79 KU13-6 2539.5 2327. 714.23N 328.17 -136.0 968.4 i E°'R~ All data is in Feet unless otherwise stated Coordinates are from Sfot and ND's are from Rig (Datum #1 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 i MARATHON Oil Company KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Slot #KBU22-6, Pad 14-6 CLEARANCE LISTING Page 13 ~i~~ Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, INTEQ Alaska(Imported) -- -- =~ - Reference MD(ft] - -- Reference TVD(ft] Reference North[ft] Reference East[ft] - Offset Well Offset MD(ft] ----- Offset TVD[ft] r Offset North[ft] Offset East[ft] _ Angie From ~ Highside Ctosest ;Ellipse J " I P Approach ~ Se aration 'Dlstanca [ftj ft" 0.00 0.00 O.OON 0.00E KU14-6 5.00 0.00 227.09 308.80 -126.3 383.31 100.0 100.0 O.OON 0.00E KU14-6 105.0 100.0 227.09 308.80 -126.3 383.31 150.0 150.0 O.OON 0.00E KU14-6 155.0 150.0 227.09 308.80 -126.3 383.31 250.0 249.9 2.41N 1.03E KU14-6 254.7 249.7 227.08 308.84 -149.6 385.6 350.0 349.6 9.62N 4.11E KU14-6 354.0 349.0 227.07 308.96 -150.1 392.4 450.0 448.7 21.62N 9.24E KU14-6 452.4 447.4 227.03 309.18 -150.8 404.01 550.0 547.0 38.3 N 16.40 KU14-6 550.7 545.7 226.97 309.63 -151.7 420.3 6 0.0 644.31 59.84N 25.57 KU14-6 646.9 641.9 226.86 310.39 -152.8 441.6 750.0 740.1 85.96N 36.73 KU14-6 741.7 736.7 226.71 311.43 -153.9 467. 850.0 834.4 116.65 49.84 KU14-6 835.8 830.8 226.55 312.51 -155.1 499.1 950.0 926.81 151.84 64.88 KU14-6 929.0 924.0 226.43 313.36 -156.2 534.9 1050.0 1017.0 191.42 81.79 KU14-6 1020.1 1015.1 226.35 313.91 -157.4 575.4 1150.0 1104.9 235.29 100.54 KU14-6 1108.2 1103.1 226.28 314.3 -158.5 620.6 1250.0 1190.1 283.33 121.07 KU14-6 1193.3 1188.3 226.22 314.79 -159.5 670. 1350.0 1272.5 335.41 143.32 KU14-6 1275.1 1270.1 226.16 315.24 -160.3 725.01 1450.0 1351.9 391.39 167.24 KU14-6 1354.4 _ 1349.3 226.08 315.75 -961.1 783.9 1550.0 1427.9 451.10 192.76 KU14-6 1430.3 1425.2 226.01 316.24 -161.7 847.0 1638.6 1492.4 507.01 216.65 KU14-6 1494.0 1489. 225.94 316.70 -162.1 906.4 1700.0 1536.0 546.69 233.60 KU14-6 1537.6 1532.61 225.89 317.04 -162.8 948.7 ~ - - ~~t Idle f wP~t --- s- ~E~or' Mode ,_ ~_ . _~ All data is in Feet unless otherwise stated Coordinates are from Slot and TVD's are from Rig (Datum #1 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 Oil Company KBU22-6 Vers#1, KBU22-6 Vers#1 MARATHON Slot #KBU22-6, Pad 14-6 • CLEARANCE LISTING Page 14 ~/t~ Date Printed: 22-Feb-2005 Kenai Gas Field, Kenai Peninsula, INTEQ Alaska(Imported~ ___._ - Reference MD[ft] Reference TJD[ftj deference North(ftj Reference East[ftj Offset Weit Offset MO[ft] Offset TVD[ftj Offset North[ft] Offset East[ftj ` Angle from Highside Closest j Approach Distance ~ ft Ellipse G Separation (ftj 0.00 0.00 O.OON 0.00E KU21-7 0.00 2.00 118.09 257.88 -114.6 283.6 2.00 2.00 O.OON 0.00E KU21-7 0.00 2.00 118.09 257.88 -114.6 283.6 100.0 100.0 O.OON 0.00E KU21-7 96.20 98.20 118.14 258.18 -114.6 283.9 150.0 150.0 O.OON 0.00E KU21-7 146.2 148.2 118.20 258.50 -114.6 284.2 250.0 249.9 2.41N 1.03E KU21-7 245.1 247.1 118.40 259.52 -137.9 287.2 350.0 349.6 9.62N 4.11E KU21-7 347.4 349.3 118.63 259.87 -138.9 293.4 450.0 448.7 21.62N 9.24E KU21-7 445.6 447.6 118.84 260.12 -140.3 3 3.7 550.0 547.0 38.38N 16.40 KU21-7 543.1 545.0 119.26 260.20 -142.2 318.3 650.0 644.31 59.84N 25.57 KU21-7 637.7 639.7 121.60 260.32 -144.5 338.6 7 0.0 740.1 85.96N 36.73 KU21-7 747.9 749.6 127.83 255.47 -148.3 362.1 850.0 834.4 116.65 49.84 KU21-7 844.9 845.9 133.95 247.09 -1 2.0 388.71 950.0 926.81 151.84 64.$8 KU21-7 944.4 944.81 140.15 236.63 -155.8 420.11 1050.0 1017.0 191.42 81.79 KU21-7 1033.5 1033.0 145.73 225.52 -159.0 456.4 1150.0 1104.9 235.29 100.54 KU21-7 1115.1 1113.41 153.11 213.85 -162.0 499.7 1250.0 1190.1 283.33 121.07 KU21-7 1194.6 1191.4 161.67 201.02 -164.9 549.3 1350.0 1272.5 335.41 143.32 _ KU21-7 1267.3 1262.5 170.81 188.54 -167.4 605.3 1450.0 1351.91 391.39 167.24 KU21-7 1341.4 1334.7 180.69 175.68 -169.8 667.2 1550.0 1427.9 451.10 192.76 KU21-7 1415.0 1406.6 190.32 162.82 -171.9 733.6 1638.6 1492.4 507.01 216.65 KU21-7 1478.1 1468.21 198.25 151.77 -173.6 796.0 1700.0 1536.0 54 .69 233.60 KU21-7 1522.1 _ 1511.21 203.58 144.03 -174.8 840.3 1800.0 1607.1 611.32 261.22 KU21-7 1588.7 1576.2 211.62 132.34 -176.5 912.7 1900.0 1678.3 675.96 288.84 KU21-7 1651.2 1637.2 219.32 121.37 -177.8 985. .-- fset UC6etibore ~v+~y T©ol P~~i~s •> W li Wellbor Surve Nam M ft S rve T I ~ Er t~fo I _ _ All data is in Feet unless othervvise stated Coordinates are from Slot and TVD's are from Rig (Datum #1 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 File Edit Profiles Table Tools Offset Data Units Window Help ~."". LSi4 1 ~ ~ ~~ ~ ~2D 1 40 12DR ~ 13U ~ '~ WellboreDetailsl0ffsetData Wel.~atllTargetslCom~men't_sllErrorslHo\IeSectionslCasings) Name KBU22-6Vers#7 Start MD ~ ft TVD ~ ' ~ ft ' Section t" Defauk f'-' Specialise ~~;1'9tC 4 e.. .3J J J 9 E JJ JJJ ID 723990 -- --- - ------ North f~ i' ~'' East ~ ~' ~ ~~ ~ Azimuth 2.~ 1:~? 1 1` Arbitrary tie • J _, MD [ft] E Inc [degJ Azi (deg] { TVD [ft] { North (ft] I East [ft] ; DLS { Tface [deg) fi VS [ft] ~ 1 i ~ nur 23.137 r ~ r [deg/100f1 r r~ K -r r r -- -- 3 ~ q ( ., - ' T ,~ r r a7, r ~ ~ -JJJ fur at~re ~ Target ~r - ~ ~ ~~~~ B~.rld r~ ~~ ~ ~_ r ..o ~.r r. '~.~ei~p~tr. r ~,=~I r F~~l~ r~~~~t~~,E -- Coordinates -- - MD -i ;- TVD ----_ ___ C" Field C Installation l~ Slot C Slot ~ Rig Datum ~' ' ~" Field C' Installation l'"' Slot f~ Rg Datum Datui o Paradigm Geophysical Ltd. 2003 P: Datum #1 [87.0] 22-Feb-2005 -JJ ~[ • s'~~~~ • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. INTEGRATED FLUIDS ENGINEERING PROJECT PLAN _ =1FE Prepared For: MARATHON OIL COMPANY Well KBU 22-6 Prepared by: Tony Tykalsky Reviewed by: Mark Fairbanks Presented to: Will Tank March 22, 2005 ~~ Kenai Peninsula, Alaska • Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will: • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Enclosed is the recommended drilling fluid program for the KBU 22-6 Well to be drilled this year. The following is a brief synopsis of the program. Overview: KBU 22-6 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 GeUGelex 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. SafeCarb bridging material will be maintained according to the mud program to minimize losses to the formation. Fluid loss should be maintained @ 7 - 9 cc's API. NOTE: Since this fluid will also be used in the production interval, care should be taken to maintain recommended mud properties while drilling the intermediate interval. Production Interval: This interval will be drilled with the same fluid that was used to drill the intermediate interval. The fluid will be pre-treated with Bicarb and/or citric acid prior to drilling out the cement. Any further fluid dilutions will be made in order to keep the mud properties at the recommended specifications. Fluid loss should be maintained @ 7 - 9 cc's API for this interval. Based on offset well history, mud weights above 10.0 PPG may be required. Completion: The cement will be displaced with 6% KCl brine for the completion phase of the program. Conqor 303A and Sodium Meta Bisulfate will be added to the drilling fluid that will be left between the 3-1/2" completion string and the 9-S18" casing on the final circulation prior to cementing. Tony Tykalsky Project Engineer /M-I SWACO Reference Wells: KBU 43-7X; KBU 42-7; KBU 24-6; KBU 11-8X; KBU 42-6 NOTE: This program is provided as a guide only. Well conditions will always dictate fluid properties required. 0 • • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. EXECUTIVE SUMMARY ~t~ ~~°~~ ,,< ;; ,~ ~.. ~RONME~Pv •• 0 Our overall goal is no spills and no incidents while providing fluids and solids control services to Marathon Oil Company. Our goal for KBU 22-6 is to remove drill solids from the mud system at a cost of less than $0.24 per pound. This has been the average for the last three years of centrifuge van operations With the revised fluid formulation (utilizing the intermediate interval fluid for the production interval), we expect to drill this well for a product cost of less than $25.79 per foot. Use of the MI Swaco centrifuge van for the last four years has provided an estimated savings in dilution and disposal costs to Marathon Oil of over $800,000. '~ With continued usage of our equipment, we expect to provide more savings to you during future operations. '" r-E • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Interval Benchmarks and Targets Drilling {ntervals Depth Benchmark 1 Benchmark 2 Benchmark 3 Benchmark 4 Interval eft) Fluid cost per foot Volume Usage Solids Removal 0 -1649' < $5.85 ft < 2040 bbls 1649 - < $32.54 ft < 3119 bbls 6498' 6498 - 8563' < $25.79 ft < 756 bbls Total Avg. Max. Project < $25.79 ft <5916 bbls < $0.24 Ib No Spills from Targets for Centrifuge Van Drilling Operation Interval ~~ • • '~ Marathon Oil Company Well Name: KBU 22-6 i Location: Kenai, Alaska. Project Summary Casing Hofe Casing Depth ND Mud Mud Sum Interval Size Size Program System Weighf Days Mud Cost (in) (in) (ft) (ft) Solids Control (ppg) 13-3/8" 16" ~ ~ ~ ' ~~ ~ 1649' 1500' GeUGelex Spud '~~ Mud 8.6 - 9.4 5 $1:3,560 '~ >~~~~ Screens 150/180 x i~t~, mesh ~`~ < <, ~„ Desilter , ~~ ~~~ h Centrifuge Van r * ~ ~1~~ 9-5/8" 12-1/4" ~ >~. 6498' 5370' Flo-Pro " "" w/SafeCarb 9.0 - 10 $165,595 't t Screens 180 - 210 < 9.5 . ~~:~, ~ mesh ~,Q-. X` ~'` Desilter ,'~: 'r', Centrifuge Van z Y~`~ 3-1/2" 8-1/2" 8563' 7525' Flo-Pro ~~~~ wlSafeCarb 9.0 - 7 $61,246 ;~~" Screens 230 - 210 10.0+ mesh ~~~~~~ ~ ` Desilter ~ '' ~- Centrifuge Van ;~: 3 1/2" 8-1/2" Completion 8563' 7525' 6% KCl 8.55 2 $4,166 - 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 1% Lubetex concentration in intermediate and production interval. • • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Estimated Product Usage Summary PRODUCT Surface 16" Intermediate 12-1/4" Production 8-1/2" Completion 3-112" Total Usage % of Total Cost M-I Bar 0 312 908 0 1220 4.03 M-I Gel 612 0 0 0 612 2.30 Gelex 26 0 0 0 26 0.17 Soda Ash 10 16 8 0 34 0.22 Caustic Soda 10 31 8 0 49 0.74 Congor 404 0 7 3 0 10 5.53 Sodium Meta Bisulfate 20 31 8 4 63 1.81 Bicarb 10 16 15 0 41 0.32 Conqor 303 0 0 0 4 4 0.84 F1oVis 0 250 61 0 311 26.85 Desco CF 10 0 0 0 10 0.21 Polypac UL 10 125 30 0 165 11.33 KCl 0 1310 318 42 1670 9.21 Safecarb 0 1872 303 0 2175 18.18 Lubetex 0 25 12 0 37 11.90 EMI 920 0 0 6 0 6 2.41 Citric Acid 0 0 4 0 4 0.19 Defoam X 0 35 4 0 39 1.51 ,E~~ineerSer~rc~ 5 1~ 7 i 2, 24 ~~ • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Offset Well Information Well Hole Size Depth PPG PV YP FL Comments KBU 43-7X 16" 1500 9.15 14 30 14 Spud in, drlg to casing point 12.25' 2900 9.2 5 24 16 Drlg out, disp to 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 weight 8610 10.6 15 28 4.6 Gas - increase mud weight KBU 42-7 17.5" 1006 8.9 12 30 11.2 Spud in, drlg to casing point 1760 9 12 19 116 Drlg out, LOT 15.6 ppg 12.25" 3455 9.3 10 17 8.9 Drlg ahead 4371 9.35 9 25 11 Trip OK 5205 9.4 14 11 5.5 Drlg ahead, some losses, 100 % losses @ 4899' pump SafeCarb LCM (M & C) 5590 9.3 14 18 7.6 Drlg to csg point, spot LCM pill, lost 50 bbls during cementing 8.5" 6131 9.7 13 24 10.8 Drlg out, LOT 13.3 6733 10 15 19 8 Hole swelling, inc mud weight to 10.0 ppg 7000 9.9 15 19 7.8 Drlg ahead 7293 10.15 15 21 7.5 Drlg ahead, inc mud weight to 10.3 popg 7570 10.6 22 22 6.6 Drlg to TD increase mud weigh (gas) KBU 24-6 17.5" 1008 8.85 28 67 7.5 Spud in, drlg to casing point 1525 8.65 12 26 11.4 Sweep hole prior to running csg 12.25" 1818 8.75 7 27 6.2 Drlg out, LOT 18.4 ppg 3611 8.95 8 20 6.9 Drlg ahead 4011 9 8 16 7.8 Drlg ahead 4532 8.9 8 22 8.2 Drlg ahead 4982 9.7 9 22 10 Drlg ahead 5213 9.8 11 27 8 Drlg ahead 5505 9.6 7 14 7.8 Run csg, lost returns spot LCM pill (1289 bbl losses) 8.5" 6395 9.55 8 25 7.7 Drlg out, LOT 14.5 ppg 7420 9.6 9 27 7.5 Drlg ahead, inc mud ppg 7500 10.3 11 25 6.2 Spot 16.0 ppg pill on bottom, run liner KBU 11-8X 16" 720 9 13 32 14 Spud in, drill ahead 1517 9.05 13 12 16 Drlg to casing point, condition mud, POH to run casing 12.25" 2326 9.1 11 13 8.2 Drlg out, disp to Flo Pro, drlg ahead, keep mud thin for high GPM 3719 9.5 11 16 7.8 Drlg ahead, short trip OK, drlg ahead 4825 9.4 12 19 6.4 Drlg ahead, high torque, add lubetex 5334 9.5 11 22 7.2 Slow ROP, add lubetex for sliding 5611 9.7 13 21 7.5 Drlg to casing point, condition mud, POH to run casing 8.5" 6338 9.4 13 21 6.8 Drlg out, displace to new mud, drlg ahead 7402 9.85 13 21 6 Short trip OK, increase PPG to 9.8 7659 10 8 18 11.2 Drlg to TD, fluid loss increasing to to bacterail contamination, POH for logs 7659 10.2 11 14 9.1 Finish logging, run excape completion. • • '~ Marathon Oil Company Well Name: KBU 22-6 _ Location: Kenai, Alaska. Offset Well Information 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, drlg ahead 1525 9.4 12 21 7.2 Drlg to casing point, condition mud, POH to run casing 1525 9.4 12 17 8.8 Cement casing, good cement to surface 12.25" 1525 9.05 12 18 8.8 Drlg out, displace to new mud, LOT = 15.3, ppg drlg ahead 2469 9.2 10 15 8.0 Drill ahead 4414 9.3 10 19 6.6 Drlg ahead, short trip OK, drlg ahead 5543 9.3 13 21 8.2 Drlg to 5417, lost returns pumped 3 LCM pills, stop losses, drlg ahead 6171 9.4 12 14 5.8 Drlg ahead, lost circulation, spot LCM pill 6176 9.1 10 14 7.4 Spot added LCM pills, losses as high as 100 BPH 6176 9 11 15 7.2 Stop losses prior to running 9-5/8" casing 6176 9.2 20 13 7.4 Run & cement csg, no losses until end of cement 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 22 26 5.2 POH, log well, RIH cleanout trip, OK 8624 11.05 21 25 4.4 Poh, run excape completion, cement same. i..~:.~~ • • '~ Marathon Oil Company Well Name: KBU 22-6 _ 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 B3 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. ~~ 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 . ~~ Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Interval Summary -16" hole 0 -1649' 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 Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Fluid Properties. Depth Mud Funnel .Yield API Drill Interval Weight. Viscosity Point Fluid Loss pH Solids (ft) (ppg) (sec./qt) (Ib./100ftz) (ml/3Omin)- (%) 0-1649' 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 secondslquart 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 - 2040 barrels. - Estimated haul off volume - 3280 barrels. ~~ ~ ~ • • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Interval Summary -12-1/4" hole 1649 - 6498' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / PolyPac Supreme UL / KCl / SafeCarb 10, 40, 250 MI Bar / Caustic Soda J Conqor 404 /Sodium Meta Bisulfate Solids Control. Shale Shakers / Desilter /Centrifuge Van Recommended initial shaker screens - 180/180/150 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Fluid Properties Depth Mud Plastic LSRV API .Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (PPg) (cP.) (cps) (ml/30min) (%) 1649 - 6498' 9.0 - < 9.5 8 - 12 40,000+ 7 - 9 < 7.5 +/- 5% - Use one rig pit to drill out surface casing. In other rig pits, build new Flo-Pro fluid using the enclosed fluid formula. Pre-heat makeup water with steam hoses as much as possible. - After drilling out surface casing, displace hole to Flo-Pro fluid prior to running leak off test - As mud heats up, increase F1oVis concentration to 2 PPB and install 180 mesh shaker screens on end panel. - NOTE: Beware of whole mud losses to the Sterling A8 & Unner Beluga formations. Ensure adequate brid~in~ material (30 PPB) is in the mud while drilling these formations. - If torque or sliding problems occur, add 1 - 3% Lubetex. - NOTE: This fluid will be used in the production interval. It is inherent to maintain proper_ fluid properties for that purpose. - Estimated volume usage for interval - 3119 barrels. - Estimated haul off volume - 4241 barrels. - Condition mud prior to running 9-5/8" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ~~ • • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Fluid Formula -12-1/4" Interval 12-1/4" Interval from 1649 - 6498 Input Descri tion KBU 22-6 Mud Wei ht 9.0 - 9.5 Preh rated Gel No Wei ht Material Code SafeCarb Preh: rated Gel Canc. Wei ht Material SG 2.8 KCI Wt°!o 6 NOTE: Pre-heat m akeu 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 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 5.00 5.00 0.005 1.80 Brid in A ent 7b SafeCarb 40 20.00 20.00 0.020 7.20 Brid in A ent 7c SafeCarb 250 5.00 5.00 0.005 1.80 Brid in A ent If for ue becomes a roblem or slidin is difficult add 1 - 3% of t he followin 8 Lubetex 14.00 14.00 0.041 14.43 Lubi•icit If bit ballin becomes a roblem add the followin 9 D-D CWT 1.00 1.00 0.003 1.00 Reduce BHA Balling Total Calculated Mud Total Chloride 399 399 1.000 350 9.500 Estimated Volume Usa a 3119 Barrels 29600 ~ ~ ~ • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Bridging Formula -12-1/4" Interval ~ Operator: Marathon Oil Company Mi SWACQ~~ ~ P T I B R I DG E' "" Well Name: KBU 22-6 Location: Kenai Gas Field ®1999 - 2004 M-I L.L.C. • All Rights Reserved Comments: Sterling A8 Sand Optimum Bridging Agent Blend c O 7 a N_ O d ((N^^ -f m _V L.. A a 7 E U Max Permeability : 4000 mDarcy Sand Control Davlce D10-D50-D90 ~'I D70 Target I Blend: 2.5 I 3.0 microns D50 Target /Bland: 63.2 I 57.8 microns D90 Target 181end: 205.0 I 244.4 microns Optimum Blend for 0 to 100 ~~~ CPS Range Brand Name Brld0lna AOentllblbbll Vol Y. B=SafeLarb 10 (F) 0.0 0.00 D=SafeLarb 40 (M) 28.8 88.67 E=Safe-Cart 250 (C) 3.4 11.33 E 71.9% D 88.7°/. -- Simulation Accuracy Calcium Carbonate added Avg Enor 0 -100 ~ CPS Range ~ ~` Max Error 0 -100 N CPS Range Particle Slze (microns) - Zone of interest -Sterling A-8 & Upper Beluga sands - Pore Pressure - 0.8 - 7.3 Maximum Porosity - 2500 mD - Measured Depth - Sterling A8 4548' (3570' TVD) /Upper Beluga 5852' (4730' TVD) - Build additional volume as needed using the blend listed above. ~~ r 30 Iblbbl 1.32 Y 8.75 • ~~ • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Interval Summary - 8-1/2" hole 6498 - 8563' Drilling Fluid System Flo-Pro Fluid Key Products Flo-Vis / Polypac Supreme UL 1 KCl 1 SafeCarb F & M / MI Bar / Caustic Soda / Congor 404 /Sodium Meta Bisulfate Solids Control Shale Shakers / Desilter /Centrifuge Van Recommended shaker screens - 210 - 230 mesh Potential Problems Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions nterval Drilling Fluid Properties .Depth Mud Plastic LSRV API Drill Interval Weight Viscosity 1 min Fluid Loss MBT Solids (ft) (p g) (cp.) (cps) (mll30min) (%) 6498 - 8563' 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: Receive aanroval from Pete Beraa or Will Tank nrior to adding EMI 920 lubricant to the mud system. (EMI 920 may provide reduction from metal-to-metal torque) - If running coals become a problem, treat with a 2 PPB addition of Asphasol Supreme. - Estimated additional volume for interval - 756 barrels. - Estimated haul off volume - 2141 barrels. - Condition mud prior to running 3-1/2" casing. NOTE: Follow BOSCO guidelines when adding biocide, oxygen scavenger and corrosion inhibitor. ir~~ • • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Dilution Formula - 8-1/2" Interval 8-/12" Interval from 6498 - 8563' Innu+ Descri tion KBU 22-6 Mud Wei ht 9.0 - 9.5 Preh .rated Gel No Wei ht Material Code MI BaR Preh drated Gel Conc. Wei ht Material SG 4.2 KCI'Wt% 6 Out ut -1 bbl Order of Products Concentration Volume Addition Field, Ib Lab m Field, bbl Lab, ml 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 Fine 15.00 22.50 0.017 5.67 Brid in A ent 5b SafeCarb Medium 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 If slidin or hi h for ue becomes a roblem add 1 - 3% of the followin 10 Lubetex 7.00 7.00 0.021 7.00 Lubricit If sloughing coals become a roblem add 2 - 4 b of the followin 11 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 Volume Usa a 756 Barrels Calculated Mud Wei ht 9.050 Total Chloride 29600 ~~ ~ ~ • • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Interval Summary -Completion Procedures Corrosion Control Additive in Casing x Tubing Annulus Well KBU 22-6 Volumes: Tubing Volume 3-1/2" Tubing ~a.so barrels Annular Volume Casing x Tubing 3sa.ss barrels 3.50 x 2.992 x 8563 ft 9.625 x 8.681 @ 6498 ft MD 8.500 x 3.50 @ 8563 ft M D Open Hole x Tbg 120.41 barrels Total Annular Volume 518.94 Tubing Volume ~a.5o Total Hole Volume 593.43 Treatment Procedures. 1. After the 3-1 /2" tubing is run and the drilling fluid is circulated and conditioned for the cement job, circulate an additional 398 barrels of drilling fluid. 2. Add 4 drums of Conqor 303A and 4 sacks Sodium Meta Bisulfate to this 398 barrels. 3. After the 398 barrels of drilling fluid with Conqor 303A and Sodium Meta Bisulfatehave been pumped downhole, begin the cement job. 4. This procedure will place corrosion control in the 3-1/2" x 9-5/8" annulus. ~~ r • • ~~ HSE Issues Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. 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. • • '~ Marathon Oil Company Well Name: KBU 22-6 _ 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. • • ~'~~ Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Flammability Reactivity PPE M-I BAR Weighting Agent *1 0 0 E M-I GEL Viscosity control *1 1 0 E GELEX Bentonite Extender 1 1 0 E FLOVIS Viscosifier 1 1 0 E DUAL-FLO Modified Starch 1 1 0 E POLYPAC Fluid Loss Reducer *1 1 0 E XCD Viscosifyer 1 1 0 E HEC Loss Circulation Material 1 1 0 E Safe-Garb F,M,C Bridging and weighting agent *1 0 0 E LO WATE Weighting agent *1 0 0 E Nut Plug Loss Circulation Material *1 1 0 E M-I Seal F, M, C Loss circulation Material *1 1 0 E Mix II F,M,C Loss circulation Material *1 1 0 E DESCO CF Dispersant 1 1 0 E SPERSENE CF Dispersant 1 1 0 E TANNATHIN Dispersant 1 1 0 , E VENTROL 401 Surfactant ? ? ? ? SALT (Solar) Densifier 1 0 0 E BROMIDE (Naar) ~ Brine Solution Densifier 1 0 0 F POTASSIUM ~~i'~~~il^t Shale Inhibitor 1 0 0 E ~~ • • ~'~ Marathon Oil Company - Well Name: KBU 22-6 _ Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS Product Function Health Flammability Reactivity PPE CAUSTIC SODA Ikalinity control 3 0 1 X CAUSTIC POTASH pH Modifier 3 0 1 X BORAX Inorganic Borate 1 0 -0 =- E SAPP Sodium Pyrophosphate *1 0 0 E SODA ASH Ikalinity control 1 1 0 E SODIUM BICARBONATE Ikalinity control 1 0 0 E CITRIC ACID pH Adjuster 1 0 0 E BIOBAN BP-PLUS Biocide *2 0 0 J GREEN CIDE 25G - Biocide 3 0 0 J DEFOAM X- Defoamer 1 1 0 J G-SEAL Sized graphite LCM 1 1 0 E EM1920 Lubricant 1 1 0 J LUBE TEX Lubricant 1 1 0 J D-D CWT Detergent 2 1 0 J Concor 404 Corrosion Inhibitor 1 1 0 J SAFEKLEEN Drilling fluid additive 1 1 0 J sphasol Supreme Shale Inhibitor 1 1 0 J Soltex Shale Inhibitor 1 1 0 J Sodium Meta Bisulfate Oxygen Scavenger 1 1 0 J ~~ • '~ Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Product Health and Safety Reference HMIS HAZARD RATINGS HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 -Severe hazard 3 -Serious hazard 2 -Moderate hazard 1-Slight hazard 0 -Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the material. HMIS PERSONAL PROTECTIVE EQUIPMENT INDEX A -Safety Glasses B -Safety Glasses, Gloves C -Safety Glasses, Gloves, Synthetic Apron D -Face Shield, Gloves, Synthetic Apron E -Safety Glasses, Gloves, Dust Respirator F -Safety Glasses, Gloves, Synthetic Apron, Dust Respirator G -Safety Glasses, Gloves, Vapor Respirator H -Splash Goggles, Gloves, Synthetic Apron, Vapor Respirator I -Safety Glasses, Gloves, Dust and Vapor Respirator J -Splash Goggles, Gloves, Synthetic Apron, Dust and Vapor Respirator K -Air Line Hood or Mask, Gloves, Full Suit, Boots X -Consult your supervisor for special handling directions • Marathon Oil Company Well Name: KBU 22-6 Location: Kenai, Alaska. Contacts Contact Title a-mail Work Cellular Pete Berga Drilling pkberga@marathonoil.com 907 565-3032 907 231-0663 Marathon Superintendent Will Tank Drilling Engineer wjtank@marathonoil.com 713 296-3273 713 203-8398 Marathon Tony Tykalsky Project Engineer ttykalsky@miswaco.com 907 274-5011 907 227-2412 MI SWACO Gus Wik Warehouse Manager gwik@miswaco.com 907 776-8722 907 776-8680 MI SWACO Michael Barry Senior Field gratefulmen@hotmail.com 907 260-4666 947 590-3636 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. ~~ Check No Check Date Bank Bank No vendor No Marathon Oil Company P O B 3128 Direct In uiries to: ACCOUNTS PAYABLE DEPARTMENT Hnd~ g 1167780 03/21 /2005 NCBAS 7780 5001123 . . ox Houston, Tx 77253 Accts Payable Contact Center Phone: 918-925-6097 HS t11v0ECe~~tVuillber tnvolce:Date E3ocumgtitVo~: Remi#:Comm2ttt..'.. Gross~Amount ~:~: [xsco~nf 3rtvordelPayAmouht L100.00 03/21/2005 1900013883 TOTAL: 100.00 100.00 100.0 100.0 • • TRANSMITAL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER ~V'ELL NAME PTD# Development Exploration Service ~ Stratigraphic CNECI{ VYAAT ADD-ONS "CL1JE"• APPLIES (OP770NS • MULTI The permit is for a new wellbore segment of LATERAL existing well ~ . Permit No, API No. (lf API number Production. should continue to be reported as _ last two. (2) digits a function'of the original API number siaied are between 60-69) above. • PILOT I30LE In accordance vritb ~ 20 AAC 25.005(1), all (PIS records, data and logs acquired. for 16e pilot • bole must be clearly differentiated 'in both • name (name on permit pins Ply snd API number (SO - 70/80) tram 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 sad produce is contingent upon issuance of a conservation order approving a spacing ~ eseeption. ~Comuanv Namel assumes the liability of any • protest to the spacing .esception that may occur. DRY DITCH AA dry ditch sample sets submined to the SAMPLE Commission must be in ao greater than 30' . sample inier•vals from below the perms~frost • or from where samples are first caught and . IO' sample intervals through target Zones. WELL PERMIT CHECKLIST Field & Pool KENAI, UPPER TYONEK BELUGA GAS -44857 Well Name: KENAI UNIT KBU 22-6 Program DEV Well bore seg ^ PTD#:2050540 Company MARATHON OIL CO Initial Class/type DEV 11-GAS GeoArea Unit On/Off Shore On Annular Disposal ^ Administration 1 Permitfee attached- _ - _ Yes _ - - - 2 Lease number appropriate____-_ __ __---_--_Yes__-_-_ _- -__._ 3 Uniquewell_nameandnumber-___________________________ _________ Yes.-___-- __-__- 4 Well located in a-defnedpo4l_-_-___-__-_. Yes______ ________ 5 Well located proper distance from drilling unitboundary- - - - - - - - - - - - - - - -Yes - _ - 6 Well located proper distancef[omotherwells-.____-__-_____-_ _.___Yes_-____- _- - - 7 Sufficient acreageayailablein_drillingunit_--_.___---_-_-______ _________Yes_-___ -_- -_..__- 8 IfdeyiatQd,is_wellboreplat_included-----------------_--_-_- __-_-_-_-Yes ____ __._. ------------------------------------------------------------- 9 Ope[atotonlyaffectedparty_______________________________ __.____-Yes-___-_ __- - - 10 Ope[atoChas.approgriate-bond in force________________________ _________Yes___--._ -__-__--_ .. -- - 1 t Permit can be issued without conservation order Yes Appr Date 12 Permit-can be issued without administrative.approva_I - - - - - - - - - - - - - - - Yes - _ - - - RPC 3/3012005 13 Can permk be approved before 15-day wait Yes 14 Well located within area and-strata authorized fly Injection Order # (pt~tl9# in_comments)_(Foc NA- - - - - - - - - - - - - - - - - _ _ _ _ _ - _ - _ _ _ - - _ _ _ - - _ . - _ . 15 All wells within114_milearea.ofreyiewidentified(Forserv-ice wellonly)______ _________ NA_-__-___ __,-._-___.___-__--__._____.__-__________-__--_-.,_-______-__-_., 16 Pre-produced injector: duration of pre prod4~ction less than- 3 months-(For_service well only) NA_ - _ - . - _ . - - - - - 17 ACMP_Finding of Consistency-has been issued-for_this project_ - - - - _ - - - NA_ - - - Engineering 18 Conductor string_plovided----.-------_ -_-, ---- -- ----Yes------- 20"~a130'.:--,_ _-- --------------- - --- -------------------_-. 19 Surface casing protectsall_knownUSDWs,_-_-_-._------------ -------_Yes--_._._ - - - - 20 CMT,V01 adeguate_to circul_ate_on conductor & su_rf_csg _ - - _ Yes - - - - Adequate excess, - - - - 21 CMT-vol_adequate_totie-inlgngstring to surfcsg_________________ _-__-_-_ No_-__-_._ __-_- 22 CMT-will cover all known-productive horizons_ - _ - - . - - _ - - Yes . _ 23 Gasingdesignsadequatef_o(C,_T,B&_permafrost------------------ --- - ---Yes----.- -----------.---.------------------------------.------------ _-- 24 Adequatetankage-o_rreservepit_-_.-----.--.-- -------- ------ --Yes------- Glacier_DrillingRig1,--_---,--------------------------- -------------_-,-- 25 If a_re-drill, has_a.10-403 for abandonment been approved - - - NA_ - _ _ - - New well. _ - _ _ _ _ _ _ - - - 26 Adequatewellboleseparation_proposed------------------------ ------_-Yes-.-..-- -.-..-_:_ 27 Ifdiverterrequired,doesitmeetregulations_.__________________ _______-Yes__.__ _-_._.:_._____-_- -.__ Appr Date 28 Drillingfluid-programschematic&ectuiplistadequate___- -_,__ Yes_-.---- Max MW.10,0-ppg._____-________________________________-_________ WGA 313112005 29 BOPES,dotheymeetregu_lation_--_________________-__, _ ___-_-Yes__-_-_ - - - - - - 30 BOPE press rating appropriate; test to_(put prig in comments)_ _ - - _ _ _ - - _ Yes - - _ - - Test to 2900 psi. _MSP 1821 psi.- - _ - - _ _ 31 Choke_manifoldcomplieswiAPI-RP-53(May84)___________________ _________Yes-_-___- _-_____ ----------------------------------------------------------- 32 Work willoccurwithoutoperationshutdown__-__---------------- --- - ---Yes-_-_--- - ---__ - - 33 Is Rresence-of H2S gasprobable - - - - - - - N0 - - - - - - - - - - - - 34 Mechanical_conditionofwellswithinAORyerified(For_servicewellonlyj__-_ _--_-_-_-NA__-__._ ___-____-_____-_-_-______--_-__--___-_-,________________ Geology 35 Permits-an be issuedwlohydrogen-sulfidemeasures__- -_-.___-__. _----__-Yes____- --__-_____-_____________________„_- _'-_______-_-_.---- 36 Data_presented on potential overpressure zones _ _ - - - _ _ _ _ - _ _ - - - NA- _ - _ - - - - - - - - - Appr Date 37 Seismic analysis-of shallow gas zones_-___-__-_---_-___-___ _____--_. NA____-_ _-_--____, - - - - RPC 313012005 38 Seabedcondjtionsurvey.(ifoff-shore)_-___--_--_-_--_---_-_ __.__,_-NA_--__-_ - - - _._ 39 -Contactna_melphgneforweeklyprogress_reports[exploratoryoAly]________ _____„__ NA__,___-_ _-._-___-_____- ,_-.-__-______--_--__-__--.--___-_-__-____--_ Geologic pate: Engineering Date is ' Date Commissioner: Commissioner: oner ~S 3~31~5 (~- ~-3~-05 ~3~ a~-- .7 J