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Home My WebLink About203-0661.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,610'6079' (fill) 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: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 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 todd.sidoti@hilcorp.com 7,434'4,823'4,029'1,229 6013', 5040', 4918' 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 FEDA028142 203-066 50-133-20522-00-00 Kenai Beluga Unit (KBU) 43-07X Kenai Gas Field / Sterling 3 Gas Pool Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY N/A TVD Burst N/A 10,160psi MD 5,750psi 3,960psi 3,450psi 138' 1,469' 5,340' 138' 1,510' 7,413'3-1/2" 20" 13-3/8" 138' 9-5/8"6,463' 1,510' 8,589' Perforation Depth MD (ft): 6,463' See Attached Schematic 8,589' Authorized Title: 17.I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: September 24, 2021 N/A wwn amamm eeeee d ed ss No ss No Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Meredith Guhl at 2:50 pm, Sep 10, 2021 321-464 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.09.10 14:26:55 -08'00' Taylor Wellman (2143) , Sterling Gas Pool 4 SFD SFD bjm DSR-9/13/21SFD 9/10/2021 This Sundry is denied because the proposed perforations are above the 9-5/8" x OH annular cement, which would not comply with 20 AAC 25.030(d)(5). CO 510B Perorations in the Sterling Gas Pools 3 and 4 cannot be open at the same time without an order approving downhole commingling from the AOGCC. inng Exceptionn Required? Yes No Subseeque roved by:C ss Nocing Exception Required?Yes proved by:C CSPtE s Subseque C Nocing Exception Reqequired??Yes proved by:C C S ss Subseque C No RBDMS HEW 9/24/2021 Well Prognosis Well: KBU 43-07X Date: 09/10/2021 Well Name: KBU 43-07X API Number: 50-133-20522-00-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: 09/24/2021 Rig: N/A Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 203-066 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Maximum Expected BHP: ~1591 psi @ 3616’ TVD (Based on normal gradient) Max. Allowable Surface Pressure: ~1229 psi (Based on 0.1 psi/ft gas gradient) Brief Well Summary: KBU 43-07X drilled and completed in 2003 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making 6 MMCFD. The well went offline in 2017 due to sand/water production. Several attempts to revive the well via slickline bailing with no success. The well has cum’d just under 12 BCF and 245 MBW of water. A non-rig workover was performed in early 2021 to isolate the backside of the 3-1/2”. The initial targets were the Sterling B5B, B5A and B2A – all which would either not flow or brought in sand/water. Objective: The purpose of this project is to isolate the existing open perfs and recomplete in the Sterling B1, A11, A10 and A9 formation(s). These sands are all in the same pool. Ahead of E-line, slickline will have to try and bail and possibly recover 112’ wire and spent 2.5” gun to have access to the proposed B1 sands. Wellbore Notes: x Last tag at 4,468’ RKB on 5/18/2021 w/ a 2.5” DD Bailer w/ wire skirt. (Full of mud) x Followed up with 2.72” RE magnet to 4,472’ RKB – Tag, POOH with metal shavings/broken E-line strands. x Min ID: 2.992” x Fluid level @ 1,410’ RKB – slickline determined from LIB run on 5/18/2021. NON-SUNDRIED STEP Slickline: 1. MIRU slickline and pressure test lubricator to 250 psi low / 2000 psi high. 2. Bail fill and fish 112’ of 7/32” eline and 5’ 2.5” gun assembly (OAL 29’). a. Minimum depth to bail down to is 4625’ 3. Drift for CIBP to PBTD. 4. RDMO BEGIN SUNDRIED STEPS E-Line: 1. MIRU E-Line and pressure test lubricator to 250 psi low / 2000 psi high. 2. RIH and set CIBP at ~4605’. a. Correlate to CBL dated 17-Jan-2021. 3. Dump bail 25 ft of cement on CIBP. 4. RDMO Sterling A11, A10, and A9 sands are in the Sterling Gas Pool 3; Sterling B1 sand is in the Sterling Gas Pool 4. SFD 9/10/2021 Well Prognosis Well: KBU 43-07X Date: 09/10/2021 Slickline: 1. MIRU slickline and pressure test lubricator to 250 psi low / 2000 psi high. 2. Swab well dry. 3. RDMO. E-line: 1. MIRU E-line, PT lubricator to 250 psi low and 2000 psi high. 2. Perforate the below zones from the bottom up with 2-3/8” HSC Guns: Sand Name Top MD Bottom MD Top TVD Bottom TVD Total MD P3_A9 ±4,273’ ±4,283’ ±3,616’ ±3,626’ ±10’ P3_A10 ±4,350’ ±4,390’ ±3,674’ ±3,704’ ±40’ P3_A11 ±4,410’ ±4,460’ ±3,719’ ±3,756’ ±50’ P3_B1 ±4,498’ ±4,505’ ±3,785’ ±3,792’ ±7’ P3_B1 ±4,553’ ±4,559’ ±3,826’ ±3,832’ ±6’ a. Discuss wellhead pressure with OE, anticipate wanting to hold 900 psi for initial shot. If necessary RU sales gas or Nitrogen to pressure up well prior to perforating. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Trudi Hallett 907.301.6657 Geologist Ben Siks 907.229.0865 d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. 3. RD E-Line. 4.Turn well over to production. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Nitrogen (Contingency) If Nitrogen is required to pressure up well prior to perforating or push fluid away: 1.MIRU Nitrogen Unit, review Nitrogen SOP, pressure well to desired perforating pressure. E-line Procedure (Contingency) If any zone produces sand and/or water or needs isolated: 1.MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 2.RIH and set 3-1/2” Casing Patch or set 3-1/2” CIBP above the zone and dump 25’ of cement on top of the plug. Attachments: Current Well Schematic Proposed Well Schematic Standard Well Procedure – N2 Operations Fish Schematic Sterling Gas Pool 3 -------------------------- Sterling Gas Pool 4 Isolation required between pools SFD 9/10/2021 r or needs isolated: P4_B1 SFD 9/10/2021 TOC in 9-5/8" x 12-1/4" annulus would not be compliant with 20 AAC 25.030(d)(5) if these perfs were allowed. Application denied. bjm P4_B1 Excape System Details - 17 Excape module system -Green control line connected to modules 1ĺ9 -Red control line connected to modules 10ĺ17 - Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) Isolated Perfs: (41’ net) = 6,706’ - 6,747’ (perf'd 10/18/08) (36’ net) = 6,770’ - 6,806’ (perf'd 10/18/08) Module 17 = 6,899' - 6,909' (frac'd 9/3/03) Module 16 = 6,940' - 6,950' (frac'd 9/3/03) Module 15 = 6,980' - 6,990' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,140' - 7,150' (frac'd 9/3/03) Module 11 = 7,193' - 7,203' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,432' - 7,442' (perf'd 9/3/03) Module 8 = 7,471' - 7,481' (frac'd 9/3/03) Module 7 = 7,540' - 7,550' (frac'd 9/3/03) Module 6 = 7,589' - 7,599' (perf'd 9/3/03) Module 5 = 7,690' - 7,700' (frac'd 9/3/03) Module 4 = 7,753' - 7,763' (frac'd 9/3/03) Module 3 = 7,920' - 7,930' (frac'd 9/3/03) Module 2 = 8,385' - 8,395' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) KOP:250' Build:2.5 deg per 100' Hold Angle:43 deg at 2,300' DOP:5,350' Drop:2.0 deg per 100' Final Angle:8 deg at 7,450' KBU 43-7x Pad 41-7 41' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 203-066-0 API #: 50-133-20522-00-00 Prop. Des: FED A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27' 34.67" Longitude: -151° 14' 47.43" X: 274,996.71 Y: 2,362,053.16 Spud: 5/22/2003 TD: 6/11/2003 Rig Released: 6/15/2003 06:00 hrs PA #: Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' TVD 0' 138' Surface Casing 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' 5,340' 12-1/4" hole, Cmt w/ 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' TVD 0' 7,413' Cmt w/ 970 sks of Class G TD 8,610' MD 7,434' TVD PBTD 4,823' MD 4,029' TVD Weatherford straddle packer assembly (set @ 6,698 MD RKB on 12/16/09): - WEA ER Packer (ID: 1.812")= 2.86' 2,800# to release - 2-3/8" spacer pipe (ID: 1.994")= 22.2' - WEA SO Tie Back (ID: 1.74")= 2.00' 2,760# to release - 2 3/8" spacer pipe (ID: 1.994")= 22.2' - WEA Snap latch seal (ID: 1.75")= 0.92' 5,520# to release - WEA ER Packer (ID: 1.812")= 2.70' Well Name & Number: Municipality: Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 43-7x Kenai Peninsula Borough 2.5º / 100ft @ 250 ft 6/16/2003 Todd Sidoti Lease: State: Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 7ºĺ 20º RKB:66' (AMSL)21' (AGL) 06/14/21 Excape System - Flapper depths (Module 16 & Module 1 = no flappers) Module 17 - 6,918' Module 16 - NA Module 15 - 6,999' Module 14 - 7,072' Module 13 - 7,113' Module 12 - 7,159' Module 11 - 7,212' Module 10 - 7,253' Module 9 - 7,451' Module 8 - 7,490' Module 7 - 7,559' Module 6 - 7,608' Module 5 - 7,709' Module 4 - 7,772' Module 3 - 7,939 Module 2 - 8,404' Module 1 - NA Tree cxn = 4-3/4" Otis SCHEMATIC 3-1/2" x 8-3/4" TOC @ 5450' (CBL 01/17/21) CIBP @ 6013' w/ 35' of cement, TOC @ 5978' 03/23/21 Tubing Cut @ 5370' 03/23/21 3-1/2" x 9-5/8" TOC @ 1760' (CBL 04-21-21) Sterling Perfs P4_B2A 4,655'-4,660' (05/14/21 Open) P5.2_B5A 5,006'-5,013' (04/22/21 Isolated) P5.2_B5B 5,051'-5,064' (04/13/21 Isolated) 9-5/8" x 12.25" TOC @ 4300' (Calculated using 145 bbls of cement with 20% washout) CIBP @ 5040' 04/22/21P5.2_B5B P5.2_B5A CIBP @ 4918'w/ 25' cement, TOC @ 4823' 04/11/21 P4_B2A E-line fish covered with fill @ 4472' 05/18/21 Excape System Details - 17 Excape module system -Green control line connected to modules 1ĺ9 -Red control line connected to modules 10ĺ17 - Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) Isolated Perfs: (41’ net) = 6,706’ - 6,747’ (perf'd 10/18/08) (36’ net) = 6,770’ - 6,806’ (perf'd 10/18/08) Module 17 = 6,899' - 6,909' (frac'd 9/3/03) Module 16 = 6,940' - 6,950' (frac'd 9/3/03) Module 15 = 6,980' - 6,990' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,140' - 7,150' (frac'd 9/3/03) Module 11 = 7,193' - 7,203' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,432' - 7,442' (perf'd 9/3/03) Module 8 = 7,471' - 7,481' (frac'd 9/3/03) Module 7 = 7,540' - 7,550' (frac'd 9/3/03) Module 6 = 7,589' - 7,599' (perf'd 9/3/03) Module 5 = 7,690' - 7,700' (frac'd 9/3/03) Module 4 = 7,753' - 7,763' (frac'd 9/3/03) Module 3 = 7,920' - 7,930' (frac'd 9/3/03) Module 2 = 8,385' - 8,395' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) KOP:250' Build:2.5 deg per 100' Hold Angle:43 deg at 2,300' DOP:5,350' Drop:2.0 deg per 100' Final Angle:8 deg at 7,450' KBU 43-7x Pad 41-7 41' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 203-066-0 API #: 50-133-20522-00-00 Prop. Des: FED A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27' 34.67" Longitude: -151° 14' 47.43" X: 274,996.71 Y: 2,362,053.16 Spud: 5/22/2003 TD: 6/11/2003 Rig Released: 6/15/2003 06:00 hrs PA #: Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' TVD 0' 138' Surface Casing 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' 5,340' 12-1/4" hole, Cmt w/ 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' TVD 0' 7,413' Cmt w/ 970 sks of Class G TD 8,610' MD 7,434' TVD PBTD 4,823' MD 4,029' TVD Weatherford straddle packer assembly (set @ 6,698 MD RKB on 12/16/09): - WEA ER Packer (ID: 1.812")= 2.86' 2,800# to release - 2-3/8" spacer pipe (ID: 1.994")= 22.2' - WEA SO Tie Back (ID: 1.74")= 2.00' 2,760# to release - 2 3/8" spacer pipe (ID: 1.994")= 22.2' - WEA Snap latch seal (ID: 1.75")= 0.92' 5,520# to release - WEA ER Packer (ID: 1.812")= 2.70' Well Name & Number: Municipality: Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 43-7x Kenai Peninsula Borough 2.5º / 100ft @ 250 ft 6/16/2003 Trudi Hallett Lease: State: Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 7ºĺ 20º RKB:66' (AMSL)21' (AGL) 9/9/2021 Excape System - Flapper depths (Module 16 & Module 1 = no flappers) Module 17 - 6,918' Module 16 - NA Module 15 - 6,999' Module 14 - 7,072' Module 13 - 7,113' Module 12 - 7,159' Module 11 - 7,212' Module 10 - 7,253' Module 9 - 7,451' Module 8 - 7,490' Module 7 - 7,559' Module 6 - 7,608' Module 5 - 7,709' Module 4 - 7,772' Module 3 - 7,939 Module 2 - 8,404' Module 1 - NA Tree cxn = 4-3/4" Otis PROPOSED 3-1/2" x 8-3/4" TOC @ 5450' (CBL 01/17/21) CIBP @ 6013' w/ 35' of cement, TOC @ 5978' 03/23/21 Tubing Cut @ 5370' 03/23/21 3-1/2" x 9-5/8" TOC @ 1760' (CBL 04-21-21) Sterling Perfs P3_A9 ±4,273' - ±4,283' Proposed TBDP3_B1 ±4,498' - ±4,505'P3_B1 ±4,553' - ±4,559' P4_B2A 4,655'-4,660' (05/14/21 Open) P5.2_B5A 5,006'-5,013' (04/22/21 Isolated) P5.2_B5B 5,051'-5,064' (04/13/21 Isolated) 9-5/8" x 12.25" TOC @ 4300' (Calculated using 145 bbls of cement with 20% washout) CIBP @ 5040' 04/22/21P5.2_B5B P5.2_B5A CIBP @ 4918'w/ 25' cement, TOC @ 4823' 04/11/21 P4_B2A E-line fish covered with fill @ 4,472' 05/18/21 PROPOSED STERLING PERFS See table of proposed perfs on page 2. SFD Sterling A11, A10, and A9 sands are in the Sterling Gas Pool 3; Sterling B1 sand is in the Sterling Gas Pool 4. SFD 9/10/2021 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. Company Date Well Name Co. Rep Field Engineer Borough Unit # State Wireline Length O.D 12.00 1.44 84.00 1.69 82.00 1.56 78.00 1.69 1.00 1.69 18.00 2.50 72.00 2.50 347.00 Comments 28.91 feet same filled with Titan 1/16 gun gamma 1 11/16 Teardrop 2.5 strip gun firing head 2.5 STP Stripgun fired Excalibur Impact Select Jars Hilcorp Alaska 5/14/2021 KBU 43-07 Billy Applewhite KGF Joe Dalebout TOTAL OAL Weight bar 1 11/16 x 7' KPB Silver Alaska 1/4" Description Rope Socket 1 7/16 tied 6 x 2 1" fishing neck David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Hilcorp North Slope, LLC DATE: 07/21/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 43-7X (PTD 203-066) CIBP-CMT-PERF_GPT 03/23/2021 Please include current contact information if different from above. 37' (6HW Received By: 07/21/2021 By Abby Bell at 3:08 pm, Jul 21, 2021 David Douglas Hilcorp Alaska, LLC Sr. Geotechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 564-4422 Received By: Date: Hilcorp North Slope, LLC DATE: 07/21/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 43-7X (PTD 203-066) CIBP-CMT-PERF_GPT 05/12/2021 Please include current contact information if different from above. 37' (6HW Received By: 07/22/2021 By Abby Bell at 3:08 pm, Jul 21, 2021 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: N2/Cement Packer Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number):8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071):10. Field/Pool(s): 11. Present Well Condition Summary: 4918, Total Depth measured 8,610 feet 5040, 6013 feet true vertical 7,434 feet 7,893 (Fill) feet Effective Depth measured 4,823 feet 6,698 feet true vertical 4,029 feet 5,557 feet Perforation depth Measured depth See Attached Schematic True Vertical depth See Attached Schematic Tubing (size, grade, measured and true vertical depth)3-1/2" 9.3# / L-80 8,589'(MD) 7,413(TVD) 6,698'(MD) Packers and SSSV (type, measured and true vertical depth)Straddle Packer 5,557'(TVD) N/A N/A 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure:N/A 13. Prior to well operation: Subsequent to operation: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Taylor Wellman 777-8449 Contact Name:Todd Sidoti Authorized Title:Operations Manager Contact Email: Contact Phone:777-8443 todd.sidoti@hilcorp.com Senior Engineer:Senior Res. Engineer: Burst 3,950psi 10,160psi 138' 1,469' 6,870psi 3,450psi Collapse 1,500psi 1,950psi 4,750psi 10,530psi Casing Structural 20" 13-3/8" 9-5/8" Length 138' 1,510' 6,463' 8,589' Conductor Surface Intermediate Production Authorized Signature with date: Authorized Name: 430 Casing Pressure Liner 0 0 Representative Daily Average Production or Injection Data 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. 321-095 25 Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 0 Gas-Mcf 26 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 203-066 50-133-20522-00-00 4. Well Class Before Work:5. Permit to Drill Number: 3. Address: 2. Operator Name:Hilcorp Alaska, LLC 00 Kenai Beluga Unit (KBU) 43-07X N/A FEDA028142 6,463' Plugs Junk measured 3800 Centerpoint Dr Suite 1400 Anchorage, AK 99503 Kenai Gas Fieldk / Sterling 3, 4, 5.1 & 5.2 GasN/A measured TVD Tubing PressureOil-Bbl measured true vertical Packer 3-1/2"8,589' 5,340' 7,413' WINJ WAG 0 Water-Bbl MD 138' 1,510' 0 t Fra O 6. A G L PG , R Form 10-404 Revised 3/2020 Submit Within 30 days of Operations By Samantha Carlisle at 1:13 pm, Jun 18, 2021 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.06.18 11:32:51 -08'00' Taylor Wellman (2143) BJM 11/18/21 RBDMS HEW 6/22/2021 SFD 6/21/2021DSR-6/21/21 Rig Start Date End Date 3/23/21 5/18/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 43-07X 50-133-20522-00-00 203-066 03/25/2021 - Thursday PTW, JSA. MIRU rain for rent supply and return tank. RU HAK hot oil truck and AK E-line head pin and otis x over on tubing. Rig up pump hose. Rig 1502 iron from IA to 400 bbl diffuser tank. Cruz tanker truck loading supply tank with 400 bbls of fresh water. PT pump line 250/4,500 psi. Online down tubing at 1 bbl.min 3,600 psi. After 8 bbls pumped pressure dropped to 700 psi, online max rate circulation pressure 2,500 psi at 3.5 bbls/min. Vac truck hauling loads to G&I while circulating. Pump a total of 1,163 bbls. Returns cleaned. Swapped pump lines to reverse out after 355 pumped. Continue to haul returns to G&I facility. Rig down hot oil truck and fluid tanks. Bring AK E-line Otis x over and head pin to KDU 10. Mobe hot oil truck to farm yard. Location secure. SDFN. PTW, JSA with AK E-line. Hot oil truck enroute from Cruz shop. Having issues with ignition switch on hot oil truck. Remove snow around wellhead. MIRU AK E-line services. Spot in HAK hot oil truck. Stab on well with drift BHA. PT E-line stack 250/2,500 psi. RIH with 1-11/16" GGR, 1-11/16" x 7' WB, junk basket and 2.77 Gauge ring. Tagged at 6,009' uncorrected ccl depth. Log OOH to correlate, tagged up at surface. Pop off well and make up CIBP. RIH with 1-11/16" GR, 1-11/16" x 7' WB, and 2.75" CIBP. Log strip OOH. Top of plug 6,013.4'. Set plug. Good indication of set. 210 lb weight loss. Pick up and RIH to tag plug. Plug set and confirmed at 6,013.4'. POOH to surface. Make up cement dump bailer BHA. RIH with 2.5" x 30' bailer. tag plug. Pick up tension/slack and dump cement at 6,010'. POOH to surface. Tag up. Mix 2nd batch of cement. Stab on well. RIH with 2nd cement dump bailer run to 6,000'. Dump cement. POOH to surface. 35' of cement dumped on top of CIBP. Rig up 2.5" jet cutter. RIH. Log strip and correlate. 22.5' CCL top of cut. Park CCL at 5,347.5'. Pressure up on tubing with hot oil truck to 2,000 psi. 22 psi IA. Cut tubing at 5,370'. WHP dropped from 2,000 psi to 1,000 psi. IA pressure bobbled from 22 psi to 56 psi and slowly climbed to 75 psi. OOH with jet cutter. Confirm fire. Rig down E-line and hot oil truck. Mobe hot oil truck to farm yard for triplex pump discharge seal replacement planned for the AM. 03/23/2021 - Tuesday Daily Operations: 03/29/2021 - Monday HES cementing arrive on location. PTW with HAK field operator. Hold PJSM with crews. Spot in cement pump, 2x ABT trucks. RU 1502 iron to wellhead ottis connection. RIg up return iron from IA to return tank. 0 psi tubing , 0 psi IA. Open well and break circulation with 2 bbls of fresh 80°F water. Close in HES downhole valve at wellhead. Pressure test 250/4,000 psi. Good test. Cement wet. Verify cement density is 15.3 ppg. Pump 705 sks of primary cement at 15.30 PPG, 1.24 ft/sk, 5.05 gl/sk. Pumped for a total of 153 bbls at average pump rate of 4 bbls/min @ 230 psi. Shut down pumps. Launch wiper ball and chase with 48 bbls of fresh water for displacement. (1 bbl over). Shut down pumps. Close in master and swab valve. Final SITP 1,010 psi. Close IA gate valve. Cement job went as planned. Full 1:1 returns during cementing operations. Informed production that the tree will need to be covered and heated prior to Slick line work due to having fresh water across tree post cement job. Manifest returns to G&I. HES depart location. Location walk around complete. 04/02/2021- Friday MIRU SL run READ memory CBL. Pump 705 sks of primary cement at 15.30f PPG, 1.24 ft/sk, 5.05 gl/sk. Pumped for a total of 153 bbls See attached email for log interpretation and further MITIA requirements. RIH with 2nd cement dump bailer run to 6,000'. Dump cement. Pump a total of 1,163 bbls. Returns cleaned. Top of plug 6,013.4'. Set Cut tubing at 5,370'. W Pick up tension/slack and dump cement at 6,010' POOH to surface. 35' of cement dumped on top of CIBP. R Cement job went as planned. Full 1:1 returns during cementing operations. Tagged at 6,009' chase with 48 bbls of fresh water for displacement. (1 bbl over) Pick up and RIH to tag plug. Plug set and confirmed at 6,013.4' READ memory CBL. Rig Start Date End Date 3/23/21 5/18/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 43-07X 50-133-20522-00-00 203-066 Daily Operations: Sign in. Mobe to location. Spot equipment. PTW and JSA. Rig up lubricator, PT to 250 psi and 2,500 psi high. TP - 78 psi. RIH w/2-1/2" x 7' 4 spf, 60 deg phase spiral strip gun and tie into Perf log and tag high at 4,889'. Run correlation log and send to town. Told to run a 500' log. Ran correlation log and send to town. Said it was on depth. POOH. Called Halliburton SL and they showed up about same time AKE-line was out of hole. Rig down AKE-Line Stand by til 1720 hrs. PTW, JSA and SIMOPS with AKE-Line. Spot and RU Halliburton equipment. PT lubricator 2,500 psi. MU 2-1/2" x 13' pump bailer. RIH w/ 2-1/2" x 13' pump bailer and tag at 4,897' KB. Worked bailer to 4,912' and POOH. Flapper broke and just got back a little bit of gray mud and foam like grey water. Fix bailer flapper and run back in hole to 4,912' and bailed down to 4,921'. POOH. Got about 3' of grey mud and rest foamy grey water. RIH w/ 2.80" gauge ring to clean wall off and tagged at 4,928' KB. Spudded to 4,940'. POOH. RIH w/ 2.5 "x 6' Drive Down Bailer and tag at 4,940', Bailed to 4,946.5'. Bailing was harder this time. POOH. Had about 1' of grey mud and rest grey water. Told Halliburton to make sure they brought some smaller bailers just in case they have to bail a pilot hole. Rig down Halliburton lubricator for the night. Secure well and they will be back at 0700 hrs in the morning. Leaving 2 samples in coffee cups on Kraig desk. 04/22/2021 - Thursday Sign in. PTW, JSA, and SIMOPS w/AKE-Line and Fox (N2). Spot equipment and rig up hard lines and lubricator. PT to 250 psi low and 4,000 psi high. RIH w/GPT and 2.75" CIBP and correlate with Jet cut log. Run correlation log and send to town. Get ok to set plug at 5,040' with 2,000 psi on on tubing. Spot and set plug. Lost 200 lbs line tension. Pick up 30' and go back down and tag. POOH. Tools look good. Good set. RIH w/ 2-1/2" x 7' Spiral Strip gun, 4 spf, 60 deg phase and tie into Plug log. Run correlation log and send to town. Get ok to perf from 5,006' to 5,013'. Spot and fire gun w/1,036 psi on tubing. After 5 min - 1,047 psi, 10 min - 1,049' psi, and 15 min - 1,051' psi. All shots fired. Rig down equipment and lubricator off well. Secure well and turn well over to field. 05/05/2021 - Wednesday 04/13/2021 - Tuesday Sign in. Mobe to location. Spot equipment and rig up lubricator. PT lubricator to 250 psi low and 2,500 psi high. RIH w/ 2- 1/2" x 10' Spiral, 4 spf, 60 deg phase strip gun and tie in to CBL log. Run correlation log and send to town. Town said add 8'. Add 8' and send back to town. Get ok to perf from 5,054' to 5,064' w/1,025 psi on well. After 5 min -1,021 psi, 10 min - 1,021 psi and 15 min - 1,020 psi. POOH/All shots fired. Rig down lubricator and secure well. Turn well over to field and finish rig down. Sterling 5.2 Gas pool o set plug at 5,040' with 2,000 psi on on tubing. Spot and set plug. A condition of approval on the sundry was an MITIA to 1500 psi after perforating, before producing. AOGCC sent an email to Hilcorp 4/17/21 allowing for the post-cement MITIA to be done after 10 days of production on IA cement packer squeezes. This well didn't produce for 10 days. See 2 attached emails. BJM o perf from 5,054' to 5,064' Sterling 5.2 Gas pool RIH w/ 2.80" gauge ring to clean wall off and tagged at 4,928' KB. S perf from 5,006' to 5,013'. Spot and fire gun w Rig Start Date End Date 3/23/21 5/18/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 43-07X 50-133-20522-00-00 203-066 Daily Operations: 05/11/2021 - Tuesday Sign in. Mobe to location. PTW and JSA. Spot and rig up equipment. PT lubricator to 250 psi low and 2,500 psi high. TP - 0 psi. RIH w/2,75" CIBP w/Setting tool, CCL, GR and tie into Tag log. Tagged high at 4,920'. Had Collar at 4,923'. Ran correlation log and send to town. We are on depth. Town got permission to set plug as low as we could. Bottom of plug at 4,919', Top of plug 4,917.5'. Spot and set plug at 4,917.5'. Lost 200 lbs when plug set. Pick up 30' and go backdown at tag plug. POOH. Tools look good. Good set. RIH w/ 2-1/2" x 30' dump bailer filled with 4.5 gal of 16ppg cement and dump bail 12.5' of cement on top of plug at 4,917.5'. Lost weight and pull out of hole. Good dump. Tools looked good. RIH w/ 2-1/2" x 30' dump bailer filled with 4,5 gal of 16ppg cement and dump bail 12.5' of cement on top of cement we just dumped. (25 gals total.) Cement In place a 1614 hrs, Est TOC is 4,892.5'. Rig down off well and secure well. Well be back tomorrow and perforate well. 05/12/2021 - Wednesday Sign in. Mobe to location. PTW and JSA. Rig up equipment and lubricator. PT to 250' low and 2,500psi high. Field put 130 psi on tubing for perf job. RIH w/ 2-1/2" x 5' Spiral, 4 spf, 60 deg phase strip gun and tie into perf log. Run correlation log and send to town. Get ok to perf from 4,660' to 4,655'. Spot and fired gun with 130 psi on tubing. POOH. Gun did not fire due to bad detonator. WO GPT tool. Tool showed up at 1430 hrs. RIH with GPT tool down to 2,082' and found out sensor was stopped up and log showed fluid at 2,082'. Was showing gas and then started showing fluid. It turned out to be fluid level at 896'. POOH. Rig down equipment and lubricator. Secure well and turn over to field. Will have to swab well down and come back to perforate. 05/13/2021 - Thursday No activity to report. Tagged high at 4,920'. l have to swab well down and come back to perforate. Cement In place a 1614 hrs, Est TOC is 4,892.5' RIH w/ 2-1/2" x 30' dump bailer filled with 4.5 gal of 16ppg cement a Spot and set plug at 4,917.5' RIH w/2,75" CIBP w Gun did not fire due to bad detonator. Rig Start Date End Date 3/23/21 5/18/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 43-07X 50-133-20522-00-00 203-066 Daily Operations: 05/15/2021 - Saturday Arrive @ KGF- Perform JSA & Gain permit approval- Depart for pad. Arrive @ Pad. Begin PT to 2000#- Test Good. RIH W/ 2.73 Bell Guide JDC to 2372'KB- W/T- No Latch- POOH. RIH W/ 2.72 LIB to 2372'KB- W/T- POOH W/ E-line Impressions. RIH W/ 2.5 GR W/ 2.5 Baitsub W/ 2.56 Internal Wiregrab to 2372'KB- W/T- overpull noted- W/T. POOH W/ 400# Overpull to 2318' and come tight- Make 1100# Jar lick and come free- POOH.;RIH W/ 2.5 GR to 2355'KB- W/T- Latch- Pull 1400# Jar Lick & Come free- POOH- Grab Set. Begin Rig down of .125 Wire- Prep unit for .160 Operations. RIH W/ 2.5 PR to 2350'KB- W/T- Latch- Pull up to 1500# & Come free- POOH W/ Wire Grab. RIH W/ GR & Baited 2.65 WireGrab to 2360'KB- W/T- Cannot latch- POOH & pump 100' Diesel downhole. RIH W/ Same to 2350'KB- W/T- Gain overpull- make 3 1500# Jarlicks & Come free- Wiregrab set.;RIH W/ 2.5 PR to 2350' W/T- Latch- Pull jarlicks from 2000# Ranging to 3600# (3 3500& 1 3600#), No Movement- Shear off- POOH. Begin Lay Down- Secure Well & Equipment for the evening. 05/16/2021 - Sunday Arrive @ KGF- Perform JSA & Gain permit approval- Depart for pad. Arrive @ Pad- Begin R/U of Braided line. RIH W/ PR to 2345'KB- W/T- Gain Over pull- Initial Jar Lick @ 3500#- Then straight pull to 8000#. W/ No movement- Apply 5000# Jar lick followed by 4 7000# Jar Licks- Straight pull to 8600#. And break free- POOH W/ 900# Over pull. Apply Eline BOP when at surface. Break off and note Single String of braided line.;Separate E-line from Wire grab and lay down braided line to prep for RIH W/ Baited Wire Grab W/ GR to 75'KB- W/T- E-line engaged- POOH W/ 800# Over pull. Apply E-Line BOP & Break off- Note Single string of E-Line- Lay down to prep for wire stripping. Standby for E-line Wire Stripping. Confirmed 2200' E-line string recovered- Estimated 112' Remaining along side tool string & Cutter. Secure Equipment for evening. 05/14/2021- Friday Sign in. Mobe to location, PTW and JSA. Spot and start rig up. Line started creeping on drum while rigging up. Have to fix line on drum. Pressure up tubing to 120 psi. PT to 250 psi low and 2,500 psi high. RIH w/ 2.50" x 5', Spiral 4 spf, 60 deg phase and tie into OHL. Run correlation log and send to town. Get ok to perforate from 4,655' to 4,660' w/110 psi on tubing. Spotted and fired gun w/110 psi. Lost 500 lbs of line tension when shot but got it back. Pulled free up to 4,580' and pulled tight. Picked up to 2,200' and either jars went off or line slipped besid tools. Pick up to 4,564' and same thing happend but pulled up to 3,200 lbs. Pulled up 4,551' and pulled up to 3,800 lbs from 3,200 lbs. We would pull 200 lbs increments. Couldn't get it to move so we called town again. We were in communictions with town and Andy and Chad in the field. One or the other was there most of the time. Decision was made to get slickline out with a kinley cutter. Pollard has them in stock, Got cutter out there to cut wire while waiting on SL unit with 160 wire. Put Kinley cutter on line and set timer for 60 min. Pulled 300 lb overpull on line (800) and dropped cutter. At 1608 hrs cutter went off and line jumped and we were showing light on line weight and when we got to approx 2,300' it was showing 68 lbs. Then at 2,230' line pulled tight. Checked turns on swab and closed swap carefully. Pop lubricator off and did not have the cutter on line. The line caught in grease tube looked like a good Kinley cut on the line as far as Pollard and AKE-Line. I haven't seen that many but it look like it was cut instead of work into. The cutter isn't susposed to come off line but i have heard of them doing it. Looks like approx 2,230' of line and tools in hole plus Kenly cutter should be on top of line in hole. Pollard is staging equipment and will be there at 0700 hrs. in the morning. rforate from 4,655' to 4,660' w/110 psi on tubing. Spotted and fired gun w Sterling 4 gas pool Fishing e-line wire and toolstring Rig Start Date End Date 3/23/21 5/18/21 Hilcorp Alaska, LLC Well Operations Summary API Number Well Permit NumberWell Name KBU 43-07X 50-133-20522-00-00 203-066 Daily Operations: Arrive @ KGF- Perform JSA & Gain permit approval- Depart for pad. Arrive @ Pad- Begin R/U of Braided line. RIH W/ 2.72 LIB to 3869'KB- W/T- POOH W/ Nipple impression. RIH W/ 2.70 Guided JDC to 3869'KB- W/T- Latch- POOH W/ Kinley cutter. RIH W/ 2.72 LIB to 4395'KB- W/T- POOH W/ Wire impression. RIH W/ 2.5 Baited Sub W/ GR to 4398' W/T- No Latch- POOH W/ Kinley Cutter Wedge.;RIH W/ 2.7 LIB to to 4398'KB- W/T- POOH W/ E-line Impression. RIH W/ Baited Wire Grab to 4398'KB- W/T- No Latch- POOH. RIH W/ 2.6 RE Magnet to 4437'KB- W/T- POOH W/ E-line Strands. RIH W/ Baited Wire Grab to 4437'KB- W/T- No Latch- POOH. Begin Lay down- Secure Well & Equipment for the evening- depart for shop. 05/18/2021 - Tuesday Arrive @ KGF- Perform JSA & Gain permit approval- Depart for pad. Arrive @ Pad- Begin R/U of Braided line. RIH W/ 2.73 LIB To- 4437'KB- W/T-POOH W/ No marks- *Fluid determined @1410'KB. RIH W/ Baited Wire grab to 4437'KB- W/T- No Latch- POOH. RIH W/ 1.75 DD Bailer W/ Wire Skirt to 4337'KB- W/T- POOH W/ Full Mud/Fill- Standby for Bailers. RIH W/ 2.5 P-Bailer W/ Wire Skirt to 4435'KB- W/T- POOH W/ 3/4 Full Mud.;RIH W/ Same to 4442'KB- W/T- POOH W/ 1/2 Full Mud. RIH W/ Same to 4454'KB- W/T- POOH W/ 1/2 Full Mud. RIH W/ Same to 4461'KB- W/T- POOH W/ 1/2 Full Mud. RIH W/ Same to 4468'KB- W/T- POOH W/ 1/2 Full Mud. RIH W/ 2.72 RE Magnet to 4472'KB - Tag- POOH W/ metal shavings/broken E-line strands. Begin R/D- Secure Well & Prep Equipment for Transit. 05/17/2021- Monday Gave up on fishing wireline and wireline toolstring. 08/15/21 - Excape control lines were cemented. See attached email. 10/11/21 - MITIA to 1600 psi passed. See attached email and test chart. Excape System Details - 17 Excape module system -Green control line connected to modules 1ĺ9 -Red control line connected to modules 10ĺ17 - Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) Isolated Perfs: (41’ net) = 6,706’ - 6,747’ (perf'd 10/18/08) (36’ net) = 6,770’ - 6,806’ (perf'd 10/18/08) Module 17 = 6,899' - 6,909' (frac'd 9/3/03) Module 16 = 6,940' - 6,950' (frac'd 9/3/03) Module 15 = 6,980' - 6,990' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,140' - 7,150' (frac'd 9/3/03) Module 11 = 7,193' - 7,203' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,432' - 7,442' (perf'd 9/3/03) Module 8 = 7,471' - 7,481' (frac'd 9/3/03) Module 7 = 7,540' - 7,550' (frac'd 9/3/03) Module 6 = 7,589' - 7,599' (perf'd 9/3/03) Module 5 = 7,690' - 7,700' (frac'd 9/3/03) Module 4 = 7,753' - 7,763' (frac'd 9/3/03) Module 3 = 7,920' - 7,930' (frac'd 9/3/03) Module 2 = 8,385' - 8,395' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) KOP:250' Build:2.5 deg per 100' Hold Angle:43 deg at 2,300' DOP:5,350' Drop:2.0 deg per 100' Final Angle:8 deg at 7,450' KBU 43-7x Pad 41-7 41' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 203-066-0 API #: 50-133-20522-00-00 Prop. Des: FED A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27' 34.67" Longitude: -151° 14' 47.43" X: 274,996.71 Y: 2,362,053.16 Spud: 5/22/2003 TD: 6/11/2003 Rig Released: 6/15/2003 06:00 hrs PA #: Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' TVD 0' 138' Surface Casing 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' 5,340' 12-1/4" hole, Cmt w/ 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' TVD 0' 7,413' Cmt w/ 970 sks of Class G TD 8,610' MD 7,434' TVD PBTD 4,823' MD 4,029' TVD Weatherford straddle packer assembly (set @ 6,698 MD RKB on 12/16/09): - WEA ER Packer (ID: 1.812")= 2.86' 2,800# to release - 2-3/8" spacer pipe (ID: 1.994")= 22.2' - WEA SO Tie Back (ID: 1.74")= 2.00' 2,760# to release - 2 3/8" spacer pipe (ID: 1.994")= 22.2' - WEA Snap latch seal (ID: 1.75")= 0.92' 5,520# to release - WEA ER Packer (ID: 1.812")= 2.70' Well Name & Number: Municipality: Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 43-7x Kenai Peninsula Borough 2.5º / 100ft @ 250 ft 6/16/2003 Todd Sidoti Lease: State: Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 7ºĺ 20º RKB:66' (AMSL)21' (AGL) 06/14/21 Excape System - Flapper depths (Module 16 & Module 1 = no flappers) Module 17 - 6,918'Module 16 - NA Module 15 - 6,999' Module 14 - 7,072' Module 13 - 7,113'Module 12 - 7,159' Module 11 - 7,212' Module 10 - 7,253' Module 9 - 7,451'Module 8 - 7,490' Module 7 - 7,559' Module 6 - 7,608' Module 5 - 7,709' Module 4 - 7,772' Module 3 - 7,939 Module 2 - 8,404' Module 1 - NA Tree cxn = 4-3/4" Otis SCHEMATIC 3-1/2" x 8-3/4" TOC @ 5450' (CBL 01/17/21) CIBP @ 6013' w/ 35' of cement, TOC @ 5978' 03/23/21 Tubing Cut @ 5370' 03/23/21 3-1/2" x 9-5/8" TOC @ 1760' (CBL 04-21-21) Sterling Perfs P4_B2A 4,655'-4,660' (05/14/20 Open) P5.2_B5A 5,006'-5,013' (04/22/21 Isolated) P5.2_B5B 5,051'-5,064' (04/13/21 Isolated) 9-5/8" x 12.25" TOC @ 4300' (Calculated using 145 bbls of cement with 20% washout) CIBP @ 5040' 04/22/21P5.2_B5B P5.2_B5A CIBP @ 4918'w/ 25' cement, TOC @ 4823' 04/11/21 P4_B2A E-line fish covered with fill @ 4551' 05/15/21 P4_B2A 4,655'-4,660' (05/14/20 Open) P5.2_B5A 5,006'-5,013' (04/22/21 Isolated) P5.2_B5B 5,051'-5,064' (04/13/21 Isolated) 5054-5064' noted in report - bjm Data Collection Report Chassis Left Scale Right Scale Serial Number 823373 567620 Datatype Lower Units PSI G Lower -200.0 0.0 200.0 400.0 600.0 800.0 1000.0 1200.0 1400.0 1600.0 1800.0 PSI G 43-7X MIT -11-Oct-21, 03:31:18, 1187 Data Points 1 Winston, Hugh E (CED) From:McLellan, Bryan J (CED) Sent:Tuesday, April 6, 2021 11:04 AM To:Todd Sidoti - (C) Subject:RE: KBU 43-07X (PTD 203-066) CBL Todd, Fortunately it looks like good cement across most of P4 and P3 proposed perf intervals. The cement across the proposed P5 intervals from 4750‐5051 looks a bit questionable, but there is good isoloation between the P4 and P5 (and also between P4 and P3), so there shouldn’t be an issue with comingling when you plug back from P5 and move up hole. The Sundry 321‐095 requires a MITIA after perforating and before returning to production. Whenever you decide to add perfs up hole, you’ll need to repeat the MITIA to make sure you haven’t perf’d into a channel. Also, you’ll need to add this well to the list for cementing the Escape System lines. Jake Flora has a bunch of similar wells and he’s planning a campaign to cement these lines. Let me know if you’d like to discuss further. Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Sent: Tuesday, April 6, 2021 9:46 AM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: KBU 43‐07X (PTD 203‐066) CBL Hi Bryan, Here is the CBL we ran on 43‐07X prior to our planned perforations. The cement job did not go great, our TOC showed up ~1200’ higher than planned. This matched up pretty well with the lift pressure we saw as well (1010 psi). My analysis is that even though the CBL response is low throughout the log there must be some channeling going on. Looking at the VDL I would expect that we do not have good isolation from 2332’‐3650’ with a few exceptions. Fortunately I do believe that we have good cement isolation between all proposed perforation intervals: 4351’‐5070’. Please let me know if you want to discuss further. Thanks, Todd Todd Sidoti | Kenai Ops Engineer | Hilcorp Alaska | 907‐632‐4113 1 Winston, Hugh E (CED) From:McLellan, Bryan J (CED) Sent:Tuesday, May 11, 2021 2:18 PM To:Todd Sidoti - (C) Subject:RE: KBU 43-07X (PTD 203-066) Plug Depth Todd, Sounds good. You have the go ahead to proceed with your plan. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Sent: Tuesday, May 11, 2021 12:23 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: KBU 43‐07X (PTD 203‐066) Plug Depth Hi Bryan, We are setting a plug and dumping cement at 43‐07X in order to move from the Sterling 5.2 Gas Pool to the Sterling 4 Gas Pool. We have encountered fill in the well and bailed sand but the sand came back in on us. Open perforations exist from 5006’‐5013’. Original plug set depth was ~4980 but we propose a new plug depth of ~4920’. Thanks, Todd Todd Sidoti | Kenai Ops Engineer | Hilcorp Alaska | 907‐632‐4113 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 1 Winston, Hugh E (CED) From:McLellan, Bryan J (CED) Sent:Monday, October 11, 2021 9:29 AM To:Todd Sidoti - (C) Subject:RE: [EXTERNAL] KBU 43-07X (PTD 203-066) MITIA Todd We still need an MITIA to 1500 psi to close out the IA cement job 10‐404 for Sundry #321‐095. Please have one done and I’ll attach the results to the 10‐404. Thanks Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 From: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Sent: Friday, October 8, 2021 12:49 PM To: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] KBU 43‐07X (PTD 203‐066) MITIA Hi Bryan, I know for certain that this well did not produce, this project was a $500k failure. No post production MIT‐IA was performed. Thanks, Todd From: McLellan, Bryan J (CED) <bryan.mclellan@alaska.gov> Sent: Friday, October 8, 2021 12:12 PM To: Todd Sidoti ‐ (C) <Todd.Sidoti@hilcorp.com> Subject: [EXTERNAL] KBU 43‐07X (PTD 203‐066) MITIA Todd, I’m looking at another 10‐404 for an IA cement squeeze and there is no mention of the MITIA being done after perforating. Can you send me the report and test chart if one was done? Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250‐9193 1 Winston, Hugh E (CED) From:Todd Sidoti - (C) <Todd.Sidoti@hilcorp.com> Sent:Thursday, November 18, 2021 3:30 PM To:McLellan, Bryan J (CED) Subject:KU 43-07X (PTD 203-066) Missed Reporting Attachments:43-7X MIT-IA 10-11-21.xlsx Hi Bryan, I dropped the ball during my transition to the field in following up with you on this well’s status. We performed a passing MIT‐IA per your request on 10‐11‐21, it is attached. We also did cement up the control lines on 8‐15‐21. I have included the morning report for 8‐15‐21 as documentation. Please let me know if you have any follow‐up required. I think that our new 10‐404 plan will prevent this from happening moving forward. Thanks, Todd From: Shea Mullin <smullin@hilcorp.com> Sent: Monday, August 16, 2021 5:39 AM To: Chad Johnson <chjohnson@hilcorp.com>; Chris Walgenbach <cwalgenbach@hilcorp.com>; Kraig Mcghie <kmcghie@hilcorp.com>; Andy Graves <agraves@hilcorp.com>; Taylor Wellman <twellman@hilcorp.com> Subject: 8‐15‐21 morning report Kenai Highlights Route Yesterday oday VARIANCE CLU‐1 & 3 34‐ 31 43‐32 Routine 1114 1663 551 4 0 0 14‐6 Line locates cmplete for 3‐7X and KDU‐1 0 0 563 1659 0 0 41‐ 7 41‐ 18 cement escape lines on 43‐7X 0487 ‐2199 0 0 0 0 Field 1840 ‐113 266 ‐59 Route Today 2 3.75 0.08 CLU‐1 & 3 34‐ 31 43‐32 Prep CLU‐14 tank to be moved 530 ‐95 550 0 5048 ‐81 14‐6 Routine 6108 11,700 2542 ‐18824 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 05/10/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 43-07X (PTD 203-066) PERF Log 04/22/2021 Please include current contact information if different from above. PTD: 2030660 E-Set: 35111 05/11/2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 05/04/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 43-07X (PTD 203-066) CBL Cement Bond Log 04/13/2021 Please include current contact information if different from above. PTD: 2030660 E-Set: 35082 Received by the AOGCC 05/04/2021 05/04/2021 Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 04/14/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 43-7X (PTD 203-066) MRCBL Memory Radial Cement Bond Log 04/03/2021 Please include current contact information if different from above. PTD: 2030660 E-Set: 34993 Received by the AOGCC 04/14/2021 04/14/2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: N2/Cement Packer 2.Operator Name:4.Current Well Class:5.Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6. API Number: 7. If perforating:8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): 8,610'6079' (fill) 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: Todd Sidoti Operations Manager Contact Email: Contact Phone: 777-8443 Date: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE COMMISSION Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Authorized Title: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Signature: March 1, 2021 N/A 8,589' Perforation Depth MD (ft): 6,463' See Attached Schematic 8,589' 7,413'3-1/2" 20" 13-3/8" 138' 9-5/8"6,463' 1,510' 3,960psi 3,450psi 138' 1,469' 5,340' 138' 1,510' N/A TVD Burst N/A 10,160psi MD 5,750psi Length Size CO 510A Hilcorp Alaska, LLC 3800 Centerpoint Dr, Suite 1400 Anchorage Alaska 99503 PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 FEDA028142 203-066 50-133-20522-00-00 Kenai Beluga Unit (KBU) 43-07X Kenai Gas Field / Sterling 3, 4, 5.1 & 5.2 Gas COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): See Attached Schematic todd.sidoti@hilcorp.com 7,434'7,806'6,636'1,180 N/A N/A ; N/A N/A ; N/A Perforation Depth TVD (ft): Tubing Size: Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 9:54 am, Feb 24, 2021 321-095 Digitally signed by Taylor Wellman (2143) DN: cn=Taylor Wellman (2143), ou=Users Date: 2021.02.23 22:23:10 -09'00' Taylor Wellman (2143) CBL is required to establish top of cement in 3-1/2" x 5-1/2" annulus. MITIA to 1500 psi required after perforating. SFD 2/24/2021 Sterling 3, 4, 5.1 & 5.2 Gas DSR-2/24/21BJM 3/3/21C n Required? Yes 3/4/21 dts 3/3 3021 JLC 3/4/2021 RBDMS HEW 3/5/2021 10-404 Well Prognosis Well: KBU 43-07X Date: 02/3/2021 Well Name: KBU 43-07X API Number: 50-133-20522-00-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: 03/01/2021 Rig: N/A Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 203-066 First Call Engineer: Todd Sidoti (907) 777-8443 (O) (907) 632-4113 Second Call Engineer: Jake Flora (907) 777-8442 (O) (720) 988-5375 Reg. Approval Req’d? 10-403 Date Reg. Approval Rec’vd: Maximum Expected BHP: ~1600psi @ 4199’ TVD (Based on offset data ) Max. Allowable Surface Pressure: ~1180psi (Based on 0.1 psi/ft gas gradient) Brief Well Summary: KBU 43-07X drilled and completed in 2003 targeting the Beluga/Upper Tyonek formation and completed as an Excape completion. The well came online making 6 MMCFD. The well went offline in 2017 due to sand/water production. Several attempts to revive the well via slickline bailing with no success. The well has cum’d just under 12 BCF and 245 MBW of water. Objective: The purpose of this non-rig workover is to isolate the existing open perfs, cement the backside of the 3-1/2” up above all hydrocarbon bearing zones, and recomplete in the Sterling formation. Wellbore Notes: - 9-5/8” Intermediate cemented in place with 210 bbls of 13.5 ppg class G cement. 65 bbls were lost during the 482 bbl displacement. Top of cement in the 9-5/8” was calculated at 4300’. This is assuming that all 65 bbls of cement were lost in addition to 20% washout throughout. - SL taged @ 6079’ with 2.5” DD Bailer on 6/18/18 - Logged CBL in 3-1/2” with TOC @ 5450’ on 1/17/21 - MITIA Passed to 1500psi on 1/12/21 Procedure E-Line & Pump Truck: 1. MIRU E-Line and pressure test lubricator to 250 psi low / 2500 psi high. 2. RIH with JB/GR and drift to PBTD for CIBP. 3. RIH and set CIBP at ~6070’. a. Correlate to CBL dated 17-Jan-2021. 4. Dump bail 35 ft (13 gallons) of cement on CIBP. 5. Load tubing with water. 6. Pressure up on tubing to 2000 psi. 7. Jet Cut tubing at 5390’. 8. Confirm communication with IA and attempt to circulate with water. a. Once circulation is established RDMO e-line. b. If unable to establish circulation contact OE and plan to perform another cut higher up. 9. Circulate IA clean with water. 10. Freeze protect surface equipment. 11. RDMO pumper. Fullbore Cement: 1. MIRU Cementers & PT surface lines to 250 psi low and 4000 psi high. Top of cement in the 9-5/8” was calculated at 4300’. T recomplete in the Sterling formation. isolate the existing open perfs, Well Prognosis Well: KBU 43-07X Date: 02/3/2021 2. Establish circulation down the tubing and up the IA. 3. Mix and pump 153 bbls 15.3ppg cement slurry. Planned TOC in 3-1/2” x 9-5/8” annulus = ~3000’. 4. Drop wiper ball, displace with 48 bbls water (overdisplacing by 1 barrel) and record final lift pressure. 5. Shut in well with both master valves to trap pressure. 6. Wash up and RDMO cementers. 7. WOC minimum of 3 days. Slickline: 1. MIRU Slickline, PT lubricator to 250 psi low / 2500 psi high. 2. Run JB/GR to PBTD. a. Minimum target depth is 5200’ b. If tag is high contact OE to plan on troubleshooting. 3. Log memory CBL from PBTD to surface. 4. Swab well down to 5200’. 5. RDMO Slickline. Coiled Tubing Milling (Contingency): 1. If cement is left too high in 3.5” tubing. 2. MIRU CTU. 3. If necessary, notify AOGCC 24 hours ahead to extend witness offer for BOP test a. Conduct BOP test 250psi low, 4000psi high 4. RIH w milling BHA, mill out cement to ~5200’ 5. Blow down well with nitrogen, trap 1500 psi for perforating. 6. RDMO CTU. E-line: 1. MIRU E-line, PT lubricator to 250 psi low and 2500 psi high. 2. Perforate the below zones from the bottom up with 2-1/2” Shogun Spiral Guns: Sand MD Top MD Bottom Total Footage (MD) TVD Top TVD Bottom Pool P3_A10 ±4,351' ±4,384' 33' ±3,675' ±3,708' STERLING 3 GAS P3_A11 ±4,424' ±4,457' 33' ±3,728' ±3,761' STERLING 3 GAS P4_B1A ±4,493' ±4,558' 65' ±3,782' ±3,847' STERLING 4 GAS P4_B2A ±4,617' ±4,662' 45' ±3,874' ±3,919' STERLING 4 GAS P5.1_B4A ±4,750' ±4,786' 36' ±3,974' ±4,010' STERLING 5.1 GAS P5.1_B4B ±4,855' ±4,885' 30' ±4,052' ±4,082' STERLING 5.1 GAS P5.2_B5A ±4,992' ±5,014' 22' ±4,154' ±4,176' STERLING 5.2 GAS P5.2_B5B ±5,051' ±5,070' 19' ±4,199' ±4,218' STERLING 5.2 GAS Well Prognosis Well: KBU 43-07X Date: 02/3/2021 a. Discuss wellhead pressure with OE, anticipate wanting to hold 900 psi for initial shot. If necessary RU sales gas or Nitrogen to pressure up well prior to perforating. b. Final Perfs tie-in sheet will be provided in the field for exact perf intervals. c. Use GR/CCL to correlate against Open Hole Log provided by Geologist. Send the correlation pass to the following for confirmation. Reservoir Engineer Trudi Hallett 907.301.6657 Geologist Ben Siks 907.229.0865 d. Install Crystal gauges (or verify PTs are open to SCADA) before perforating. Record tubing pressures before and after each perforating run. e. Sands that are not in the same pool will need to be isolated with a CIBP and 35’ of cement. 3. RD E-Line. 4. Turn well over to production. (Test SSV with-in 5 days of stable production on well – notify AOGCC 24hrs before testing) Nitrogen (Contingency) 1. If Nitrogen is required to pressure up well prior to perforating or push fluid away: 2. MIRU Nitrogen Unit, review Nitrogen SOP, pressure well to desired perforating pressure. E-line Procedure (Contingency) 1. If any zone produces sand and/or water or needs isolated: 2. MIRU E-Line and pressure control equipment. PT lubricator to 250 psi Low / 2,500 psi High. 3. RIH and set 3-1/2” Casing Patch or set 3-1/2” CIBP above the zone and dump 35’ of cement on top of the plug. Attachments: Current Well Schematic Proposed Well Schematic Standard Well Procedure – N2 Operations CTU BOP Schematic MITIA to 1500 psi after perforating, before return to production. BJM Excape System Details - 17 Excape module system -Green control line connected to modules 1ĺ9 -Red control line connected to modules 10ĺ17 - Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) Isolated Perfs: (41’ net) = 6,706’ - 6,747’ (perf'd 10/18/08) Active Perfs: (36’ net) = 6,770’ - 6,806’ (perf'd 10/18/08) Module 17 = 6,899' - 6,909' (frac'd 9/3/03) Module 16 = 6,940' - 6,950' (frac'd 9/3/03) Module 15 = 6,980' - 6,990' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,140' - 7,150' (frac'd 9/3/03) Module 11 = 7,193' - 7,203' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,432' - 7,442' (perf'd 9/3/03) Module 8 = 7,471' - 7,481' (frac'd 9/3/03) Module 7 = 7,540' - 7,550' (frac'd 9/3/03) Module 6 = 7,589' - 7,599' (perf'd 9/3/03) Module 5 = 7,690' - 7,700' (frac'd 9/3/03) Module 4 = 7,753' - 7,763' (frac'd 9/3/03) Module 3 = 7,920' - 7,930' (frac'd 9/3/03) Module 2 = 8,385' - 8,395' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) KOP:250' Build:2.5 deg per 100' Hold Angle:43 deg at 2,300' DOP:5,350' Drop:2.0 deg per 100' Final Angle:8 deg at 7,450' KBU 43-7x Pad 41-7 41' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 203-066-0 API #: 50-133-20522-00-00 Prop. Des: FED A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27' 34.67" Longitude: -151° 14' 47.43" X: 274,996.71 Y: 2,362,053.16 Spud: 5/22/2003 TD: 6/11/2003 Rig Released: 6/15/2003 06:00 hrs PA #: Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' TVD 0' 138' Surface Casing 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' 5,340' 12-1/4" hole, Cmt w/ 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' TVD 0' 7,413' Cmt w/ 970 sks of Class G TD 8,610' MD 7,434' TVD PBTD 8,556' MD 7,380' TVD Coil tubing cleaned to 7,893' MD (6/9/18) Weatherford straddle packer assembly (set @ 6,698 MD RKB on 12/16/09): - WEA ER Packer (ID: 1.812")= 2.86' 2,800# to release - 2-3/8" spacer pipe (ID: 1.994")= 22.2' - WEA SO Tie Back (ID: 1.74")= 2.00' 2,760# to release - 2 3/8" spacer pipe (ID: 1.994")= 22.2' - WEA Snap latch seal (ID: 1.75")= 0.92' 5,520# to release - WEA ER Packer (ID: 1.812")= 2.70' Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 43-7x Kenai Peninsula Borough 6,770' - 8,480' 2.5º / 100ft @ 250 ft 6/16/2003 Todd Sidoti Lease: State: Perf (TVD): Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA 5,525' - 7,305' 7ºĺ 20º RKB:66' (AMSL)21' (AGL) 02/12/18 Excape System - Flapper depths (Module 16 & Module 1 = no flappers) Module 17 - 6,918' Module 16 - NA Module 15 - 6,999' Module 14 - 7,072' Module 13 - 7,113' Module 12 - 7,159' Module 11 - 7,212' Module 10 - 7,253' Module 9 - 7,451' Module 8 - 7,490' Module 7 - 7,559' Module 6 - 7,608' Module 5 - 7,709' Module 4 - 7,772' Module 3 - 7,939 Module 2 - 8,404' Module 1 - NA Tree cxn = 4-3/4" Otis SCHEMATIC SLTagged fill w/ 2.5" Bailer at 6,079' (6/18/18) Excape System Details - 17 Excape module system -Green control line connected to modules 1ĺ9 -Red control line connected to modules 10ĺ17 - Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) Isolated Perfs: (41’ net) = 6,706’ - 6,747’ (perf'd 10/18/08) (36’ net) = 6,770’ - 6,806’ (perf'd 10/18/08) Module 17 = 6,899' - 6,909' (frac'd 9/3/03) Module 16 = 6,940' - 6,950' (frac'd 9/3/03) Module 15 = 6,980' - 6,990' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,140' - 7,150' (frac'd 9/3/03) Module 11 = 7,193' - 7,203' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,432' - 7,442' (perf'd 9/3/03) Module 8 = 7,471' - 7,481' (frac'd 9/3/03) Module 7 = 7,540' - 7,550' (frac'd 9/3/03) Module 6 = 7,589' - 7,599' (perf'd 9/3/03) Module 5 = 7,690' - 7,700' (frac'd 9/3/03) Module 4 = 7,753' - 7,763' (frac'd 9/3/03) Module 3 = 7,920' - 7,930' (frac'd 9/3/03) Module 2 = 8,385' - 8,395' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) KOP:250' Build:2.5 deg per 100' Hold Angle:43 deg at 2,300' DOP:5,350' Drop:2.0 deg per 100' Final Angle:8 deg at 7,450' KBU 43-7x Pad 41-7 41' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. Permit #: 203-066-0 API #: 50-133-20522-00-00 Prop. Des: FED A - 028142 KB elevation: 87' (21' AGL) WBS #: Latitude: 60° 27' 34.67" Longitude: -151° 14' 47.43" X: 274,996.71 Y: 2,362,053.16 Spud: 5/22/2003 TD: 6/11/2003 Rig Released: 6/15/2003 06:00 hrs PA #: Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' TVD 0' 138' Surface Casing 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' 5,340' 12-1/4" hole, Cmt w/ 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' TVD 0' 7,413' Cmt w/ 970 sks of Class G TD 8,610' MD 7,434' TVD PBTD 5,565' MD 4,951' TVD Weatherford straddle packer assembly (set @ 6,698 MD RKB on 12/16/09): - WEA ER Packer (ID: 1.812")= 2.86' 2,800# to release - 2-3/8" spacer pipe (ID: 1.994")= 22.2' - WEA SO Tie Back (ID: 1.74")= 2.00' 2,760# to release - 2 3/8" spacer pipe (ID: 1.994")= 22.2' - WEA Snap latch seal (ID: 1.75")= 0.92' 5,520# to release - WEA ER Packer (ID: 1.812")= 2.70' Well Name & Number: Municipality: Perforations (MD): Angle @ KOP & Depth: Date Completed: Revised by: Kenai Beluga Unit 43-7x Kenai Peninsula Borough TBD 2.5º / 100ft @ 250 ft 6/16/2003 Todd Sidoti Lease: State: Perf (TVD): Kenai Gas Field Country: Angle @ Perfs: Ground Level: Revision Date: Alaska USA TBD 7ºĺ 20º RKB:66' (AMSL)21' (AGL) 02/09/21 Excape System - Flapper depths (Module 16 & Module 1 = no flappers) Module 17 - 6,918'Module 16 - NA Module 15 - 6,999' Module 14 - 7,072' Module 13 - 7,113'Module 12 - 7,159' Module 11 - 7,212' Module 10 - 7,253' Module 9 - 7,451'Module 8 - 7,490' Module 7 - 7,559' Module 6 - 7,608' Module 5 - 7,709' Module 4 - 7,772' Module 3 - 7,939 Module 2 - 8,404' Module 1 - NA Tree cxn = 4-3/4" Otis PROPOSED SCHEMATIC 3-1/2" x 8-3/4" TOC @ 5450' (CBL 1/17/21) CIBP w/ 35' of cement @ ~6070' Tubing Cut ~5390' 3-1/2" x 9-5/8" TOC @ 3000' (Volumetric) Sterling Perfs P3_A10 ~4,351'-4,384' (TBD)P3_A11 ~4,424'-4,457' (TBD)P4_B1A ~4,493'-4,558' (TBD)P4_B2A ~4,617'-4,662' (TBD)P5.1_B4A ~4,750'-4,786' (TBD)P5.1_B4B ~4,885'-4,885' (TBD)P5.2_B5A ~4,992'-5,014' (TBD)P5.2_B5B ~5,051'-5,070' (TBD) 9-5/8" x 12.25" TOC @ 4300' (Calculated using 145 bbls of cement with 20% washout) Top set of perfs only 51 feet from 9-5/8" x OH annulus TOC 9-5/8" csg shoe at 6463' MD Coiled Tubing Services Pressure Category 1 BOP Configuration (0-3,500 psi) Client: Hilcorp Date: April 3rd, 2017 Drawn: Chad Barrett Revision: 0 Well Category: CAT I 4-1/16" 10K Combi BOP Top Set: Blind/Shear Second Set: Pipe/Slip Wellhead 4-1/16" 10K Conventional Stripper 4-1/16" 10K x Wellhead Adapter Flange 5K CO62 x 4-1/16" 10K Flange 5K CO62 Lubricator 4-1/16" 10K Flow Cross Manual 2x2 Valve 1: 2" 1502 x 2-1/16" 10K Flange Manual 2x2 Valve 2: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 3: 2-1/16" 10K x 2-1/16" 10K Flange Manual 2x2 Valve 4: 2" 1502 x 2-1/16" 10K Flange 21 3 4 WH PSI 2" 1502 x 2-1/16 10K Flanged Valve (Manual) 2-1/16 10K x 2-1/16 10K Flanged Valve (Manual) Kill Port Coiled Tubing HR580 Injector Head & Gooseneck Weight = 12,850 lbs Kenai Gas Field KBU 43-07X 02/09/2021 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. Samuel Gebert Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: 907 777-8337 Fax: 907 777-8510 E-mail: sam.gebert@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or FAX to 907 777.8510 Received By: Date: DATE: 02/01/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL KBU 43-7X (PTD 203-066) CBL Cement Bond Log 01/17/2021 Please include current contact information if different from above. Received by the AOGCC 02/02/2021 PTD: 2030660 E-Set: 34639 Abby Bell 02/02/2021 Regg, James B (CED) jj r From: Regg, James B (CED) Sent: Tuesday, February 18, 2020 11:25 AM "l d To: David Gorm Subject: RE: K -Valve Design for well NS -25 (PTD # 2031660). Your call this morning asked for approval to continue producing NS -25 with the K -valve removed. Additional details are included in your follow-up email message below. 20 AAC 25.2650) allows for the removal of a SSSV for tubing workover, well intervention, or routine well pad operations; resizing the K -valve and installing a new profile lock fails under this paragraph. It notes further that the "subsurface safety valve maybe temporarily blocked or removed" and "must be made operable not later than 14 days after the date that the well is returned to service, and be tested [performance test] not later than 5 days after installation..." I can see where this is a bit confusing since the implication is the well is shut in for the workover/intervention. I did some quick research and found that we have previously applied this rule to the removal/resizing/reinstallation of K - valve in the past - typically it is associated with flowing the well to get the well performance info needed to come up with the proper K -valve design. Based on past practice, the K -valve must be installed in NS -25 not later than March 1, 2020; if that cannot be accomplished NS -25 must be shut in. Jim Regg Supervisor, Inspections AOGCC 333 W.7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 CONFIDENTIALITY NOTICE. This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC), State of Alaska and is for the sole use of the intended recipient(s). It may contain confidential and/or privileged information. The unauthorized review, use or disclosure of such information may violate state or federal law. If you are an unintended recipient of this e-mail, please delete it, without first saving or forwarding it, and, so that the AOGCC is aware of the mistake in sending it to you, contact Jim Regg at 907-793-1236 or jim.regg@alaska.gov. -----Original Message ----- From: David Gorm <dgorm@hilcorp.com> Sent: Tuesday, February 18, 2020 9:49 AM To: Regg, James B (CED) <jim.regg@alaska.gov> Subject: Fwd: K -Valve Design for well NS -25 (PTD # 2031660). Jim, We pulled the K -valve on NS -25 on Feb 16th, due to extensive corrosion on the profile lock holding the K -valve we were unable to install a new K -valve. We currently have a new license built out of chrome being built with plans to install the adjusted k -valve on Thursday feb 20th this week. Attached is the new k -valve sheet. Please let me know if you have any questions. Thanks David Gorm 505-215-2819 Sent from my iPhone Begin forwarded message: From: David Gorm<dgorm@hilcorp.com<mailto:dgorm@hilcorp.com>> Date: January 28, 2020 at 10:05:18 AM AKST To: "'jim.regg@alaska.gov<mailto:jim.regg@alaska.gov>"' <jim.regg@alaska.gov<mailto:jim.regg@alaska.gov>> Subject: FW: K -Valve Design for well NS -25 (PTD # 2031660). Hello Jim, Referencing the K -valve that was installed in well NS -25 (PTD # 2031660) that has been converted from an injector to a producer per sundry #318-400 for a 1 year production test. NS -25 has been producing since 11-1-2019 and over that production period as expected the GOR has improved to the point that our current K -valve settings requires an adjustment. The current K -valve closing pressure was set for 3420 psi, the updated design we will be targeting a 2400 psi closing pressure which we expect to be able to achieve now that the well's GOR has improved. The valve is currently being setup based on attached calculation sheet. We are planning to make this valve change in the next two weeks when we get an available slickline crew. After the K - valve change the well will be left shut-in until ready for testing. Please let me know if you need any additional information. Thank You, David Gorm Operations Engineer — Northstar/Endicott Hilcorp Alaska Office: 907-777-8333 Cell: 505-215-2819 The information contained in this e-mail message is confidential information intended only for the use of the recipient(s) named above. In addition, this communication may be legally privileged. if the reader of this e-mail is not an intended recipient, you have received this e-mail in error and any review, dissemination, distribution or copying is strictly prohibited. If you have received this e-mail in error, please notify the sender immediately by return e-mail and permanently delete the copy you received. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. OF 74.4., • \ A THE STATE Alaska Oil and Gas F�• "? � Of A LAsKA Conservation Commission == 333 West Seventh Avenue 4,0 GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 10E-`^� Main: 907.279.1433 ALAS Fax: 907.276.7542 www.aogcc.alaska.gov Chad Helgeson fi9 Operations Manager Hilcorp Alaska, LLC 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Re: Kenai Field, Upper Tyonek Beluga Gas Pool, KBU 43-07X Permit to Drill Number: 203-066 Sundry Number: 318-175 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, Hollis S. French Chair DATED this 2-3 day of April, 2018. • R0 ECEIVED STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APR 19 20 p 1 ¢ 2 APPLICATION FOR SUNDRY � APPROVALS 20 AAC 25.280 AO GCC 1.Type of Request: Abandon ❑ Plug Perforations❑ Fracture Stimulate 0 Repair Well 0 Operations shutdown 0 Suspend ❑ Perforate 0 Other Stimulate 0 Pull Tubing ❑ Change Approved Program❑ Plug for Redrill ❑ Perforate New Pool 0 Re-enter Susp Well 0 Alter Casing 0 Other: Pull Pkr;CTCO-N2❑✓ . 2.Operator Name: 4.Current Well Class: 5.Permit to Drill Number: Hilcorp Alaska, LLC Exploratory 0 Development ❑✓ • 203-066 • 3.Address: 3800 Centerpoint Dr,Suite 1400 Stratigraphic 0 Service ❑ 6.API Number: Anchorage Alaska 99503 50-133-20522-00-00 7. If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? N/A Kenai Beluga Unit 43-07X Will planned perforations require a spacing exception? Yes 0 No ❑� 9.Property Designation(Lease Number): 10. Field/Pool(s): FEDA028142 • Kenai Field/Up Tyonek Beluga Gas • 11. PRESENT WELL CONDITION SUMMARY Total Depth MD(ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP(psi): Plugs(MD): Junk(MD): 8,610' • 7,434' • 7,806' 6,636' —2,473psi N/A 7,896'(fill) Casing Length Size MD TVD Burst Collapse Structural Conductor 138' 20" 138' 138' 3,960psi 1,500psi Surface 1,510' 13-3/8" 1,510' 1,469' 3,450psi 1,950psi Intermediate 6,463' 9-5/8" 6,463' 5,340' 6,870psi 4,750psi Production 8,589' 3-1/2" 8,589' 7,413' 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 Schematic 3-1/2" 9.3#I L-80 7,413' Packers and SSSV Type: Packers and SSSV MD(ft)and TVD(ft): Straddle Pkr: N/A 6,698'MD/5,557'TVD;N/A 12.Attachments: Proposal Summary Q Wellbore schematic Q 13.Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ❑ Exploratory 0 Stratigraphic El ,.._,Development . Service 0 14.Estimated Date for 15.Well Status after proposed work: May 3,2018 Commencing Operations: OIL 0 WINJ 0 WDSPL 0 Suspended 0 16.Verbal Approval: Date: GAS 0 • WAG 0 GSTOR 0 SPLUG 0 Commission Representative: GINJ 0 Op Shutdown 0 Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Chad Helgeson 777-8405 Contact Name: Ted Kramer Authorized Title: Operations Manager Contact Email: tkramerehilcora.com f/� /� / Contact Phone: 777-8420 Authorized Signature: Q/%//��--— Date: YAr/�'? COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 31Z— ' Plu Inte ri �1 g g ty 0 BOP Test rie Mechanical Integrity Test ❑ Location Clearance 0 Other: -i_d1O©0 (5.., Ig 0 l t (c. 7- Post Initial Injection MIT Req'd? Yes 0 No 0 Cx_. ) J RBDM APR 14 201i Spacing Exception Required? Yes ❑ No ( Subsequent Form Required: /6 -- 4/6 LI APPROVED BY Approved by: �� M SS ONER THE COMMISSION Date: 4 z3 1,e O I NA L ,qø*e 4i_„0,,,, orm and Form 10-403 Revised 4/20173Approved application is valid for 12 months from the date of approval. Attachments in Duplicate • Well Prognosis Well: KBU 43-7X Hilcorp Alaska,LLI Date:04/18/2018 Well Name: KBU 43-7X API Number: 50-133-20522-00-00 Current Status: SI Gas Well Leg: N/A Estimated Start Date: 05/3/18 Rig: CTU Reg.Approval Req'd? Yes Date Reg.Approval Rec'vd: Regulatory Contact: Donna Ambruz 777-8305 Permit to Drill Number: 203-066 First Call Engineer: Ted Kramer (907) 777-8420 (0) (985) 867-0665 (M) Second Call Engineer: Chad Helgeson (907) 777-8405 (0) (907) 229-4824(M) AFE Number: Current Surface Pressure: 460 psi SI press. for Bailing Work Flowing BHP: Unknown Well is SI Maximum Expected BHP: —3,206 psi @ 7332' TVD (Assumed 0.437 psi/ft gradient) Max. Potential Surface Pressure: —2,473 psi (Assumed 0.10 psi/ft gas gradient) Brief Well Summary KBU 43-7X was drilled,completed, and placed on production in September of 2003. • In 2008,two Beluga Sands were perforated. The upper set was isolated with a straddle patch the next year (12/09). The KBU 43-7X was producing between 900 mcfd and 1.0MMcfd of gas per day until it filled up with Sand/Mud and died in�ber 2017. Subsequent attempts to bail the fill proved to be unsuccessful. The purpose of this Sundry is to Clean out the fill down to the Straddle packer assembly and then displace the fluid with nitrogen and blow the well down to see if it will unload. If that works,the well will be put back on . line. If the well will not kick off, Hilcorp then plans to clean out to 6698', pull the patch, and then clean out the well to 8,508'. The well will be jetted dry with Nitrogen, and placed back on production. If water production is an issue, the straddle assembly will be re-installed. Notes Regarding Wellbore Condition • Top of fill at 6,256' recovering thick mud and sand with 460 psig surface pressure on 1/31/18. • Well is deviated to 29 degrees at 6,256'. Safety Concerns /• Discuss nitrogen asphyxiation concerns and identify any areas where nitrogen could collect and people could enter. Nitrogen will be used during this job. • Consider tank placement based on wind direction and current weather forecast (if venting methane and nitrogen during this job) • Ensure all crews are aware of stop job authority Coiled Tubing Procedure: 1. Submit 24 hr. witness notification to AOGCC via web base notification. p g ' MIRU Coiled Tubing, PT BOPE to 4,000 psi high/250 psi low. • Well Prognosis Well: KBU 43-7X Hilcurp Alaska,LL) Date:04/18/2018 3. RIH with Coil and jet out fill from 6,256'to 6,698'. Blow dry with Nitrogen and leave 1,000 psi on the well head. POOH. 4. Turn well over to production to blow down and test to see if well will flow. 5. If well kicks off,then the job is complete. If it doesn't go to Step#6. 6. RU up Coil injector head and pressure test as in step#2. 7. PU packer retrieving tool and RIH and pull straddle packer assembly. POOH.Send in to be redressed. 8. RIH W/Coil jetting with 3% KCL water jetting fill/fluid back to a tank down to 8,508'. 9. Switch to Nitrogen and blow well dry leaving 1,000 psi on the tubing. 10. RDMO Coil Tubing. Turn well over to production to flow. 11. Gradually bleed down nitrogen from tubing pressure while checking for Methane with an LEL meter. Once methane is established,turn well into compression suction and establish a stable rate. 12. MIRU E-line. Pressure test lubricator to 3,000 psi. 13. PU and RIH with Logging tools. Run production log. Re-run Patch if necessary. 14. RDMO E-line. 15. Turn well over to production. Attachments: 1. Actual Schematic 2. Proposed Schematic 3. Wellhead Diagram 4. CT BOPE Schematic 5. CT Schematic(forward jetting) 6. Standard Well Procedure—Nitrogen Operations • • KBU 43-7x 11 Pad 41-7 Hilcarp Alaska Permit#: 203-066-0 41'FSL, 4,088'FWL, API#: 50-133-20522-00-00 Sec. 6, T4N, R11W, S.M. Conductor Prop.Des: FED A-028142 20" K-55 133 ppf KB elevation: 87' (21'AGL) ;1 Top Bottom WBS#: Latitude: 60°27' 34.67" 1 MD 0' 138' Longitude: -151°14' 47.43" 4 TVD 0' 138' X: 274,996.71 ii .. Y: 2,362,053.16 4Surface Casing Spud: 5/22/2003 !' , TD: 6/11/2003 i .0 13-3/8" K-55 68 ppf BTC Rig Released: 6/15/2003 06:00 hrs / Tom Bottom PA#: G V 0' 1,510' TVD1,469' "t• `" Cmt w/759 sks(335 bbls)of 12 ppg Type-1, tt 0102 sks(45 bbls)to surface 5* t IAIntermediate Casing Tree cxn=4-3/4"Otis - . 1d 9.5/8" L-80 40 ppf BTC r Top Bottom �J MD 0' 6,463' TVD 0' 5,340' KOP:250' t- 12-1/4"hole,Cmt w/647 sks (210 bbls)of Build:2.5 deg per 100' ,. - j Class G (lost 65 bbls) Hold Angle:43 deg at 2,300' ' ' t'' DOP:5,350' �7v Drop:2.0 deg per 100' (l Ca T�? Production Casing L-80 9.3 Final Angle:8 deg at 7,450' / ----"- 3-1/2" Top Bottom EUE 8rd MD 0' 8,589' y- TVD 0' 7,413' r r; '`": Cmt w/970 sks of Class G N Weatherford straddle packer assembly ) t (set @ 6,698 MD RKB on 12/16/09): Excape System Details WEA ER Packer(ID:1.812")=2.86' 9/•-•- ,„,„„ - -17 Excape module system 2,800#to release t'4 -Green control line connected to modules 1-,9 -2-3/8"spacer pipe(ID:1.994")=22.2' // wv, k+a , -Red control line connected to modules 10--k17 -WEA SO Tie Back(ID:1.74")=2.00' I { -Both control lines open for methanol 2,760#to release injection(9/3/03) -2 3/8"spacer pipe(ID:1.994") 22.2' '( -Ceramic flappers removed with coil(9/3/03) -WEA Snap latch seal(ID:1.75")=0.92' 5,520#to release iii Isolated Perfs: -WEA ER Packer(ID:1.812")=2.70' (41'net) 6,706' 6,747'(perf'd 10/18/08) Active Perfs: , (36'net) = 6,770'-6,806'(perf'd 10/18/08) MocKTI e 17 = 6,599'-6,909' (frac'd 9/3/03) Module 16 = 6,940'-6,950' (frac'd 9/3/03) Module 15 = 6,980'-6,990' (frac'd 9/3/03) Module 14 = 7,053'-7,063' (frac'd 9/3/03) Module 13 = 7,094'-7,104' (fracd 9/3/03) Module 12 = 7,140'-7,150' (fracd 9/3/03) Module 11 = 7,193'-7,203' (fracd 9/3/03) 4;y Module 10 = 7,234'-7,244' (fracd 9/3/03) iii vv. Module 9 = 7,432'-7,442' (perf'd 9/3/03) Excape System -Flapper depthsI Module 8 = 7,471'-7,481' (fracd 9/3/03) 1=no flappers) 8 Module 7 = 7,540'-7,550' (fracd 9/3/03) (Module 16&-Module 11 k, Module 6 = 7,589'-7,599' (pertd 9/3/03) Module 17 - 91 Module 5 = 7,690.-7,700' (frac'd 9/3/03) Module 16 Module 15 - 6NA I '-' Module 4 = 7,753°-7,763' (frac'd 9/3/03) Module 14 - 6,999' l Module 3 = 7,920'-7,930' (frac'd 9/3/03) Module 13 - 7,113' I Module 2 = 8,385'-8,395' (frac'd 9/3/03) Module 12 - 7,159' e r" Module 1 = 8,470'-8,480' (frac'd 9/3/03) Module 11 - 7,212' ; Module 10- 7,253' 4. v. i ,0 Module 9 - 7,451' I Module 8 - 7,490' , 7 4'a Module 7 - 7,559' 6, .ta Module 6 - 7,608' *' "' Module 5 - 7,772' ii 1 Module 4 - 7,772' F Module 3 - 7,939 Module 2 - 8,404' .' '� *Tagged @ w/2.74"GR 7,806' (12/15/09) Module 1 - NA " `Coil tubing cleaned to 8,508'MD(9/4/03) TD PBTD 8,610'MD 8,556'MD 7,434'TVD 7,380'TVD Well Name&Number: Kenai Beluga Unit 43-7x Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,770'-8,480' Pell(TVD): 5,525'-7,305' Angle @ KOP&Depth: 2.5°/100ft @ 250 ft Angle @ Perfs: 7°-4 20° Date Completed: 6/16/2003 Ground Level: 66'(AMSL) RKB: 21'(AGL) Revised by: Tom Fouts Revision Date: 1/23/2014 ill • • PROPOSED IiIC(} a Alaska KBU 43-7x Pad 41-7 SCHEMATIC Permit#: 203-066-0 ' 41' FSL, 4,088'FWL, API#: 50-133-20522-00-00 Sec.6, T4N, R11 W, S.M. Conductor Prop.Des: FED A-028142 KB elevation: 87' (21'AGL) 20" K-55 133 ppf WBS#: Top Bottom Latitude: 60°27' 34.67" MD 0' 138' Longitude: -151°14' 47.43" TVD 0' 138' X: 274,996.71 Y: 2,362,053.16 �p Spud: 5/22/2003 1 f� Surface Casing TD: 6/11/2003 y, { 13-318" K-55 68 ppf BTC Rig Released: 6/15/2003 06:00 hrs , Top Bottom PA#; .,„Tx! MD 0' 1469 TVD 0' 1,469' s Cmt w/759 sks(335 bbls of 12 ,� ) ppg Type-1, 1 102 sks(45 bbls)to surface <= Intermediate Casino Tree cxn=4-3/4"Otis �V 9-5/8" L-80 40 ppf BTC _ Top Bottom c MD 0' 6,463' TVD 0' 5,340' KOP 250 ') 12-1/4"hole,Cmt w/647 sks (210 bbls)of Build:2.5 deg per 100' ." Class G (lost 65 bbls) Hold Angle:43 deg at 2,300' *" DOP:5,350' Drop:2.0 deg per 100 t f Production Casing Final Angle:8 deg at 7,450' 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom = l MD 0' 8,589' -. -. ' x- TVD 0' 7,413' ,..,,___._ __...._ „_ _ Cmt w/970 sks of Class G Weatherford straddle packer assembly (set @ 6,698 MD RKB on 12/16/09): ff..4ft Excape System Details -WEA ER Packer(ID:1.812")=2.86' $ 2,800#to release �g -17 Excape module system 2-3/8"spacer pipe(ID:1 994")=22.2' 1', 1/t ) -Green control line connected to modules 1-A9 } Red control line connected to modules 10-A17 -WEA SO Tie Back(ID:1.74")=2.00' 2,760#to release Dt Both control lines open for methanol injection(9/3/03) -2 3/8" pipe1.994 (ID:spacer ")=22.2' p -WEA Snap latch seal(ID:1.75")=0.92' y. Ceramic flappers removed with coil(9/3/03) 5,520#to release ' 1t} -WEA ER Packer(ID:1.812")=2.70' CL Isolated Perfs: (11'net) - 6,706' 6,747'(perf'd 10/18/08) If Active Perfs: (36'net) = 6,770'-6,806'(perf'd 10/18/08) Module 17 = 6,899'-6,909' (frac'd 9/3/03) j Module 16 = 6,940'-6,950' (frac'd 9/3/03) Module 15 = 6,980'-6,990' (frac'd 9/3/03) b. 3 Module 14 = 7,053'-7,063' (frac'd 9/3/03) j� ey Module 13 = 7,094'-7,104' (frac'd 9/3/03) Module 12 = 7,140'-7,150' (frac'd 9/3/03) Module 11 = 7,193'-7,203' (frac'd 9/3/03) Module 10 = 7234'-7244' (frac'd 9/3/03) Module 9 = 7,432'-7,442' (perf'd 9/3/03) Excape System -Rapper depths Module 8 = 7,471'-7,481' (frac'd 9/3/03) (Module 16&Module 1=no flappers) f Module 7 = 7,540'-7,550' (frac'd 9/3/03) Module 17 - 6,918' , i Module 6 = 7,589'-7,599' (perf'd 9/3/03) Module 16 - NA Module 5 = 7,690'-7,700' (frac'd 9/3/03) Module 15 - 6,999' 1Module 4 = 7,753'-7,763' (frac'd 9/3/03) Module 14 - 7,072' , Module 3 = 7,920 -7,930' (frac'd 9/3/03) Module 13 - 7,113' I Module 2 = 8,385'-8,395' (frac'd 9/3/03) Module 12 - 7,159' II Module 1 = 8,470'-8,480' (frac'd 9/3/03) Module 11 - 7,212' I i'' Module 10- 7,253' Module 9 - 7,451' „ I Module 8 - 7,490' Module 7 - 7,559' ' ° VI Module 6 - 7,608' II Module 5 - 7,709' Module 4 - 7,772' 41 Module 3 - 7,939 Module 2 - 8,404' :: 'Tagged @ w/2.74"GR 7,806' (12/15/09) Module 1 - NA " `" *Coil tubing cleaned to 8,508'MD(9/4/03) TD PBTD 8,610'MD 8,556'MD 7,434'TVD 7,380'TVD Well Name&Number: Kenai Beluga Unit 43-7x Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,770'-8,480' Pert(TVD): 5,525'-7,305' Angle @ KOP&Depth: 2.5°/100ft @ 250 ft Angle @ Perfs: 70-, 20° Date Completed: 6/16/2003 Ground Level: 66'(AMSL) RKB: 21'(AGL) Revised by: Donna Ambruz Revision Date: 04/16/18 0 KBU 43-07XKenas Field 04/17/2018 Hille orp Marko.LIA: Kenai Gas Field False hanger neck Vetco KBU 43-07X Gray MB-196,13 5/8 SM x 3" 20X133/8X95/8X3'/: CIWTypeHBPVprofile w/ special packing cartridge set for packing off 3%tubing No Lift Threads Tree cap,Otis,3 1/16 10M FE X 6'/:Otis Quick Union 3• �0 `b. h� °t 4 to Valve,Swab,VG-300, .(.0\:042,‹),"O<<`<.,'� y0�`$ �OO��P°�Q 3 1/16 10M FE,HWO, 4e, ,y0 JCS o�tt�� DD trimIII J2,,\''Y Oc -' ,a\\ e�S° Q� --'''' ,,, "kir" '11 (\l‘ , t Valve,Upper Master, _, VG 300,3 1/16 10M F INIA HWO,DD trim ' Valve,Master,VG-300, ; 3 1/16 10M FE,HWO, 0 DD trim r— a Adapter,Vetco,13 5/8 SM I stdd X 3 1/1610M stdd top, ■ prepped f/7"PP seal pocket Multibowl,Vetco MB-196, ■ for false hanger neck 13 5/8 3M stdd bottom X _ „, �, '� 13 5/8 5M FE top,w/ _ • ::_ilire,„.4_,:wf,, ■_up 2-2 1/16 SM SSO Exca e S stem :I �. Valve,Gra C,2 1 16 5M FE, . HWO,AAtrim Control lines X2 ij i Control lines c. _ Starting head, .! Vetco MB-196, ' 13 S/8 3M X 13 3/8 VG-Loc n bottom,w/2-2"LPO �• ar E 20" 13 L, __ 9.625" llt 3.5" 11/ • II Kenai Gas Field KBU 43-07x 04/16/2018 II,L,,rp tlb,ka.LLC 11111. 1114•0111 ,114.0414\ t r 40 !i ces^. �I F�I ° �1 N N !Iil■_ •��-_,li■ter a .I!IM�O, Coiled Tubing HR580 Injector Head&Gooseneck II• I �1 kl Weight=12,850 lbs E1 u_o TI;'.'. aLJr 1 _I • 1 4-1/16"10K Conventional Stripper it'll 16.1.1 5K C062 Lubricator WH PSI AO 2'1502x2-1/1610K Flanged Valve 5K 0062 x 4-1/16"10K Flange (Manual) 2-1/16 10K x2-1/16 - 4-1/16"10K Combi BOP 10K Flanged Valve Top Set:Blind/Shear (Manual) iu■C;-.I®I.7I'•; 1 Second Set:Pipe/Slip i.u. . ME an":1 4-1/16"10K Flow Cross �_ Manual 2x2 Valve 1:2"1502 x 2-1/16"10K Flange 411014110�1(t11O�1{1.�1[0�1'11r01� -44 Manual 2x2 Valve 2:2-1/16"10K x2-1/16"10K Range 010111011011111rOil 2x2 Valve 3:2-1/16"10K x2-1/16"10K Flange Manual 2x2 Valve 4:2"1502 x 2-1/16"10K Flange Min . 41 4-1/16"10K x Wellhead Adapter Flange allitI!101I(4I111 ,rokilo, Wellhead • g c 83 (i) i 3 c e D U 1 C ag ,1 E ~ w Q 7 U 1 '] 0N I .3 Q t : 12 El' � Z111 od e s_ t A NW :3a=aa N v' E o `/ -c Ott A• A• L CP • • Z 1)51• N , Z A t V1 ►•4 s_ 0 o C U 0 O 0- 0 I I�I 11 1 I�I ..L:' i I 7 Iiil I i t 11141111111;. I,I iiiiJJJJ mu IIII 11 Ill _ TN s c 0 H a 0 I E v a 6 = O c si 111 A11 �� 1 ` O l 0 ie 5 ; 8 t1 \`tea 011 r'-' 7 P .0 o Q gl 12 (-) N oZ o E; w 8 0 1 G M M • • STANDARD WELL PROCEDURE Ilikeorp;tia La. NITROGEN OPERATIONS 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/CO2/02 levels. Ensure Nitrogen vendor has a working and calibrated detector as well that measures 02 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. 12/08/2015 FINAL v1 Page 1 of 1 Image p!ject Well History File ccfer Page XHVZE This page identifies those items that were not scanned during the initial production scanning phase. They are available in the original file, may be scanned during a special rescan activity or are viewable by direct inspection of the file. ~ 03 - () 100 Well History File Identifier Organizing (done) D Two-sided 1111111111111111111 D Rescan Needed 111111111111111111I R)pCAN ¡. Color Items: o Greyscale Items: DIGITAL DATA OVERSIZED (Scannable) D Maps: D Other Items Scannable by a Large Scanner D Diskettes, No. D Other, NolType: o Poor Quality Originals: OVERSIZED (Non-Scannable) o Other: D Logs of various kinds: NOTES: D Other:: BY: ~ Date: d- ~. Y DS- . 151 yY\p 11111111111I1111111 VV\f Project Proofing BY: ~ Date: I a- 'a-: 0 ç 151 Scanning Preparation BY: ~ ~ana J J á x 30 ,= &.0 + ~ L- = TOTAL PAGES 8-'- P r'\"-- (Count does not include cover sheet) nIl Date: I {1- í 9- (.,C) Isl I' , 1111111111111111111 Production Scanning Stage 1 Page Count from Scanned File: ~ 3 (Count does include cover sheet) Page Count Matches Number in Scannin~ pr::.pration: V YES ~ Date: J ~I ¡ CJ-f DS- If NO in stage 1, page(s) discrepancies were found: YES Isl NO 11) Wlr Stage 1 BY: NO BY: Maria Date: Isl 11/11111111111 /11/1 Scanning is complete at this point unless rescanning is required. ReScanned II! 111111111111111I BY: Maria Date: 151 Comments about this file: Quality Checked 111111111111 1111111 10/6/2005 Well History File Cover Page.doc STATE OF ALASKA ALA .OIL AND GAS CONSERVATION COMM ON REPORT OF SUNDRY WELL OPERATIONS 1.Operations Abandon U Repair Well U Plug Perforations U Perforate a Other u Remove Capstring Performed: Alter Casing ❑ Pull Tubing❑ Stimulate-Frac ❑ Waiver ❑ Time Extension❑ Change Approved Program ❑ Operat.Shutdown❑ Stimulate-Other ❑ Re-enter Suspended Well❑ 2.Operator 4.Well Class Before Work: 5.Permit to Drill Number: Name: Hilcorp Alaska,LLC Development Q Exploratory ❑ • 203-066 3.Address: 3800 Centerpoint Drive,Suite 100 Stratigraphic❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 • 50-133-20522-00-00 7.Property Designation(Lease Number): 8.Well Name and Number: FEDA028142 ' Kenai Beluga Unit 43-07X 9.Logs(List logs and submit electronic and printed data per 20AAC25.071): 10.Field/Pool(s): N/A ' Kenai Field/Up Tyonek Beluga Gas 11.Present Well Condition Summary: Total Depth measured • 8,610 feet Plugs measured N/A feet true vertical 7,434 feet Junk measured 7,806(Fill) feet Effective Depth measured 7,806 feet Packer measured 6,698 feet true vertical 6,636 feet true vertical 5,557 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 138' 20" 138' 138' Surface 1,510' 13-3/8" 1,510' 1,469' Intermediate 6,463' 9-5/8" 6,463' 5,340' RECEIVED Production 8,589' 3-1/2" 8,589' 7,413' Liner JAN 2 3 2014 Perforation depth Measured depth See Attached Schematic SCANNED AOGCC True Vertical depth See Attached Schematic SCANNED MAY 2 9 2014 Tubing(size,grade,measured and true vertical depth) 3-1/2" 9.3#/L-80 8,589'(MD) 7,413(TVD) 6,698'(MD) Packers and SSSV(type,measured and true vertical depth) Straddle Packer 5,557'(TVD) N/A N/A 12.Stimulation or cement squeeze summary: N/A Intervals treated(measured): N/A RBDMSMAY 18 2014 Treatment descriptions including volumes used and final pressure: N/A � 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,322 19.1 0 101 Subsequent to operation: 0 3 0 0 104 14.Attachments: 15.Well Class after work: Copies of Logs and Surveys Run N/A Exploratory❑ Development Q • Service ❑ Stratigraphic ❑ Daily Report of Well Operations N/A 16.Well Status after work: Oil 0 • Gas Q WDSPL❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP❑ SPLUG❑ 17.I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O.Exempt: N/A Contact Jeremy Mardambek Emailimardambeka7hilcorp.com Printed Name Jeremy Mardambek Title Reservoir Engineer Signature ij "1„,....----'� — Phone 907-777-8388 Date 1/23/2014 / I3---2c: -tK Form 10-404 Revised 10/2012 /6- Submit Original Only KBU 43-7x II Pad 41-7 Hilcorp Alaska Permit#: 203-066 41' FSL, 4,088' FWL, API#: 50-133-20522-00-00 Sec.6, T4N, R11 W, S.M. Conductor Prop.Des: FED A-028142 i KB elevation: 87' (21'AGL) 20" K-55 133 ppf WBS#: Top Bottom Latitude: 60°27' 34.67" MD 0' 138' Longitude: -151°14' 47.43" TVD 0' 138' X: 274,996.71 Y: 2,362,053.16 Spud: 5/22/2003 . , 1 ryq Surface Casing TD: 6/11/2003 y..,„ 13-3/8" K-55 68 ppf BTC Rig Released: 6/15/2003 06:00 hrs TO Bottom PA#: F' ' °� MD 0' 1,510' Te .a 4; TVD 0' 1,469' 1. -f Cmt w/759 sks(335 bbls)of 12 ppg Type-1, 102 sks(45 bbls)to surface Intermediate Casing Tree cxn=4-3/4"Otis r! 9-5/8" L-80 40 ppf BTC Top Bottom y ; MD 0' 6,463' TVD 0' 5,340' KOP:250' 0� _ _ 12-1/4"hole,Cmt w/647 sks (210 bbls)of Build:2.5 deg per 100' Class G (lost 65 bbls) Hold Angle:43 deg at 2,300' DOR:5,350' Drop:20 deg per 100' . .g ______ _mutt `_ Production Casing L-80 9.3 ppf Final Angle:8 deg at 7,450' .- 3 v2 Top Bottom EUE 8rd �:_ �- MD 0' 8,589' TVD 0' 7,413' Cmt w/970 sks of Class G I Weatherford straddle packer assembly ) (set @ 6,698 MD RKB on 12/16/09): Ill "ry Excape System Details -WEA ER Packer(ID:1.812")=2.86' -17 Excape module system DTt 2,800#to release I C -Green control line connected to modules 1-09 -2-3/8"spacer pipe(ID:1.994")=22 2' ) -Red control line connected to modules 10-.17 -WEA SO Tie Back(ID:1.74")=2.00' Di f -Both control lines open for methanol 2,760#to release ) injection(9/3/03) -2 3/8"spacer pipe(ID:1.994")=22.2' U)I -Ceramic flappers removed with coil(9/3/03) -WEA Snap latch seal(ID:1.75")=0.92' ) 5,520#to release -WEA ER Packer(ID:1.812")=2.70' �j f Isolated Perfs: r (11'net) - 6,706' 6,717(perf'd 10/18/08) Dir Active Perfs: (36'net) = 6,770'-6,806'(perf'd 10/18/08) -n' Module 17 = 6,899'-6,909' (frac'd 9/3/03) +SSS Module 16 = 6,940'-6,950' (frac'd 9/3/03) Module 15 = 6,980'-6,990' (frac'd 9/3/03) ( Module 14 = 7,053'-7,063' (frac'd 9/3/03) DI ' Module 13 = 7,094'-7,104' (frac'd 9/3/03) C Module 12 = 7,140'-7,150' (frac'd 9/3/03) �! Module 11 = 7,193'-7,203' (frac'd 9/3/03) Module 10 = 7,234'-7,244' (frac'd 9/3/03) _ } Module 9 = 7,432'-7,442' (perf'd 9/3/03) LL Module 8 = 7,471'-7,481' (frac'd Excape System -Flapper depths t 9/3/03) (Module 16&Module 1 =no flappers) . it C Module 7 = 7,540'-7,550' (frac'd 9/3/03) Module 17 - 6,918' CL Module 6 = 7,58V-7,599' (perfd 9/3/03) Module 16 - NA Module 5 = 7,690'-7,700' (frac'd 9/3/03) Module 15 - 6,999' I t t Ikl, Module 4 = 7,753'-7,763' (frac'd 9/3/03) Module 14 - 7,072' Module 3 = 7,920'-7,930' (frac'd 9/3/03) Module 13 - 7,113' ', I Module 2 = 8,385'-8,395' (frac'd 9/3/03) Module 12 - 7,159' '!t Module 1 = 8,470'-8,480' (frac'd 9/3/03) Module 11 - 7,212' rli 1. Module 10- 7,253' 71 Module 9 - 7,451' I cEl Module 8 - 7,490' lar, Module 7 - 7,559' , Module 6 - 7,608' st Module 5 - 7,709' ix Module 4 - 7,772' Module 3 - 7,939 Module 2 - 8,404' `Tagged @ w/2.74"GR 7,806' (12/15/09) Module 1 - NA *Coil tubing cleaned to 8,508'MD(9/4/03) TD PBTD 8,610'MD 8,556'MD k 7,434'TVD 7,380'TVD Well Name&Number: Kenai Beluga Unit 43-7x Lease: Kenai Gas Field Municipality: Kenai Peninsula Borough State: Alaska Country: USA Perforations(MD): 6,770'-8,480' Perf(TVD): 5,525'-7,305' Angle©KOP&Depth: 2.5°/100ft @ 250 ft Angle @ Perfs: 7°-> 20° Date Completed: 6/16/2003 Ground Level: 66'(AMSL) RKB: 21'(AGL) Revised by: Tom Fouts Revision Date: 1/23/2014 t Hilcorp Alaska LLC Weekly Operations Summary Well Name API Number Well Permit Number Start Date End Date KBU 43-7X 50-133-20522-00-00 203-066 1/22/14 1/22/14 Daily Operations: 1/22/2014-Wednesday RU Dynacoil unit. Remove slips. Remove 3/8" capstring and from 7,759'. Shut in swab valve. Remove capstring master valve and pack-off. RD and return to production. 1/23/2014-Thursday No operations to report. 1/24/2014- Friday No operations to report. 1/25/2014-Saturday No operations to report. 1/26/2014-Sunday No operations to report. 1/27/2014- Monday No operations to report. 1/28/2014-Tuesday No operations to report. McMains, Stephen E (DOA • From: Skiba, Kevin J. [kskiba@marathonoil.com] ~~~ Sent: Thursday, August 26, 2010 11:48 AM To: McMains, Stephen E (DOA) Subject: Corrected Lease Numbers Steve, ~~,~~ ~~~ After having discussion with representatives from the BLM, it was determined that the correct Lease # for KBU 33-06x &KBU 43-07x is FED A-028142. I have updated my database to reflect this correction. Thanks again for all of your help, Kevin Skiba Regulatory Compliance Representative Marathon Alaska Production LLC Office (907) 283-1371 Cell (907) 394-1880 Fax (907) 283-1350 ~~n clatc~ fZR~M115 RBDMS AU6 2 6 10~ =Cs 1 • lUlarathon MARATHON Alaska Praductian LLC January 26, 2010 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 43-7x Mar~Tfion Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ap3~ ~~ JAr~ ~ ' 201 Dear Mr. Aubert: Attached for your records is the10-404 Report of Sundry Well Operations for KBU 43-7x well. This report covers the work performed to a 3/8" stainless steel capillary string to a setting depth of 7,759' MD. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, t Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS STATE OF ALASKA ALASKA AND GAS CONSERVATION COMMISS~ REPORT OF SUNDRY WELL OPERATIONS 1. Operations Abandon Repair Well Plug Perforations Stimulate Other ~ Install Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver^ Time Extension ^ Capillary String Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ 2. Operator 4. Well Class Before Work: .Permit to Drill Number: Name: Marathon Alaska Production LLC Development ~ Exploratory^ 203-066 3. Address: PO Box 1949 Stratigraphic ^ Service ^ .API Number: Kenai Alaska, 99611-1949 50-133-20522-00-00 7. Property Designation (Llsase Number): \\ Well Name and Number. A - 028083 Kenai Belu a U D 9. Field/Pool(s): Kenai Gas Field /Beluga & Tyonek Pools 11. Present Well Condition Summary: Alaska 0~ ~ Gas Cons. Connml$$I Total De th measured P e 8,610' feet Plugs (measured) NA feet AnCherape true vertical 7,434' feet Junk (measured) NA feet Effective Depth measured 8,556' feet Packer (measured) NA feet true vertical 7,380' feet (true vertical) NA feet Casing Length Size MD TVD Burst Collapse Structural Conductor 117' 20" 138' 138' 3,060 psi 1,500 psi Surface 1,489' 13-3/8" 1,510' 1,469' 3,450 psi 1,950 psi Intermediate 6,442' 9-5/8" 6,463' 5,340' 6,870 psi 4,750 psi Production 8,568' 3-1/2" 8,589' 7,413' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 6,770' - 8,480' True Vertical depth: 5,625' - 7,305' MD TVD Excape Tubing 3-1/2' L-80 8,589' 7,413' Tubing (size, grade, MD &TVD): Capillary Tubing 3/8" 2205 Stainless Steel 7,759' 6,590' SSSV: NA NA NA Packers and SSSV (type, MD &TVD): Packers: NA NA NA 11. Stimulation or cement squeeze summary: Intervals treated (measured): A 3/8' stainless steel capillary string was installed to a setting depth of 7,759' MD. Treatment descriptions including volumes used and final pressure: 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,000 31 1 351 Subsequent to operation: 0 1,380 - 1 325 13. Attachments: 14,Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ^~ Service ^ Daily Report of Well Operations X Well Status after work: Oil Gas ~ WDSPL GSTOR ^ WAG ^ GINJ^ WINJ ^ SPLUG ^ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: NA Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba > Title Regulatory Compliance Technician ~ Signature ~ ~ ~f~-.K/1~~ Phone (907) 283-1371 Date January 26, 2010 R~DMS JAN 2 92010 ~jy~ Form 10-404 Revised 712009 d ~ • ~ Submit Original Only -` IVlarathon t~erations Summary Report by Job ~ „~~ ,„ail Cornpalrry Well Name: KENAI BELUGA UNIT 43-7X OtrlOtr, 61ock, Sec, Town, Range Field Name License No. StatelProvince Country 6006004N011 VlN1 KENAI ALASKA USA Casing Flange Elevation (tt} Ground Elevation (ft} KB-Casing Flange Distance (ft) KB-Ground Distance (ft) Spud Date Rig Release Date Daily Operations Re ort Date: 7222070 Job Cate o WORifOVER 24 Hr Summary MIRU BJ Dynacoil. Begin PT on packoff and found leaking- packoff successfully bench tested 112D/10. RD for night and WO parts. Ops Trouble Start Time End Time Dur hrs 0 s Code Activi Code Status Code Comment 08:30 09:3D 1.00 SAFETY MTG AF Held PJSM wl BJ Dynacoil, Pollard, and operator. Discussed crane ops, slippery conditions, and lifting heavy objects. Obtained safe work permit. 09:30 10:00 0.50 RURD EQIP AF Remove wellhouse. 10:00 10:30 0.50 RURD COIL AF Spot equipment and secure location. 10:30 12:30 2.00 RURD COIL AF Set FCV to 3400psi. Install 3!B" coil in injector head and stab on well. Begin PT on packoff and found leaking from top seal. 12:30 14:30 2.00 RURD COIL TA MSOT Order parts for new seal assembly, rig down injector and secure well for night. Turn in safe work permit, sign out, and leave location. 14:3D 06:OD 15.50 WAITON EOIP TA MSOT Wait on parts. Re ort Date: 7!232010 Job Cate a WORNOVER 24 Hr Summary RU BJ Dynacoil. RIH w( 3!H" capillary string and tag fill @ 7,903' MD RKB. POOH and set capstring @ 7,759'. Connect string to chemical feed, fill string, and begin pumping foamer at 1 gallday. Replace wellhouse and RDMO BJ Dynacoil. Ops Trouble Start Time End Time Dur hrs 0 s Code Activi Code Status Code Comment 06:00 12:00 6.00 WAITON OTHR TA MSOT Wait on packoff parts. 12:00 12:45 0.75 SAFETY MTG AF Held PJSM wl BJ Dynacoil. Discussed working in the cold, emergency operations, and fluids containment. 12:45 13:30 0.75 WAITON REGS TA LOWP Wait on safe work permit. Obtained safe work permit. 13:30 13:45 0.25 RURD COIL AF RU Dynacoil unit and crane. 13:45 15:OD 1.25 RURD COIL AF MU BHA- 14"x 0.75" sinker bar and 0.75" FCV. Pull test capstring to 2400# and FCV to 500# good test. Land injector head on wellhead. PT packoff to 3000psi- good test. 15:00 18:30 3.50 RUNPUL COIL AF RIH w13/8" capillary string and tag fill @ 7903' MD RKB l;dynacoil measurement). POOH and hang off capstring @ 7759' (Module 4J. Nowell issues. 18:3D 20:3D 2.00 RURD COIL AF Connect capstring to chemical feed. Pump 28 gal foamer to fill line. Set rate @ 1 gallday. RD BJ Dynacoil unit, replace wellhouse, sign out, turn in work permit, and leave location. www.peloton.com Page 711 Report Printed: 726/2070 U 43-7x 50-133-20522-00-00 A - 028083 n: 87' (21' AGL) Pad 41-7 41' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. tude: 60° 27' 34.67" itg ude: -151° 14' 47.43" 274,996.71 2,362,053.16 id: 5/2212003 6111/2003 Released: 611512003 06:00 hrs Tree cxn = 4-3/4" Otis Weatherford straddle packer assembl (set @ 6,698 MD RKB on 12/16/09): -WEA ER Packer (ID: 1.812")= 2.86' 2,800# to release -2 3/8" spacer pipe (ID: 1.994")= 22.2' -WEA SO Tie Back (ID: 1.74")= 2.00' 2,760# to release -2 3/8" spacer pipe (ID: 1.994")= 22.2' -WEA Snap latch seal (ID: 1.75")= 0.92' 5,520# to release -WEA ER Packer (ID: 1.812")= 2.70' KOP: 250' Build: 2.5 deg per 100' Hold Angle: 43 deg at 2,300' DOP: 5,350' Drop: 2.0 deg per 100' Final Angle: 8 deg at 7,450' Capillary Tubing (Installed 1122/2010) 318" OD 2205 0.049" Stainless Steel Wall Thickness Top Bottom MD 0' 7,759' TVD 0' 6,590' Tagged @ 7,806' (12/15/09) w/ 2.74" GR Coil tubing cleaned to 8,508' MD (9/4/03) ~L L ~Ia TD PBTD 8,610' MD 8,556' MD 7,434' TVD 7,380' TVD M ~~~rnoM Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' TVD 0' 138' Surface Casing 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casino 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' 5,340' 12-114" hole, Cmt wl 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casing 3-112" L-80 9.3 ppf EUE Srd Top Bottom MD 0' 8,589' TVD 0' 7,413' Cmt w/ 970 sks of Class G - 17 Excape module system -Greer, control line connected to modules 1~ 9 -Red control line connected to modules 10-~ 17 -Both control lines open for methanol injection (9/3/03) -Ceramic flappers removed with coil (9/3/03) Isolated Perfs: in~~ ..,,.~ a ~na~ c ~n~~ i..~.ra ~ni~Qin4~ - ~~ Active Perfs: , (36' net) = 6,770' - 6,806' (perFd 10/18/08) Module 17 = 6,898' - 6,908' (frac'd 913/03) Module 16 = 6,939' - 6,949' (frac'd 9/3/03) Module 15 = 6,978' - 6,988' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,141' - 7,151' (frac'd 9/3/03) Module 11 = 7,194' - 7,204' (frac'd 913/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,433' - 7,443' (perfd 9/3/03) Module 8 = 7,472' - 7,482' (frac'd 9/3/03) Module 7 = 7,541' - 7,551' (frac'd 9/3/03) Module 6 = 7,590' - 7,600' (perFd 9/3/03) Module 5 = 7,691' - 7,701' (frac'd 9/3/03) Module 4 = 7,754' - 7,764' (frac'd 9/3/03) Module 3 = 7,921' - 7,931' (frac'd 9/3/03) Module 2 = 8,386' - 8,396' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) Well Name & Number: Kenai Beluga Unit 43-7x Lease: Kenai Gas Field, A-028083 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,770' - 8,480' (TVD): 5,525' - 7,305' Angle/Perfs: 20° -• 7° Angle @ KOP and Depth: 2.5° / 100ft @ 250 ft Dated Completed: 6/16/2003 Ground Elevation: 66' above Sea Level Revised by: Kevin Skiba Last Revison Date: 1/26/2010 1lrlarathon !MARATHON Alaska Production LLB January 13, 2010 Maron Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 `i Lt..l ~~~ y ~ 2.010 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 43-7x Dear Mr. Aubert: ;~~s~Ca col C~> Ctr.^.s. Commission '~- .. r-, o3M ©~to Attached for your records is the10-404 Report of Sundry Well Operations for KBU 43-7x well. This report covers the work performed to isolate the 6,706'-6,747' MD perforations with a Weatherford straddle patch. Initial test show that water production has been reduced by 39 bbls per day. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-404 Report of Sundry Well Operations cc: Houston Well File Well Schematic Kenai Well File Operations Summary KJS ~tF. -~ ~/ STATE OF ALASKA ALASKA~L AND GAS CONSERVATION COMMISS~ ~f~~`: ~ `~ j.J~J REPORT OF SUNDRY WELL OPERATION tas~~l iii ~s f~!*. Commissif~ri 1. Operations Abandon Repair Well Plug Perforations Stimulate Other `'`I all Staddle Performed: Alter Casing ^ Pull Tubing ^ Perforate New Pool ^ Waiver ^ Time Extension ^ Patch Change Approved Program ^ Operat. Shutdown ^ Perforate ^ Re-enter Suspended Well ^ 2. Operator 4. Well Class Before Work: .Permit to Drill Number: Name: Marathon Alaska Production LLC Development ^~ Exploratory^ 203-066 3. Address: PO Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 ~ 50-133-20522-00-00 7. Property Designation (Lease Number): 8. Well Name aRd Number: A - 028083 ~ Kenai Belu a Unit 43-7x 9. Field/Pool(s): Kenai Gas Field /Beluga & Tyonek Pools 11. Present Well Condition Summary: Total Depth measured ~ $,610' feet Plugs (measured) NA feet true vertical ~ 7,434' feet Junk (measured) NA feet Effective Depth measured 8,556' feet Packer (measured) Nq feet true vertical 7,3$0' feet (true vertical) NA feet Casing Length Size MD TVD Burst Collapse Structural Conductor 117' 20" 138' 138' 3,060 psi 1,500 psi Surface 1,489' 13-3/8" 1,510' 1,469' 3,450 psi 1,950 psi Intermediate 6,442' 9-5/8" 6,463' 5,340' 6,870 psi 4,750 psi Production 8,568' 3-1/2" 8,589' 7,413' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 6,770' - 8,480' True Vertical depth: 5,625' - 7,305' Tubing (size, grade, MD &TVD): Excape Tubing 3-1 /2" L-80 8,589' 7,413' SSSV: NA NA MD NA TVD Packers and SSSV (type, MD &TVD): Packers: NA NA MD NA TVD 11. Stimulation or cement squeeze summary: Intervals treated (measured): A 53' straddle patch was placed in the 3-1/2" production casing at 6,698' - 6,751' MD isolating the perforations at Treatment descriptions including volumes used and final pressure: 6,706' - 6,747' MD. 12. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 1,868 72 1 309 Subsequent to operation: 0 1,402 33 1 320 13. Attachments: .Well Class after work: Copies of Logs and Surveys Run Exploratory ^ Development ~ Service ^ Daily Report of Well Operations X .Well Status after work: Oil Gas ~ WDSPL GSTOR ^ WAG ^ GINJ^ WINJ ^ SPLUG ^ 16. I hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 309-405 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Technician ~ Signature Phone (907) 283-1371 Date January 13, 2010 ~ RBDMS JAH 141010 Form 10-404 Revised 7/2009 ~'~ Submit Original Only Marathon (rations Summary Report by Jof~ ~M ~Qj~~pany ell Name: KENAI BELUGA UNIT 43-7 Qtr/Qtr, Block, Sec, Town, Range Field Name License No. State/Province Country 6006004N011 W01 KENAI ALASKA USA Daily Operations Report Date: 12/16/2009 Job Cate o WORKOVER 24 Hr Summary MIRU Pollard slickline. RIH w/ 2.74" GR and tag @ 7,806' MD RKB. RIH w/ 2.53" GR and tag @ 7,806'- apparent fill. RIH w/ 2.76" x 4' dummy packer and drift past 6,900'. RIH w/dummy straddle assembly (consisting of 50' of 2 3/8" tubing below a dummy packer assembly) and drift past 6,900'. No issues drifting well. RD Polllard. - Ops Trouble I - -- - - _.... _- I Start Time End Time Dur (hrs) Ops Code Activity Code Status Code I Comment 09:00 09:30 0.50 SAFETY MTG AF Held PJSM w/ Pollard. Discussed crane ops, using wireline clamp, and sim ops. Obtained safe work permit. 09:30 10:00 0.50 RURD EOIP AF RU crane and move wellhouse. 10:00 12:30 2.50 RURD SLIK AF RU slickline truck and equipment. PU 70+ feet of lubricator and MU tool string. 12:30 13:15 0.75 TEST EQIP AF PT lubricator to 150psi low and 2000psi high- good test. 13:15 14:00 0.75 RUNPUL SLIK AF RIH w/ 1.75" RS, KJ, 8' x 2.30" stem, KJ, OJ, SSSJ, and 2.74" GR. Set down @ 6940' MD RKB, WT and fell through. Set down @ 7804' and WT down to 7806'. Appears to be fill. POOH. 14:00 14:45 0.75 RUNPUL SLIK AF RIH w/ same BHA and 2.53" GR. Set down @ 7806', WT and no progress. POOH. 14:45 15:45 1.00 RUNPUL SLIK AF RIH w/ same BHA and 2.76" x 4' dummy packer. Drift past 6900' with no issues. POOH. 15:45 17:00 1.25 RUNPUL SLIK AF RIH w/ same BHA and dummy straddle assembly (consisting of 50' of 2 3/8" tubing below 2.76" dummy packer). Drift past 6900' with no issues. POOH. 17:00 18:00 1.00 RURD SLIK AF LD lubricator and RD slickline equipment. Sign out, turn in safe work permit, and leave location. Report Date: 12/17/2009 Job Category: WORKOVER 24 Hr Summary Well previously flowing 1.1 MMSCFD @ 300psi w/ 78 BWPD. MIRU Expro wireline to set straddle packer. RIH w/ Weatherford ER packer and correlate to module # 17 and set @ 6,751' MD RKB. RIH w/ approx 50' of 2 3/8" tubing below Weatherford ER packer and sting into lower packer. Confirm set w/ 500# overpull and set upper packer @ 6,698' MD RKB (top of packer). RD Expro. - - r Ops Trouble -- Start Tome End Time Dur (hrs) Ops Code Activity Code. Status': Code Comment 09:00 10:15 1.25 SAFETY MTG AF Held PJSM w/ Expro and operator. Discussed working with explosives, sim ops, emergency procedures, and crane operations. Obtained safe work permit. 10:15 11:15 1.00 RURD ELEC AF RU wireline truck and PU lubricator. 11:15 11:30 0.25 PULD PKR AF Hold explosives safety meeting. Arm setting tool, MU tool string, and pull into lubricator. 11:30 12:00 0.50 TEST EQIP AF PT lubricator to 2000 psi- good test. 12:00 14:00 2.00 SETREL PKR AF RIH w/ RS, 10' of stem, CCL, MSST, and 2.74"x2.70' Weatherford ER packer. Correlate to module 17 and set @ 6751' MD RKB (element). Confirm set with tag. POOH. 14:00 15:00 1.00 PULD PKR AF PU additional lubricator to hold straddle packer assembly. Held explosives safety meeting. Arm setting tool, MU packer and tail pipe assembly, and pull into lubricator. 15:00 15:15 0.25 TEST EQIP AF PT lubricator to 2000 psi- good test. 15:15 17:15 2.00 SETREL PKR AF RIH w/ RS, CCL, MSST, 2.72"x2.86' Weatherford ER packer, 2.375"x22.2' spacer pipe, 2.74"x2' SO tieback, 2.375"x22.2' spacer pipe, and 2.74"x0.92' snap-latch seal assembly. Set down on lower packer @ 6,751', sting into packer and jar down several times to latch. Confirm latch w/ 500# overpull. Set upper packer @ 6,698' (top of packer). POOH. www.peloton.com Page 1/2 Report Printed: 1/11/2010 `- Marathon Orations Summary Report by Jol ,~,•~, ~Qjjny Well Name: KENAI BELUGA UNIT 43- Casing Flange Elevation (ft) Ground Elevation (ft) KB-Casing Flange Distance (ft) KB-Ground Distance (ft) Spud Date Rig Release Date Ops Trouble ~~~ Start Time ! End Time Dur (hrs) Ops Code Activity Code. Status ~ Code Cpmment 17:15 18:15 1.00 RURD ELEC AF LD lubricator and RD wireline equipment. Sign-out, turn in work permit, and leave location. Final Straddle Packer description: Weatherford straddle packer assembly (top @ 6,698 MD RKB on 12/16/09): -WEA ER Packer (ID: 1.812")= 2.86' 2800# to release -2 3/8" spacer pipe (ID: 1.994")= 22.2' -WEA SO Tie Back (ID: 1.74")= 2.00' 2760# to release -2 3/8" spacer pipe (ID: 1.994")= 22.2' -WEA Snap latch seal (ID: 1.75")= 0.92' 5520# to release -WEA ER Packer (ID: 1.812")= 2.70' www.peloton.com Page 2/2 Report Printed: 1/11/2010 U 43-7X 50-133-20522-00-00 A - 028083 n: 87' (21' AGL) tude: 60° 27' 34.67" itude: -151° 14' 47.43" 274,996.71 2,362,053.16 d: 5122/2003 6/11/2003 Released: 6/15/2003 06:00 hrs Tree cxn = 4-3/4" Otis Weatherford straddle packer assembly (set @ 6,698 MD RKB on 12/16/09): -WEA ER Packer (ID: 1.812")= 2.86' 2,800# to release -2 3/8" spacer pipe (ID: 1.994")= 22.2' -WEA SO Tie Back (ID: 1.74")= 2.00' 2,760# to release -2 3/8" spacer pipe (ID: 1.994")= 22.2' -WEA Snap latch seal (ID: 1.75")= 0.92' 5,520# to release -WEA ER Packer (ID: 1.812")= 2.70' Pad 41-7 41' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. J ~ ~. ~~ :~ ~Y i .I KOP: 250' Build: 2.5 deg per 100' Hold Angle: 43 deg at 2,300' DOP: 5,350' Drop: 2.0 deg per 100' Final Angle: 8 deg at 7,450' Tagged @ 7,806' (12/15/09) w/ 2.74" GR Coil tubing cleaned to 8,508' MD (9/4/03) ~,• +,r ~_: ,+i4 .'r. ~, ', , TD PBTD 8,610' MD 8,556' MD 7,434' TVD 7,380' TVD M MARATHON Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' ND 0' 138' Surface Casing 13-318" K-55 68 ppf BTC Top Bottom MD 0' 1,510' ND 0' 1,469' Cmt wl 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' ND 0' 5,340' 12-1/4" hole, Cmt w/ 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casing 3-112" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' ND 0' 7,413' Cmt w/ 970 sks of Class G - 17 Excape module system - Grey^_ r~ control line connected to modules 1-> 9 - Red control line connected to modules 10~ 17 -Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) (36' net) = 6,770' - 6,806' (perFd 10/18/08) Module 17 = 6,898' - 6,908' (frac'd 9/3/03) Module 16 = 6,939' - 6,949' (frac'd 9/3!03) Module 15 = 6,978' - 6,988' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,141' - 7,151' (frac'd 9/3/03) Module 11 = 7,194' - 7,204' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,433' - 7,443' (perFd 9/3/03) Module 8 = 7,472' - 7,482' (frac'd 9/3/03) Module 7 = 7,541' - 7,551' (frac'd 9/3/03) Module 6 = 7,590' - 7,600' (perfd 9/3/03) Module 5 = 7,691' - 7,701' (frac'd 9/3/03) Module 4 = 7,754' - 7,764' (frac'd 9/3/03) Module 3 = 7,921' - 7,931' (frac'd 9/3/03) Module 2 = 8,386' - 8,396' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) Well Name & Number: Kenai Beluga Unit 43-7x Lease: Kenai Gas Field, A-028083 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,706' - 8,480' (TVD): 5,564' - 7,305' Angle/Perfs: 20° -~ 7° Angle @ KOP and Depth: 2.5° / 100ft @ 250 ft Dated Completed: 6/16/2003 Ground Elevation: 66' above Sea Level Revised by: James Ostroot Last Revison Date: 12/16/2009 �7 L 2 SEAN PARNELL, GOVERNOR L Li V- k If ALASKA OIL AND GAS 333 W. 7th AVENUE, SUITE 100 CONSERVATION COMUSSION ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Mr. Kevin Skiba Regulatory Compliance Technician Marathon Alaska Production LLC P.O. Box 1949 Kenai, AK 99611-1949 Re: Kenai Gas Field, Beluga &. Tyonek Pools, Kenai Beluga Unit 43-7x Sundry Number: 309-405 "iF,' r � 2009 Dear Mr. Skiba: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the 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. -r1t Chair DATED this day of December, 2009 Encl. • Marathon Alaska Production LLC Alaska Asset Team Marathon P.O. Box 1949 M.Alaska Production LLC Kenai, AK 99611 Telephone 907/283 -1371 Fax 907/283 -1350 RECEIVED December 4, 2009 DEC 0 7 2009 Mr. Winton Aubert Alaska Oil & Gas Cons. Commission Alaska Oil & Gas Conservation Commission Anchorage 333 W 7 th Ave Anchorage, Alaska 99501 Reference: 10 -403 Application for Sundry Approvals Field: Kenai Gas Field Well: Kenai Beluga Unit 43 -7x Dear Mr. Aubert: Attached for your approval is the10 -403 Application for Sundry Approvals for KBU 43 -7x well. Marathon proposes to isolate the excessive water production from the 6,706' - 6,747' MD perforations with a Weatherford straddle patch. Please contact me at (907) 283 -1371 if you have any questions or need additional information. Sincerely, " ' ` 'j la, Kevin J. Skiba Regulatory Compliance Technician I Enclosures: 10 -403 Application for Sundry Approvals cc: AOGCC Current Well Schematic Houston Well File Detailed Operations Program Kenai Well File KJS - ( STATE OF ALASKA ECEIVED�� J C 0 ALASKJOL AND GAS CONSERVATION COMMIS N W IV' APPLICATION FOR SUNDRY APPROVALS DEC 0 7 ?009 20 AAC 25.280 1. Type of Request: Abandon ❑ Suspend ❑ Operational shutdown❑ Perforate ❑ A1 18 SWUPS OBIS. 06 nis 1� Alter casing ❑ Repair well ❑ Plug Perforations d Stimulate ❑ Time Extension fn hQ`ffl)@all straddle Change approved program ❑ Pull Tubing ❑ Perforate New Pool ❑ III GA— Re -enter Suspended Well ❑ patch 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Marathon Alaska Production LLC Development 0 Exploratory ❑ 203 -066 3. Address: PO Box 1949 Stratigraphic ❑ Service ❑ 6. API Number: Kenai Alaska, 99611 -1949 50- 133 - 20522- 00 -00- 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: Spacing Exception Required? Yes ❑ No Kenai Beluga Unit 43 -7X, 9. Property Designation: 7- KB Elevation (ft): 11. Field / Pool(s): A - 028083 , (21' AGL) I 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): 8,610' 7,434' 8,556' 7,380' NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 117' 20" 138' 138' 3,060 psi 1,500 psi Surface 1,489' 13 -3/8" 1,510' 1,469' 3,450 psi 1,950 psi Intermediate 6,442' 9 -5/8" 6,463' 5,340' 6,870 psi 4,750 psi Production 8,568' 3 -1/2" 8,589' 7,413' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6,706' - 8,480' % 5,564'. 7,305' Excape 3 -1/2" L -80 8,589' Capillary Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ❑ 14. Well Class after proposed work: Detailed Operations Program BOP Sketch ❑ Exploratory ❑ Development 0- Service ❑ 15. Estimated Date for } 16. Well Status after proposed work: Commencing Operations: December 8, 008 Oil ❑ Gas 2 , Plugged ❑ Abandoned ❑ 17. Verbal Approval: Date: WAG ❑ GINJ ❑ WINJ ❑ WDSPL ❑ Commission Representative: 18. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283 -1371 Printed Name Kevin J. Skiba A Title Regulatory Compliance Technician Signature one (907) 283 -1371 Date December 4, 2009 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: p — 4 4 , APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date: 0 U RIGINAL Form 10 -403 Revised 06/2006 Submit in Duplicate M MARATHON MARATHON ALASKA PRODUCTION LLC ALASKA ASSET TEAM KBU 43 -7X Kenai Gas Field Pad 41 -7 Straddle Packer Procedure WBS # WO.09.XXXXX.CAP APPROVALS: Jaiaw (9aftovt 11131119 Program Writer .Miami �<q'uPWit 11 /3U/U9 Mickey Mullin L. C. Ibpei, 1212109 Lyndon lbele Well Status: The well was producing 2.OMM at 150 psi with around 50 BWPD (11/212009). History: Excessive water production resulting in numerous and expensive water haulingrisk to stabilized gas production indicated the necessity to shut off water production from the interval 6,706'— 6,747' ELMD. The PLT run on 7/24/2009 indicated that this interval was providing the vast majority of the water production from the well. Objectives: This procedure covers work to install a 3.5" CIBP just above the previous tag to isolate th lower water productive intervals. Also, a 2.375" OD x 50' (2.74" max OD) Weatherford straddle packer will be installed across perforations at 6,706'— 6,747' ELMD to shut off the excessive water production from the perforations added to this well in October, 2008. This assembly is designed to be run in two runs via E -line and pulled in three runs via slickline if removal is necessary. Resources: 1. Slickline — To run dummy packer assembly 2. Electric Line — To run and set CIBP and straddle packer 3. 3 V Weatherford CIBP (2'/" OD), wireline setting adapter f/ multi stage setting tool (MSST), and MSST 4. Weatherford straddle packer (see packer assembly sheet for dimensional and pinning requirements) — contains: a. (2)3 ER Packers w/WLEG b. (2) 22' jts of 2 3/8" tbg cut w/ NU 10 round threads c. (2) 3 %2" SO tie -back receptacles d. Wireline setting adapter f/ multi stage setting tool (MSST) e. Owen MSST 5. Rental Equipment — Manlift. Light plant and heater depending on the season. KBU 43-7X Straddle Packer Procedure J GO Page 1 11/03/2009 i� Procedure: 1. MIRU rental equipment. Deliver diesel -fuel man -lift and two light towers. 2. De- energize electrical and remove wellhouse (if necessary). Move in crane. Pull wellhouse and set out of the work area. 3. MIRU Pollard Slick line Unit to run 2.85" GR . Hold PJSM, complete work permit form, and complete fall protection checklist. PU pump -in tee and wireline valve to Otis tree cap connection. PU lubricator and pull centralized 2.85" OD swage, spang jars, oil jars, stem, and weight bars into lubricator. Pressure test lubricator with methanol water to 250/2000 psi. Shut well in. Bring Gauge rings 2.60" - 2.80" to accurately determine what size will pass if the 2.85" does not pass. 4. RIH w/ 50'x 2.375" dummy packer assembly RIH with bottom 2.74" dummy packer element, 50' section of 2.375" OD straddle sleeve, and top 2.74" OD dummy packer element, crossover, bait sub, spang jars, oil jars, and stem on slickline to 6,800'850'. POOH. 5. RDMO Pollard Wireline 6. MIRU Expro Wireline Unit to set CIBP A_ 8,100' ELMD and straddle packer across 6,701- 6,751' ELMD a. Hold PJSM, complete work permit form, and complete fall protection checklist. b. MU wireline valve with pump -in sub to 4- 1/16" 5K tree. c. MU and PU sufficient 5" lubricator to set a 50' long straddle packer. d. MU and pull into lubricator 3'/" Weatherford CIBP, wireline setting adapter, Owen MSST, and CCL. Hold Explosives Safety Meeting. Arm setting tool. e. Take lubricator to wellhead. Pressur esfilubricator to 250/2000 psi with methanol water. RIH i to desired space out to set CIBP @ 8,1 (ELMD tied into per(s and correlated to completion log dated 6/14/03). Set CIBP. PO and LD setting tool. f. Un -arm setting tool and make up 3 %" Weatherford ER packer, wireline setting adapter, Owen MSST, and CCL. Hold Explosives Safety Meeting and re -arm setting tool. PU tools into lubricator and quick test to 2000 psi. RIH to desired space out to set lower packer @ 6,751' (ELMD tied into perfs and correlated to completion log dated 6/14/03). Set lower assembly. POOH and LD setting tool. g. Un -arm setting tool and make up SO tie -back, 22' of 2 3/8" tubing, SO tie -back, 22' of 2 3/8" tubing, 3'/z" Weatherford ER packer, wireline setting adapter, Owen MSST, and CCL. Hold Explosives Safety Meeting and re -arm setting tool. PU tools into lubricator and quick test to 2000 psi. h. RIH w/ upper assembly and slow speed when approaching lower packer @ 6,751' ELMD. Latch upper assembly on lower packer and confirm latch w/ 800 # overpull. Set upper packer and POOH. LD setting tool and LD lubricator. i. RDMO Expro. J. Flow test well through test separator with particular emphasis on measuring the daily produced water and gas volumes at a stabilized FTP. 2 Flow well to roduction facility. Request Operators to put into test when stabilized to p 4 p p Y determine success of water - isolation. KBU 43 -7X Straddle Packer Procedure JGO Page 2 11/03/2009 a Straddle Packer Dimensional and Pressure Data: Burst = 5,000 psi Collapse = 5,000 psi CIBP OD = 2.5" ER packer OD = 2.74" ER packer ID = 1.812" SO tie -back receptacle OD = 2.72" SO tie -back receptacle OD = 1.75' Spacer tubing OD = 2.375' Spacer tubing ID = 1.994" Min ID after setting = 1.75' WBD LINK Straddle Packer Considerations, Instructions, and Planning / It is mandatory that the Weatherford straddle packer specifications be consulted and reviewed with the electric line provider ( Expro at this time) to ensure that the packer can be run and set properly. Straddle packer dimensions can be obtained from the following site: http:/ /www.weatherford.com /weatherford /groups/ public /documents /intervention /wi productinformation.hcsp A gauge ring alone will not provide sufficient proof or comfort that the straddle packer can be run and set. A dummy packer assembly which mimics the packer length and tubular OD and uses the same short (end) assemblies without the setting tools installed should be run past the target interval with slickline. If the dummy can be run and retrieved easily, the straddle packer should not be a problem to install. Ensure that the personnel running the straddle packer are knowledgeable and trained properly. At this time, Ed Hawker and Justin Weaver, with Expro Wireline in Nikiski, AK, are the only known personnel who have this experience and training in Alaska. It is necessary to consult them with considerations on straddle packer length, as we are limited by lubricator length and crane height. KBU 43 -7X Straddle Packer Procedure JGO Page 3 11/03/2009 r 0 0 KBU 43 -7x M Permit #: 203 -066 Pad 41 -7 MARATHON API #: 50- 133 - 20522 -00 -00 41' FSL, 4 088' FWL, Prop. Des: A - 028083 , KB elevation: 87' (21' AGL) Sec. 6, T4N, R11 W , S.M. Conductor WBS #: 20" K -55 133 ppf Latitude: 60° 27' 34.67" Top Bottom Longitude: -151° 14' 47.43" VD 0' 138' X. 274,996.71 Y: 2,362,053.16 Spud: 5/22/2003 Surface Casing TD: 6/11/2003 13 -318" K -55 68 ppf BTC Rig Released: 611512003 06:00 hrs Top Bottom PA #: MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks (335 bbls)of 12 ppg Type -1, 102 sks (45 bbls) to surface Intermediate Casing 9 -5/8" L -80 40 ppf BTC Tree cxn = 4 -3/4" Otis Top Bottom MD 0' 6,463' TVD 0' 5,340' -_ 12 -1/4" hole, Cmt wl 647 sks (210 bbls) of KOP: 250' / Class G (lost 65 bbls) Build 2.5 deg per 100' 4 Hold Angle: 43 deg at 2,300' Production Casing DOP: 5,350' 3 -112" L -80 9.3 ppf EUE 8rd Drop . p er 100 Top Bottom �� 20 deg ' p ?� MD 0' 8,589' Final Angle 8 deg at 7,450' TVD 0' 7,413' Cmt w/ 970 sks of Class G r Excape System Details �r - 17 Excape module system 1 - Gres control line connected to modules 1- 9 - Red control line connected to modules 10- 17 } - Both control lines open for methanol injection (9/3/03) ? - Ceramic flappers removed with coil (9/3/03) } Perfs: (41' net) = 6,706' - 6,747' ( perfd 10/18/08) (36' net) = 6,770' - 6,806' ( perfd 10/18/08) ? Module 17 = 6,898'- 6,908' (frac'd 9/3/03) Module 16 = 6,939'- 6,949' (frac'd 9/3/03) ' * Module 15 = 6,978'- 6,988' (frac'd 9/3/03) } Module 14 = 7,053'- 7,063' (frac'd 9/3/03) - t Module 13 = 7,094'- 7,104' (frac'd 9/3/03) Tagged @ 8,104' ELM (7/23109) r Module 12 = 7,141'- 7,151' (frac'd 9/3/03) w/ 2.25" centralizer & 1.25" Swage Module 11 = 7,194'- 7,204' (frac'd 9/3/03) Module 10 = 7,234'- 7,244' (frac'd 9/3/03) Module 9 = 7,433'- 7,443' (perfd 9/3/03) Coil tubing cleaned to ([ Module 8 = 7,472'- 7,482' (frac'd 9/3/03) 8,508' MD (914/03) �1 C Module 7 = 7,541'- 7,551' (frac'd 9/3/03) 4` Module 6 = 7,590'- 7,600' (perfd 9/3/03) Module 5 = 7,691'- 7,701' (frac'd 9/3/03) Module 4 = 7,754'- 7,764' (frac'd 9/3/03) Module 3 = 7,921'- 7,931' (frac'd 9/3/03) Module 2 = 8,386'- 8,396' (frac'd 9/3/03) E6M PBTD Module 1 = 8,470'- 8,480' (frac'd 9/3/03) 8D 8,556' MD 7, D 7,380' TVD Well Name & Number: Kenai Beluga Unit 43 -7x Lease: Kenai Gas Field, A- 028083 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,706'- 8,480' (TVD): 5,564'- 7,305' Angle /Perfs: 20° 7° Angle @ KOP and Depth: 2.5° / 1 00f @ 250 ft Dated Completed: 6/16/2003 Ground Elevation: 66' above Sea Level Revised by: Kevin Skiba Last Revison Date: 9/25/2009 it ~ ~ IVlarathan l~hARATHON ~Alaska Prvductivn LL~ ~~CEI~l~Q September 30, 2009 Mr. Winton Aubert Marathon Alaska Production LLC Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 OCT A ~. ~~~9 ~as~Ce Oil & Gas ~ans. ~unr~n~~s~on Anchor~~ Alaska Oil & Gas Conservation Commission 333 W 7th Ave ~ Anchorage, Alaska 99501 ~3._.. Q ~ ... -....... ...~,_._ .. Reference: 10-404 Report of Sundry Well Operations Field: Kenai Gas Field Well: Kenai Beluga Unit 43-7x ~~~~~~~~ ~~ `~ ~~~~~9 Dear Mr. Aubert: Attached for your records is the10-404 Report of Sundry Well Operations for KBU 43-7x. This report covers the work performed to add 77' of perforations to the Beluga formation. The additional perforations introduced significantly larger volumes of water than the / wellbore had previously experienced. Based in this water influx, a decision was made to discontinue with the remaining approved perforation additions. An evaluation is underway to determine the best way to isolate the infiltrating water. A 10-403 will be submitted, for your approval, upon completion of the remedial strategy. / Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, . . ~~ .,e~l~'~~ ` Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-404 Report of Sundry Well Operations Well Schematic Operations Summary cc: Houston Well File Kenai Well File KJS STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS ~~~EI1/~,~ oc~r o ~~~~~~z°°4 ~llaska ~ii ~ Gas Cans. Comm~asian 1. Operations Abandon Repair Well Plug Perforations Stimulate Other nchorage Performed: Alter Casing ~ Pull Tubin~ Perforate New Pool ~ Waiver^ Time Extension ~ Change Approved Program ~ Operat. Shutdowr~ Perforate Q Re-enter Suspended Well ~ 2. Operator Marathon Oil Company N 4. Well Class Before Work: 5. Permit to Drill Number: ~ ame: Development ^~ Exploratory^ ' 203-066 3. Address: p0 BOX 1949 Stratigraphic ^ Service ~ 6. API Number: Kenai Alaska, 99611-1949 ~ 50-133-20522-00-00 7. KB Elevation (ft): 9. Well Name and Number: , 87' 21' AGL ' Kenai Belu a Unit 43-7x 8. Property Designation: 10. Field/Pool(s): ''r A- 028083 ~ Kenai Gas Field / Beluga & Tyonek Pools 11. Present Well Condition Summary: 'fotal Depth measured .$,610' feet Plugs (measured) NA true vertical '~ 7,434' feet Junk (measured) NA Effective Depth measured 8,556' feet true vertical 7,380' feet Casing Length Size MD TVD Burst Collapse Structural Conductor 117' 20" 138' 138' 3,060 psi 1,500 psi Surface 1,489' 13-3/8" 1,510' 1,469' 3,450 psi 1,950 psi Intermediate 6,442' 9-5/8" 6,463' S,340' 6,870 psi 4,750 psi Production 8,568' 3-1/2" 8,589' 7,413' 10,160 psi 10,530 psi Liner Perforation depth: Measured depth: 6,706' - 8,480' True Vertical depth: 5,564' - 7,305' Excape Tubing 3-1/2" L-80 8,589' Tubing: (size, grade, and MD) Capillary String Packers and SSSV (type and measured depth) NA NA 12. Stimulation or cement squeeze summary: 77' of perforations were added during three perf gun runs. The added Intervals treated (measured): perforation intervals are: 6,706' - 6,726' Treatment descriptions including volumes used and final pressure: 6,726' - 6,747' 6,770' - 6,807' 13. Representative Daily Average Production or Injection Data Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 2,870 26 20 455 Subsequent to operation: 0 2,105 89 20 425 14. Attachments: 15. Well Class after work: ;~ Copies of Logs and Surveys Run Exploratory ^ Development Q Service ^ Daily Report of Well Operations X 16. Well Status after work: Oil^ yGas ^~ 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: 308-352 Contact Kevin Skiba (907) 283-1371 Printed Name Kevin J. Skiba Title Regulatory Compliance Technician ~ Signature ~ , Phone (907) 283-1371 Date September 30, 2009 ~ v ~~ ~.f~p~~11~ C~'( r ~c~ ~~, Form 10-404 Revised 04/2006 Submit Original Only ~ ~~~~ Dperations Summary Report ,,,,,Q„T,~„ sd~~ ~~~~ VMlell Name: KENAI BELUGA UNIT 43-7X Report Date: 10M9f2008 Job Category: R&M MAINTENANCE ~l N r S~mmary Perforated the upper 2 zones. Test over night. Corrtinue perforating SgrtTme E~aTlne D~r O Cotle AcW Catle ops ~a Tro~bkCOtle Canme~t 06:00 07:00 1.00 SAFETY MTG AF MIRU Expro, held PJSM and obtained work permit. VvHP= 425 pisg, 2.14 MMCFPD ~.rn 26 BrWPD. Discussed operations prior to rigging up e line unit. 07:00 08:00 1.00 RURD ELEC AF Spot up equipmerrt and and environmerrtal iiner. MU 1 11116" tool string with CCL and 2 3~" RTG loaded ~ 4 SPF, 60 deg phased, with tag 2375-402NT}{ charges on each run. MU 36' qun for run number #1 . 08:00 09:00 1.u0 RURD ELEC AF Safe firing system will be used to arm perf gun on Each run in well. 09:00 10:00 1.0~ RURD ELEC AF MU lubrica~tor with 36' gun,. Prior to arming perforaRing gun, held Go to communication black 8 held safety meeting. PT lubricator to 2000 psig. Good test. O en well. RIH with run #1 . 10:00 11:00 1.u0 Rlt ELEC AF RIH below modula #1 , log up through and correlate depth to Schlumberjay Compensation density log dated 10-2003. 11:00 12:00 1.Od RK ELEC AF Pull gun in to pastion to perforarte from 6770' - 6807' DIL (36'). Shut vwell in, build WHP to 600 psig, fired gun. POOH. After 15 minutes shut in well. Flow well to production while POOH with gun #1 . 12:00 13:00 1.00 RI4 ELEC AF OOH all shats fired, well flow rate at same rate prior to perforating. MU gun#2 same gun type same as above, 21'. Go to well vwith gun, PT using uick test sub. ood test. 13:00 14:00 1.00 RK ELEC AF RIH with gun, Correlate depth as before. Pull gun in to postion to perforate from 6726' - 6747' DIL (21'). Shut well in. Pressure built to 590 psig, fired gun. POOH. After 15 minutes shut in well. Open well to production while POOH with gun #2. no ch~nge in rate. 14:00 15:00 1.00 RK ELEC AF OOH all shots fired. MU gun#3 s~me gun type as above, 20'. Go to well with un PT usin uick test sub. ood test. 15:00 16:00 1.00 RI( ELEC AF RIH with gun, Correlate depth as before. Pull gun in to postion to perforaite from 6706' - 6726' DIL (2d'). Shut well in. Pressure buift to 590 psig, fired gun. POOH. After 15 minutes shut in well. Flow well to production while POOH with gun #3. no change in rate. 16:00 18:00 2.00 RK E~EC AF OOH all shots fired. Test well over night to decide if we will cor~tinue perfoating. Well a 2300 MCFPD, 425 psig. Secured well for night. Expro left lease. Note AM resutts were + 60 bbls of additional water, 2000 MCFPD, (-400) SCF PD ra~te. We plan to test well before erforatin further. Daify Operations Report Date: 11f8~'2008 Job Category: R&M MAIHTEHANCE ~t M r Simmary Rar~ PLT 65dd - 6$60 to identify water entry o~a SttirtTnie E~4TIne ~~~ 0 COtl2 AG111 COtlt ~S Tro1bkCOd! Comme~t ~9:00 09:30 0.50 RURD ELEC AF Evalu~te location. Wellhouse is off cerrter. 09:30 10:30 1.00 RUftD ELEC RF Hold PJSM with roustabout crew and issua permit. Mave wellhouse 2'. 10:30 11:00 O.SO SAFETY MTG AF Hold Ex ro PJSM. Discuss Ex ro JSA assi n tasks. 11:00 12:00 1.00 RURD ELEC AF RU elinE unit. PU PLT tools. 12:00 13:00 1.00 REPAIR EQIP AF Spinner not communiceting with computer. troublashoot and repair spinner. 13:00 15:00 2.00 LOG CSG AF RIH PLT tools. Log 650d' - 6860' at 30, 60, and 90 fpm both up and down. ater errtry is in upper section of upper preforations. 15:00 15:45 0.75 RUNPUL ELEC AF POH 15:45 17:00 1.25 RURD ELEC AF RD and release expro. Test tree cap with well pressure. Close permit, sign out and leave location. www.peloton.com Report Prirrted: 9f24r2009 ~~~~ ~perations Summary Report ~*Q~~ ~n~~ Well Name: KENAI BELUGA UNIT 43-7X Report Date: 5C17R009 Job Category: R&M MAINTENANCE 2l N r S~mmary R~n dynamic and static PT surveys w1 Pollard to iderrtify wartEr errtry. SgrtTlne E~OTIne D~r 0 Cotle Pct~ Co6e o~s Sgds TroibkCOtle Canme~t 07:30 O1:57 0.45 SAFETY MTG AF Held PJSM wl Pollard, field operator, and other third party personnel. Discussed SimOps, emergency procadures, crane ops, warterfowl, ~nd verrtin as. 4btained safe work ermit. 07:57 09:27 1.50 RURD SLII{ AF Spot equipmer~t, RU wireline truck and PU lubricator. 09:27 09:42 0.25 TEST EQIP AF PT lubricator to 2250 psi. Good test. 09:42 10:42 1.00 RUNPUL SLIK AF RIH wI RS, A@T, I(J, 1.S" x 10' of stem, KJ, OJ, LSS, and 2.5" GR. Sat down ~ 8,180' (between modules 2 8 3), WT and would not pass. Appears to be fill. POOH. 10:42 19:42 5.Ot7 LOG PROD AF RIH wl RS, ABT, ItJ, 1.5" x 10' of stem, KJ, OJ, and tandem PT gauges. Log down pass flowing ~ 60 ftlmin to 8,180' and sit far 10 min. Shut well in. After 1 hr shut in time, log up pass ~ BO ftnnin to 6671'. After 2 hrs shut in ime, log down pass ~ 60 ftRnin to 8,180'. After 4 hrs shut in time, log up ass Cao 60 ftRnin to surf~ce and sit for 10 min. 19:42 20:12 0.50 LOG PROD AF Download tool darta and check. Good darta. 2~:12 20:42 0.50 RURD SLilt AF LD lubricator, RD wireline truck and equipment. Turn in safe work permit, sign out, and leave location. Uaily Operations Report Date: 7r24l2009 Job Category: R&M MAIHTEMANCE 2~ H r S~mmaq~ MIRU Expro wireline. RIH wI 2.25" cerrtralizer & 1.25" swage and tag ~ 8104'RKB. Secure lufaricartor for night. SgrtTlne E~tlTlne D~r 0 Caae a~ctu Co6e opa s~ua Tro~DkCOCk Canmeit 17:30 18:00 0.50 SAFETY MTG AF Traveled to location. Held PJSM w! Expro. Discussed crane ops, securing IubricaRor overnight, emergency procedures, smoking/muster areas, and inciderrt re ortin . Obtained safe work ermit. 18:00 19:00 1.00 RURD ELEC AF RU lubricator and wireline equipmerrt. 19:00 19:30 O.Sd TEST EQIP AF PT lubricator to 2500 psi. Good test. 19:30 21:00 1.Sd RUNPUL ELEC AF RIH wI 2.25" cer~tralizer and 1.25" swage. Set down ~ 8104'RKB (correlated off St~V'S GRrCCL 6M 4~03). WT and POOH. 21:00 22:30 1.50 RURD ELEC AF LD IubricaRor secure tree for night. Sign out, turn in safe work permit, and leave location. Report Date: 7!'25!'2 009 Job Category: R& M MAIHTENA HCE 2~ MrS~mmary MIRU Expro wireline. RIH wI PL string and perform flowing suruey to TD to evaluate casing patch and cap string. Log down passes over perforations after 1, 2, and 4 hours after shut in. RDMO Expro. o~ St~rtTlne E~dTlne O~r O Cotle AcW Cotle SYads Tro~bkCatle Canme~t 07:30 08:30 1.00 SAFETY MTG AF Traveled to location. Attended pad SimOps meeting. Held PJSM wI Expro. Discussed crane ops, blowing down lubricator, visitors, emergency procedures, smokingRnuster areas, and incider~t reporting. Obtained safe work ermit. 08:30 09:00 ~7.SU RURD ELEC AF RU lubric~tor 8 access well tree. 09:00 09:30 0.50 TEST EQIP AF PT lubricator to 2500 psi. Good test. 09:30 12:30 3.00 LOG PROD AF RIH wI PL tool string as follows: Air: 13.9psia 8 46.ldegF S min bench on surface- start: 332.1 psia 8 47.4degF end: 327.2psia 8 56.2degF RIH t16500'RKB and log down pass ~ 60fpm. 5 min bench ~ TD (8050') start: 92$.4psia & 123.6degF end: 934.8psia 8123.~degF Spinner quit during bench, WT and spinner wonY free. POOH and rebuild s inner. 12:30 12:45 0.25 LOG PROD ,~F RIH w/ PL string. Spinner quit and POOH to rebuild. 12:45 14:45 ~ i ii i ~n~.; PRC;D ,~,F RIH ~,~:~ / PL ~rinr~ tl F~-,i ii P ar~d Ir_~q dr_~~,~,~ r~ pa:= =.: ~ct! yi ifF_~m. Loq ~_~F_~ pa:=::=: ~?~ iit;r~i' i='~' F;innrr a it:r~~;r1 ':yrv,F_r-~Ht t ~r: I ~~ ~~~~ ~perations Summary Report ,~„~ s~~~ ~n~~ 11Uell Name: KENAI BELUGA UNIT 43-7X SgrtTlne E~CTtne o~r o coae ,~u coae o~ sgas Tro~bkCOtle canme~t 14:45 22:00 7.25 LOG PROD AF RIH wI PL string as follows: Log down pass ~ 120fpm from 6500'. Log up pass @ 120fpm from 8050'. RIH tI 7980' and log up pass ~W 60fpm. RIH t/ 7980' and log up pass ~ 90fpm. Shut well in. Atter 1 hr shut in, down pass 60 fpm t17980'. Up pass 60 fpm tf 6500'. After 2 hrs shut in, down pass 60 fpm t! 79$0'. Up pass 60 fpm t/6500'. After 4 hrs shut in, down pass 60 fpm tI 1980'. Up pass 60 fpm t16500'. POOH. 22:00 23:30 1.SO RURD ELEC AF LD lubricator 8 RD wireline equipmerrt. Sign out, turn in safe work permit, and leaue location. www.pe~oton.com Report Prirrted: 9J24f2009 50-133-20522-00-00 A - 028083 n: 87' (21' AGL) tude: 60° 27' 34.67" itude: -151° 14' 47.43" 274,996.71 2,362,053.16 id: 5/2 212 0 0 3 6f11/2003 Released: 6/15/2003 06:00 hrs Tree cxn = 4-3/4" Otis 250' 2.5 deg per 1fl0' 4nq1e: 43 deg at 2,300' 5.350' 2.0 deg per 1~0' KBU 43-7x Pad 41-7 41' FSL, 4,088' FWL, Sec. 6, T4N, R11 W, S.M. M M~-ww-nioM Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' ND 0' 138' Surface Casi~q 133/8" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt wl 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casinq 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' S,340' 12-1/4" hole, Cmt wl 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casinq 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' ND 0' 7,413' Cmt w/970 sks of Class G - 17 Excape module system - Greer control line connected to modules 1~ 9 - Red control line connected to modules 10--~ 17 - Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) Tagged @ 8,104' ELM (7/23/09) w/ 2.25" centralizer & 1.25" Swage Coil tubing cleaned to 8,508' MD (9/4/03) (41' net) = 6,706' - 6,747' (perf'd 10/18/08) (36' net) = 6,770' - 6,806' (perf'd 10/18/08) Module 17 = 6,898' - 6,908' (frac'd 9/3/03) Module 16 = 6,939' - 6,949' (frac'd 9/3/03) Module 15 = 6,978' - 6,988' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,141' - 7,151' (frac'd 9/3/03) Module 11 = 7,194' - 7,204' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9= 7,433' - 7,443' (perf'd 9/3/03) Module 8= 7,472' - 7,482' (frac'd 9/3/03) Module 7= 7,541' - 7,551' (frac'd 9/3/03) Module 6= 7,590' - 7,600' (perf'd 9/3/03) Module 5= 7,691' - 7,701' (frac'd 9/3/03) Module 4= 7,754' - 7,764' (frac'd 9/3/03) Module 3= 7,921' - 7,931' (frac'd 9/3/03) Module 2= 8,386' - 8,396' (frac'd 9/3/03) Module 1= 8,470' - 8,480' (frac d 9/3/03) Well Name & Number: Kenai Beluga Unit 43-7x Lease: Kenai Gas Field, A-028083 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,706' - 8,480' (TVD): 5,564' - 7,305' Angle/Perfs: 20° ~ 7° Angle @ KOP and Depth: 2.5° / 100ft @ 250 ft Dated Completed: 6/16/2003 Ground Elevation: 66' above Sea Level Revised by: Kevin Skiba Last Revison Date: 9/25/2009 • • N w^ P` ~ f ~ p ~~ ~ ~ $ggg!! B ~ ~ ~ ~i skd ~t~ ~~C ~~ ~~ ~~ i ~~ ~~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ e e ~ ~ SARAH PALIN, GOVERNOR 4 V ~ ~ p ~ € ' ~ e ~ ~ e ~~ ~-~ 2 r: ~.,°~ ~~ z ~"~ ~,~ ~ '~.`"~ I ~ 'mow ~~ aL.~, ALA-7IiA OIL A1QD (iAS ~ 333 W. 7th AVENUE, SUITE 100 C01~5ERQA'rIOI~T CO1rII~'IISSIOI•T ~ ANCHORAGE, ALASKA 99501-3539 r PHONE (907) 279-1433 FAX (907) 276-7542 Michael D. Dammeyer Production Engineer Marathon Oil Company P.O. Box 1949 ~j Kenai, Alaska 99611-1949 ~,Q ~~ b Re: Kenai Gas Field, Beluga & Tyonek Pool, Kenai Beluga Unit 43-7x Well Sundry Number: 309-192 Dear Mr. Dammeyer: 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, ~~ DATED this _ day of June, 2009 Daniel T. Searnount, Jr. Chair Encl. ,. M Marathon MARATHON Oil Company • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 ~~~ June 4, 2009 Mr. Winton Aubert Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, Alaska 99501 Reference: 10-403 Application for Sundry Approvals Field: Kenai Gas Field Well: Kenai Beluga Unit 43-7x Dear Mr. Aubert: ~U~i t~ ~ 1iJ[ ~l~l~ka Oil & Gas Cons. ~n~~irr~ission AnGhoraso Marathon proposes to run a 3/8" capillary string in KBU 43-7x well. The tubing would serve as a conduit to direct foamer into the wellbore at a setting depth that would better ~,. assist inrith the water unloading process. The target setting depth of this capillary string is ';475'' MD. ''Please call me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~~~ s~ Kevin J. Skiba Regulatory Compliance Technician Enclosures: 10-403 Application for Sundry Approvals cc: AOGCC Current Well Schematic Houston Well File Detailed Operations Program Kenai Well File KJS ~, ,~,~~ b ~~ ~~'Ir STATE OF ALASKA 6-z3-D9 ALAS~OIL AND GAS CONSERVATION COMMON ~ j~j~-- I i ~ , APPLICATION FOR SUNDRY APPROVALS ~~~'il%'°`~'~~'" ~ '~~"~ 20 AAC 25.280 1. Type of Request: Abandon ^ Suspend ^ Operational shutdown^ Perforate ^ Waiver &~~~~ ~~ Other ~ ~O lnstaapillary Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Change approved program ^ Pull Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ String 2. Operator Name: Marathon OII ColYl an p y 4. Current Well Class: 5. Permit to Drill Number: Development ^ _ Exploratory ^ 203-066' 3. Address: p0 Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20522-00-00 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: ~ ^ Kenai Beluga Unit 43-7x Spacing Exception Required? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): A- 028083 ~ 87' ~ (21' AGL) 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): 8,610' - 7,434' - 8,556' - 7,380' - NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 117' 20" 138' 138' 3,060 psi 1,500 psi Surface 1,489' 13-3/8" 1,510' 1,469' 3,450 psi 1,950 psi Intermediate 6,442' 9-5/8" 6,463' 5,340' 6,870 psi 4,750 psi Production 8,568' 3-1/2" 8,589' 7,413' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): .,6,89648,480' ~4 =7,305' Excape 3-1/2" L-80 8,589' - t~ t~`jUto' w"~~ - Capillary Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program 0 BOP Sketch ^ Exploratory ^ Development ^~ ~ Service ^ 15. Estimated Date for j" 16. Well Status after proposed work: Commencing Operations: .luly 1, 2009 Oil ^ Gas ^~ Plugged ^ Abandoned ^ 17. Verbal Approval: Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Michael D. Dammeyer Title Production Engineer Signature Phone (907) 283-1333 Date June 4, 2009 COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: ^ /~Z Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: ., f , ,.2i~~ (~ e} ?UQ~ Subsequent Form Required: r ~ ..,~ ~~ ~} i APPROVED BY : COMMISSIONER THE COMMISSION Date: ~ A roved b j pp y ~11fi1 Form 10-403 Revised 06/2006 Submit in Du licate ` 2008 Capillary String Installatio• KBU 43-7x Capillary String Install Pad 41-7 WBS: Requested Objective Install capillary string (3/8" 2205 0.049" WT) into well for delivering foamer to alleviate liquid loading. Procedure Capstring Set Depth: 8,475' '~ TVD at Set Depth: 7,300' Coil length: 9,000' Tag: 5,806' (11/08) all mods open Installation Procedure: Disconnect power to wellhouse (call electrician) MI crane, manlift. Remove wellhouse. On site: 9,000' spool, Well Head Adapter -Long (WHA), Sundry, Work Permit, Well Control Standards Sheet. Install Capillary Strin (g JSA): l . MIRU BJ Dyna-Coil unit. Place liner around wellhead and truck. / 2. Shut swab valve, pull tree-cap flange, remove OTIS blanking plug. 3. Replace plug with WHA (note o-ring). MU flange. Pressure test 1.Sx SIWHP. 4. P/iJ Dyna-Coil injector with crane, run 3/8" string through injector. 5. Set Fluid Control Valve pressure = (Setting TVD 7,300')(0.433 psi/ft H20)(1.036 foamer SG) =`3~~,,... psi (use BHP as a safety factor). 6. MU BHA; run the 3/8" string through pack-off; attach BHA. 7. Perform "pull test" on BHA. 8. Thread pack-off assembly into 2-7/8" female connection (a wrench or chain tongs maybe needed to hold the adapter from turning). Wrap wellhead with absorbents to catch drips. 9. Configure tubing to pump foamer downhole while running in, or cap tubing end. 10. Set Rattiguns to running tightness, and pump up pressure on pack-off. 11. Open swab valve. 12. Adjust Rattiguns and pressure on pack-off as needed to minimize leaks. 13. RIH to setting depth of 8,475'. 14. Set slips. Set Rattiguns; leave 1.5 times SIWHP on hydraulic pack-off. 15. Pull tubing excess through injector. 16. Cap tubing with a Swagelok cap and valve, pressure gauge, and filter. 17. Lockout Swab, Upper Master, and Lower Master as per Capstring Lockout Procedure. 18. Hookup injection line to CICM. / NOTE: Start foamer at 1 gpd. 19. RDMO. Cleanup site. Sign-out. 20. Replace well house NOTE: When replacing well house, be careful of the tubing "bend" as it goes back inside if it extends through the roof. KBU 43-7x M Mi~-nroM Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' TVD 0' 138' Surface Casing 13-318" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks (335 bbls)of 12 ppg Type-1, 102 sks (45 bbls) to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' 5,340' 12-1/4" hole, Cmt w/ 647 sks (210 bbls) of Class G (lost 65 bbls) Production Casing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' TVD 0' 7,413' Cmt w/ 970 sks of Class G - 17 Excape module system -Green control line connected to modules 1-> 9 - Red control line connected to modules 10-~ 17 -Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) Perfs: (41' net) _ / 6,706' - 6,747' (perfd 10/18/08) (36' net) = 6,770' - 6,806' (perfd 10/18/08) Module 17 = 6,898' - 6,908' (frac'd 9/3/03) Module 16 = 6,939' - 6,949' (frac'd 9/3/03) Module 15 = 6,978' - 6,988' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,141' - 7,151' (frac'd 9/3/03) Module 11 = 7,194' - 7,204' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,433' - 7,443' (perf'd 9/3/03) Module 8 = 7,472' - 7,482' (frac'd 9/3/03) Module 7 = 7,541' - 7,551' (frac'd 9/3/03) Module 6 = 7,590' - 7,600' (perf'd 9/3/03) Module 5 = 7,691' - 7,701' (frac'd 9/3/03) Module 4 = 7,754' - 7,764' (frac'd 9/3/03) Module 3 = 7,921' - 7,931' (frac'd 9/3/03) Module 2 = 8,386' - 8,396' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) Well Name & Number: Kenai Beluga Unit 43-7x Lease: Kenai Gas Field, A-028083 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,898' - 8,480' (TVD): 5,747' - 7,305' Angle/Perfs: 20° -~ 7° Angle @ KOP and Depth: 2.5° 1100ft @ 250 ft Dated Completed: 6/16/2003 Ground Elevation: 87' Revised by: Kevin Skiba Last Revison Date: 6/3/2009 ~rmit #: 203-066 r Pad 41-7 ~I #: 50-133-20522-00-00 7 41' FSL, 4,088' FWL, oa. Des: A - 028083 3 elevation: 8T (21' AGL) ~~ Sec. 6, T4N, R11 W, S.M. ~ g , ~---~ ~~ ~ L~ ~,_"~-, }~ ~` ' ~ ~ 4 ~ l ~"~ ~ SARAH PAL/N, GOVERNOR x l.6 ~.~../` L~ t a t_ COI~TSERQATIOI~T COl-II~SS IpK Kyle Miranda Production Engineer Marathon Oil Company PO Box 1949 Kenai AK 996 1 1-1 949 't~:a'~6''~~~ ~jl~~~ .~ ~ ~~~~' 333 W. 7th AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 a-~%- Re: Kenai Gas Field, Upper Tyonek/Beluga Gas Pool, KBU 43-7x Sundry Number: 308-352 Dear Mr. Miranda: Enclosed is the approved Application for Sundry Approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. When providing notice for a representative of the Commission to witness any required test, contact the Commission's petroleum field inspector at (907) 659-3607 (pager). As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the Commission grants for good cause shown, a person affected by it may file with the Commission an application for rehearing. A request for rehearing is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. A person may not appeal a Commission decision to Superior Court unless rehearing has been requested. Sincerely, Daniel T. Seamount, Jr. Z ~ ~ Chair DATED this 3 day of October, 2008 Encl. • M Marathon MARATHON Oil Company September 29, 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 43-7x Dear Mr. Maunder: • Marathon Oil Company Alaska Asset Team P.O. Box 1949 Kenai, AK 99611 Telephone 907/283-1371 Fax 907/283-1350 Submitted for your approval is the10-403 Application of Sundry Approvals for KBU 43-7x well. Marathon proposes to enhance gas production by adding 135' of perforations across five Beluga formation intervals. Please contact me at (907) 283-1371 if you have any questions or need additional information. Sincerely, ~~ ~~ Kevin J. Skiba Engineering Technician Enclosures: 10-403 Application of Sundry Approvals cc: Houston Well File Well Schematic Kenai Well File Perforation Procedure KJS ylb~ STATE OF ALASKA f • ALF~ OIL AND GAS CONSERVATION COMMON ` APPLICATION FOR SUNDRY APPROVALS ~n aar. ~~ ~Rn /Pd~~ ~~ ~ ~ 0 1. Type of Request: Abandon^ Suspend ^ Operational shutdown^ Perforate^ ~ Waiver^ Other^ Alter casing ^ Repair well ^ Plug Perforations ^ Stimulate ^ Time Extension ^ Change approved program ^ PuII Tubing ^ Perforate New Pool ^ Re-enter Suspended Well ^ 2. Operator Name: Marathon Oil Company 4. Current Well Class: 5. Permit to Drill Number: Development ^ , Exploratory ^ 203-066' 3. Address: p0 Box 1949 Stratigraphic ^ Service ^ 6. API Number: Kenai Alaska, 99611-1949 50-133-20522-00-00. 7. If perforating, closest approach in pool(s) opened by this operation to nearest 8. Well Name and Number: property line where ownership or landownership changes: S ^ ^ Kenai Beluga Unit 43-7x - pacing Exception Required? Yes No 9. Property Designation: 10. KB Elevation (ft): 11. Field/Pool(s): ~ A - 028083- 87' (21' AGL) - Kenai Gas Field /Beluga 8~ Tyonek Pools 12. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD (ft): Effective Depth TVD (ft): Plugs (measured): Junk (measured): 8,610'. 7,434' ~ 8,556' - 7,380' - NA NA Casing Length Size MD TVD Burst Collapse Structural Conductor 117' 20" 138' 138' 3,060 psi 1,500 psi Surface 1,489' 13-3/8" 1,510' 1,469' 3,450 psi 1,950 psi Intermediate 6,442' 9-5/8" 6,463' 5,340' 6,870 psi 4,750 psi Production 8,568' 3-1/2" 8,589' 7,413' 10,160 psi 10,530 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6,898'-8,480' 5,747'-7,305' 3-1/2" L-80 8,589' Packers and SSSV Type: Packers and SSSV MD (ft): NA NA 13. Attachments: Description Summary of Proposal ^ 14. Well Class after proposed work: Detailed Operations Program Q BOP Sketch ^ Exploratory ^ Development^ • Service ^ 15. Estimated Date for 16. Well Status after proposed work: Commencing Operations: October 15, 2008 Oil ^ Gas Q , Plugged ^ Abandoned ^ 17. Verbal Approval Date: WAG ^ GINJ ^ WINJ ^ WDSPL ^ Commission Representative: 18. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Kevin Skiba (907) 283-1371 Printed Name Kyle Mir. nda ~, - Title Production Engineer Signature ~ e-~ e Phone `. ~ `1 ' "'~~ (907) 283-1370 Date September 29, 2008 ~ ~' ~ COMMISSION USE ONLY 35a- ~ ' Conditions of approval: Notify Commission so that a representative m ay witness Sundry Number: J Q Plug Integrity ^ BOP Test ^ Mechanical Integrity Test ^ Location Clearance ^ Other: Subsequent Form Required: ~~~ APPROVED BY ~~ J L/ Approved by: COMMISSIONER THE COMMISSION Date: Form 10-403 Revised 06/2006 Submit in Duplicate September 17, 2008 MARATHON Marat on Oil Corporation Field: Kenai Beluga Unit WBS: Not requested yet Pad: 41-7 KBU 43-7x Well Status: 3.275 MMcf/d @ 442 psi (SCADA 9-16-08) and 24 bwpd (TOW 9-16-08). Objective: Perforate five Beluga sands. Depths and surface pressure to fire guns: 6491' - 6515' (24' net, 14' & 10' tandem guns, single run) - 520 psi 6620' - 6640' (20' net, 20' guns, single run) - 530 psi 6676' - 6690' (14' net, 14' guns, single run) - 530 psi 6706' - 6747' (41' net, 20' & 20' guns, single run) - 590 psi 6770' - 6806' (36' net, 20' & 10' & 6' guns) - 600 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• 1. a) No well house currently on wellhead. 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 2.75" GR 6806' MD + minimum depth needed for CCL correlation. POOH GR. 2. a) RIH w/ 36' of guns (type shown above, 20' & 10' & 6' tandem guns, single run). b) Correlate Expro CBL/GR/CCL log depth to open-hole logs. c) SI well long enough to obtain 600 psi WHP (underbalanced at 40% DD). d) Pull up into position and shoot 6770' - 6806' (OH). Leave well shut in for 15 minutes while POOH. Observe and note pressure build rate over 15 minutes. Open well to flow while continuing to POOH. a) RIH w/ 41' of guns (type shown above), 20' & 20' guns, single run). b) Correlate Expro CBL/GR/CCL log depth to open-hole logs. c) SI well long enough to obtain 590 psi WHP (underbalanced at 40% DD). d) Pull up into position and shoot 6706' - 6747' (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. • 4. a) RIH w/ 14' of guns (type shown above, 14' guns, single run). b) Correlate Expro CBL/GR/CCL log depth to open-hole logs. c) SI well long enough to obtain 530 psi WHP (underbalanced at 40% DD). d) Pull up into position and shoot 6676' - 6690' (OH). Leave well shut in for 15 minutes while POOH. Observe and note pressure build rate over 15 minutes. Open well to flow while continuing to POOH. e) LD spent perf gun and lubricator. RD Expro. Return well to production. Flow test. 5. a) RU Expro b) RIH w/ 20' of guns (type shown above, 20' guns, single run). c) Correlate Expro CBL/GR/CCL log depth to open-hole logs. d) SI well long enough to obtain 530 psi WHP (underbalanced at 40% DD). e) Pull up into position and shoot 6620' - 6640' (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. 6. a) RIH w/ 24' of guns (type shown above, 14' & 10' tandem guns, single run). b) Correlate Expro CBL/GR/CCL log depth to open-hole logs. c) SI well long enough to obtain 520 psi WHP (underbalanced at 40% DD). d) Pull up into position and shoot 6491' - 6515' (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 8. Produce well to sales. CONTACTS Ken Walsh: 907-283-1311 (w) Jennifer Enos: 713-296-3319 (w) 907-394-3060 (c) 713- 408-3583 (c) Lyndon Ibele: 907-565-3042 (w) Clyde Scott: 713-296-2336 (w) 907-748-2819 (c) KGF Operators: 907-283-1305 Perf MD Perf TVD Formation 40% dd Surface Pressure at to Bottom Bottom Pressure" Formation pressure fire guns (WAM calc) temp 6515 5388 965 579 516 133 6640 5503 988 593 527 129 6690 5549 996 598 530 125 6747 5603 1115 669 592 121 6806 5659 1126 676 596 109 *Pressures are a rough estimate. Be conservative on firing pressure. KBU 43-7x Add perfs - MD Dammeyer 9/29/2008 2:55:19 PM • KBU 43-7x tude: 60° 27' 34.67" itude: -151° 14' 47.43" 274,996.71 2,362,053.16 d: 5/22/2003 Tree cxn = 4-3/4" Otis KOP: 250' Build: 2.5 deg per 100' Hold Angie: 43 deg at 2,300' DOP: 5.350' Drop: 2.0 deg per 100' Final Angle: 8 deg at 7,450' M~w-rnoN Conductor 20" K-55 133 ppf Top Bottom MD 0' 138' TVD 0' 138' Surface Casino 13-3/8" K-55 68 ppf BTC Top Bottom MD 0' 1,510' TVD 0' 1,469' Cmt w/ 759 sks of Class G to surface Intermediate Casing 9-5/8" L-80 40 ppf BTC Top Bottom MD 0' 6,463' TVD 0' 5,340' Cmt wl 647 sks of Class G Production Casing 3-1/2" L-80 9.3 ppf EUE 8rd Top Bottom MD 0' 8,589' TVD 0' 7,413' Cmt w/ 970 sks of Class G Excage Svstem Details - 17 Excape modules run - Both control lines open for methanol injection (9/3/03) - Ceramic flapp ers removed with coil (9/3/03) Perfs: Module 17 = 6,898' - 6,908' (frac'd 9/3/03) Module 16 = 6,939' - 6,949' (frac'd 9/3/03) Module 15 = 6,978' - 6,988' (frac'd 9/3/03) Module 14 = 7,053' - 7,063' (frac'd 9/3/03) Module 13 = 7,094' - 7,104' (frac'd 9/3/03) Module 12 = 7,141' - 7,151' (frac'd 9/3/03) Module 11 = 7,194' - 7,204' (frac'd 9/3/03) Module 10 = 7,234' - 7,244' (frac'd 9/3/03) Module 9 = 7,433' - 7,443' (perfd 9/3/03) Module 8 = 7,472' - 7,482' (frac'd 9/3/03) Module 7 = 7,541' - 7,551' (frac'd 9/3/03) Module 6 = 7,590' - 7,600' (perfd 9/3/03) Module 5 = 7,691' - 7,701' (frac'd 9/3/03) Module 4 = 7,754' - 7,764' (frac'd 9/3/03) Module 3 = 7,921' - 7,931' (frac'd 9/3/03) Module 2 = 8,386' - 8,396' (frac'd 9/3/03) Module 1 = 8,470' - 8,480' (frac'd 9/3/03) Well Name & Number: Kenai Beluga Unit 43-7x Lease: Kenai Gas Field, Pad 41-7 County or Parish: Kenai Peninsula Borough State: Alaska Country: USA Perforations (MD): 6,898' - 8,480' (TVD): 5,747' - 7,305' Angle/Perfs: Angle @ KOP and Depth: Dated Completed: 6/16/2003 Ground Elevation: 87' Revised by: Kevin Skiba Last Revison Date: 9/29/2008 ~: 2o3-oss Pad 41-7 50-133-20522-00-00 41' FSL, 4 088' FWL, es: A - 028083 ation: 87' (21' AGL) Sec. 6, T4N, R11 W, S.M. U‘ •Operations Summary Report by J• ti‘ Marathon Oil Well Name: KENAI BELUGA UNIT 43 -7X .i •� 20-O(Q� r Qtr /Qtr, Block, Sec, Town, Range Field Name License # State /Province Country 6006004N011 W01 KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.12 26.52 6.40 5/22/2003 6/15/2003 Daily Operations Report Date: 7/18/2003 Job Category: COMPLETION 24 Hr Summary Pull BPV. Ops Trouble - Start Time End Time Dur (hr) Ops Code Activity Code Status Code - Com - - 08:00 10:00 2.00 RURD EQIP AF Pull back pressure valve. Report Date: 7/19/2003 Job Category: COMPLETION 24 Hr Summary Jetted completion fluid from well and left 1800 psi N2 cap. Recovered 103 bbl 6% KCI to flowback tank. Ops Trouble Start Time -End Time Dur (hr) Ops Code Activity Code Status Code -Com 07:00 12:00 5.00 RURD COIL AF Finish RU CT on KBU 43 -7x. RU MOC flowback choke and iron. Pressure test lines to 5000psi. Shell test BOPs to 250 /3000psi via kill line (function test completed in BJ shop). Isolate valves, test no good. Pump up pressure via CT. Test good. Bleed off pressure and blowldown fluid to tank. 12:00 14:00 2.00 TRIP BHA AF Open well and RIH w/o pumping taking displacement returns to open top tank. 14:00 14:20 0.33 PUMP N2 AF Tag at 8490' CTM with 45 bbl recovered. Begin pumping N2 ant minimum rate, then come up to 2000 scfm taking returns to tank. 14:20 14:45 0.42 PUMP N2 AF Begin pinching in flowback choke per choke schedule while pumping N2 on bottom (objective is to have final surface pressure at 1800 psi to limit pert drawdown). 14:45 16:40 1.92 TRIP BHA AF POOH w/ 2500 psi on well. 103 bbl completion fluid recovered to flowback tank. 16:40 19:00 2.33 RURD COIL AF At surface with 1850psi on well. Close valves and bleed off CT. RD unit and stack aside for night. Report Date: 7/25/2003 Job Category: COMPLETION 24 Hr Summary Move in frac tanks. Test manifold. Build dyke around frac tanks. Ops Trouble Start Time. End Time Dor(ttr),, r- Ops Code ActiwityCode . Status. Code Com 07:00 19:00 12.00 RURD EQIP AF MIRU seventeen 500 -bbl Rain - for -Rent frac tanks. RU manifold on frac tanks and hydro test to 10 psig. MI flowback tank, water tank, slop tank, and PTS tandem seperator. Finish building dyke around frac tanks and other tanks. Report Date: 9/2/2003 Job Category: COMPLETION 24 Hr Summary RU coil tubing, frac iron, and flowback iron. Pressure test. Load tanks with diesel. Held safety meeting. 'D os: -= °.Trouble Start Time. _ End Time Dur (hr) Ops Code Activity Code . Status Code Com- . -_ 07:00 17:00 10.00 PUMP FRAC AF MIRU BJ fracturing iron and 1.75 "" coil tubing on KBU 43 -7x. RU flowback iron. Load seventeen frac tanks with 8000 bbl of Williams #2 diesel. Load three Sand Kings with proppant. Pressure test frac lines to 8000 psi. Test flowback iron to 4000/1200/250 psi. Test coil BOPE to 250/5000 psi. Conduct pre -job safety and operations discussion. Perforate module #1, 8470' - 8480'. SITP increased from 1770 to 1810 psi in 15 minutes, then appeared to stabilize. Report Date: 9/3/2003 Job Category: COMPLETION 24 Hr Summary Pert and frac stimulate Excape modules 1 - 17 using a total of 598,300 lbs of proppant. Use coil tubing to break all flapper assemblies. Unable to flow well due to plugging in flowback iron. :.- -__ -,- - .- . a . - .Ops Trouble.•- ._ -. _ _ _ .. .. - _ Start Time . EndTime , Dur (hr). - Ops-Code Activity Code , ;- .Status . -_ Code - _ Com , 06:00 07:00 1.00 SAFETY SMTG AF Held prejob safety and operations meeting. 07:00 07:45 0.75 PUMP FRAC AF Prime up pumps and prepare to frac. 07:45 09:00 1.25 PUMP FRAC AF Loaded the hole then pump 14 bbl straight diesel into Module #1 perfs at 8470'- 8480'. Final rate = 10 bpm at 5750 psi. BH -ISIP = 6805 psi (0.93 psi /ft). Step -rate analysis shows low pert friction. Minifrac data perhaps shows closure at G =2.0. Begin fracture stimulation with gelled fluid. Frac stimulate at 15 bpm, 5600 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Placed 44,400 lbs of 16/30 Ottawa Sand (99% of design). ISIP = 4565 psi. Load to recover = 436 bbl. St,ANNED JUN 2 1 2012 www.peloton.com Page 1/3 Report Printed: 8/3/2011 •Dperations Summary Report by J• Marathon Oil Well Name: KENAI BELUGA UNIT 43 -7X Qtr /Qtr, Block, Sec, Town, Range Field Name I License # State/Province Country 6006004N011W01 KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) I KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.12 26.521 6.40 5/22/2003 6/15/2003 Ops Trouble Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 09:00 09:30 0.50 PUMP FRAC AF Perforate Module #2, 8386'- 8396'. Frac stimulate at 15 bpm, 4900 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Placed 42,400 Ibs of 16/30 Ottawa Sand (94% of design). ISIP = 3529 psi. Load to recover = 385 bbl. 09:30 10:15 0.75 PUMP FRAC AF Perforate Module #3, 7921'- 7931'. Frac stimulate at 15 bpm, 4275 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Placed 78,900 Ibs of 16/30 Ottawa Sand (131% of design). ISIP = 3000 psi. Load to recover = 459 bbl. 10:15 10:45 0.50 PUMP FRAC AF Perforate Module #4, 7754'- 7764'. Frac stimulate at 15 bpm, 4250 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Placed 42,200 Ibs of 16/30 Ottawa Sand (93% of design). ISIP = 2780 psi. Load to recover = 308 bbl. 10:45 11:30 0.75 PUMP FRAC AF Perforate Module #5, 7691'- 7701'. Frac stimulate at 15 bpm, 4150 psi, staging proppant from 2 - 7 ppg in 4/4 Super Rheogel. Placed 56,000 Ibs of 16/30 Ottawa Sand (110% of design). ISIP = 2810 psi. Load to recover = 350 bbl. 11:30 11:45 0.25 PUMP FRAC AF Attempt to perforate Module #6, 7590'- 7600'. Unable to detect perforating event with any certainty. Since frac modeling showed that fracs in modules 6 & 7 would grow together and the plan was to only frac one of these intervals, decided to bypass fracturing module #6 in favor of module #7. 11:45 12:30 0.75 PUMP FRAC AF Perforate Module #7, 7541'- 7551'. Frac stimulate at 15 bpm, 4200 psi, staging proppant from 2 - 8 ppg in 4/4 Super Rheogel. Placed 65,600 Ibs of 16/30 Ottawa Sand (95% of design). ISIP = 2940 psi. Load to recover = 369 bbl. 12:30 13:15 0.75 PUMP FRAC AF Perforate Module #8, 7472'- 7482'. Frac stimulate at 10 bpm, 4050 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Placed 54,900 Ibs of 16/30 Ottawa Sand (97% of design) with 12.5% 12/20 Flexsand MSE. ISIP = 2930 psi. Load to recover = 350 bbl. 13:15 13:30 0.25 PUMP FRAC AF Perforate Module #9, 7433'- 7443'. As per design, did not frac stimulate this interval. Broke down perfs by pumping diesel. Load to recover = 4 bbl. 13:30 14:00 0.50 PUMP FRAC AF Switch to second Excape control line to fire remaining modules. Attempt to install pressure transducer on the original control line but unable to get it functioning. 14:00 14:30 0.50 PUMP FRAC AF Perforate Module #10, 7234'- 7244'. Frac stimulate at 10 bpm, 3400 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Placed 19,700 Ibs of 16/30 Ottawa Sand (93% of design) with 12.5% 12/20 Flexsand MSE. ISIP = 2426 psi. Load to recover = 202 bbl. 14:30 15:00 0.50 PUMP FRAC AF Perforate Module #11, 7194'- 7204'. Frac stimulate at 15.5 bpm, 3750 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Placed 29,300 lbs of 16/30 Ottawa Sand (98% of design) with 12.5% 12/20 Flexsand MSE. ISIP = 2940 psi. Load to recover = 230 bbl. 15:00 15:30 0.50 PUMP FRAC AF Perforate Module #12, 7141'- 7151'. Frac stimulate at 15 bpm, 3700 psi, staging proppant from 2 - 7 ppg in 4/4 Super Rheogel. Placed 43,400 Ibs of 16/30 Ottawa Sand (97% of design) with 12.5% 12/20 Flexsand MSE. ISIP = 2550 psi. Load to recover = 276 bbl. 15:30 16:15 0.75 PUMP FRAC AF Perforate Module #13, 7094'- 7104'. Frac stimulate at 10.5 bpm, 3700 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Placed 27,000 lbs of 16/30 Ottawa Sand (96% of design) with 12.5% 12/20 Flexsand MSE. ISIP = 2520 psi. Load to recover = 219 bbl. 16:15 16:45 0.50 PUMP FRAC AF Perforate Module #14, 7053'- 7063'. Frac stimulate at 15 bpm, 4000 psi, staging proppant from 2 - 8 ppg in 4/4 Super Rheogel. Placed 31,500 Ibs of 16/30 Ottawa Sand (96% of design). ISIP = 2179 psi. Load to recover = 204 bbl with 12.5% 12/20 Flexsand MSE. 16:45 17:15 0.50 PUMP FRAC AF Able to get pressure transducer working on original control line to serve as a deadstring gauge. Perforate Module #15, 6978' -6988' and Module #16, 6939'- 6949'. Frac stimulate simultaneously as per design at 15 bpm, 3500 psi, staging proppant from 2 - 6 ppg in 4/4 Super Rheogel. Cut rate to 10 bpm during the 6 ppg stage due to continual decrease in treating pressure observed via the deadstring. Placed 42,000 Ibs of 16/30 Ottawa Sand (91% of design) with 12.5% 12/20 Flexsand MSE. Forced to cut job slightly short in order to leave some proppant available for the final stage. ISIP = 2155 psi. Load to recover = 291 bbl. www.peloton.com Page 2/3 Report Printed: 8/3/2011 •Operations Summary Report by J• Marathon Oil Well Name: KENAI BELUGA UNIT 43 -7X Qtr/Qtr, Block, Sec, Town, Range Field Name License # State /Province Country 6006004N011W01 KENAI ALASKA USA Casing Flange Elevation (m) Ground Elevation (m) KB- Casing Flange Distance (m) I KB- Ground Distance (m) Spud Date Rig Release Date 0.00 20.121 26.521 6.40 5/22/2003 6/15/2003 Ops Trouble - Start Time End Time Dur (hr) Ops Code Activity Code Status Code Com 17:15 17:30 0.25 PUMP FRAC AF Perforate Module #17, 6898'- 6908'. Frac stimulate at 15 bpm, 3400 psi. Decided to aggressively ramp proppant from 2 - 6 ppg since we are short of proppant to finish the original design. Continued to use 4/4 Super Rheogel. Perfs took the aggreesive ramp without any difficulty. Placed 21,000 Ibs of 16/30 Ottawa Sand (45% of design) with 12.5% 12/20 Flexsand MSE. Flushed with straight diesel. ISIP = 2300 psi. Load to recover = 179 bbl. 17:30 21:15 3.75 RURD COIL AF RD fracturing equipment. Total load to recover (all stages) = 4,262 bbl. RU 1.75 "" coil tubing equipped with chisel nose wash tool. Conduct prejob safety meeting. Body test lubricator 250/5000 psi. 21:15 05:00 7.75 JET AF SITP = 1080 psi. RIH circulating nitrogen at 500 scfm while holding surface pressure constant. Tag and break Excape flappers for modules 17, 15, 14, 13, 12, 11, 10, 9, 7, and 2. Possibly broke flappers for modules 8 and 6, although the indication was slight. Did not see any indication of flappers at modules 5, 4, and 3. (Note: Modules 16 and 1 do not have flappers.) Tag bottom at 8508'. PU 30' and jet dry. Attempt to POOH, but coil is stuck. Circulate KCI water at 2.5 bpm to try to free stuck coil. Gas buster cut out due to solids. Shut down, rerouted returns line to returns tank. Resumed pumping KCI water, but unable to get returns. Pump nitrogen at 500 scfm while continuing to pump KCI water at 1.5 bpm, but still no returns. Pull coil up to 38,000 lbs and come free. POOH. After getting above perfs, SD KCI water and continue to jet well in while POOH. Stand back coil. SITP = 1000 psi. 05:00 06:00 1.00 FLOW TEST AF Attempt to flow well, but dump line on sand buster is plugged. Standby. Report Date: 9/4/2003 Job Category: COMPLETION 24 Hr Summary Produce well to sales at 3.7 mmcfd. Ops Trouble - - . Start Time , End Time Dur (hr) Ops Code Activity Code Status Code . Com 06:00 14:00 8.00 FLOW TEST AF Clear plugged dump line on sand buster. Prepare to flow well. SITP gradually dropping throughout the day, from 1000 psi down to 750 psi just prior to opening the well. 14:00 06:00 16.00 FLOW TEST AF Line well up to atmospheric tank to bleed off remaining nitrogen trapped in wellbore. Flow well to atmospheric tank. Pressure stabilized at 450 psi, and well began unloading fluid. Switched well to low pressure gathering system. Well gaining in strength. At report time, well producing 3.7 mmcfd to sales, with 1400 psi FTP and making 180 bfpd on a 20/64 "" positive choke. See PTS report for details. Report Date: 9/11/2003 Job Category: COMPLETION 24 Hr Summary Flow well at 3.9 mmcfd. Opened choke, increase flow to 4.7 mmcfd. Cps Trouble . ,start Time : End Time -. Our (hr) -- : -. Ops Code Activity Code . - Status . " . . Code - . - , Com • . • 06:00 21:00 15.00 FLOW TEST AF Produce well to HP system. Flowing at 3.9 mmcfd, 20 bwpd, 1540 psi FTP on a 20/64 "" choke. Making some slight sand and fighting freezing problems. 21:00 06:00 9.00 FLOW TEST AF Open choke up to a 21/64 " ". Flow increased to 4.7 mmcfd, 30 bwpd, 1500 psi FTP. About an hour after opening the choke the well coughed up a slug of sand that plugged off the dump on the sand buster. Cleared that out, and subsequently the well continued to make some sand but having no trouble handling it. Fluid sample shows approximately 10% diesel. Report Date: 9/12/2003 Job Category: COMPLETION 24 Hr Summary Continue to flow well. Ops' Trouble StartTirne. - End Time Dur(hr) Ops Code - -, Activity Code Status . Code • Com , . 06:00 08:00 2.00 FLOW TEST AF Continue to flow well through PTS iron to sales at 4.7 mmcfd. 08:00 06:00 22.00 FLOW TEST AF Switch well out of PTS iron to flow directly to MOC iron. RD and release PTS flowback equipment. www.peloton.com Page 3/3 Report Printed: 8/3/2011 li • Casing & Cement • Marathon oil Well Name: KENAI BELUGA UNIT 43 -7X For String: SURFACE CASING Casing Detail: Casing Description Prop Run? Run Date Set Depth (mKB) Set Tension (tonnef) Wellbore Centralizers Scratchers SURFACE CASING No 5/25/2003 00:00 460.25 0.0 KENAI BELUGA UNIT 43 -7X Comment There are some inconsistencies on casing information. The Excel spreadsheet for this casing run indicates that the pipe was set at 1509.4T with the same length of pipe. This would make the reference point to cut -off 20.4T. , DFW String Key = ANQ6D Casing Components Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING JOINT(S) Casing 339.7 315.3 101.195 K -55 BTC 5.19 6.40 11.59 ThreadLock Y /N: Y (black) Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 36 CASING JOINT(S) Casing 339.7 315.3 101.195 K -55 BTC 435.32 11.59 446.91 (black) Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING FLOAT Casing 339.7 BTC 0.59 446.91 447.50 ThreadLock YIN: Y COLLAR (black) Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING JOINT(S) Casing 339.7 315.3 101.195 K -55 BTC 12.23 447.50 459.73 ThreadLock Y /N: Y (black) Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING FLOAT Casing 339.7 BTC 0.52 459.73 460.25 ThreadLock Y /N: Y SHOE shoe Cementing Job Details: • , . , _ . Cementing Start Date Cementing End Date Cementing Company 5/26/2003 00:00 ` ! B.J. SERVICES Comment Job done with 4" DP inner sting. Coil tubing unit indicator: N Tool company: Shoe and collar Wait on cement (hrs): 8 'Type Description T 'String Welibore p y SURFACE CASING !Casing SURFACE CASING, 460.25mKB KENAI BELUGA UNIT 43 -7X Cement Stage #1 Description: . Float Failed? Plug Failed? Full Retum? Pipe Reciprocated? Pipe Rotated? Pressure Held (kPa) No ! Yes Yes No ! No Stage Number Top Depth (mKB) Bottom Depth (mKB) Cement Volume Retum (m') 1 6.40 460.55 4.77 Top Plug? Bottom Plug? Initial Pump Rate (m'/min) Final Pump Rate (m' /mm) Pump Start Time Pump End Time No ! No ( 1.216 ! Avg Pump Rate (m' /min) Drill Out Dia (mm) Plug Bump Pressure (kPa) Pressure Release Date 1.113! ! Final Pump Pressure (kPa) 0.0) Comment Annular flow after cement job (Y /N): N Hours circulated between stages: 1 Pressure before cementing: 500 Excess volume measured from: returns Retums: Full Time cementing mixing started: 15:00 Cement Fluids " . LEAD Class !Density (kg /m') !Yield (m'ttonne) !Volume Pumped (m') 1,437.9 1.548 53.26 Comment , Displacement fluid used: MUD Time displacement started: : Wait on Cement Time: 8 Compressive strength temp #2: 85 Pressure slurry density was measured at: 0 Temperature used in fluid loss test: 80 Free water test temperature: 80 Total water used: 165 Fluid Type Amount (1000kg) Mix H2O Ratio (m'ttonne) Percent Excess Pumped ( %) LEAD 29.3 0.901 50.0 Cement Fluid Additives Add Amount - Amount Units - Conc Unit CiSflc Type CD -32 0.3 % BWOC FP-6L 1.0 GPHS LW-6 20.0 % BWOC www.peloton.com Page 1/2 Report Printed: 8/3/2011 • • ljj''1 g, • Casing & Cement • Marathon Oil Well Name: KENAI BELUGA UNIT 43 -7X For String: SURFACE CASING Cement Fluid Additives Add Amount Amount Units Conc Unit Conc Type MPA 20.0 % BWOC SMS 1.0 % BWOC Wellheads Install Date Type Job Removed Date Comment www.peloton.com Page 2/2 Report Printed: 8/3/2011 11.0Z/£/8 :pa ;u!Jd podaa Z/1. °Bed wo3•uo;oIed•mmm Iqq /sqi 0'0Z 1V/3S 10)1 Iqq /sql 0' l 3>1d1d 01133 Iqq /sql 8'0£ 311NO1N38 Iqq /sql O'Z6 31121V8 ad4l ouo3, - gun moo shun )unowy ,unowy PPV senl3!Ppy P!nld;uawa3 0'9£ I 2133VdS Q31HOI3M (%) padwnd ssaox3 luawed (auuoihw) ogee ON MN (610001) lunowv adkl P!nld 0 : ;sal ssoi p!ng u! pasn am;eJadwal 0 :le painseaw sem Al!suap A.IJn!s ainssald Z1 :aw!l ;uawa3 uo Hem : :papels;uawaoe!ds!p am' dew :pasn p!ng;uawa3e!ds10 ,uawwo3 LL'4 I£'861' 1 V/N (.w) pedwnd awnlon I (auuop,w) way, Weft H!suaa sse!3 2133VdS Q31HDI3M sp!nI3 r1. aura3 L0:00 :Palle ;s 6u!x!w 6u! ;uawao 0w41 wn;ai pnw !!nd :suln;aa pa;e!n3!e3 :wall painseaw awnlon ssa3x3 491 :Bu! ;uawa3 aio ;aq ainssaid Z :sa6e ;s uaam;aq pa;e!nai!o sJnoH N :(N /A) gof;uawa3 moil .le!nuuy ,uawwo3 IL'Z99'6 (8'468'9 I IZLZ' 1. ales asea!ee ainssaJd (edit) aJnssaid dwn8 Mild (ed>I) ainssaid dwnd lewd (ww) en in011u0 (u!w /.w) awe dwnd 6AV I 069'1 I saA I saA awe, dwnd awe, dwnd (u!w /cw) awe dwnd !eu!d (u!w/,w) awe dwnd lee!ul i6nld woo 4 dol £Z'OL6' 1 L6'9L6 1 (,w) wnlae awnlon,uawa3 (sew) U1deo wopo8 (Flew) y,daa dol Jagwne a6e1S ON I ON SG), ON I ON (edit) PIaH amssaid iPeleloe ed!d ipaleoadpee ad!d iwniae find iPa!!ed 6n1d LPe!!ed Mold :uo d!i3sea 1 #e6elS luewe3 8Nw40'0L6' 1 XL JJNfl Hon IVN3)1 '9NISVf3 31VI43W2i31N1 6u!se3 ONISV3 31V1a3I I31N1 aioq!!eM BuuiS adAi uogduosaa Z; :(sNU) ;uawa3 uo ;!eM leo!d piepue;S 318 :duedwoa poi N :J01e0ipu! l!un 6u!gn; 03 N :(N /A) loo; eau!! uo punol ;uawa3 A :(N /A) Je!!o3 pue Mog3 uaaM;as uo punod ,uawa3 N :(N /A) pa66o! 1H8 )uewwoo S33IA I3S T'8I I 00:00 £003/9/9 �(uedwoo Buguawe3 alea pu3 Buluawa3 ma Psis 6u!luewe3 :sl!elea qop 6u! ;uawa3 a0gs 3OHS aoUS 1eo!d 40'016' 1 1.9'696' I. 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Casing & Cement • Marathon Oil Well Name: KENAI BELUGA UNIT 43 -7X 2o For String: PRODUCTION CASING #1 Casing Detail: Y Casing Description Prop Run? Run Date Set Depth (mKB) Set Tension (tonnef) Wellbore Centralizers Scratchers PRODUCTION CASING #1 No 6/14/2003 00:00 2,617.89 0.0 KENAI BELUGA UNIT 43 -7X Comment Joints 1 - 246 have 5.25 "" OD slotted couplings. Remaining couplings are standard, non - slotted couplings. The top six full joints (non - slotted couplings) have 6.25 "" OD protectors for the control lines, secured with set screws. Banded control lines and protective cable with 920 stainless steel bands. Control lines are 1/4 "" OD, 0.049 "" wall, SS, welded. Protective cable is 7/16 "" OD. DFW String Key = BBTEG Casing Components Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 2 Cut off Joint Casing 88.9 13.840 L -80 EUE 9.55 1.38 10.93 (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 9.44 10.93 20.37 (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 PUP JOINT Casing 88.9 13.840 L -80 EUE 2.44 20.37 22.81 (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 22 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 2,076.29 22.81 2,099.10 1 (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.74 2,099.10 2,110.84 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 0.69 2,110.84 2,111.53 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 9.62 2,111.53 2,121.15 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 2.37 2,121.15 2,123.52 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.88 2,123.52 2,135.40 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 2 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 1.67 2,135.40 2,137.07 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg/m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 9.10 2,137.07 2,146.17 (black) 8rdMod Jts ' Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.85 2,146.17 2,158.02 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 0.69 2,158.02 2,158.71 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.79 2,158.71 2,170.50 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg/m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 2.46 2,170.50 2,172.96 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.79 2,172.96 2,184.75 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 2 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 4.35 2,184.75 2,189.09 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.84 2,189.09 2,200.93 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 1.00 2,200.93 2,201.93 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.83 2,201.93 2,213.76 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 1.23 2,213.76 2,214.99 ASSEMBLY (black) 8rdMod www.peloton.com Page 1/3 Report Printed: 8/3/2011 flik1. l • Casing & Cement • Marathon oil Well Name: KENAI BELUGA UNIT 43 -7X For String: PRODUCTION CASING #1 Casing Components Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 5 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 47.00 2,214.99 2,261.99 (black) 8rdMod Jts Item Descnption Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 2 EXCAPE Casing 88.9 13.840 EUE 23.61 2,261.99 2,285.61 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 9.41 2,285.61 2,295.02 (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.89 2,295.02 2,306.91 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 3.03 2,306.91 2,309.94 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.80 2,309.94 2,321.74 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 2 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 18.86 2,321.74 2,340.60 (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.88 2,340.60 2,352.48 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 3 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 7.36 2,352.48 2,359.84 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.83 2,359.84 2,371.66 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 1.26 2,371.66 2,372.92 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 4 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 37.72 2,372.92 2,410.64 (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.89 2,410.64 2,422.53 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 3 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 7.97 2,422.53 2,430.50 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 13 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 121.94 2,430.50 2,552.44 (black) 8rdMod Jts Item Descnption Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 11.89 2,552.44 2,564.33 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 2 EXCAPE PUP Casing 88.9 13.840 L -80 EUE 4.92 2,564.33 2,569.24 ASSEMBLY (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 9.43 2,569.24 2,578.68 (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 EXCAPE Casing 88.9 13.840 EUE 10.74 2,578.68 2,589.42 MODULES (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 2 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 18.52 2,589.42 2,607.94 (black) 8rdMod Jts Item Description Icon OD (mm) ' ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING FLOAT Casing 88.9 13.840 EUE 0.35 2,607.94 2,608.28 ThreadLock Y /N: Y COLLAR (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING JOINT(S) Casing 88.9 13.840 L -80 EUE 9.30 2,608.28 2,617.58 ThreadLock Y /N: Y (black) 8rdMod Jts Item Description Icon OD (mm) ID (mm) Wt (kg /m) Grade Top Thread Length (m) Top (mKB) Btm (mKB) Comment 1 CASING FLOAT Casing 88.9 13.840 EUE 0.31 2,617.58 2,617.89 ThreadLock Y /N: Y SHOE shoe 8rdMod www.peloton.com Page 2/3 Report Printed: 8/3/2011 • MAW Casing & Cement • Marathon Oil Well Name: KENAI BELUGA UNIT 43 -7X For String: PRODUCTION CASING #1 Cementing Job Details: Cementing Start Date Cementing End Date Cementing Company 6/14/2003 00:00 B.J. SERVICES Comment Coil tubing unit indicator: N Tool company: Weatherford Gemoco Wait on cement (hrs): 8 Descnption Type Stnng Wellbore PRODUCTION CASING #1 Casing PRODUCTION CASING #1, KENAI BELUGA UNIT 43 -7X 2,617.89mKB Cement Stage #1 Description: Float Failed? Plug Failed? Full Return? Pipe Reciprocated? Pipe Rotated? Pressure Held (kPa) No No Yes Yes No Stage Number Top Depth (mKB) Bottom Depth (mKB) Cement Volume Return (m') 1 0.00 0.00 Top Plug? Bottom Plug? Initial Pump Rate (m' /min) Final Pump Rate (m' /min) 'Pump Start Time Pump End Time Yes No 0.954 Avg Pump Rate (m' /mm) Drill Out Dia (mm) Final Pump Pressure (kPa) Plug Bump Pressure (kPa) Pressure Release Date 0.715 11,031.6 14,479.0 Comment PIPE MOVEMENT NOTES: Drag down 65000 Drag up 100000 Pipe movement: RECIPROCATING Time stopped reciprocating: 16:30 Time started reciprocating: 15:50 Annular flow after cement job (Y /N): N Hours circulated between stages: 1.05 Pressure before cementing: 1300 Excess volume measured from: Caliper Log Returns: Full - Cement Fluids WEIGHTED SPACER Class 'Density (kg /m') Yield (m'ttonne) 'Volume Pumped (m') 1,258.2 7.95 Comment Time displacement started: : Wait on Cement Time: 8 Pressure slurry density was measured at: 0 Temperature used in fluid loss test: 0 Fluid Type 'Amount (1000kg) 'Mix H2O Ratio (m'/tonne) 'Percent Excess Pumped ( %) WEIGHTED SPACER 35.0 Cement Fluid Additives 'Add' : :''Amount _ : Amount,Units _ ConaUnit Conc : -- Type - TAIL 11 Class Yield (m'ttonne) Volume Pumped (m') CLASS G !Density (kg /m') 1,893.31 0.7181 31.48 Comment Compressive strength temp #2: 120 Pressure slurry density was measured at: 0 Temperature used in fluid loss test: 120 Free water test temperature: 120 Total water used: 113.6 Fluid loss test pressure: 1000 Fluid Type Mix H2O Ratio (monne) Percent Excess Pumped ( %) TAIL 'Amount (1000kg) 44.0 'tt 0.411 35.0 Cement Fluid Additives Add Amount Amount Units 'Conc Unit Conc Type _ FP -6L 0.01 gal /sack Defoamer BA -56 1.2 % BWOC Gas Migration Wellheads Install Date 'Type Job Removed Date 'Comment www.peloton.com Page 3/3 Report Printed: 8/3/2011 • • v_-~` -.. MICROFILMED 03/01/2008 DO NOT PLACE ~_. _~ _ :T. _:.; ANY NEW MATERIAL UNDER THIS PAGE F: ~LaserFiche\CvrPgs_Inserts~Microfilm_Marker. doc )'òcr DATA SUBMITTAL COMPLIANCE REPORT 12/5/2005 Permit to Drill 2030660 Well Name/No. KENAI BELUGA UNIT 43-07X Operator MARATHON OIL CO ;"wL K~~~..) API No. 50-133-20522-00-00 MD 8610/ TVD 7434""" Completion Date 9/5/2003 /" Completion Status 1-GAS Current Status 1-GAS UIC N - - - ---. ------- ---------- REQUIRED INFORMATION Mud Log No Samples No Direction~:survey ~ ~ -- -------.----- DATA INFORMATION Types Electric or Other Logs Run: PEX-CMR-GR-NEU Well Log Information: Log/ Electr Data Digital Dataset Type Med/Frmt Number Name (data taken from Logs Portion of Master Well Data Maint Name Interval Start Stop Log Log Run Interval OH/ -~- Scale Media No Start Stop CH Received Comments 2 6453 8550 Open 10/10/2003 AIT/PEXlCMR - Process CMR - DLlS & LAS files also on disk. 2 6453 8550 Open 1 0/1 0/2003 AIT/PEXlCMR - Process CMR - DLlS & LAS files also on disk. ""., 2 6453 8550 Open 1 0/1 0/2003 AIT/PEXlCMR - Process CMR - DLlS & LAS files also on disk. ~ 2 6453 8550 Open 10/10/2003 AIT/PEXlCMR - Process CMR - DLlS & LAS files also on disk. ---- 2 6453 8550 Open 10/1 0/2003 AIT/PEXlCMR - Process CMR - DLlS & LAS files also on disk. - - Sample Set Sent Received Number Comments --- ~---.~- :~ C Pds 12158 Magnetic Resonance "ÉD C Pds 12158 Neutron .ÉD C Pds 12158 I nd uction/Resistivity / ED C Pds 12158 Caliper log ./ ED C Pds 12158 Density - - --------- Well Cores/Samples Information: ADDITIONAL INFORMATION Well Cored? Y Ð Chips Received? .~ Daily History Received? @N {Y/N Formation Tops Analysis Received? ~ Permit to Drill 2030660 MD 8610 TVD 7434 Comments: - -- -- --- -.----- ---------- Compliance Reviewed By: _ DATA SUBMITTAL COMPLIANCE REPORT 12/5/2005 Well Name/No. KENAI BELUGA UNIT 43-07X Operator MARATHON OIL CO Completion Date 9/5/2003 Completion Status 1-GAS Current Status 1-GAS ~ Date: API No. 50-133-20522-00-00 UIC N )--¡)tt.A- ~ r- ~~ --.....-' ) ') MEMO TO EACH WELL FILE LISTED BELOW Date January 7, 2004 Two· previously undefined intervals, the DI sand of the Tyonek Formation and the Beluga Formation in the Kenai Unit of the Kenai Gas Field, have been combined into a single defined pool the Kenai, Beluga/Tyonek Gas Pool, field & pool code number , 448571. This change was effective in January 2004. Production from these two intervals had previously been reported to production codes 448569 Kenai, Beluga Undefined Gas and 448570 Kenai, Tyonek Gas. These codes have been deleted from some of the wells listed below. The wells listed below have had their production records modified reflecting this change. 184-109 KBU 23X-06 200-023 KTU 32-07 181-153 KBU 31-07 168-049 KDU2 195-055 KBU 31-07RD 184-108 KTU 13-05 174-050 KU 14-06RD 199-024 KBU 33-06 178-055 KDU5 195-054 KTU 43-06XRD 1 77-029 KBU 13-08 203-066 KBU 43-07X 185-181 KBU 33-07 199-073 KTU 24-06H 202-043 KTU 32-07H 195-054 KBU 43-06XRD 179-029 KBU 41-07 169-012 KDU4 184-108 KTU 13-05 179-030 KBU 43-06X 199-024 KBU 33-06 199-025 KBU 42-07 200-188 KBU 24-06 202-025 KBU 41-07X 200-179 KBU 44-06 ) Alaska f )ess Unit l~C)3--0 W (PI Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 October 6, 2003 Alaska Oil & Gas Conservation Commission Attn: Howard Oakland 333 W. ih Avenue, Suite 100 Anchorage, AK 99501 VIA COURIER RE: Marathon KBU 43-7X CONFIDENTIAL DATA Dear Mr. Oakland: Enclosed are CONFIDENTIAL data for the above referenced well as listed below. DISK 1 (list of contents attached) \ ð \ S 3 Please indicate your receipt of this data by signing below and returning one copy to me at the letterhead address. Thank you, cj{~~ ~ Kaynell Zeman Technical Assistant Enclosure .. C"' Received B~\ ~ j~"D,-c: ("( ~."jy\ Date: ~~;":'/ED tt..~, 'l~ OCT: ?OO;) _'·tI.&~.(\St Ut; ¿'",.;~~~:,-.,G¡;~·. ~;ùmm!5$tOr. .r~nQ1mage '\:::"~'i.~ ~'\" S~ File Folder 10/6/2003 11 :10 AM DLIS File 6/1112003 1 :04 AM DLIS File 6/11/2003 12:54 AM FMA File 6/12/20032:16 PM FMA File 6/12/20033:21 PM FMA File 6/12/20032:31 PM FMA File 6/12/20032:46 PM LAS File 6/11/2003 1 :15 PM LAS File 6/1112003 1 :15 PM PDSView Document 6/11/2003 9:22 AM PDSVlew Document 6/12/20033:22 PM PDSView Document 6/11/20032:47 PM PDSView Document 6/12/20032:45 PM 59,771 KB DLlS File 6/11/20033:21 PM 5 KB FMA File 6/11/20033:21 PM 'I KB FMA File 6/1212003 2:'S PM 5 KB FMA File 6/11/2003 3:37 PM 5 KB FMA File 6/11/20033:37 PM 1 KB FNL File 6/11120033:37 PM 300 KB PDSView Document 6/11/20033:37 PM 10 KB PDSView Document 6/11/20033:33 PM '15 KB PDSView Document 6/11/20033:37 PM ~¡¿:~:~··~~¡:··Z:~~~1I~:it~:~·~~·:¿~t:~-i~~~·~:·6t·i·HMA [!iJ Combined.PDS, FMA [!!J HdrTðil.PDS.FMA [!1 Heðder .PDS. FMA ~ combined.FNL ¿;) Combined .PDS ¿;)HdrTaiI.PDS ¿J Heðder .PDS 43,172 KB 14,188 KB HB HB HB 4 K8 916 KB 319 KB 503 KB 4,854 KB 1,024 KB 648 KB Name (4i) PEX FILES PDSl/ieW30.exe CMR_ooßPUP.DlIS CMR...OllPUP ,DLlS ÇtllR~QI3PUP ,DLlS iIì CMR_OHPlJP.DLIS Ii CMR_OIßPUP.CILIS J¡f CMR_037tUP.OLIS ... kbu43·1x-PfocesseO_cmr .dlis 1M SPlICE_CMR_016.DLLS ¡- CMR_ooßPUP.CILIS.FMA . CMR_OllPUP,OLIS.FMA ~CI't'IP.~QI3PUP,DLI$,f'MA ~CMR_Ot4PUP,DLtS.FMA !:1 CMfUJ1E1PUP.DLlS.FMA >~ CMR_037tlJP.OLtS..FMA . ~. CI't'IP._LQCjIOS.ÞD$.FMA ¡ .. CMR_LQC_Ol1.POS.FMA , ~.-. CMIUQCJH3.POS.FMA ~CMRj.QC_014.POS.FMA , ~ CMRJ,QC_037 . POS. FMA , ~ CMRT JIINYOR'pEPTH_LOG_OOS.POS.FMA ~'.~. CMRT J:lINyoo._PEPTH_LOGJH1.POS.FMA ~CMRT J'lINYOFCOEPTH_LOG_Ol3 ,POS.FMA I'~...'. CMRT. JIUCPORj:)EPTH_LOG_014,POS.FMA .. CMRT _8IN_POR.Pf;PTH_LOG_031.PDS,FMA ~ Anal CMFUornbíned.PDS.FMA .. SPLICE_CMR~pI6.DLtS.FMA - CMRJ)OSPUP .!as ~CMR_Ol1PlJP'lðs . CMR_Ol3PUP.lðs .. <>I>..OI_.!os I- CMR..018PUP.Ið$ .. CMR_~nup.!as .. kbu43-7xßoce$s«tc::mr.!as ~.' File descrlptlon,doc !;J CMR_LQC_008.PDS £) CMR_LQC_Ol1 ,PDS :J CMR_LQC_013.PDS I:J CMR_LQC_014.PDS l;;Q CMR_LQC_037 .PDS l!J CMR T _BIN_POR_DEPTH_LOG_008, PDS ~ CMRT _BINYOR_DEPTH_LOG_O 11 ,PDS ~CMRT BIN POR DEPTH LOG 013.PDS l;;Q CMR T =BINYOR=DEPTH=LOG=01'1 .PDS ßJ CMRT _BIN_POR_DEPTH_LOG_037 ,PDS [!Q Final CMR combined. PDS [!} kbu43-7x_cmr _comblned_a.pds (! CopyRight.txt (i) readme.txt ~1~~f~~:::¡:~~:~t~~JCFL_CNL_O'. , ~= RepeatAIT _TLD_MCFL_CNL_002.., !. Caliper Combined . PDS. FMA ¡. CombinedTCOM,PDS,FMA [!!I NuclearCombined. PDS, FMA ~ TVD TcomComblned,PDS.FMA ~Maln PassAIT_TLD_MCFL_CNL_O... 1:1 RepeatAIT _ TLD _MCFL_CNL_002. . . l:!:J Caliper Combined . PDS ~ ComblnedTCOM.PDS ŒJ NuclearCombined.PDS [!)TVD Tc:omCombined,PDS ..,.. 1· ..... .... ·~~·r T~ ...., ..... ···IM~~d .... F»e Folder 10/6/2003 11 :40 AM 9,884 KB App!itðtlòn 2/26/2003 2:47 AM a.o77 KB DUS File 6/11/2003 9:O<f AM 34,636 KB DLIS Fae 6/11/1003 9:15 Af<ll ZO,SS1 KB DlIS File 6/1.1/20039:26 AM 17,620 KB OLIS File 6/11/20039:33 AM 49,162 KB DLIS File 6/1112003 12;02 PM 10,230 r..a DLIS Faa 6/11/l003 10:56 AM 43'7 K8 OUS file 6/12/20033:59 AM 49,080 KB DLIS File 6/11/2003 11 :57 AM 5 KB FMA File 6/11120039:04 AM 5 r..a FMA File 6/11/20039: 15 AM 5 KB FMA File 6/11/20039:28 AM 5 KB FMA File 6/t 1/20039:33 AM 5 ì<S FMA File 6/11'l003 lZ:02 PM 5 KB FMA File 6/11/2003 10:56 AM 5 KB FMA File 6/11/2003 11 :51 AM 5 K8 FMA File 6/11/2003 11 :44 AM 5 KB fMA File 6/1112003 11 :51 AM 5 KB FMA File 6/11/2003 11 :57 AM 5KB FMAF»e 6/11/200311:51 AM 5 K8 FMA File 6/11/20039:46 AM 5 K8 FMA File 6/1112003 11 :12 AM 5 KB FMA File 6/11/20039:52 AM 5 KB FMA File 6/11/2003 10:52 AM 5 KB FMA Fi1ì!I 6/11/2003lt:06AM 41<8 FMA File 6/1112003 1 :50 PM " KB FMA file 6/11/2003 11 :57 AM 194KB LASFiIe 6/11120031:42PM 753 K8 LAS File 6/11/20031:42 PM 464 K8 LAS File 6/1112003 1 :42 PM 395 KB LAS File 6/11/2003 1 :42 PM 1,OS6 KB LAS File 6/11/2003 1: 18 PM 240 KB LAS File 6/11/2003 1 :42 PM 1,263 K8 LAS File 6/12/20033:59 AM 19 KB Microsoft ". 6/12/20033:39 PM 82 K8 PDSVlew". 6/11/20039:04 AM 275 KB PDSView... 6/11/20039:15 AM 171KB PDSView". 6f11/20039:2BAM 118 KB PDSView.., 6/11/20039:33 AM 96 KB PDSVlew... 6/11/200310:56 AM 85 KB PDSVlew, .. 6/11/2003 9: 46 AM 299 KB PDSVlew." 6/11/20039:'19 AM 185 KB PDSView". 6/11/20039:52 AM 160 KB PDSView". 6/11/20039:55 AM 101 KB PDSView... 6/11/200311:06 AM 1,359 KB PDSVlew." 6/11/20031:2'1 PM 1,668 KB PDSView." 6/12/20038:23 AM 1 KB Text Docu... 11/14/20022:59 AM 1 KB Text Docu." 6/12/20038:39 AM ·r ") Marathon KBU 43~7X Disk 1 ,f ) ,~ ) c/67--- b60ð STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1. Status of Well OILD GAS[8] SUSPENDEDD 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 41' FSL, 4088' FWL, Sec. 6, T4N, R11W, S.M. At top of Producing Interval ABANDONEDD At Total Depth 3452' FNL, 3552' FWL, Sec. 7, T4N, R11W, S.M. 5. Elevation in feet (indicate KB, DF, etc.) RT-GL: 21.0' Classification of Service Well SERVICED 7. Permit Number 203-066 8. API Number 50-133-20522-00 9. Unit or Lease Name Kenai Beluga Unit 10. Well Number KBU 43-7x 11. Field and Pool 6. Lease Designation and Serial No. A-028083 12. Date Spudded 22-May-03 17. Total Depth (MD+TVD) 8610' MD, 7434' TVD 13. Date T.D. Reached 12-Jun-03 18. Plug Back Depth (MD+TVD) 8556' MD, 7380' TVD 14. Date Comp., Susp. or Aband. 5-Sep-03 Kenai Gas Field, Beluga 15. Water Depth, if offshore N/A feet MSL 16. No. of Completions 1 22. Type Electric or Other Logs Run PEX-CMR-GR-NEU 19. Directional Survey 20. Depth where SSSV set Yes~No D N/A feet MD 21. Thickness of Permafrost N/A 23 CASING SIZE WT. PER FT. 20" 133 13-3/8" 68 9 5/8" 40 3-1/2" 9.3 GRADE K-55 L-80 L-80 L-80 CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD TOP BOTTOM surf 138' surf 1510' surf 6463' surf 8589' CEMENTI NG RECORD N/A 759 sacks(cement to surface) 647 sacks 970 sacks 24. Perforations open to Production (MD+ TVD of Top and Bottom and interval, size and number) 6spf: 6898'-6908',6939'-6949',6978'-6988', 7053'-7063', 7094'-7104', 7141'-7151',7194'-7204',7234'-7244', 7433'-7443', 7472'-7482', 7541'-7551', 7590'-7600',7691'-7701',7754'-7764', 7921'-7931', 8386'-8396', 8470'-8480' MD HOLE SIZE Driven 17-1/2" 12-1/4" 8-1/2" 25. SIZE N/A AMOUNT PULLED N/A TUBING RECORD DEPTH SET (MD) PACKER SET (MD) 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. DEPTH INTERVAL (MD) AMOUNT & KIND OF MATERIAL USED See Sand Frac Summary I See Sand Frac Summary 6 spf: 5747'-5757',5786'-5796',5824'-5834', 5895'-5905', 5935'-5945', 5981'-5991',6032'-6042',6072'-6082', 6267'-6277', 6306'-6316', 6374'-6384', 6423'-6433', 6523'-6533', 6585'-6595', 6750'-6760', 7211'-7221', 7295'-7305' TVD 27. PRODUCTION TEST Date First Production Method of Operation (Flowing, gas lift, etc.) 5-Sep-03 Flowing Date of Test Hours Tested PRODUCTION FOR 12-Sep-03 24 TEST PERIOD -----. Flow Tubing Pres. Casing Pressure CALCULATED 1515 0 24-HOUR RATE-----, OIL-BBL o OIL-BBL o GAS-MCF 4,780 GAS-MCF 4,780 WATER-BBL CHOKE SIZE GAS-OIL RATIO 42 21/64" N/A WATER-BBL OIL GRAVITY-API (corr) 42 N/A -. 28. Brief description of lithology, porosity, fractures, apparent dips and presence of oil, gas or water. Submit core chips. no cores taken ¡~; !~~_: Form 10-407 Rev. 7-1-80 CONTINUED ON REVERSE SIDE Submit in Triplicate ,/ G}/ ReOMS S,Ft ORIGINAL ~ç:p ? f.I\ 1~~~) AOGCC Completion KBU 43-7x.xls ) ) 29. 30. GEOLOGIC MARKERS FORMATION TESTS NAME MEAS.DEPTH TRUE VERT. DEPTH Include interval tested, pressure data, all fluids recovered and gravity, GOR, and time of each phase. Sterling Lower Beluga Not Logged N/A 6489' MD 5364' TVD N/A 7268' MD 6105' TVD N/A 8348' MD 7174' TVD Middle Beluga Upper Tyonek 31. LIST OF ATTACHMENTS wellbore schematic, directional survey, daily operations summary, sand fracturing summary I hereby ce~e toregoi;,i\ ~~ and correct to the best of my knowledge Signed '\-- ~~ ~ ____ Gary Eller Title Production Engineer INSTRUCTIONS 32. Date 24-Sep-03 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. Item 1: Classification of Service Wells: Gas injection, water injection, steam injection, air injection, salt water disposal, water supply for injection, observation, injection for in-situ combustion. Item 5: Indicate which elevation is used as reference (where not otherwise shown) for depth measurements given in other spaces on this form and in any attachments. Item 16 and 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 16, and in item 24 show the producing intervals for only the interval reported in item 27. Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval. Item 21: Indicate whether from ground level (GL) or other elevation (DF, KB, etc.) Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, Other-explain. Item 28: If no cores taken, indicate "none". Form 10-407 AOGCC Completion KBU 43-7x.xls API: 50-133-20522-00 AOGCC: 203-066 RT -GL: 21.00' 41' FSL, 4088' FWL, Sec. 6, T4N, R11W, S.M. Tree cxn = 4-3/4" Otis KOP: 250' Build: 2.5 deg per 100' Hold Anqle: 43 deg at 2300' DOP: 5350' Drop: 2.0 deg per 100' Final Anqle: 8 deg at 7450' Directional survey Coil tubing cleaned to 8508' MD (9/4/03 ) Well Name & Number: County or Parish: Perforations (MD) Angle/Perfs BHP: Dated Completed: Prepared By: ') ') .. M MARATHOI ~ ~ i ~...c ;it' :¡. ~ , .( ~"i.: :0<) ,,"1 s~ :r~ .~~ ~. "í.;;' \~ I: ~~ i'i: 'J'{ ';t,~i ~I~ ...t ".. ...~ .O! ~i,,: ¡~ <~ ~~ " Wi: ~~ ?; ~ ~~ ,1\ ):' ;~ ..t ~ .. F.\. ¡~ .~ ;r~ ~ ~.& KBU 43-7x Lease: State/Provo I Drive Pipe: 20", 133 ppf, K-55 to 138' Surface Casinq: 13-3/8", 68 ppf, L-80, BTC @ 1510' Cmt w/759 sks of class G to surface Int. Casinq: 9-5/8", 40 ppf, L-80, BTC @ 6463' Cmt w/ 647 sks of class G Prod. Casinq: 3-1/2", 9.3 ppf, L- 80, EUE 8rd with 5.25" OD slotted couplings to 8589' Cmt w/ 970 sks of class G Excape System Details - 17 Excape modules run - Both control lines open for methanol injection (9/3/03) - Ceramic flappers removed with coil (9/3/03) Perfs: Module 17 - 6898' - 6908' (frac'd 9/3/03) Module 16 - 6939' - 6949' (frac'd 9/3/03) Module 15 - 6978' - 6988' (frac'd 9/3/03) Module 14 - 7053' - 7063' (frac'd 9/3/03) Module 13 -7094' -7104' (frac'd 9/3/03) Module 12 - 7141' - 7151' (frac'd 9/3/03) Module 11 - 7194' - 7204' (frac'd 9/3/03) Module 10 - 7234' - 7244' (frac'd 9/3/03) Module 9 - 7433' - 7443' (perfd 9/3/03) Module 8 - 7472' - 7482' (frac'd 9/3/03) Module 7 - 7541' - 7551' (frac'd 9/3/03) Module 6 - 7590' - 7600' (perfd 9/3/03) Module 5 - 7691' - 7701' (frac'd 9/3/03) Module 4 - 7754' - 7764' (frac'd 9/3/03) Module 3 - 7921' - 7931' (frac'd 9/3/03) Module 2 - 8386' - 8396' (frac'd 9/3/03) Module 1 - 8470' - 8480' (frac'd 9/3103) Excape module details Frac details Kenai Gas Field, Pad 41-7 Alaska I Country: I (TVD) Angle @ KOP and Depth BHT: I Completion Fluid: 6/16/2003 J.G. Eller I Last Revison Date: ~ ., , ¡: .,. ~.\ ¡~~ -.r~1 '~.. l. .1-" , l, .~:~ , I I I I ¡ rl PBTD - 8556' TD - 8610' KBU 43-7x Kenai 9/12/2003 ) ) MARATHON Oil Company Pad 41-7 KBU43-7X slot #KBU43-7X Kenai Gas Field Kenai Peninsula, Alaska SUR V E Y LIS TIN G by Baker Hughes INTEQ Your ref Our ref License MWD <0-8610> svy6903 Date printed Date created Last revised 13-Jun-2003 23-May-2003 13-Jun-2003 Field is centred on 270916.030,2362063.980,999.00000,N Structure is centred on 270916.030,2362063.980,999.00000,N Slot location is n60 27 34.626,w151 14 47.284 Slot Grid coordinates are N 2362048.230, E 275003.930 Slot local coordinates are 63.03 N 4087.61 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North ) MARATHON Oil Company Pad 4l-7,KBU43-7X Kenai Gas Field,Kenai Peninsula, Alaska Measured Inclin Depth Degrees 0.00 198.00 255.00 315.00 376.00 436.00 497.00 557.00 617.00 677.00 738.00 803.00 866.00 928.00 990.00 1050.00 1114.00 1177.00 1240.00 1304.00 1366.00 1429.00 1465.00 1551. 00 1612.00 1675.00 1737.00 1798.00 1862.00 1924.00 1987.00 2049.00 2110.00 2175.00 2237.00 2299.00 2363.00 2426.00 2488.00 2551. 00 2614.00 2675.00 2739.00 2802.00 2863.00 2926.00 2988.00 3049.00 3112.00 3173.00 10.28 11.16 11. 71 13.04 15.48 17.18 18.72 19.31 19.24 20.32 21.68 22.52 23.69 22.92 23.26 23.89 25.41 27.79 30.80 32.68 34.35 35.79 36.88 37.95 39.57 41. 29 42.95 42.95 42.37 42.27 42.09 42.00 41. 63 41. 21 40.97 41.27 41. 28 40.88 41.80 43.06 Azimuth Degrees 0.00 1. 73 2.16 2.65 3.91 0.00 309.20 307.70 295.30 280.30 True Vert Depth 0.00 197.97 254.94 314.88 375.78 435.50 495.98 555.35 614.63 673.80 733.86 797.72 859.47 920.03 980.12 1037.70 1098.59 1158.16 1217.63 1277.85 1335.73 1394.11 1427.22 1506.20 1562.32 1620.07 1676.42 1730.96 1786.77 1839.50 1892.02 1942.77 1991.90 2043.53 2091. 87 2139.07 2186.54 2232.65 2278.24 2324.83 2371.51 2416.81 2464.51 2511. 75 2557.73 2605.19 2651. 78 2697.77 2745.07 2790.09 R E C TAN G U L A R COO R DIN ATE 8 O.OON 1.89N 3.09N 4.37N 5.35N 5.80N 5.69N 5.06N 3.56N 1.17N 1.928 6.338 11.738 18.168 26.698 37.298 50.968 66.628 83.618 102.178 121. 858 143.188 156.078 187.458 209.818 233.938 259.258 286.338 317.568 350.148 384.918 420.528 456.648 496.108 534.888 575.058 617.938 660.838 702.818 745.198 787.448 828.258 870.878 912.518 952.568 993.958 1034.818 1074.878 1116.468 1157.588 O.OOE 2.32W 3.83W 5.98W 9.30W 15.00W 23.00W 31. 62W 40.75W 50.41W 60.63W 71. 88W 83.14W 94.75W 107.40W 120.51W 134.70W 147.91W 159.90W 171.02W 181.34W 191. 67W 197.44W 210.58W 219.07W 226.26W 231. 41W 234.84W 237.07W 238.52W 239.61W 240.54W 241.77W 243.36W 244.95W 246.77W 248.49W 250.07W 251. 79W 253.64W 255.63W 257.59W 259.60W 261. 49W 263.31W 265.15W 266.83W 268.30W 269.57W 271.15W Dogleg Deg/100ft 8URVEY LI8TING Your ref Last revised 0.00 0.87 0.76 1.19 2.48 0.00 -1. 64 -2.68 -3.74 -4.36 ) Vert 8ect G RID Easting Page 1 MWD <0-8610> 13-Jun-2003 COO R D 8 Northing 2362048.23 2362050.16 2362051.39 2362052.72 2362053.76 2362054.32 2362054.36 2362053.90 2362052.58 2362050.37 2362047.47 2362043.28 2362038.11 2362031.90 2362023.61 2362013.27 2361999.88 2361984.47 2361967.72 2361949.38 2361929.91 2361908.78 2361896.00 2361864.88 2361842.69 2361818.71 2361793.50 2361766.49 2361735.31 2361702.76 2361668.03 2361632.44 2361596.35 2361556.93 2361518.19 2361478.07 2361435.22 2361392.37 2361350.43 2361308.10 2361265.89 2361225.14 2361182.56 2361140.97 2361100.96 2361059.62 2361018.79 2360978.78 2360937.22 2360896.13 All data in feet unless otherwise stated. Calculation uses mlnlmum curvature method. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Bottom hole distance is 3534.20 on azimuth 188.73 degrees from wellhead. Vertical section is from wellhead on azimuth 185.91 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ 7.06 8.01 8.57 9.21 9.89 271. 30 267.40 264.40 257.20 255.00 251. 40 246.00 242.90 239.30 233.20 229.10 223.30 217.10 213.30 208.70 206.70 205.00 203.30 202.10 199.50 193.80 189.30 185.30 183.00 182.10 181.50 181.50 182.40 182.20 182.50 182.70 181.90 182.30 182.40 182.60 182.80 182.70 182.70 182.50 182.70 182.40 182.30 181.90 181.60 182.80 5.43 1. 77 1.18 2.14 1. 29 -4.22 -3.29 -1. 78 0.65 4.03 1. 21 2.05 1. 31 2.48 4.62 8.16 13.70 20.22 27.82 37.61 3.42 3.68 3.34 1. 99 2.96 49.50 64.55 81.50 99.62 119.23 2.48 1. 68 3.74 1. 05 1. 76 139.86 162.15 175.56 208.13 231.25 3.75 3.89 4.88 5.02 3.13 255.98 281. 70 308.99 340.28 372.83 2.70 2.32 1. 99 1. 66 2.63 407.53 443.05 479.10 518.52 557.25 2.78 2.73 0.43 0.94 0.27 597.39 640.23 683.06 724.99 767.34 0.36 0.18 0.58 0.70 0.45 809.57 850.36 892.97 934.57 974.60 0.57 0.11 0.78 1. 49 2.46 1015.96 1056.78 1096.78 1138.28 1179.35 275003.93 275001.65 275000.16 274998.03 274994.73 274989.04 274981. 05 274972.41 274963.25 274953.55 274943.27 274931.95 274920.58 274908.85 274896.04 274882.73 274868.28 274854.76 274842.46 274830.98 274820.28 274809.55 274803.52 274789.79 274780.87 274773.21 274767.58 274763.63 274760.79 274758.72 274756.96 274755.34 274753.41 274751.07 274748.73 274746.13 274743.59 274741.19 274738.66 274735.99 274733.18 274730.44 274727.61 274724.91 274722.32 274719.68 274717.22 274714.98 274712.91 274710.53 ) MARATHON Oil Company Pad 41-7,KBU43-7X Kenai Gas Field,Kenai Peninsula, Alaska Measured Inclin Depth Degrees Azimuth Degrees 3236.00 3299.00 3362.00 3423.00 3488.00 3550.00 3612.00 3678.00 3740.00 3803.00 3863.00 3925.00 3987.00 4049.00 4112.00 4175.00 4238.00 4299.00 4362.00 4423.00 4486.00 4549.00 4612.00 4674.00 4736.00 4800.00 4861. 00 4923.00 4987.00 5050.00 5112.00 5174.00 5237.00 5300.00 5363.00 5425.00 5489.00 5551.00 5612.00 5675.00 5740.00 5791. 00 5860.00 5923.00 5988.00 6051. 00 6115.00 6177.00 6239.00 6302.00 43.09 42.85 42.66 42.43 42.42 42.14 41.72 41. 31 41. 46 41.15 40.65 40.42 40.12 39.87 39.51 39.10 40.13 41. 76 41.64 41.37 41.21 41.00 40.86 40.90 42.26 42.19 41.97 41.60 41. 28 41.12 40.90 40.62 40.54 40.54 40.38 39.78 39.67 39.12 38.92 37.37 36.46 35.72 35.47 35.60 34.80 181.90 182.50 182.10 182.00 181.70 181.50 182.00 182.40 183.00 182.50 182.40 182.20 182.00 182.50 182.00 182.80 181. 30 181. 90 182.60 182.80 181.90 182.50 182.90 181.80 180.90 180.10 180.40 179.90 180.10 181.20 181.20 181.30 180.50 180.40 181.80 181.00 181.00 181.10 181.00 181.20 181.70 181.00 181.80 181.90 181. 30 34.05 33.12 31. 60 30.29 28.91 181.30 181. 70 182.50 182.90 183.10 True Vert Depth 2836.11 2882.21 2928.47 2973.41 3021. 39 3067.26 3113.38 3162.80 3209.32 3256.65 3302.00 3349.12 3396.43 3443.92 3492.40 3541.15 3589.68 3635.76 3682.80 3728.48 3775.82 3823.29 3870.89 3917.76 3964.14 4011. 53 4056.81 4103.04 4151.02 4198.42 4245.20 4292.17 4340.01 4387.89 4435.83 4483.27 4532.49 4580.40 4627.79 4677.34 4729.31 4770.52 4826.63 4877.90 4931. 01 4982.98 5036.29 5088.66 5141.84 5196.61 R E C TAN G U L A R COO R DIN ATE 8 1200.578 1243.488 1286.228 1327.448 1371.268 1412.968 1454.378 1498.088 1539.038 1580.568 1619.818 1660.078 1700.128 1739.948 1780.148 1820.018 1860.158 1900.118 1941. 998 1982.378 2023.908 2065.298 2106.528 2147.068 2188.208 2231.208 2272.088 2313.408 2355.758 2397.258 2437.928 2478.398 2519.378 2560.328 2601.198 2641.098 2681. 998 2721. 338 2759.738 2798.638 2837.668 2867.708 2907.848 2944.448 2981.898 3017.508 3052.898 3086.058 3117.908 3148.978 272.92W 274.57W 276.28W 277.76W 279.17W 280.34W 281.60W 283.28W 285.21W 287.21W 288.89W 290.51W 291.97W 293.54W 295.12W 296.79W 298.22W 299.34W 300.98W 302.89W 304.59W 306.18W 308.13W 309.79W 310.76W 311.13W 311.31W 311.42W 311.42W 311. 89W 312.74W 313.62W 314.27W 314.59W 315.37W 316.35W 317.06W 317.78W 318.49W 319.23W 320.22W 320.93W 321. 91W 323.09W 324.14W 324.95W 325.87W 327.08W 328.58W 330.21W Dogleg Deg/100ft 8URVEY LI8TING Your ref Last revised 0.98 0.75 0.53 0.39 0.31 1222.29 1265.14 1307.82 1348.98 1392.72 ) Page 2 MWD <0-8610> 13-Jun-2003 Vert 8ect G RID Easting COO R D 8 Northing 2360853.19 2360810.32 2360767.63 2360726.45 2360682.66 2360640.99 2360599.62 2360555.95 2360515.05 2360473.56 2360434.35 2360394.13 2360354.12 2360314.34 2360274.18 2360234.35 2360194.24 2360154.32 2360112.48 2360072 .15 2360030.65 2359989.31 2359948.12 2359907.62 2359866.52 2359823.53 2359782.66 2359741.36 2359699.01 2359657.54 2359616.89 2359576.44 2359535.49 2359494.56 2359453.71 2359413.83 2359372.96 2359333.64 2359295.26 2359256.38 2359217.38 2359187.37 2359147.25 2359110.68 2359073.26 2359037.67 2359002.31 2358969.18 2358937.37 2358906.33 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Bottom hole distance is 3534.20 on azimuth 188.73 degrees from wellhead. Vertical section is from wellhead on azimuth 185.91 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ 0.50 0.87 0.74 0.68 0.72 1434.31 1475.63 1519.28 1560.21 1601. 73 0.84 0.43 0.53 0.66 0.76 1640.94 1681.16 1721.14 1760.91 1801. 06 1. 03 2.23 2.75 0.76 0.49 1840.89 1880.97 1920.83 1962.66 2003.02 0.98 0.71 0.47 1.16 2.40 2044.51 2085.84 2127.05 2167.54 2208.56 0.85 0.49 0.80 0.54 1.18 2251. 38 2292.06 2333.16 2375.30 2416.62 0.35 0.46 0.84 0.10 1. 46 2457.16 2497.51 2538.33 2579.10 2619.83 1. 28 0.17 0.89 0.34 2.47 2659.63 2700.38 2739.59 2777.85 2816.63 1. 47 1. 66 0.77 0.23 1. 34 2855.55 2885.50 2925.53 2962.06 2999.42 1.19 1. 49 2.55 2.14 2.20 3034.92 3070.22 3103.33 3135.16 3166.23 274707.94 274705.46 274702.92 274700.65 274698.40 274696.43 274694.37 274691.84 274689.12 274686.33 274683.89 274681. 50 274679.26 274676.93 274674.58 274672.14 274669.93 274668.04 274665.59 274662.91 274660.41 274658.02 274655.28 274652.84 274651.08 274649.87 274648.91 274648.00 274647.19 274645.92 274644.28 274642.62 274641.19 274640.08 274638.50 274636.76 274635.26 274633.78 274632.33 274630.84 274629.10 274627.81 274626.06 274624.17 274622.40 274620.91 274619.30 274617.45 274615.34 274613.11 ) ') MARATHON Oil Company 8URVEY LI8TING Page 3 Pad 41-7,KBU43-7X Your ref MWD <0-8610> Kenai Gas Field,Kenai Peninsula, Alaska Last revised 13-Jun-2003 Measured Inclin Azimuth True Vert R E C T A N G U L A R Dogleg Vert G RID C o 0 R D 8 Depth Degrees Degrees Depth C 0 0 R D I N A T E 8 Deg/100ft 8ect Easting Northing 6364.00 27.52 182.70 5251.24 3178.248 331. 70W 2.26 3195.51 274611.06 2358877.10 6427.00 25.80 181.90 5307.55 3206.498 332.84W 2.79 3223.72 274609.38 2358848.88 6484.00 24.35 182.70 5359.17 3230.628 333.80W 2.61 3247.82 274607.95 2358824.77 6547.00 23.47 182.40 5416.76 3256.138 334.94W 1. 41 3273.31 274606.32 2358799.29 6610.00 22.24 183.80 5474.82 3280.568 336.25W 2.13 3297.75 274604.54 2358774.89 6671. 00 20.74 185.50 5531. 58 3302.848 338.05W 2.66 3320.09 274602.31 2358752.66 6733.00 19.51 186.60 5589.79 3324.058 340.30W 2.08 3341. 42 274599.66 2358731.49 6795.00 18.54 188.70 5648.40 3344.088 342.98W 1. 91 3361.62 274596.59 2358711.52 6856.00 17.49 189.80 5706.41 3362.708 346.01W 1. 81 3380.45 274593.20 2358692.96 6921. 00 17.05 190.10 5768.48 3381. 708 349.34W 0.69 3399.70 274589.51 2358674.02 6984.00 16.00 191.90 5828.88 3399.298 352.75W 1. 85 3417.55 274585.76 2358656.50 7046.00 14.68 192.90 5888.67 3415.318 356.27W 2.17 3433.84 274581.93 2358640.55 7109.00 13.71 196.70 5949.75 3430.258 360.19W 2.13 3449.10 274577.72 2358625.70 7173.00 12.57 202.10 6012.07 3443.968 364.99W 2.62 3463.24 274572.66 2358612.08 7234.00 11. 87 202.80 6071. 69 3455.908 369.92W 1.17 3475.62 274567.50 2358600.24 7296.00 10.81 203.50 6132.48 3467.118 374.71W 1. 72 3487.26 274562.49 2358589.13 7358.00 9.76 212.30 6193.48 3476.888 379.84W 3.04 3497.51 274557.18 2358579.45 7422.00 8.79 220.30 6256.65 3485.208 385.90W 2.52 3506.41 274550.96 2358571.26 7485.00 8.44 224.90 6318.94 3492.148 392.28W 1. 23 3513.97 274544.45 2358564.43 7547.00 8.09 233.00 6380.30 3497.998 398.97W 1. 96 3520.48 274537.64 2358558.72 7609.00 8.35 247.10 6441. 67 3502.378 406.60W 3.27 3525.62 274529.93 2358554.49 7672.00 8.96 259.70 6503.95 3505.038 415.65W 3.15 3529.19 274520.84 2358552.00 7736.00 9.05 268.90 6567.17 3506.028 425.58W 2.25 3531.20 274510.88 2358551.21 7797.00 8.35 274.10 6627.47 3505.798 434.80W 1. 73 3531.92 274501.68 2358551.61 7860.00 7.91 278.35 6689.84 3504.838 443.65W 1.18 3531. 88 274492.84 2358552.74 7924.00 7.65 277.30 6753.25 3503.658 452.23W 0.46 3531. 59 274484.29 2358554.08 7986.00 7.38 276.24 6814.71 3502.708 460.28W 0.49 3531. 47 274476.25 2358555.20 8049.00 7.38 276.60 6877.19 3501. 798 468.33W 0.07 3531. 40 274468.23 2358556.25 8112.00 7.21 276.90 6939.68 3500.858 476.27W 0.28 3531. 28 274460.31 2358557.35 8176.00 6.94 277.30 7003.19 3499.888 484.09W 0.43 3531.12 274452.51 2358558.47 8296.00 7.38 279.80 7122.26 3497.648 498.88W 0.45 3530.42 274437.77 2358560.99 8362.00 6.94 277.30 7187.74 3496.428 507.01W 0.82 3530.03 274429.66 2358562.37 8440.00 6.86 276.60 7265.18 3495.288 516.31W 0.15 3529.86 274420.38 2358563.69 8510.00 6.77 275.50 7334.68 3494.418 524.57W 0.23 3529.84 274412.14 2358564.72 8610.00 6.77 275.50 7433.99 3493.288 536.30W 0.00 3529.92 274400.43 2358566.08 All data in feet unless otherwise stated. Calculation uses minimum curvature method. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Bottom hole distance is 3534.20 on azimuth 188.73 degrees from wellhead. Vertical section is from wellhead on azimuth 185.91 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ ) MARATHON Oil Company Pad 41-7,KBU43-7X Kenai Gas Field,Kenai Peninsula, Alaska MD TVD ----------------------------------------------------------------------------------------------------------- 8610.00 7433.99 Top MD Top TVD Rectangular Coords. ) 8URVEY LI8TING Page 4 Your ref MWD <0-8610> Last revised : 13-Jun-2003 Comment Comments in wellpath -------------------- -------------------- 3493.288 536.30W Projection to TD Casing positions in string 'A' Rectangular Coords. ------------------------------ ------------------------------ Rectangular Coords. Bot MD Bot TVD 0.00 0.00 0.00 0.00 0.00 0.00 ----------------------------------------------------------------------------------------------------------- Casing Target name O.OON O.OON O.OON O.OOE O.OOE O.OOE 1510.00 6461.00 8570.00 1468.49 5338.27 7394.27 172.588 3221.048 3493.738 Geographic Location Targets associated with this wellpath ------------------------------------- ------------------------------------- KBU43-7X - T/Mid Bel 274611.620,2358858.810,999.00 5250.00 KBU43-7X - TD - 3/26 274605.840,2358558.880,999.00 7325.00 T.V.D. 204.45W 333.38W 531. 61W 3196.528 3496.518 Rectangular Coordinates 330.79W 26-Mar-2003 330.79W 26-Mar-2003 13 3/8 Casing 9 5/8 Casing 3 1/2 Liner ----------------------------------------------------------------------------------------------------------- Revised KBU 43-7x Sand Fracturing Summary Sand Module Fluid Volume Placed Number M D Depth (bbls) Fluid Type Sand Type (Ibm) Super Rheogel in #2 Diesel 8470 436 (Williams - Anchorage) 16/30 Ottawa 44,400 Super Rheogel in #2 Diesel 2 8386 385 (Williams - Anchorage) 16/30 Ottawa 42,400 Super Rheogel in #2 Diesel 3 7921 459 (Williams - Anchorage) 16/30 Ottawa 78,900 Super Rheogel in #2 Diesel ~~ .' 4 7754 308 (Williams - Anchorage) 16/30 Ottawa 42,200 Super Rheogel in #2 Diesel 5 7691 350 (Williams - Anchorage) 16/30 Ottawa 56,000 Super Rheogel in #2 Diesel 6 7590 0 (Williams - Anchorage) 16/30 Ottawa Super Rheogel in #2 Diesel 7 7541 369 (Williams - Anchorage) 16/30 Ottawa 65,600 Super Rheogel in #2 Diesel 16/30 Ottawa12.5 % by 8 7472 350 (Williams - Anchorage) weight 12/20 Flexsand MSE 54,900 Super Rheogel in #2 Diesel 16/30 Ottawa 12.5 % by 9 7433 4 (Williams - Anchorage) weight 12/20 Flexsand MSE Super Rheogel in #2 Diesel 16/30 Ottawa 12.5 % by 10 7234 202 (Williams - Anchorage) weight 12/20 Flexsand MSE 19,700 Super Rheogel in #2 Diesel 16/30 Ottawa 12.5 % by 11 7194 230 (Williams - Anchorage) weight 12/20 Flexsand MSE 29,300 Super Rheogel in #2 Diesel 16/30 Ottawa 12.5 % by -~ 12 7141 276 (Williams - Anchorage) weight 12/20 Flexsand MSE 43,400 Super Rheogel in #2 Diesel 16/30 Ottawa 12.5 % by 13 7094 219 (Williams - Anchorage) weight 12/20 Flexsand MSE 27,000 Super Rheogel in #2 Diesel 16/30 Ottawa 12.5 % by 14 7053 204 (Williams - Anchorage) weight 12/20 Flexsand MSE 31,500 Super Rheogel in #2 Diesel 16/30 Ottawa 12.5 % by 15&16 6939 291 (Williams - Anchorage) weight 12/20 Flexsand MSE 42,000 Super Rheogel in #2 Diesel 16/30 Ottawa 12.5 % by 17 6898 179 (Williams - Anchorage) weight 12/20 Flexsand MSE 21,000 Totals 4262 598,300 ') ) Daily Summary for Well: KENAI BELUGA UNIT 43-7X Report Date Report Number MD TVD Daily Cost Summary .............................................................................................................................................................................................................................................................. Drilling Event: 21-May-03 1 $29,200 MIRU drilling equipment. 22-May-03 2 $47,917 R/U rig. 23-May-03 3 426 426 $44,860 N/U diverter and test. P/U DP and BHA. RIH and tag @ 55'. Clean out conductor F/55' to 137'. Drill F/137' to 426'. 24-May-03 4 1,170 1,152 $43,713 Dir drill and survey F/426' to 1040'. Circ. clean. Wiper trip to bit. Drill F/1 040' to 1170'. 25-May-03 5 1,515 1,473 $53,428 Drill F/1170' to 1515'. Circ. clean. POOH(SLM). RIH. Circ. clean. POOH. R/U CSG tools. Run 26-May-03 6 1,515 1,473 $125,737 Run 13 3/8" CSG. Run innerstring. Cement 13 3/8" CSG. Remove Diverter. 27 -May-03 7 1,515 1,473 $74,046 Remove 20" head. Install 13 5/8" 3M X 13 5/8" 5M wellhead. N/U 135/8" 5M BOP. Test BOP. M/U bit and BHA. RIH. P/U 4" DP. 28-May-03 8 1,545 1,500 $36,238 P/U 4" DP. Slip and cut drill line. Service rig. Install MWD. RIH drill shoe tract and shoe. Clean old hole to 1515'. Drill new hole 1515' to 1535'. Circ. clean. Perform LOT. Drill F/1535' to 1545'. 29-May-03 9 3,038 2,690 $89,683 Drill F/1545' to 3038'. Circ. clean. POOH to 1510'. Service rig. 30-May-03 10 4,225 3,579 $67,205 Service rig. RIH. Drill F/3038' to 4225'. MWD failed. POOH. 31-May-03 11 5,075 4,217 $67,192 W/R OOH to 1510'. Circ. clean. POOH C/O MWD. RIH to 4225'(several tight spots, W/R). Drill F/4225' to 5075'. 01-Jun-03 12 5,413 4,474 $78,992 Drill F/5075' to 5313'. Circ. clean. W/R OOH to 3226'. POOH to 1510'. 02-Jun-03 13 5,800 4,857 $51,591 Service rig. RIH to 5413'(W/R as required). Circ. condo mud. POOH to 4787'. RIH to 5413'. Drill F/5413' to 5800'. 03-Jun-03 14 5,920 4,874 $59,275 Drill F/5800' to 5841'. Circ. clean. POOH. Test BOPE. P/U new motor and bit. RIH. Drill F/5841' to 5920'. 04-Jun-03 15 6,322 5,212 $62,258 Drill F/5920' to 6164'. Circ. clean. Wiper trip to 3850'. RIH. Drill F/6164' to 6322'. 05-Jun-03 16 6,477 5,353 $77,302 Drill fl 6322' to 6477' MD. C & C mud. WT. C & C hole. POOH to run casing, LD BHA. Change rams. Printed - 9/25/2003 .) Dailv Summary for Well: Report Date Report Number MD TVD Daily Cost .........................................................................................................................................................................................................................,.................................... Summary 6,477 5,353 $286,257 RU & run 9-5/8" casing to 6463' MD. Cement casing. CIP @ 01 :45 hrs, 6/6/2003. RO casers. RU top drive. 6,497 5,371 $53,753 Change rams, test BOPE. TIH w/ 8-1/2" BHA. Test casing to 3500 psi. Drill shoe track and 20' of new formation f/6477' to 6497' MD. Pull to shoe. Perform LOT to 14.73 ppg EMW. Displace hole to 8.9 ppg Flopro mud. Mix & build surface mud volume. Build volume. Circulate @ shoe. Drill f/6497' to 7210' MD. Drill f/721 0' to 7232'. Pull to shoe. Rpr rig. TIH. Drill f/ 7232' to 7984'. Circ/raise MW. Drill f/7984' to Drill f/ 8110' to 8236' MD. Circulate. WT. Drill f/ 8236' to planned TO @ 8500' MO, 7325' TVO. Circulate. WT. Drill f/ 8500' to final TO @ 8570' MO, 7394' TVO. Circ for logs. Pull to shoe, hole not taking proper fill, TIH. Circ, raise MW. 8,570 7,394 $60,551 Circulate, raise MW to 10.5 ppg. POOH. Run open hole logs. 8,610 7,434 $138,915 Finish run open log logs. MU bit, TIH. Drill f/8570' to 8606' MD. Trip for wash out. TIH. Drill f/ 8606' to 8610' MD. See completion report. Circulate & condition hole & mud. Pull to shoe. Service rig. WO completion eqpt. TIH. C & C mud. POOH LOOP. RU to run 3-1/2" EXCAPE completion. RU to run 3-1/2" EXCAPE completion. Run perf modules 1 - 17, break circ, continue running 3-1/2" completion tubing w/ control lines, break circ @ shoe. Run 3-1/2" tubing. 8,610 7,434 $162,356 Finish running 3-1/2" EXCAPE completion. Circulate casing. Run correlation log. Put casing on depth. Circulate casing while batch mixing cement. Cement 3-1/2" casing. WOC. NO BOP. Set slips. Make rough cut. Set out stack. Make final cut. 8,610 7,434 $435,190 Install/test secondary pack-off. Install/test tree, install BPV. ROMO drilling equipment. Rig released to KU 14X-6 @ 06:00 hrs, 6/16/2003. 8,610 7,434 $31,916 Jetted completion fluid from well and left 1800 psi N2 cap. Recovered 103 bbl 6% KCI to flowback Move in frac tanks. Test manifold. Build dyke around frac tanks. RU coil tubing, frac iron, and flowback iron. Pressure test. Load tanks with diesel. Held safety Perf and frac stimulate Excape modules 1 - 17 using a total of 598,300 Ibs of proppant. Use coil tubing to break all flapper assemblies. Unable to flow well due to plugging in flowback iron. Produce well to sales at 3.7 mmcfd. Flow well at 3.9 mmcfd. Opened choke, increase flow to 4.7 mmcfd. 06-Jun-03 17 07-Jun-03 18 08-Jun-03 19 7,210 6,047 $77,723 09-Jun-03 20 8,110 6,937 $75,591 10-Jun-03 21 8,570 7,394 $54,872 11-J un-03 22 12-Jun-03 23A Rig Completion Event: 12-Jun-03 23B 8,610 7,434 $5,768 13-Jun-03 24 8,610 7,434 $41 ,276 14-Jun-03 25 8,610 7,434 $100,615 15-Jun-03 26 16-Jun-03 27 Non-Rig Completion Event: 19-Jul-03 25-Jul-03 2 $51,300 02-Sep-03 3 $418,547 03-Sep-03 4 $707,623 04-Sep-03 5 11-Sep-03 6 12-Sep-03 7 $6,550 $6,550 $6,550 ) KENAI BELUGA UNIT 43-7X Continue to flow well. Printed - 9/25/2003 Alaska, .~ness Unit d03()b~ Marathon Oil Company P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 June 18, 2003 Mr. Robert P. Crandall Mr. Winton Aubert Alaska Oil and Gas Conservation Commission 333 W. 7th Ave., Suite 100 Anchorage, AK 99501 RE: KBU 43-7X Completion Kenai Gas Field, Alaska Dear Mr. Crandall and Mr. Aubert: Thank you again for the time to discuss the completion of the KBU 43-7X last Thursday. As a follow up, our discussion resulted in these points of approval and understanding: The completion of upper Tyonek and Beluga gas bearing sands does not constitute commingling since both intervals are in the same "Beluga Undefined" Pool. Marathon will work to bring a definition of the "Beluga Undefined" to AOGCC for approval. Marathon will work to get the well production from upper Tyonek sands that has been grouped with the Tyonek Pool 1 reported to the "Beluga Undefined" or the newly defined pool. We anticipate the new pool definition mentioned above to represent the top and bottom of the pool and to coincide with the base of the Sterling Pool 6 and the top of the Tyonek Pool 1. Spacing requirements for all gas pools were addressed by Conservation Order No. 175. This order removed the spacing requirements for the pools as set out in Conservation Order 82. The definition of the new pool should be forthcoming. Best Regards, (d~;i David Brimberry Geologist RECE J U N 1 9 "", Alaska Oil & GiY.' - DLB/cdg Via Certified Mail cc: File Jkch.:-- ~líf6\llt c0 w Ilil L U:o ~ ') f ~:!Æ~~~!Æ l ) ~¡ FRANK H. MURKOWSKI, GOVERNOR AI,ASKA. OIL AND GAS CONSERVATION COMMISSION Willard J. Tank Senior Drilling Engineer Marathon Oil Company PO Box 196168 AnchorageAK 99519-6168 333 w. rrn AVENUE, SUITE 100 ANCHORAGE, ALASKA 99501-3539 PHONE (907) 279-1433 FAX (907) 276-7542 Re: Kenai.Beluga Unit KBU 43-7X Marathon Oil Company Pennit No: 203-066 Surface Location: 42' FSL, 4088' FWL, Sec. 6, T4N, R11W, SM Bottomhole Location: 3455' FNL, 3757' FWL, Sec. 7, T4N, R11 W, SM Dear Mr. Tanle Enclosed is the approved application for permit to drill the above referenced development well. This pennit to drill does not exempt you from obtaining additional pennits or approvals required by law from other governmental agencies, and does not authorize conducting drilling operations until all other required pennits and approvals have been issued. In addition, the Commission reserves the right to withdraw the pennit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the tenns and conditions of this pennit may result in the revocation or suspension of the permit. Please provide at least twenty-four (24) hours notice for a representative of the Commission to witness any required test. Contact the Commission's North Slope petroleum field inspector at 659-3607 (pager). Sincerely, . y ~-h..~ Randy Ruedrich Commissioner BY ORDER QF THE COMMISSION DATED this /G' day of April, 2003 cc: Department ofFish & Game, Habitat Section w/o encl. Department of Environmental Conservation w/o encl. Exploration, Production and Refineries Section g:\Cmn\drlg\ste,r,ling\SU44-10\KBU 43-7X AOGCC Drilling per7't.xlS .... , V~6/t- --0/1 l..J,10! ) STATE OF ALASKA ) ALASKr-. OIL AND GAS CONSERVATION COMMIS~,iON PERMIT TO DRILL 210 MC 25.005 Re-Drill D Deepen D 1 b. Type of well. ExploratoryD Stratigraphic TestD Development Oil D Service D Development Gas [8] Single Zone D Multiple Zone [8] 5. Datum Elevation (DF or KB) 10. Field and Pool ./' 87' KB feet Kenai Gas Field / Beluga 1a. Type of Work Drill[8] Re-EntryD 2. Name of Operator MARATHON OIL COMPANY 3. Address P. O. Box 196168, Anchorage, AK 99519-6168 4. Location of Well at Surface 42' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. At top of Productive Interval 3,155' FNL, 3,757' FWL, Sec. 7, T4N, R11W, S.M. At Total Depth 3,455' FNL, 3,757' FWL, Sec. 7, T4N, R11W, S.M. 12. Distance to Nearest 13. Distance to Nearest Well Property Line(unit boundary) 2600 feet 16. To be Completed for Deviated Wells Kickoff Depth 250 feet Maximum Hole Angle 18. Casing Program Size Casing 20" 13-3/8" 9-5/8" 3-1/2" 1700 / Hole Driven 17-1/2" 12-1/4" 8-1/2" Specifications Grade Coupling X-56 PE K-55 BTC L-80 BTC L-80 EUE 8rd Weight 133 68 40 9.3 6. Property Designation A-028083 7. Unit or Property Name Kenai Beluga Unit ;,' 8. Well Number KBU 43-7X / 9. Approximate Spud Date 5/19/03 / 14. Number of Acres in Property 11. Type Bond (see 20 AAC 25.025) Blanket Surety Number 5194234 Amount $200,000 15. Proposed Depth (MD and TVD) feet /' 1940 8,485' MD / 7,325' TVD feet 17. Anticipated Pressure (see 20 AAC 25.035 (e) (2)) Maximum Surface 3497 r psig at Total Depth (TVD) 7325' Setting Depth Top Bottom 41.3 0 Length 116' 1521' 6492' 8506' MD TVD MD TVD 0' 0' 137' 137' 0' 0' 1500' 1462' 0' 0' 6471' 5347' 0' 0' 8485' 7325' Quantity of Cement (including stage data) 647 sx 685 sx 915 sx The KBU 43-7X well will be directionally drilled to an estimated total depth of 8485' MD, 7325' TVD from the existing Kenai Gas Field pad 41-7. The production interval will be cased with 3-1/2" casing, cemented in place, and run to surface. Marathon's drilling rig will be used to drill and complete this well. The following documents are attached: Drilling Program, Pad drawing, Location Map, Structure Map, Surface use plan, Directional Maps, Mud Pit and Blowout Preventer drawings. Diverter Sketch [8] Seabed ReportD Drilling Program [8] 20 AAC 25.050 RequirementsD 20. Attachments Filing Fee[8] Property Plat[8] BOP Sketch [8] Drilling Fluid program0 Time vs Depth PlotD Refraction AnalYSiSD 21. I hereby certify that the foregoing is true and correct to the best of my knowledge Phone: 907-564-6310 .A Signed W. J. Tank ~~ ¡ d4~ Title Senior Drilling Engineer Date 4/16/2003 Commission Use Only Permit Number API Number APProvC" . / ~ See Cover Letter ¿d"&~ - 0 6~ 50-/33 -2cJSZ:2- 1/ I D( ð -5 RPee1VEunts Conditions of Approval Samples Required DYes ...JZ]NO Mud Log Required DYes ,3NO Hydrogen Sulfide Measures DYes ~No Directional Survey Required ~Yes DNo APR 1 6 2003 Required Working Pressure for BOPE ~2M n3M D5M D10M D15M . . . Other: p~..- 7,0 AA-L '1..'5.. tJ ~S- (k) (L)) I c:e('--rtVe-v~' l ,'~ l ~ ""i)¡J "yt..V~ J. Alaska 011 & Gas Cons. CommiSSion \~c;..+- BOPE to ~'5"OO I)~t. Anchorage Approved by ~ ~ ~ I G~Ni;1d~. ~:eo~~~:SSion Date r;;: ft/o '5 Form 10-401 Rev. 12-1-85 Submit in Triplicate ') ') MARATHON MARATHON Oil COMPANY DRilliNG PROGRAM Kenai Gas Field KBU 43-7X Original 4/15/03 Originator: W.J. Tank j¥jð- Drilling Superintendent: P.K. Berga Drilling Manager: C.W. Truby Page 1 of 12 ) ) 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....................................................................................................................... .................................................7 Wellhead Equipment Summary................................... .......... ...... ............. ........................ .................. .......... ........ ..................8 Directional Program Summary........................................................ ......... .................................... ...........................................8 Directional Surveying Summary ..............................................................................................................................................9 Drilling Fluid Program Summary................................... .......... ............................................ .................... .................. ...............9 Drill ing Flu id Specifications.................................................................................................................................................. ..10 Solids Control Equ ipment ......................................................................................................................................................1 0 Cement Program Summary...................................................................................................................................................1 0 Regulatory Waivers and Special Procedures..................... .............. .......................................... .......................................... .11 Hydraulics Summary............................................................... .............................................................................................. .12 Formation Integrity Test Procedure .................................................................................. .................... .................... ............ .12 Page 2 of 12 General Well Data Well Name Surface Location Slot/Pad KB Elev. Ground Level Elev. Perm. Datum Water Depth Water Protection Depth Comments: ) ) KBU 43-7X Lease/License 42' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. ,,- WBS Code DD.03.08209.CAP.DRL Pad 41-7 Field Kenai Gas Field Spud Date 5/19/03 (est.) ./. 87 County/Province Kenai Borough API No. 66 State I Country Alaska Well Class Development KB Total MD 8,485' Rig Contractor Glacier Drilling /' N/A Total TVD 7,325' Rig Name #1 Geoloçlic ProQram Summary MD - RKB TVD - RKB Pore Pressure Pore Pressure Possible Fluid Formation (ft) (ft) (psi) (ppg) Lithology Content Sterling A-8 4,240 3,597 --; Sandstone Gas I Water ( Beluga 5,703 4,697 Sandstone Gas I Water Primary Target 6,364 5,250 Sandstone Gas I Water Middle Beluga 6,482 5,357 Sandstone Gas I Water Lower Beluga 7,225 6,067 Sandstone Gas I Water Tyonek 8,347 7,187 Sandstone Gas I Water Comments: From Lease/Block Lines Latitude Longitude UTM North (Y) UTM East (x) Tolerance Target Beluga WellTD Comments: Surface Location Coordinates 42' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. 60027' 34.626" N 151014' 47.284" W 2,362,048.226' 275,003.929' Depth MD TVD (ft) (ft) 6,364 5,250 8,485 7,325 Horizontal Displacement (ft) NIS EIW (Y) (X) Tolerance (ft) Circle 250' radius Circle 250' radius Location /. /" 3,155' FNL, 3,757' FWL, Sec. 7, T4N, R11W, S.M. -3,197 -331 3,455' FNL, 3,757' FWL, Sec. 7, T4N, R11W, S.M. -3,497 -331 Page 3 of 12 ') ') Summary of Potential DrillinÇl Hazards Hazard Event Discussion Lost Circulation in Low Pressure Sterling and Upper Control losses by using sufficiently sized LCM and appropriate mud weights. Beluga Sands Comments: Potential Hazards Statement To comply with state regulations the Potential Hazards section and the well shut-in procedures must be posted in the drillers dog house. The man on the brake (driller or relief driller) is responsible for shutting the well in (BOPE or diverter as applicable) as soon as warning signs of a kick are detected and an influx is suspected or confirmed. A copy of the approved permit to drill must be kept on location and be readily available to the AOGCC or BlM inspector. This well's primary objective is gas and no oil sands are expected to be encountered. No H2S is anticipated. Gas sands will be encountered from +/:1"'l(2;;~D (3,597' TVD) to total depth of the well. These sands will run from normal pressured to severely depleted.a.rJ£f1ost circulation and differential sticking are potential hazards. 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. No well interference hazards exist. Formation Evaluation Summary Interval Surface 0' - 1,500' MD Intermediate 1,500' - 6,471' MD Production 6,471' - 8,485' MD Completion LWD Electric Logs Mud Logs None None None NIA Basic with GCA, shale density, temperature in and out, sample collection (10' samples). Basic with GCA, shale density, temperature in and out, sample collection (10' samples). NIA None None Quad Combo (MAD Pass) NIA None Coring Requirements: None Comments: The LWD tools will be run on a MAD pass as a part of the wiper trip. It is to be run in memory mode only. No real time required. Page 4 of 12 Drillina Proaram Summary CONDUCTOR: 1. Drive 20" conductor to +/-120 ft. RKB. 2. Move in and rig up rotary drilling rig. 3. Install starting head 20" SOW x 21 1/4", 2M flanged. t//) /'/ 4. Nipple up 21 1/4", 2M diverter, 16" diverter valve, and , 6)¡Verter line. 5. Function test diverter and diverter valve.! SURFACE: 1. 2. /' Drill a 17 1/2" hole to 1,500' MD (1,462' TVD) per the directional plan. RIH with 133/8" casing and hang off in the slips. Make up stab-in sub and centralizer on 4" drill pipe. TIH with inner string and latch into stab-in float collar. Cement 13 3/8" casing. Sting out and circulate drill pipe clean. TOOH with inner string. PU 133/8" casing, set casing slips in 20", cut off 13 3/8", NO diverter. Install 13 3/8" slip lock connection X 13 5/8" 5M flanged multibowl wellhead. ./ NU 13 5/8" 5M BOP'S. Test BOP'S and choke manifold to 250/3,500 psi. ./ Set wear bushing. /' Test surface casing to 1,000 psi. 3. 4. 5. 6. 7. INTERMEDIATE: 1. Drill out float equipment and make 20' of new hole. CBU. 2. Test shoe to leak off. Estimated EMW is 13 ppg. 3. Drill 12 1/4" directional hole to 6,471' MD (5,347' TVO) as per directional plan. 4. Make wiper trip. 5. Change out variable pipe rams with 9 5/8" casing rams. Run test plug and test casing rams to 3,500 psi. 6. Run and cement 95/8" casing. Land hanger in multibowl wellhead. 7. Back out landing joint. Change out 9 5/8" casing rams with variable pipe rams. Run test plug and test pipe rams to 250/3,500 psi. 8. Set wear bushing. Test casing to 3,500 psi. PRODUCTION: 1. Drill float equipment and 20' of new formation w/8 1/2" bit. CBU. 2. Test shoe to leak off. Estimated EMW 13.5 ppg. 3. Drill a 8 1/2" hole to 8,485' MD (7,325' TVO) per the directional program. 4. TOOH. PU LWO tools. Log well on MAD pass while making the wiper trip. TOOH and laydown BHA and drill pipe. Pull wear bushing. 5. Change out single pipe ram with 3 1/2" pipe rams. Run test plug and test pipe rams to 250/3,500 psi. 6. Run 3 1/2" EXCAPE casing string. Cement 3 1/2" casing while reciprocating. Bump plug with 500 psi over displacement pressure. 7. wac. 8. PU 3 1/2" casing. PU BOP stack. Run control and electric lines out tubing head outlet. Set slips. Cut 3 1/2" casing. 9. LD BOP. Set 31/2" packoff. NU 135/8" 5M X 3 1/8" 5M tubing head adapter and 31/8" 5M tree. Test tree to 5,000 psi. 10. Rig down and move out drilling rig. Note: Perforating guns will be run on the outside of the 3 1/2" production casing with a flapper valve just below each perforating gun. Guns to be activated by control line to surface. COMPLETION: Completion will be done without a rig. Page 5 of 12 ) -) CasinÇl ProÇlram MD (ft) Connection API Ratings Q) c Casing Makeup ..... ~:=:- 0 U) ~ ëñ co tJ) ëñ a. Size Weight a.D. Torque Hole Size :J ,9; = a. c g ca o - Q) (in) Top Bottom (Ibs/ft) Grade Type (in) (ft-Ibs) (in) ü I- 13 3/8 Surface 1,500 68 K-55 BTC 14.375 NIA * 17.50 3,450 1,950 1,300 95/8 Surface 6,471 40 L-80 BTC 10.625 NIA * 12.25 5,750 3,090 979 31/2 Surface 8,485 9.3 L-80 8rd 4.5 3,200 8.5 10,160 10,530 207 Comments: * The make up of the buttress connection will be to the proper mark. CasinÇl DesiÇln Casing Shoe Safety Factors Q) c Casing Setting Mud Wt Frac. Maximum Surface tJ) a. 0 /- ..... ~ ëñ Size Weight Depth When Set Grad Pressure ~ Õ C :J Q) (in) (Ib/ft) Grade (TVD) (Ib/gal) (Ib/gal) (psi) [Q Ü I- 13 3/8 68 K-55 1 ,462 9.2 13.0 918 2.21 2.17 2.93 95/8 40 L-80 5,347 9.6 13.5 3,497 1.80 1.01 ,/' 2.75 31/2 9.3 L-80 7,325 10.0 15.0 2,505 1.17 2.30 1.62 Comments: Maximum Anticipated Surface Pressure Setting Depth Casing Size TVD MAWP * (in) (ft) (psi) 133/8 1,462 918 95/8 5,347 3,497 3 Y:z 7,325 2,505 * MAWP = Maximum anticipated wellhead pressure ** MASP = Maximum anticipated surface pressure MASP ** Mud/Gas (psi) Ratio 918 0/100 3,497 / 0/100 2,505 0/100 Comments: MASP CALCULATIONS: Surface casing: 133/8" (1,500' MD, 1,462' TVD) MASP = Injection pressure at shoe + S.F. - Hydrostatic pressure of gas column. MASP = (13.0 ppg + 1.0 ppg) x .052 x 1,462' - (.10 x 1,462') MASP = 1,064 psi - 146 psi MASP = 918 psi. ./ Page 6 of 12 ') Intermediate casing: 95/8" (6,471' MD, 5,347' TVD) MASP = Injection pressure at shoe + S.F. - Hydrostatic pressure of gas column MASP = (13.5 ppg + 1.0 ppg) x .052 x 5,347' - (.10 x 5,347') MASP = 4,032 psi - 535 psi MASP = 3,497 psi /" Production casing: 3 1/2" (8,485' MD, 7,325' TVD) MASP = Formation pressure - Hydrostatic pressure of gas column. MASP = 8.5 ppg x .052 x 7,325' - (.10 x 7,325') MASP = 3,238 psi - 733. psi MASP = 2,505 psi. /' BOPE Proaram Casing Casing Size (in) Casing Test Test Fluid Press Density (psi) (Ib/gal) MAWP (psi) MASP (psi) Surface 13 3/8 918 918 1,000 9.2 Intermediate 95/8 3,497 3,497 3,500 9.6 Production 31/2 2,505 2,505 3,000 10.0 Comments: Blowout Preventers ') BOPS Size & Rating (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 13 5/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets (1) 13-5/8" 5M annular (1) 13-5/8" 5M pipe ram (1) 135/8" 5M blind ram (1) 13-5/8" 5M drilling spool with 3-1/8" 5M outlets Test Pressure Low/High (psi) 250/3,500 /'" 250/3,500 --- 250/3,500 r- The blowout preventer stack will consist of a 13-5/8" x 5000 psi annular preventer, a 13-5/8" x 5000 psi double gate ram type preventer / with blind rams in the bottom and pipe rams in the top and a 13-5/8" x 5000 psi drilling spool (mud cross) with 3-1/8" x 5000 psi outlets. The choke manifold will be rated 3-1/8" x 5000 psi. It will include a remote hydraulic actuated choke and a hand adjustable choke. Also included is a poor-boy gas buster, and a vacuum-type degasser. A flow sensor will be installed in the flowline and the mud pits will contain sensors to measure the volume of fluid in the surface mud system. Both sensors will contain readouts convenient to the drillers console. Page 7 of 12 ) }, In 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. Wellhead EQuipment Summary Component Description 13-5/8" 3M X 13-3/8" Slip Loc W/2, 2" LPO, Landing Base for 20" Conductor, U, AA, PSL 1, PR1 13-5/8" 3M Studded Bottom X 13-5/8" 5M Fig Top, WI 2, 2-1116" 5M Studded Outlets, U,AA,PSL 1 ,PR1 13-5/8" 5M X 3-118" 5M WI Seal Pocket and 3" H BPV Threads Casing Hanger Type 13 5/8" x 9 5/8" Fluted Mandrel 135/8" x 31/2" Manual Slip / Casing Head Tubing Head /. Adapter Flange Comments: Control lines and electric cable for the EXCAPE system will be routed through the tubing head side outlet. Directional ProQram Summary Build Turn / Coordinates Sec. MD TVD Rate Rate Dogleg Inclination Azimuth NIS EIW VS No. Description (ft) (ft) (°/100') (0 1100') (°/100') (deg) (deg) (ft) (ft) (ft) Tie On 0 0 0 0 0 0 0 0 0 0 2 KOP 250 250 0 0 0 0 250 0 0 0 3 Build up Section 2.5 0 2.5 250 4 End of Build 800 794.74 2.5 0 2.5 13.75 250 -22.46 -61.72 28.70 5 BuildfTurn Section 1.81 -4.49 2.5 6 End of BuildlTurn 2,319.18 2153.53 1.81 -4.49 2.5 41.28 181.81 -606.63 -254.29 629.58 7 Hold Section 0 0 0 41.28 181.81 8 End of Hold 5,621.05 4,634.93 0 0 0 41.28 181.81 -2,783.85 -323.02 2,802.31 9 DropfTurn Section -2.0 -0.24 2.0 181.81 10 End of Drop to the 7,686.57 6,526.21 -2.0 -0.24 2.0 0 180 -3,496.50 -330.79 3,511.98 Target 11 TD 8,485.36 7,325 0 0 0 0 180 -3,496.51 -330.79 3,511.99 ~ Comments: Vertical section calculated from a reference azimuth of 185.910 taken from surface location to bottom hole location. Potential Well Interference: Well Distance (fty Depth (MD) KBU 33-6 57.8 925 KBU 42-7 81.8 287.5 KTU 24-6H 105.4 375 KTU 32-7 163.7 262.5 No serious interference exists. See attached directional plan and anticollision analysis for more details. Page 8 of 12 ') '} /' .. ..... ..... ......... .. .. ...... .! ......... ..... U l' .......... ........ ......................... . . ...... . . . v --'":'. .... .................. ..110 .... ... I .. . .. ..... ..... \\\ ...... . . ~^^ \\> . . 'JVV \ -- - : .... ~~ ... ......... ........ "- ..... ...... ...... JVVV ............ ........... '... ... . ......,..... ................ "" ....... 'TJVV . ....... ..... \\ Ì\ ....... ..... . i.'" ~ ... ., ... ¡...... ....... 6000- .. . ,', '\..-- I '):; S" I :s ;e o o o ~ .£3 & p í3 '€ C1) > ~ E-< .S ¢: o o ~ +' ~ o ~ £ ::s o en I KBU -13- \: TJrgt"1 I I West(-)/East(+) [1500ft/in] Vertical Section at 185.910 [3000ftlin] Directional SurveyinQ Summary Interval MWD Survey X X X Magnetic Multishot Gyro Multishot Comments o - 1 ,500' 1,500'-6,471' 6,471' - 8,585' Comments: DrillinQ Fluid ProQram Summary Interval - TVD From To Density (ft) (ft) (Ib/gal) 0 1,462 8.6 - 9.2 Minimum Inventory Gel Viscosifier Barite Fluid Description Additives Gel, Gelex, Soda Ash, Caustic, Barite, Polypac UL, M-I Seal, Sodium Bicarbonate Flo-Vis, KCI, Bioban BP-Plus, SafeCarb F, KlaGard, Barite, Caustic, Conqor 404, SafeScav NA, Lubetex Flo-Vis, DualFlo, KCI, Greencide 25G, SafeCarb F,M,C, Ventrol401, Barite, Caustic, Conqor 404, SafeScav NA Gel I Gelex Spud Mud 1,462 5,347 9.2 - 9.6 6% Flo-Pro wi Safecarb / 9.2 -10.0 5,347 7,325 6% Flo-Pro wI Safecarb r ~\ Comments: See mud prognosis for details. Sized CaC03 (SafeCarb) will be used to controlleakoff into the low pressure zones. Page 9 of 12 ') ') Drillin~ Fluid Specifications Interval - TVD LSRV From To Density Vis 1 min PV (ft) (ft) (Ib/gal) (seclqt) (lb.l100tr) (cP) 0 1,462 8.6 - 9.2 45 - 75 10-15 1,462 5,347 9.2 - 9.6 / 40,000 8 -14 / 5,347 7,325 9.2 -10.0 40,000 8 -14 Comments: yp Fluid Loss (lb/100 ft2) (cc) pH 20 - 40 8 -12 As recorded < 9.5 <6 9.0 - 9.5 MBT (Ib/bbl) < 7.5 Solids Control Equipment c 0 Q) Q3 ~ tš ~ Q) ro c Q) 0 £ .c Q3 ro 0> 0 U ~ Q) ~ CJ) CJ) CJ) Q3 U 0> 0> Õ C C C ~ ro ëñ u ë E E e ro CJ) .c Q) Q) ~ Q) ~ ~ Q) Interval en 0 0 ~ u u U N Comments o - 8,485' MD X X X X Closed Loop System, Full Containment Item Shaker 2 - Derrick Model 2E48-90F-3T A Desander NIA Desilter 1 - Derrick Model 0522 Mud Cleaner N/A Centrifuge 2 - MIISwaco units Cuttings Dryer NI A Cuttings Injection Marathon G&I Facility Zero Discharge N/A Equipment Specifications (quantity, design type, brand, model, flow capacity, etc) 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. Cement Pro~ram Summary Depth Gauge Top of Cement Open Casing Hole Ann Vol Slurry wac Hole Size MD TVD Size MD TVD To TOC Vol Time Excess (in) (ft) (ft) (in) (ft) (ft) (ft3) (ft3) (hrs) (%) 13 3/8 1,500 1,462 17.5 0 0 1,075 1,617 8 50 95/8 6,471 5,347 12.25 3,740 3,221 855 1,317 8 50 31/2 8,485 7,325 8.5 6,200 5,105 756 1,089 N/A 50 Page 10 of 12 ') ') Mix Water Compressive Casing Slurry TOC Strength Size Density Qty Yield Vol MD Qty WL FW (psi) (in) Slurry Cement Description (Ib/gal) (sx) (felsx) (fe) (ft) (gallsx) Type (cc) (%) 8 hr 24 hr Lead 13 3/8 647 /~.50 Tail Type I Cement 12 1,617 0 10.84 Fresh 812 0 500 1,183 Lead Class "G" 12 89 ...,,2.53 226 3,740 10.63 Fresh 95/8 Tail Class "G" 13.5 596 1.83 1,091 4,221 9.25 Fresh 10 0 60 820 Lead 915/'1.19 31/2 Tail Class "G" 15.7 1,089 6,200 4.03 Fresh 24 0 500+ 2,431 Comments: See cement prognosis for details and spacer specifications. ReQulatorv Waivers and Special Procedures I AOGCC Regulation 20 ACC 25.035 (c) (1) (b) I Requirement to have vent line diameter at least as large as the hole to be drilled. Marathon is requesting a waiver from the above regulation for KBU 43-7X. Our Glacier 1 drilling rig is outfitted with a 16" diverter line. For KBU 43-7X the plan is to drill 17 %" surface hole to a total vertical depth of 1 ,462'. This well is being drilled from the Kenai Gas Field 41-7 pad. To date 17 wells have been drilled from this pad with no gas seen above this TVD. Three grass roots wells were drilled on the pad in 2002. No gas was seen above this TVD and no problems were encountered in the surface hole. Additionally, geologic information indicates that the sands down to at least 1,500' are water saturated and do not pose a risk to drilling operations with a 16" diverter system. /' I AOGCC Regulation 20 ACC 25.035 (e) (1) (b) I 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 43-7X. 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. A similar waiver was requested for an offset well on this pad KBU 44-6 on 2/11/2002 and was granted. No problems were encountered while doing this operation on the above well last year. . -l-" t ()~SÇ.. O~ vJ 'SL?OO f ç,¿ i<S-, , . t . M() t.,c¡,C( ~ L-1. · .. I I. ? ~ \.l..L-1I"· /' J,....-- Y\Þ~ \IV vJ c.:~ Page 11 of 12 ') , Hydraulics Summary Rig mud pumps available are shown below. Liner ID Stroke Qty Make Model (in) (in) 5 8 National Oil 3 Well A600PT 5 8 5 8 /' Max Press @ Displacement @ /' 90% WP 95% eft Max Rate Hole Sections Used (psi) (gal/stroke) (spm/gpm) On 2,597 2.04 175/357 Surface 2,597 2.04 175/357 Intermediate 2,597 2.04 175/357 Production Tabulated below are the expected flow rates, standpipe pressures and nozzle sizes for each hole section. Hole Standpipe Min Nozzle Depth-MD Size Pump Rate Pressure AV ECD Size (ft) (in) (gpm) (psi) (fpm) (lb/gal) (32"s) 564 1 -18 o - 1 ,500 17.5 1,600 48 3 -12's 3 -18's 1,500 - 6,471 12.25 483 2,000 88 1 -15 6,471 - 8,485 8.5 420 2,200 183 3 -18's Comments: See separate hydraulics calculations. Formation InteQrity Test Procedure Remarks Actual Data from KBU 44-6 Actual Data from KBU 44-6 Actual Data from KBU 44-6 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 drill pipe pressures at 1/2 bbl intervals. A running plot of pressure versus volume should be kept by the drilling foreman while the test is in progress. 4. Stop pumping when the pressure curve departs form a straight line sufficiently to indicate leakage into the formation. Record as ppg equivalent mud density in the IADC and morning reports. 5. Monitor and plot pressure drop and time after shut-in for 10 minutes or until the shut-in pressure stabilizes. Page 12 of 12 \21 1/4" 2M Diverter I ~ I Diverter Spool ') "> I I" Marathon Oil Well KBU 43-7X Diverter ") I Flow line / I I / 116" Automatic Knife Valve ~¡- / / " ~ / I I "'- I I í \~ ./G / ~~iverter Line ,..,..... ..... " \ ) Marathon Oil Well KBU 43-7X BOP Stack ) I Flow Nipple I . IFlow Line I I /' 13 5/8" 5M Annular Preventer ~ ") / 1 I 1 I > < 13 5/8" 5M Double Ram Preventer I -----.. I I Pipe Ram I /' /' 21/16" 5M Check Valve 2 1/16" 5M Manually \ Operated Valves 1 > ~~ I, r IIXIIXI]ŒÐ 1135/8"5MCross I ~I~ I Blind Ram I < 1 /1 ,¡ IChoke(J@[IxI t 3 1/8" 5M Hydraulically Operated Valve , I I ( 3 1/8" 5M Manually Operated Valve 'I., cpO f yv -rl'-J \ ' ~/ ---(~t f ') Marathon Oil Well KBU 43-7X Choke Manifold '), ITO Gas Buster To Blooey Line Bleed off Line to Shakers ø 1\ II ø 1\ I' ø I I I I \ I. ~J ~ I 'I \.....-., I [ OJ [0 ( \1 I 1 L-J t I I I :~ ø I I ø I l J@[J@[ 0 ]@[]@(~ "I I I ~ I I L-J I~ ~ ~ r--'I ø I J L.....---,. 13" 5M Valves i 2 9/16" 10M Swaco Hydraulically Operated Choke 3 1/8" 5M Manually Adjustable Choke ~ I From BOP Stack " ) l~ Suñace Use Plan for Kenai Beluga Unit, well KBU 43-7X Surface location: Anticipated at 42' FSL, 4,088' FWL, Sec. 6, T4N, R11W, S.M. /. 1) Existing Roads Existing roads which will be used for access to KBU 43-7X 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 43-7X. 3) Location of existing wells Well KBU 43-7X will be drilled on Kenai Gas Field (KGF) pad 41-7. A pad drawing is enclosed that shows existing wells and the proposed location of KBU 43-7X. 4) Location of existing and/or proposed facilities The locations of existing production facilities in the KGF pad 41-7 are shown on the enclosed pad drawing. These facilities will be upgraded to handle the additional gas production. 5) Location of Water Supply A water supply well exists on the pad that KBU 43-7X will be drilled from. This is shown on the pad drawing. 6) Construction Materials No construction is planned on the pad. The recent pad expansion has already been completed and is sufficient. 7) Methods of handling waste disposal; a} Mud and Cuttings Cuttings will be dewatered on location. The cuttings and excess mud will be hauled to Pad 41-18 of the Kenai Gas Field for disposal into Well KU 24-7, a Class II disposal well (AOGCC Disposal Injection Order No.9, Permit #81-176). b) Garbage All household and approved industrial garbage will be hauled to the Kenai Peninsula Borough Soldotna Landfill. c) Completion Fluids Clear fluids will be hauled to Pad 34-31 of the Kenai Gas field and injected in Well WD #1, an approved disposal well (AOGCC Permit #7-194). d) Chemicals Unused chemicals will be returned to the vendors that provided them. Efforts will be ') ) made to minimize the use of all chemicals. e) Sewage Sewage will be hauled to the Kenai sanitation facility. 8) Ancillary Facilities A minimal camp will be established on the pad to house various supervisory and service company personnel. Approximately four trailer house type structures will be required for this purpose. Bottled water will be used for human consumption. Potable water will be obtained from the existing water well on the pad. Sand R will collect and transport sanitary wastes to their ADEC approved disposal facility. 9) Plans for reclamation of the surface KBU 43-7X will be drilled from an existing pad. Reclamation of the pad will occur after the abandonment of KBU 43-7X and the other existing wells on the pad. Approval of the plan of reclamation will be obtained from the U.S. Fish and Wildlife Service 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: 1//Iþ/ð~ , ..f/1/.' 1 /J I~ A - L Name and Title: 7V~ ~'---" Willard J. Ta ,Senior Drilling Engineer Marathon Oil Company P.O. Box 196168 Anchorage, Alaska 99519-6168 (907) 564-6319 ) SECTION 6, T4N, R11W, SEWARD MERIDIAN, AK ~ . LJJ o N_ ID ù>D:! 00> ..... 5 z,/'" S B9' 11' 33" E NW CORNER SECllON 7 X-270,90B.30 V-2.362.070.01 .f- 2361.56 ~ ~ GRID WASTE WATER BLDG. 6 WELL HOUSE ~ X-275,063.53 OVERHEAD :3 V-2,361,775.96 CONDUIT '" 20.0' 2-4" - STEEL GRATE 8 PIPESSTORAGE :,¡. ~~~s WI BLDG. 5 ~ K.U. 43-6X ~~~~T~ ~J?..... L6". PIPE ~c y ~ GOES UNDERGROUND 1( (.¡~~ -- g~:o :~~~ UJ ID I') ;¡. If) o o z ~ 4088' FWL io IX) oi ..... """'-.y S B9' 11' 33" E ~ 1/4 7 ~ X-273,269.62 V-2,362,036.73 1726.29 SUIMY WORK (1/2" REBAR) SITE EMERGENCV SHUT DOWN ~ SWITCH \ . TO 14-1 P.O. 80x 468 SOLDOTNA, AK 99669 ~ Consulting c¡'roup ~ Testing TEL 907.283.4218 FAX 907.283.3265 McLANE CONSULTING GROUP SOLD01NA. AlASKA 99669 (907) 283-4218 3/14/03 )ATE OF SURVEY: 03/26/œ. No. DATE BY APP. 3001< NO.: 03-02 ~ ~RO..ECT NO.: 033025 M )RAWlNC NO.: 033025 SCAlE 1·.100' MARATHON )RA WIll BY: 1oISt.4 · ~) UPDATED GPS COORDINATES ASP ZONE 4 NAD27 -GRID N: 2362048.226 GRID E: 275003.929 LA TITUDE: 60·27'34.626" N LONGITUDE: 151·14'47.284"W \ELEV> /~6>5 FT MSL Uì K.B.U. 43-7X LL AS STAKED N """'-.-.::;1- SECTION 8 SECTION 7 K.B.U. 42-7 . . 0 K.B.U. 33-6 K.T.U. 24-BH K.T.U. 32-7 K.B. o KGF PAD 41-7 WELL HOUSE X-275.D73.22 V-2,361 ,844.31 L~I o ~ ~~ K.U. 13-5 14.2' 10' _ WELL HOUSE WITH 17'X17' PIPE GUARD X-275,133.33 V-2,361.;71mIB: \® K.U. 43-6 . K.D.U. 4 X- 275,1 DB. 77 V-2,361,743.64 K.U. ~ X-275,1i V-2,361, . K.D.U. I '" , rr I ISSUED FOR REVIEW REVISIONS Marathon Oil Company ENGINEER APPROVAl Alaska RegIon BY DATE KENAI GAS FIELD PAD 41-7 PRO..ECT S1RUCT. PROCESS IoIECHAN. ELECT. INS1RIJ1oI. ARCH. I".tS K.B.U. 43-7X SURFACE LOCATION DIAGRAM SCAlE DWIII. ...... DATE 03/14/1)3 CHKD.... WOOD DATE 1·.100 APP.D. _ DATE APP. Ii. !U!ICH DATE FILE NO. TYPE ORe MOD DISC SYST DWC NO. SHT NO. 0001 REV o KCF 41-7 S 0 00 o 00 ...... + KDU·7 X I ¡ ¡j UNIT I BOUNDARY. ._.~ / .... 1 ...../ .. ~- I ~ ~ 4:', "'., .. 1..- .. I .. I I -R11WI - A' I .. I .. 11""" ..... .. I .. I r-I ~ () o (.) + .. -'~'~'~"clJ MIDDLE BELUGA FORMATION o c.!. : 100' 1 P I MILE MARATHON OIL COMPANY ALASKA REGION KENAI FIELD COOK INLET, ALASKA KBU 43-7X Location April 2003 HM4094 0: \free han d\ Kenai\B eluga\kbu43-7xlo c.fh9 II'-Ð" r-----' I I ¡ I CENTRIFUGE! I UNIT I I 4' ( if." I I I I I I I ! I I 1Jt.M> I ¡ r-' I ¡ ....'" I I ¡ 1..__ ___.J 1_ I I j I L________ ! ¡ ¡ ! I I r I I I I ~ 3" ( 12' . J' 111 1111 I .... ",I i . I '-- R -------i ~-----it r I 1---..1 U ¡ 1 ¡ ¡ I I I I I t I I , I I I &.. ¡:---, 11 r ¡ II I I II I ~ t II 131! I, I I I' W I I Ii I ¡ ¡ II f¡O I I 11 ! :'III: . ~ I .. II 11 ~ ! I II I I II r.1,="",--=,;!--;--- --..J . .."" ......., I I I \..... ...... J ! 1::HIP loX5 U" - - ~~.i ~iIP 6)(5 11" if4 ; t IIUI ~ ... ~.. , .. J. re ..... t .~ _ 1IIIIIIiH \. .. <> GLACIER DRILLING RIG #1 MUD PITS AND PUMP ROOM LAYOUT ~ 15HP " X :ï 11" - ; ~~i , Ìì " G<: 0; . r .. .. !l It ;(;,'",' ~I-P fi(~ U' .. & z ... o ~ o ,,~4 .. I 5V 91... 11-600 1"1 II". iIIIimm1IIII '5V 91... A-6I.II 1"1 ....... .~ ~æ ;;¡ o¡ ¡ ì . ~u," IJ ~ fit IIdIiI N.I. PrI' .!< ,w, :;:¡;: ~: .:æ.: ~<-v I I I I I , , ! j I I I I I I I I I , I ~ 13":-11" «" ,.1$; 0 ! 400 800 - 200 - 1500 - 2000 - 2400 - ~ +- CD CD 2800 - '+- '---' .J:: +- 3200 Q.. CD 0 0 3500 -I Ü I +- I- CD 4000 - > CD 4400 - I \! 4800 - 5200 - 5500 5000 - 6400 - 6800 - 7200 - 7600 S!rµc!µre : f'pd41-7 Field Kenai Gas Field o a LQcation Kenai Peninsu!o. Well: KBU43-7X 01 DLS 2.50 deg per 100 It 1200 End of Bui End of Buil rn deg per 100 It TRUE 3851 41.28 End of Buil o 400 800 rn d DLS: 2,00 deg per ·100 Middle per 100 of rn <- West 800 400 o ~ 1600 2400 2800 N ~ ,....., ,.....,1 End rn 3600 rtieal Section (feet) -> Azimuth 185.91 with reference 0.00 N, 0.00 E:from slot #KBU43-7X :l15~,5;j 181.81 e e MARATHON Oil Company Pad 41-7 KBU43-7X slot #KBU43-7X Kenai Gas Field Kenai Peninsula, Alaska PRO P 0 S ALL 1ST I N G by Baker Hughes INTEQ Your ref Our ref License KBU 43-7X Version #2 prop5438 Date printed Date created Last revised 8-Apr-2003 26-Mar-2003 8-Apr-2003 Field is centred on 2709l6.030,2362063.980,999.00000,N Structure is centred on 2709l6.030,2362063.980,999.00000,N Slot location is n60 27 34.626,w15l 14 47.284 Slot Grid coordinates are N 2362048.230, E 275003.930 Slot local coordinates are 63.03 N 4087.61 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North e e MARATHON Oil Company PROPOSAL LISTING Page 1 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version #2 Kenai Gas Field/Kenai Peninsula, Alaska Last revised 8-Apr-2003 Measured Inclin. Azimuth True Vert R E C TANGULAR Dogleg Vert Depth Degrees Degrees Depth COO R DIN ATE S Deg/100ft Sect 0.00 0.00 250.00 0.00 0.00 N 0.00 E 0.00 0.00 250.00 0.00 250.00 250.00 0.00 N 0.00 E 0.00 0.00 KOP 350.00 2.50 250.00 349.97 0.75 S 2.05 W 2.50 0.95 450.00 5.00 250.00 449.75 2.98 S 8.20 W 2.50 3.81 550.00 7.50 250.00 549.14 6.71 S 18.42 W 2.50 8.57 650.00 10.00 250.00 647.97 11.91 S 32 . 72 W 2.50 15.21 750.00 12.50 250.00 746.04 18.58 S 51. 05 W 2.50 23.74 800.00 13.75 250.00 794.74 22.46 S 61.72 W 2.50 28.70 Continue Build/Turn 900.00 14.21 239.81 891.79 32.70 S 83.50 W 2.50 41.12 1000.00 15.06 230.50 988.56 47.14 S 104.13 W 2.50 57.61 1100.00 16.25 222.34 1084.86 65.75 S 123.59 W 2.50 78.12 1200.00 17.71 215.38 1180.50 88.50 S 141.82 W 2.50 102.63 1300.00 19.38 209.51 1275.32 115.34 S 158.81 W 2.50 131.08 1400.00 21.20 204.58 1369.11 146.23 S 174.50 W 2.50 163.42 1500.00 23.15 200.42 1461. 72 181.10 S 188.89 W 2.50 199.58 1600.00 25.19 196.88 1552.95 219.89 S 201.93 W 2.50 239.51 1700.00 27.30 193.85 1642.64 262.53 S 213.60 W 2.50 283.12 1800.00 29.47 191.23 1730.62 308.93 S 223.88 W 2.50 330.33 1900.00 31.68 188.94 1816.71 359.00 S 232.76 W 2.50 381.05 2000.00 33.93 186.92 1900.76 412.65 S 240.20 W 2.50 435.19 2100.00 36.21 185.13 1982.61 469.78 S 246.21 W 2.50 492 . 63 2200.00 38.51 183.52 2062.09 530.28 S 250.77 W 2.50 553.28 2300.00 40.83 182 . 07 2139.06 594.04 S 253.86 W 2.50 617.01 2319.18 41.28 181.81 2153.53 606.63 S 254.29 W 2.50 629.58 End of Build/Turn 2500.00 41.28 181.81 2289.41 725.86 S 258.05 W 0.00 748.56 3000.00 41.28 181.81 2665.17 1055.55 S 268.46 W 0.00 1077 . 58 3500.00 41.28 181.81 3040.92 1385.25 S 278.87 W 0.00 1406.59 4000.00 41.28 181.81 3416.68 1714.94 S 289.27 W 0.00 1735.61 4500.00 41. 28 181.81 3792.44 2044.63 S 299.68 W 0.00 2064.62 5000.00 41. 28 181.81 4168.20 2374.33 S 310.09 W 0.00 2393.64 5500.00 41. 28 181.81 4543.95 2704.02 S 320.50 W 0.00 2722.65 5621.05 41.28 181.81 4634.93 2783.85 S 323.02 W 0.00 2802.31 End of Hold 5700.00 39.70 181. 67 4694.96 2835.08 S 324.57 W 2.00 2853.43 5800.00 37.71 181.49 4773.00 2897.58 S 326.30 W 2.00 2915.78 5900.00 35.71 181. 28 4853.16 2957.34 S 327.75 W 2.00 2975.36 6000.00 33.71 181.06 4935.36 3014.26 S 328.92 W 2.00 3032.11 6100.00 31.72 180.81 5019.50 3068.30 S 329.80 W 2.00 3085.95 6200.00 29.72 180.54 5105.46 3119.38 S 330.41 W 2.00 3136.82 6300.00 27.73 180.22 5193.15 3167.44 S 330.73 W 2.00 3184.65 6363.86 26.45 180.00 5250.00 3196.52 S 330.79 W 2.00 3213.59 KBU43-7X - T/Mid Beluga - 3/26/03 6363.87 26.45 180.00 5250.01 3196.52 S 330.79 W 2.00 3213.59 Top Middle Beluga 6386.61 26.00 180.00 5270.41 3206.57 S 330.79 W 2.00 3223.59 6486.61 24.00 180.00 5361.03 3248.83 S 330.79 W 2.00 3265.62 6586.61 22.00 180.00 5453.08 3287.90 S 330.79 W 2.00 3304.49 6686.61 20.00 180.00 5546.43 3323.74 S 330.79 W 2.00 3340.13 6786.61 18.00 180.00 5640.98 3356.29 S 330.79 W 2.00 3372.51 6886.61 16.00 180.00 5736.61 3385.53 S 330.79 W 2.00 3401.59 6986.61 14.00 180.00 5833.19 3411. 41 S 330.79 W 2.00 3427.34 7086.61 12.00 180.00 5930.63 3433.90 S 330.79 W 2.00 3449.71 7186.61 10.00 180.00 6028.78 3452.98 S 330.79 W 2.00 3468.69 All data is in feet unless otherwise stated. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level) . Bottom hole distance is 3512.13 on azimuth 185.40 degrees from wellhead. Total Dogleg for we11path is 93.04 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e e MARATHON Oil Company PROPOSAL LISTING Page 2 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version #2 Kenai Gas Field,Kenai Peninsula, Al.aska Last revised 8-Apr-2003 Measured Inclin. Azimuth True Vert R E C TANGU L AR Dogleg Vert Depth Degrees Degrees Depth COO RDINA T E S Deg/100ft Sect 7286.61 8.00 180.00 6127.55 3468.62 S 330.79 W 2.00 3484.25 7386.61 6.00 180.00 6226.80 3480.81 S 330.79 W 2.00 3496.37 7486.61 4.00 180.00 6326.41 3489.53 S 330.79 W 2.00 3505.04 7586.61 2.00 180.00 6426.27 3494.76 S 330.79 W 2.00 3510.25 7686.57 0.00 180.00 6526.21 3496.50 S 330.79 W 2.00 3511 . 98 End of Drop/Turn 8000.00 0.00 180.00 6839.64 3496.51 S 330.79 W 0.00 3511 . 98 8485.36/ 0.00 180.00 7325.00 3496.51 S 330.79 W 0.00 3511 . 99 KBU43-7X - TD - 3/26/03 Al.l data is in feet unless otherwise stated. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Bottom hole distance is 3512.13 on azimuth 185.40 degrees from wellhead. Total Dogleg for wellpath is 93.04 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the min~um curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad 41-7,KBU43-7X Kenai Gas Field,Kenai Peninsula, ~aska MD TVD Rectangular Coords. e PROPOSAL LISTING Page 3 Your ref KBU 43-7X Version #2 Last revised: 8-Apr-2003 Comments in we11path ----------------------------------------------------------------------------------------------------------- Comment 250.00 800.00 2319.18 5621.05 6363.86 6363.87 7686.57 8485.36 Target name 250.00 794.74 2153.53 4634.93 5250.00 5250.01 6526.21 7325.00 0.00 N 22.46 S 606.63 8 2783.85 8 3196.52 S 3196.52 8 3496.50 8 3496.51 S 0.00 E 61 . 72 W 254.29 W 323.02 W 330.79 W 330.79 W 330.79 W 330.79 W KOP Continue Build/Turn End of Build/Turn End of Hold KBU43-7X - T/Mid Beluga - 3/26/03 Top Middle Beluga End of Drop/Turn KBU43-7X - TD - 3/26/03 Targets associated with this we11path Geographic Location T.V.D. Rectangular Coordinates Revised ----------------------------------------------------------------------------------------------------------- KBU43-7X - T/Mid Bel 274611.620,2358858.810,999.00 5250.00 KBU43-7X - TD - 3/26 274605.840,2358558.880,999.00 7325.00 3196.528 3496.518 330.79W 26-Mar-2003 330.79W 26-Mar-2003 e e MARATHON Oil Company Pad 41-7 KBU43-7X slot #KBU43-7X Kenai Gas Field Kenai Peninsula, Alaska PRO P 0 S ALL 1ST I N G by Baker Hughes INTEQ Your ref Our ref License KBU 43-7X Version #2 prop5438 Date printed Date created Last revised 8-Apr-2003 26-Mar-2003 8-Apr-2003 Field is centred on 270916.030,2362063.980,999.00000,N Structure is centred on 270916.030,2362063.980,999.00000,N Slot location is n60 27 34.626,w151 14 47.284 Slot Grid coordinates are N 2362048.230, E 275003.930 Slot local coordinates are 63.03 N 4087.61 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North e e MARATHON Oil Company PROPOSAL LISTING Page 1 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version 112 Kenai Gas Field,Kenai Peninsula, Alaska La.st revised : 8-Apr-2003 Measured Inclin Azimuth True Vert R E CTANGULAR Dogleg Vert G RID COORDS Depth Degrees Degrees Depth CO ORDINATES Deg/100ft Sect Easting Northing 0.00 0.00 250.00 0.00 O.OON O.OOE 0.00 0.00 275003.93 2362048.23 250.00 0.00 250.00 250.00 O.OON O.OOE 0.00 0.00 275003.93 2362048.23 350.00 2.50 250.00 349.97 0.75S 2.05W 2.50 0.95 275001.87 2362047.52 450.00 5.00 250.00 449.75 2.98S 8.20W 2.50 3.81 274995.68 2362045.41 550.00 7.50 250.00 549.14 6.71S 18.42W 2.50 8.57 274985.38 2362041.88 650.00 10.00 250.00 647.97 11.91S 32.72W 2.50 15.21 274970.99 2362036.95 750.00 12.50 250.00 746.04 18.58S 51.05W 2.50 23.74 274952.53 2362030.64 800.00 13.75 250.00 794.74 22.46S 61 . 72W 2.50 28.70 274941.79 2362026.96 900.00 14.21 239.81 891.79 32.70S 83.50W 2.50 41.12 274919.82 2362017.15 1000.00 15.06 230.50 988.56 47.14S 104.13W 2.50 57.61 274898.91 2362003.11 1100.00 16.25 222.34 1084.86 65.75S 123.59W 2.50 78.12 274879.10 2361984.88 1200.00 17.71 215.38 1180.50 88.50S 141.82W 2.50 102.63 274860.43 2361962.48 1300.00 19.38 209.51 1275.32 115.34S 158.81W 2.50 131.08 274842.94 2361935.97 1400.00 21. 20 204.58 1369.11 146.23S 174.50W 2.50 163.42 274826.65 2361905.40 1500.00 23.15 200.42 1461.72 181.10S 188.89W 2.50 199.58 274811.60 2361870.81 1600.00 25.19 196.88 1552.95 219.89S 201. 93W 2.50 239.51 274797.81 2361832.28 1700.00 27.30 193.85 1642.64 262.53S 213.60W 2.50 283.12 274785.32 2361789.88 1800.00 29.47 191. 23 1730.62 308.93S 223.88W 2.50 330.33 274774.15 2361743.69 1900.00 31.68 188.94 1816.71 359.00S 232.76W 2.50 381.05 274764.31 2361693.80 2000.00 33.93 186.92 1900.76 412.65S 240.20W 2.50 435.19 274755.83 2361640.30 2100.00 36.21 185.13 1982.61 469.78S 246.21W 2.50 492.63 274748.72 2361583.30 2200.00 38.51 183.52 2062.09 530.28S 250.77W 2.50 553.28 274743.00 2361522.90 2300.00 40.83 182.07 2139.06 594.04S 253.86W 2.50 617.01 274738.68 2361459.22 2319.18 41.28 181.81 2153.53 606.63S 254.29W 2.50 629.58 274738.01 2361446.64 2500.00 41.28 181.81 2289.41 725.86S 258.05W 0.00 748.56 274731.95 2361327.51 3000.00 41.28 181.81 2665.17 1055.55S 268.46W 0.00 1077.58 274715.19 2360998.09 3500.00 41.28 181.81 3040.92 1385.25S 278.87W 0.00 1406.59 274698.43 2360668.67 4000.00 41. 28 181.81 3416.68 1714.94S 289.27W 0.00 1735.61 274681.68 2360339.25 4500.00 41. 28 181.81 3792.44 2044.63S 299.68W 0.00 2064.62 274664.92 2360009.83 5000.00 41.28 181.81 4168.20 2374.33S 310.09W 0.00 2393.64 274648.16 2359680.41 5500.00 41.28 181.81 4543.95 2704.02S 320.50W 0.00 2722.65 274631.40 2359350.99 5621.05 41. 28 181.81 4634.93 2783.85S 323.02W 0.00 2802.31 274627.34 2359271.24 5700.00 39.70 181.67 4694.96 2835.08S 324.57W 2.00 2853.43 274624.80 2359220.04 5800.00 37.71 181.49 4773.00 2897.58S 326.30W 2.00 2915.78 274621.87 2359157.59 5900.00 35.71 181.28 4853.16 2957.34S 327.75W 2.00 2975.36 274619.27 2359097.88 6000.00 33.71 181.06 4935.36 3014.26S 328.92W 2.00 3032.11 274617.00 2359040.99 6100.00 31.72 180.81 5019.50 3068.30S 329.80W 2.00 3085.95 274615.08 2358986.98 6200.00 29.72 180.54 5105.46 3119.38S 330.41W 2.00 3136.82 274613.49 2358935.92 6300.00 27.73 180.22 5193.15 3167.44S 330.73W 2.00 3184.65 274612.24 2358887.88 6363.86 26.45 180.00 5250.00 3196.52S 330.79W 2.00 3213.59 274611.62 2358858.81 6363.87 26.45 180.00 5250.01 3196.52S 330.79W 2.00 3213.59 274611.62 2358858.81 6386.61 26.00 180.00 5270.41 3206.57S 330.79W 2.00 3223.59 274611.43 2358848.76 6486.61 24.00 180.00 5361.03 3248.83S 330.79W 2.00 3265.62 274610.61 2358806.51 6586.61 22.00 180.00 5453.08 3287.90S 330.79W 2.00 3304.49 274609.86 2358767.45 6686.61 20.00 180.00 5546.43 3323.74S 330.79W 2.00 3340.13 274609.17 2358731.62 6786.61 18.00 180.00 5640.98 3356.29S 330.79W 2.00 3372.51 274608.54 2358699.07 6886.61 16.00 180.00 5736.61 3385.53S 330.79W 2.00 3401.59 274607.98 2358669.84 6986.61 14.00 180.00 5833.19 3411.41S 330.79W 2.00 3427.34 274607.48 2358643.97 7086.61 12.00 180.00 5930.63 3433.90S 330.79W 2.00 3449.71 274607.05 2358621.48 7186.61 10.00 180.00 6028.78 3452.98S 330.79W 2.00 3468.69 274606.68 2358602.40 All data in feet unless otherwise stated. Calculation uses min~um curvature method. Coordinates from slot IIKBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Bottom hole distance is 3512.13 on azimuth 185.40 degrees from wellhead. Total Dogleg for wellpath is 93.04 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ e e MARATHON Oil Company PROPOSAL LISTING Page 2 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version #2 Kenai Gas Field,Kenai Peninsula, Alaska Last revised 8-Apr-2003 Measured Inolin Azimuth True Vert R E C TAN GU LAR Dogleg Vert G RID C OORDS Depth Degrees Degrees Depth COO R D I N A T E S Deg/100ft Sect Easting Northing 7286.61 8.00 180.00 6127.55 3468.62S 330.79W 2.00 3484.25 274606.38 2358586.76 7386.61 6.00 180.00 6226.80 3480.81S 330.79W 2.00 3496.37 274606.14 2358574.58 7486.61 4.00 180.00 6326.41 3489.53S 330.79W 2.00 3505.04 274605.97 2358565.87 7586.61 2.00 180.00 6426.27 3494.76S 330.79W 2.00 3510.25 274605.87 2358560.63 7686.57 0.00 180.00 6526.21 3496.50S 330.79W 2.00 3511.98 274605.84 2358558.89 8000.00 0.00 180.00 6839.64 3496.51S 330.79W 0.00 3511. 98 274605.84 2358558.89 8485.36 0.00 180.00 7325.00 3496.51S 330.79W 0.00 3511. 99 274605.84 2358558.88 All data in feet unless otherwise stated. Calculation uses m1.n1DLUDL curvature method. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Bottom hole distance is 3512.13 on azimuth 185.40 degrees from wellhead. Total Dogleg for we11path is 93.04 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Grid is alaska - Zone 4. Grid coordinates in FEET and computed using the Clarke - 1866 spheroid Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad 41-7,KBU43-7X Kenai Gas Field,Kenai Peninsula, ~aska Me TVD Rectangular Coords. e PROPOSAL LISTING Page 3 Your ref KBU 43-7X Version #2 Last revised: 8-Apr-2003 Comments in wellpath ----------------------------------------------------------------------------------------------------------- Comment 250.00 800.00 2319.18 5621.05 6363.86 6363.87 7686.57 8485.36 Target name 250.00 794.74 2153.53 4634.93 5250.00 5250.01 6526.21 7325.00 O.OON 22.46S 606.63S 2783.85S 3196.52S 3196.52S 3496.50S 3496.51S O.OOE 61.72W 254.29W 323.02W 330.79W 330.79W 330.79W 330.79W KOP Continue Build/Turn End of Build/Turn End of Hold KBU43-7X - T/Mid Beluga - 3/26/03 Top Middle Beluga End of Drop/Turn KBU43-7X - TD - 3/26/03 Targets associated with this wellpath Geographic Location T.V.D. Rectangular Coordinates Revised ----------------------------------------------------------------------------------------------------------- KBU43-7X - T/Mid Bel 274611.620,2358858.810,999.00 5250.00 KBU43-7X - TD - 3/26 274605.840,2358558.880,999.00 7325.00 3196.52S 3496.51S 330.79W 26-Mar-2003 330.79W 26-Mar-2003 by S"therland For: W Tank "I Coordinates ole in feet reference siot #K8U43-7X. RKB (GIQçíer Structure; Pad 41-7 Well Plot V¡:w>íon #2. Field Kenai Gas Field Location Kenai Peninsula, Alaska <- West (feet) 400 280 360 320 280 280 240 200 160 120 o 40 80 120 160 700 1650 200 160 - 120 80 - 1350 40 - -----. /0 <9,'0 - 40 - /0 00 ¿ () ''D¿c/ () ¿ '+- '-..-/ 80 / // / 00 .r: l~ - :;¡ /6 00 0 120 - Uì I V 160 - 200 - 240 280 - I ,)20 - Ó I I ! 360 - r I 400 - 440 480 400 360 320 280 240 160 120 80 o 40 80 < - West (feet) 0 a ore ;n slol Structure; Pad 41-7 Well; KBU43-7X r~iì. BAKER HUGIIES Field: Kenai Gas Field Location: Kenai Peninsula, Alaska INTEQ <- West (feet) 2800 2600 2400 2200 2000 1800 1600 1400 1200 1000 800 600 400 200 3900 4000 400 00 4200 600 - 600 4300 4400 800 - 800 1000 - 1000 1200 1200 1400 1400 J, 3200 1600 - ¿ 3300 1600 /""""""-. ~ 3400 (j) - (J) 3500 0 (J) 1800 - 1800 C - ¿ 3600 -r '-....--' :¡- I i 3700 /""""""-. 2000 - 2000 - T 3800 (!) 0 (!) (j) J, 3900 -+- 3300 '-....--' 2200 - l 4000 2200 I I 3400 , / V v 00 3500 2400 ~ 4200 2400 1 4300 3600 f 4400 3700 ~ 2600 2600 - 3800 t 4500 3900 J, 4600 2800 - l 4700 4000 - 2800 I DO 'ì 4800 4200 3000 r 4900 4300 3000 I 5000 05100 4400 ¿ 5200 4500 3200 - 3200 4600 6300 4700 6200 5700 3400 - 6100 + 5900 3400 6000 6200 6900 6800 3500 - 5700 - 3600 5600 5500 3800 - 3800 2800 2600 2400 2200 2000 1800 1600 1400 1200 1000 BOO 600 400 200 0 200 400 < West (feet) Date plot1ed: 8~Apr~2D03 om by Sutherland For: W Tank Ver$ion #2. ore in feet reference slot #KBU43-7X. RKE3 (Glacier 1). structure: Pad 41-7 Well : KBU43-7X rll1/ BAKER HUGHES INTEQ Field : Kenai Gas Field Locatìon ; Kena! Peninsula. Alaska UE Ì\IO o 10 20 1400 290 o o 320 1 0 50 300 60 o 280 202 90 260 100 230 220 210 200 2300 Normal Pi n veiling Cylind I~ - F All depths snown ere Meesi.;red depths on Reference Well e MARATHON Oil Company Pad 41-7 KBU43-7X slot #KBU43-7X Kenai Gas Field Kenai Peninsula, Alaska e 3-D M I N I MUM D I S TAN C EeL EAR A N C ERE P 0 R T by Baker Hughes INTEQ Your ref Our ref License KBU 43-7X Version #2 prop5438 Date printed Date created Last revised 8-Apr-2003 26-Mar-2003 8-Apr-2003 Field is centred on 270916.030,2362063.980,999.00000,N Structure is centred on 270916.030,2362063.980,999.00000,N Slot location is n60 27 34.626,w151 14 47.284 Slot Grid coordinates are N 2362048.230, E 275003.930 Slot local coordinates are 63.03 N 4087.61 E Projection type: alaska - Zone 4, Spheroid: Clarke - 1866 Reference North is True North Report is limited to clearances less than 200 feet Object wellpath DECREASING CLEARANCES of less than 1000 feet are indicated by an asterisk, e.g. 487.4* Closest approach with 3-D Minimum Distance method Last revised Distance MSS <0-4453'>"KU21-7,Pad 14-6 PMSS <0 - ????>"KBU24-6,Pad 14-6 GMS <0-7375'>"KBU31-7,Pad 14-6 PMSS <5814 - 7575'>,,31-7Rd,Pad 14-6 WD-2 Version #1"WD-2,Pad 14-6 GMS <0-6950'>"KBU23X-6,Pad 14-6 MSS <0-5500'>"KU13-6,Pad 14-6 MSS <0-9895'>"KDU-l,Pad 14-6 MSS <0-6530'>"KU43-12,Pad 14-6 PMSS <O-???'>"KU 31-7,Pad 14-6 INCLINATION ONLY"KU14-6,Pad 14-6 GMS <0 - 9500>"KU14X-6,Pad 14-6 MSS <9776 - 10225>"KU14X-6,Pad 14-6 KU14X-6RD Version #1"KU14X-6Rd,Pad 14-6 MSS <9768 - 10217> DepthShifted"KU14X-6,Pad 1 GMS <0 - 9492> DepthShifted 12/10/02"KU14X-6, PGMS <778 - 5650>"KU21-6X,Pad #? MSS <0 - 5678'> Depth Shifted"KU21-6X,Pad #? MWD <3452 - 5650'>"KU21-6X,Pad #? PGMS <0-3300'>"WD-l,Pad #? MSS <0-4459'>"KUll-6,Pad #? Incl. only <0-5809'>"KU34-31,Pad #? GMS <0-10502'>"KDU5,Pad #? PGMS <0-5700'>"KU14-32,Pad #? 12-May-1995 12-Mar-2001 14-Sep~1995 28-Sep-1995 26-Mar-1999 12-May-1995 12-May-1995 12-May-1995 12-May-1995 10-Jan-2001 26-Mar-1999 11-Dec-2002 11-Dec-2002 11-Dec-2002 11-Dec-2002 11-Dec-2002 11-Jan-2002 18-0ct-2001 18-0ct-2001 30-May-1995 30-May-1995 30-May-1995 30-May-1995 30-May-1995 2643.4 2643 . 9 2142.8 2142.8 3036.2 2731.1 2765.2 3024.6 3040.5 1451.3 2962 . 1 2804.2 2804.2 2902.8 2804.2 2804.2 6218.0 6152.2 6237.7 7356.6 6539.6 7356.3 6625.0 7083.3 M.D. 2620.0 2300.0 4160.0 4160.0 1837.5 1800.0 1175.0 1762.5 1437.5 4560.0 1812.5 1750.0 1750.0 2225.0 1750.0 1750.0 1687.5 1862.5 1762.5 975.0 1762.5 950.0 1787.5 1287.5 Diverging from M.D. 2620.0 8440.0 8080.0 8320.0 1837.5 1800.0 1175.0 8485.4 1437.5 4560.0 1812.5 1750.0 1750.0 2225.0 1750.0 1750.0 1687.5 1862.5 1762.5 975.0 1762.5 950.0 8485.4 1287.5 e GMS <0-11095'>"KDU6,Pad #? MMS <0-7910'>"KBU33-7,Pad #?? GMS <0-5820'>"KU24-7,Pad #?? MWD <0-5300>"KBU41-7X,Pad 41-7 MWD <0 - 11857'>"KTU32-7H,Pad 41-7 MSS <4305 - 5701>"KU43-6,Pad 41-7 MWD <4250 - 5740>"KU43-6RD,Pad 41-7 KTU43-6XRd Ver.7,,43-6X Rd,Pad 41-7 PGMS <0-8370'>,,43-6,Pad 41-7 PMSS <7670-9464'>,,43-6X Rd,Pad 41-7 PMSS <0-8864>"KTU32-7,Pad 41-7 MSS <0-5300'>,,43-6A,Pad 41-7 MSS <0-10522'>"KDU#2,Pad 41-7 GMS <0-8120'>"KU13-5,Pad 41-7 GMS <0-7902'>"KBU33-6,Pad 41-7 PMSS <8846 - 10960>"KTU24-6H,Pad 41-7 GMS <0-5900'>"KU24-5,Pad 41-7 GMS <0-5350'>"KU11-8,Pad 41-7 PMSS <0 - 7570>"KBU42-7,Pad 41-7 MSS <0-5707'>"KU 43-7,Pad 41-7 GMS <0-5549'>"KDU4,Pad 41-7 MSS <4320 - 10810'>"KDU4Rd,Pad 41-7 MWD <3470 - 4816>"KU24-5Rd,Pad 41-7 MWD <0-7440>"KBU 44-6,Pad 41-7 GMS <0-7290>"KBU41-7,Pad 41-7 30-May-1995 31-May-1995 31-May-1995 19-Mar-2002 17-May-2002 31-Jan-2002 30-Jan-2002 20-Apr-1999 23-Ju1-1995 16-Auq-1995 31-Auq-2000 20-Jan-1994 21-Jan-1994 21-Jan-1994 22-Jun-2000 1-Auq-2000 21-Jan-1994 21-Jan-1994 9-Feb-2001 21-Jan-1994 5-May-1995 5-May-1995 9-Jan-2002 3-Mar-2002 13-Mar-2002 7387.9 798.2 2870.1 381. 3 267.4 264.0 264.0 5668.6 246.6 246.6 163.7 380.3 430.0 223.7 57.8 105.4 457.1 463.6 81.8 476.3 234.7 234.7 457.1 213.5 319.2 900.0 6899.1 6386.6 0.0 0.0 780.0 780.0 8485.4 1525.0 1525.0 262.5 462.5 362.5 0.0 925.0 375.0 0.0 425.0 287.5 180.0 2500.0 2500.0 0.0 0.0 287.5 e 1050.0 6899.1 6386.6 1587.5 8485.4 937.5 937.5 8485.4 1525.0 1525.0 8485.4 462.5 362.5 712.5 925.0 375.0 0.0 425.0 8460.0 6062.5 2500.0 2500.0 0.0 8460.0 8420.0 e e MARATHON Oil Company CLEARANCE LISTING Page 2 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version 112 Kenai Gas Field,Kenai Peninsula, Alaska Last revised : 8-Apr-2003 Refer(j!nce wellpath Object wellpath PMSS <0-8864>"KTU32-7,Pad 41-7 Horiz Minim TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 0.0 0.0 O.ON O.OE 0.1 0.1 79.3S 143.7E 118.9 164.1 164.1 100.0 100.0 O.ON O.OE 100.2 100.2 79.0S 143.8E 118.8 164.1* 164.1* 200.0 200.0 O.ON O.OE 200.5 200.5 78.1S 144.1E 118.5 163.9* 163.9* 250.0 250.0 O.ON O.OE 251.0 251.0 77.5S 144.2E 118.3 163.7* 163.7* 262.5 262.5 O.OS O.OW 263.5 263.5 77.4S 144.2E 118.2 163.7* 163.7* 275.0 275.0 O.OS O.lW 276.0 276.0 77.2S 144.2E 118.1 163.7 163.7 287.5 287.5 O.lS 0.3W 288.5 288.5 77.0S 144.2E 118.0 163.7 163.7 300.0 300.0 0.2S 0.5W 301.0 301.0 76.9S 144.2E 117.9 163.8 163.8 312.5 312.5 0.3S 0.8W 313.5 313.4 76.7S 144.2E 117.8 163.9 163.9 325.0 325.0 0.4S 1.2W 326.0 325.9 76.5S 144.2E 117.6 164.1 164.1 337.5 337.5 0.6S 1.6W 338.4 338.4 76.3S 144.3E 117.4 164.3 164.3 350.0 350.0 0.7S 2.0W 351.5 351.5 76.1S 144.2E 117.3 164.6 164.6 362.5 362.5 0.9S 2.6W 364.0 364.0 75.9S 144.2E 117.1 164.9 164.9 375.0 374.9 1.2S 3.2W 376.5 376.5 75.7S 144.2E 116.8 165.2 165.2 387.5 387.4 1.4S 3.9W 389.7 389.7 75.5S 144.1E 116.6 165.5 165.6 400.0 399.9 1. 7S 4.6W 402.2 402.1 75.4S 144.0E 116.4 165.9 166.0 412.5 412.4 2.0S 5.4W 414.6 414.6 75.2S 143.9E 116.1 166.3 166.4 425.0 424.8 2.3S 6.3W 427.1 427.1 75.1S 143.8E 115.9 166.8 166.9 437.5 437.3 2.6S 7.2W 440.2 440.2 74.9S 143.6E 115.6 167.3 167.4 450.0 449.7 3.0S 8.2W 452.7 452.6 74.8S 143.5E 115.3 167.8 168.0 462.5 462.2 3.4S 9.3W 465.7 465.6 74.6S 143.3E 115.0 168.4 168.6 475.0 474.6 3.8S 10.4W 478.1 478.1 74.5S 143.1E 114.8 169.0 169.2 487.5 487.1 4.2S 11.6W 490.6 490.5 74.5S 142.8E 114.5 169.6 169.9 500.0 499.5 4.7S 12.8W 503.6 503.5 74.4S 142.5E 114.2 170.3 170.6 512.5 511.9 5.1S 14.1W 516.0 516.0 74.3S 142.2E 113.9 171.0 171.3 525.0 524.3 5.6S 15.5W 528.5 528.4 74.3S 141. 9E 113.6 171.8 172.1 537.5 536.7 6.2S 16.9W 541.4 541.3 74.3S 141. 6E 113.3 172.6 173.0 550.0 549.1 6.7S 18.4W 553.8 553.8 74.3S 141.2E 112.9 173.4 173.9 562.5 561.5 7.3S 20.0W 566.2 566.2 74.3S 140.9E 112.6 174.3 174.8 575.0 573.9 7.9S 21.6W 579.1 579.0 74.4S 140.5E 112.3 175.3 175.8 587.5 586.3 8.5S 23.3W 591.5 591. 4 74.5S 140.0E 112.0 176.3 176.8 600.0 598.6 9.1S 25.1W 603.9 603.8 74.6S 139.6E 111.7 177.3 177.9 612.5 611.0 9.8S 26.9W 616.7 616.6 74.7S 139.2E 111.3 178.4 179.0 625.0 623.3 10.5S 28.8W 629.1 629.0 74.8S 138.7E 111.0 179.5 180.2 637.5 635.7 11.2S 30.7W 641.5 641.4 75.0S 138.2E 110.7 180.6 181.5 650.0 648.0 11.9S 32.7W 654.5 654.4 75.2S 137.7E 110.4 181.9 182.7 662.5 660.3 12.7S 34.8W 666.9 666.7 75.4S 137.1E 110.0 183.1 184.0 675.0 672.6 13.4S 36.9W 680.0 679.8 75.6S 136.5E 10~. 7 184.4 185.4 687.5 684.8 14.2S 39.1W 692.4 692.2 75.9S 135.9E 109.4 185.7 186.8 700.0 697.1 15.1S 41.4W 705.5 705.3 76.2S 135.2E 109.1 187.1 188.2 712.5 709.4 15.9S 43.7W 717.9 717.7 76.5S 134.6E 108.8 188.5 189.7 725.0 721. 6 16.8S 46.1W 730.3 730.0 76.9S 133.9E 108.5 189.9 191.2 737.5 733.8 17.7S 48.5W 743.1 742.8 77.3S 133.1E 108.2 191. 4 192.8 750.0 746.0 18.6S 51.0W 755.5 755.2 77.7S 132.4E 107.9 192.9 194.4 760.0 755.8 19.3S 53.1W 765.4 765.0 78.0S 131.8E 107.6 194.2 195.8 770.0 765.5 20.1S 55.2W 775.2 774.9 78.4S 131.2E 107.4 195.5 197.2 780.0 775.3 20.9S 57.3W 785.3 784.9 78.7S 130.6E 107.1 196.8 198.7 790.0 785.0 21.7S 59.5W 795.1 794.7 79.0S 130.0E 106.8 198.2 200.2 800.0 794.7 22.5S 61.7W 805.0 804.6 79.3S 129.4E 106.6 199.6 201.7 ~l data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from slot IIKBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e MARATHON Oil Company Pad 41-7,KBU43-7X Kenai Gas Field,Kenai Peninsula, A1aska M.D. T.V.D. Reference wellpath Rect Coordinates 0.0 100.0 200.0 250.0 262.5 0.0 100.0 200.0 250.0 262.5 275.0 287.5 300.0 312.5 325.0 275.0 287.5 300.0 312.5 325.0 337.5 350.0 362.5 375.0 387.5 337.5 350.0 362.5 374.9 387.4 400.0 412.5 425.0 437.5 450.0 399.9 412.4 424.8 437.3 449.7 462.5 475.0 487.5 500.0 512.5 462.2 474.6 487.1 499.5 511.9 525.0 537.5 550.0 562.5 575.0 524.3 536.7 549.1 561.5 573.9 587.5 600.0 612.5 625.0 637.5 586.3 598.6 611.0 623.3 635.7 650.0 662.5 675.0 687.5 700.0 648.0 660.3 672.6 684.8 697.1 712.5 725.0 737.5 750.0 760.0 709.4 721.6 733.8 746.0 755.8 770.0 780.0 790.0 800.0 812.5 765.5 775.3 785.0 794.7 806.9 825.0 819.0 O.ON O.ON O.ON O.ON 0.05 O.OS 0.15 0.25 0.35 0.4S 0.65 0.75 0.95 1.25 1.45 1. 7S 2.0S 2.3S 2.65 3.05 3.45 3.8S 4.25 4.75 5.15 5.65 6.25 6.75 7.35 7.95 8.55 9.15 9.85 10.5S 11.25 11.95 12.75 13.45 14.25 15.15 15.95 16.85 17.75 18.65 19.35 20.15 20.95 21.7S 22.55 23.55 24.65 9.3W 10.4W 11.6W 12.8W 14.1W 15.5W 16.9W 18.4W 20.0W 21.6W 23.3W 25.1W 26.9W 28.8W 30.7W 32.7W 34.8W 36.9W 39.1W 41.4W 43.7W 46.1W 48.5W 51. OW 53.1W 55.2W 57.3W 59.5W 61.7W 64.5W 67.3W Object wellpath O.OE O.OE O.OE O.OE O.OW 0.0 99.3 199.2 249:2 261.6 M.D. T.V.D. 0.0 99.3 199.2 249.1 261. 6 274.1 286.6 299.1 311.6 324.0 336.5 349.0 361.5 374.0 386.4 398.9 411.4 423.9 436.3 448.8 461. 2 473.7 486.2 498.6 511.1 523.6 536.2 548.6 561.0 573.8 586.2 599.3 611.7 624.8 637.1 649.5 662.4 674.7 687.5 699.8 712.1 724.7 737.0 749.7 759.5 769.2 779.6 789.4 799.1 811.9 824.0 e CLEARANCE LISTING Page 3 Your ref KBU 43-7X Version #2 Last revised: 8-Apr-2003 GMS <0-7902'>"KBU33-6,Pad 41-7 Rect Coordinates Horiz MinIm Bearing Dist TCyl Dist 79.95 80.45 81.2S 81.65 81.75 81.8S 81.95 82.05 82.15 82.2S 82.35 82.45 82.55 82.75 82.85 82.95 83.05 83.1S 83.25 83.35 83.5S 83.6S 83.75 83.8S 83.95 84.05 84.15 84.25 84.25 84.3S 84.25 84.25 84.15 83.95 83.75 83.45 83.15 82.85 82.45 82.05 81.55 81.15 80.65 80.15 79.65 79.25 78.65 78.15 77.65 76.85 76.05 21. 3W 21.6W 22.1W 22.5W 22.6W 22.7W 22.9W 23.0W 23.1W 23.2W 23.4W 23.5W 23.6W 23.8W 23.9W 24.0W 24.2W 24.4W 24.5W 24.7W 24.8W 25.0W 25.2W 25.4W 25.6W 25.8W 26.0W 26.3W 26.5W 26.8W 27.1W 27.4W 27.8W 28.2W 28.6W 29.0W 29.5W 30.0W 30.5W 30.9W 31.4W 31.9W 32.4W 32.9W 33.3W 33.7W 34.2W 34.6W 35.0W 35.5W 36.0W 194.9 195.0 195.3 195.4 195.5 195.5 195.4 195.4 195.2 195.1 194.9 194.7 194.4 194.2 193.8 193.5 193.1 192.6 192.1 191.6 191. 0 190.4 189.7 189.0 188.3 187.5 186.7 185.8 184.8 183.9 182.8 181.8 180.7 179.5 178.3 177.0 175.7 174.3 172.8 171.1 169.4 167.6 165.6 163.6 161. 8 160.0 158.1 156.2 154.1 151.4 148.7 82.7 83.2 84.2 84.7 84.8 82.7 83.2 84.2 84.7 84.8 O.lW 0.3W 0.5W 0.8W 1.2W 274.1 286.6 299.1 311.6 324.1 84.8 84.9 84.9* 84.8* 84.7* 84.8 84.9 84.9* 84.8* 84.7* 1.6W 2.0W 2.6W 3.2W 3.9W 336.5 349.0 361.5 374.0 386.4 84.6* 84.5* 84.3* 84.0* 83.8* 84.6* 84.5* 84.3* 84.1* 83.8* 4.6W 5.4W 6.3W 7.2W 8.2W 398.9 411.4 423.9 436.4 448.8 83.5* 83.2* 82.8* 82.4* 82.0* 83.5* 83.2* 82.9* 82.5* 82.1* 461.3 473.7 486.2 498.6 511.2 523.6 536.2 548.6 561.0 573.9 586.3 599.4 611.8 624.8 637.2 649.6 662.5 674.9 687.7 700.0 712.3 724.9 737.2 749.9 759.7 769.5 779.9 789.7 799.4 812.2 824.4 81.6* 81.1 * 80.6* 80.1* 79.6* 81.7* 81.2* 80.7* 80.2* 79.7* 79.0* 78.5* 77.9* 77.2* 76.6* 79.1* 78.6* 77.9* 77.3* 76.7* 75.9* 75.1* 74.3* 73.4* 72.6* 76.0* 75.2* 74.5* 73.6* 72.7* 71.6* 70.7* 69.7* 68.8* 67.8* 71.8* 70.9* 69.9* 69.0* 68.0* 66.8* 65.9* 65.0* 64.2* 63.6* 67.0* 66.1* 65.2* 64.3* 63.7* 63.0* 62.4* 61.9* 61. 4 * 60.8* 63.1* 62.5* 62.0* 61. 5* 60.9* 60.3* 60.4* All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ ·e e MARATHON Oil Company CLEARANCE LI8TING Page 4 Pad 4l-7,KBU43-7X Your ref KBU 43-7X Version #2 Kenai Gas Field,Kenai Peninsula, Alaska Last revised : 8-Apr-2003 Reference wellpath Object wellpath GMS <0-7902'>"KBU33-6,Pad 41-7 Horiz Min'm TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 837.5 831.2 25.88 70.0W 836.5 836.1 75.1S 36.6W 145.9 59.8* 59.8* 850.0 843.3 27.1S 72.7W 849.3 848.8 74.28 37.1W 142.9 59.3* 59.4* 862.5 855.4 28.48 75.5W 861. 4 860.8 73.28 37.7W 139.9 58.9* 58.9* 875.0 867.5 29.78 78.2W 873.5 872.9 72.28 38.2W 136.7 58.5* 58.5* 887.5 879.7 31. 2S 80.8W 886.1 885.5 71.08 38.8W 133.4 58.2* 58.2* 900.0 891.8 32.78 83.5W 898.7 898.0 69.88 39.3W 130.0 58.0* 58.0* 912.5 903.9 34.3S 86.1W 910.7 909.9 68.58 39.9W 126.5 57.8* 57.8* 925.0 916.0 35.98 88.8W 923.1 922.2 67.18 40.5W 122.8 57.8* 57.8* 937.5 928.1 37.6S 91.4W 935.0 934.0 65.68 41.0W 119.1 57.9 57.9 950.0 940.2 39.48 94.0W 947.4 946.3 64.0S 41.6W 115.2 58.2 58.2 962.5 952.3 41.28 96.5W 959.2 958.0 62.38 42.2W 111.2 58.6 58.6 975.0 964.4 43.18 99.1W 971.4 970.0 60.58 42.8W 107.1 59.2 59.3 987.5 976.5 45.18 101.6W 983.1 981.5 58.58 43.3W 103.0 60.0 60.2 1000.0 988.6 47.1S 104.1W 995.0 993.2 56.48 43.9W 98.8 61.1 61.5 1012.5 1000.6 49.2S 106.6W 1006.8 1004.7 54.28 44.4W 94.5 62.5 63.1 1025.0 1012.7 51.48 109.1W 1018.2 1016.0 51.98 45.0W 90.5 64.2 65.0 1037.5 1024.7 53.68 111.6W 1029.7 1027.2 49.68 45.5W 86.5 66.2 67.3 1050.0 1036.8 55.98 114. OW 1041. 3 1038.5 47.28 46.1W 82.7 68.5 70.0 1062.5 1048.8 58.38 116.4W 1052.6 1049.6 44.88 46.7W 79.1 71.0 73.0 1075.0 1060.8 60.78 118.8W 1064.0 1060.6 42.48 47.3W 75.7 73.9 76.4 1087.5 1072.9 63.28 121. 2W 1075.2 1071 . 6 40.0S 47.9W 72.5 77.0 80.0 1100.0 1084.9 65.78 123.6W 1086.5 1082.6 37.58 48.5W 69.4 80.3 84.0 1112.5 1096.9 68.48 125.9W 1097.7 1093.5 35.08 49.1W 66.5 83.9 88.3 1125.0 1108.8 71.18 128.3W 1108.6 1104.1 32.58 49.7W 63.9 87.7 92.9 1137.5 1120.8 73.88 130.6W 1119.7 1114.9 30.08 50.3W 61.4 91.7 97.8 1150.0 1132.8 76.68 132.9W 1130.8 1125.7 27.48 50.9W 59.0 95.9 103.0 1162.5 1144.7 79.58 135.1W 1141.5 1136.1 24.98 51.5W 56.9 100.3 108.4 1175.0 1156.7 82.48 137 . 4W 1152.5 1146.7 22.28 52.1W 54.8 104.8 114.1 1187.5 1168.6 85.4S 139.6W 1163.5 1157.3 19.68 52.8W 52.8 109.6 120.0 1200.0 1180.5 88.58 141.8W 1173.9 1167.4 17.08 53.4W 51.0 114.5 126.3 1212.5 1192.4 91.68 144.0W 1184.7 1177.8 14.3S 54.0W 49.3 119.6 132.7 1225.0 1204.3 94.88 146.2W 1195.5 1188.3 11.58 54.7W 47.7 124.8 139.5 1237.5 1216.2 98.18 148.3W 1205.5 1197.9 9.08 55.3W 46.2 130.1 146.5 1250.0 1228.0 101.48 150.5W 1216.1 1208.2 6.28 56. OW 44.8 135.6 153.7 1262 . 5 1239.9 104.88 152.6W 1226.8 1218.4 3.48 56.6W 43.4 141. 3 161.3 1275.0 1251.7 108.38 154.7W 1236.3 1227.5 0.88 57.2W 42.2 147.0 169.2 1287.5 1263.5 111 . 88 156.8W 1246.8 1237.6 2.0N 57.9W 41.0 152.9 177.3 1300.0 1275.3 115.38 158.8W 1257.2 1247.7 4.9N 58.6W 39.8 158.9 185.8 1312.5 1287 . 1 119.08 160.8W 1266.4 1256.5 7.4N 59.2W 38.8 165.1 194.6 1325.0 1298.9 122.78 162.9W 1276.8 1266 . 4 10.4N 59.8W 37.8 171.4 203.8 1337.5 1310.6 126.58 164.8W 1287.1 1276.2 13.3N 60.5W 36.7 177.8 213.3 1350.0 1322.4 130.38 166.8W 1296.0 1284.7 15.9N 61.1W 35.9 184.3 223.0 1362.5 1334.1 134.28 168.8W 1306.2 1294.4 18.9N 61.8W 35.0 190.9 232.9 1375.0 1345.8 138.18 170.7W 1314.8 1302.7 21. 4N 62.3W 34.2 197.6 243.1 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e - MARATHON Oil Company CLEARANCE LI5TING Page 5 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version #2 Kenai Gas Field,Kenai Peninsula, Alaska Last revised : 8-Apr-2003 Reference wellpath Object wellpath PMS5 <8846 - 10960>"KTU24-6H,Pad 41-7 Horiz Min I m TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 0.0 0.0 O.ON O.OE 0.4 0.4 77.65 78.6E 134.6 110.5 110.5 100.0 100.0 O.ON O.OE 101. 3 101.2 77.35 78.2E 134.7 109.9* 109.9* 200.0 200.0 O.ON O.OE 202.1 202.0 76.45 76.8E 134.9 108.3* 108.3* 250.0 250.0 O.ON O.OE 252.9 252.8 75.75 75.7E 135.0 107.1* 107.1* 262.5 262.5 0.05 O.OW 265.4 265.3 75.55 75.4E 135.0 106.7* 106.8* 275.0 275.0 O.OS O.lW 277 .9 277.8 75.35 75.1E 135.0 106.4* 106.5* 287.5 287.5 0.15 0.3W 290.5 290.5 75.15 74.8E 135.0 106.1* 106.2* 300.0 300.0 0.25 0.5W 302.6 302.5 75.0S 74.4E 134.9 105.9* 105.9* 312.5 312.5 0.35 0.8W 314.9 314.9 75.05 74.0E 134.9 105.7* 105.7* 325.0 325.0 0.45 1.2W 327.4 327.4 75.0S 73.6E 134.9 105.6* 105.6* 337.5 337.5 0.65 1.6W 339.9 339.8 75.15 73.2E 134.9 105.5* 105.5* 350.0 350.0 0.7S 2.0W 352.4 352.3 75.15 72.7E 134.8 105.5* 105.5* 362.5 362.5 0.95 2.6W 364.9 364.8 75.25 72.3E 134.7 105.5* 105.5* 375.0 374.9 1.25 3.2W 377 .4 377.3 75.2S 71.9E 134.6 105.4* 105.4* 387.5 387.4 1.45 3.9W 389.9 389.8 75.25 71.4E 134.4 105.5 105.5 400.0 399.9 1. 7S 4.6W 402.4 402.3 75.35 71. OE 134.2 105.5 105.5 412.5 412.4 2.05 5.4W 415.1 415.0 75.35 70.5E 134.0 105.6 105.6 425.0 424.8 2.35 6.3W 427.6 427.5 75.3S 70.1E 133.7 105.7 105.7 437.5 437.3 2.65 7.2W 440.1 439.9 75.45 69.6E 133.4 105.8 105.8 450.0 449.7 3.05 8.2W 452.6 452.4 75.45 69.2E 133.1 106.0 106.0 462.5 462.2 3.45 9.3W 465.0 464.9 75.4S 68.7E 132.7 106.2 106.2 475.0 474.6 3.85 10.4W 477 .5 477.4 75.4S 68.3E 132.3 106.4 106.5 487.5 487.1 4.25 11.6W 490.0 489.8 75.55 67.8E 131.9 106.7 106.7 500.0 499.5 4.7S 12.8W 502.5 502.3 75.55 67.4E 131.5 107.0 107.0 512.5 511.9 5.15 14.1W 514.9 514.7 75.5S 66.9E 131.0 107.4 107.4 525.0 524.3 5.65 15.5W 527.3 527.1 75.55 66.5E 130.5 107.7 107.8 537.5 536.7 6.25 16.9W 539.8 539.6 75.55 66.0E 129.9 108.2 108.2 550.0 549.1 6.75 18.4W 552.2 552.0 75.55 65.6E 129.3 108.6 108.7 562.5 561.5 7.35 20.0W 564.6 564.4 75.65 65.1E 128.7 109.1 109.3 575.0 573.9 7.95 21.6W 577 .1 576.8 75.6S 64.7E 128.1 109.7 109.8 587.5 586.3 8.55 23.3W 589.5 589.3 75.65 64.2E 127.5 110.3 110.5 600.0 598.6 9.15 25.1W 601.9 601.7 75.65 63.8E 126.8 111.0 111.2 612.5 611.0 9.85 26.9W 614.3 614.1 75.75 63.3E 126.1 111.8 112.0 625.0 623.3 10.55 28.8W 626.7 626.5 75.75 62.9E 125.4 112.6 112.8 637.5 635.7 11.2S 30.7W 638.8 638.5 75.75 62.5E 124.7 113.4 113.7 650.0 648.0 11.95 32.7W 651.1 650.9 75.85 62.1E 124.0 114.3 114.7 662.5 660.3 12.75 34.8W 663.5 663.2 75.8S 61.7E 123.2 115.3 115.7 675.0 672.6 13.4S 36.9W 675.9 675.6 75.8S 61.2E 122.4 116.4 116.8 687.5 684.8 14.25 39.1W 688.2 687.9 75.95 60.8E 121. 7 117.5 118.0 700.0 697.1 15.15 41.4W 700.6 700.3 75.95 60.4E 120.9 118.6 119.2 712.5 709.4 15.9S 43.7W 712.9 712.6 76.05 60.0E 120.1 119.9 120.5 725.0 721. 6 16.85 46.1W 725.2 724.9 76.0S 59.6E 119.3 121. 2 121. 9 737.5 733.8 17.75 48.5W 737.5 737.2 76.15 59.2E 118.5 122.6 123.4 750.0 746.0 18.65 51.0W 749.8 749.5 76.15 58.8E 117.6 124.1 125.0 760.0 755.8 19.35 53.1W 759.6 759.3 76.25 58.5E 117.0 125.3 126.3 770.0 765.5 20.15 55.2W 769.1 768.7 76.25 58.2E 116.3 126.6 127.7 780.0 775.3 20.9S 57.3W 778.9 778.5 76.25 57.9E 115.7 127.9 129.1 790.0 785.0 21.75 59.5W 788.7 788.3 76.35 57.6E 115.0 129.2 130.6 800.0 794.7 22.5S 61.7W 798.4 798.1 76.35 57.3E 114.4 130.7 132.1 812.5 806.9 23.55 64.5W 810.7 810.3 76.45 56.9E 113.5 132.5 133.9 825.0 819.0 24.65 67.3W 822.9 822.5 76.55 56.5E 112.7 134.3 135.7 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ · e MARATHON Oil Company CLEARANCE LI5TING Page 6 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version #2 Kenai Gas Field,Kenai Peninsula, Alaska Last revised : 8-Apr-2003 Reference wellpath Object wellpath PMS5 <8846 - 10960>"KTU24-6H,Pad 41-7 Horiz Minim TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 837.5 831.2 25.8S 70.0W 835.1 834.7 76.55 56.2E 111.9 136.0 137.5 850.0 843.3 27.15 72.7W 846.9 846.6 76.65 55.8E 111.1 137.8 139.3 862.5 855.4 28.45 75.5W 859.2 858.8 76.65 55.5E 110.2 139.6 141.1 875.0 867.5 29.75 78.2W 871.4 871. 0 76.75 55.1E 109.4 141.4 142.8 887.5 879.7 31.2S 80.8W 883.6 883.2 76.8S 54.8E 108.6 143.1 144.6 900.0 891. 8 32.75 83.5W 895.8 895.4 76.85 54.5E 107.7 144.9 146.4 912.5 903.9 34.3S 86.1W 907.9 907.5 76.9S 54.1E 106.9 146.6 148.2 925.0 916.0 35.95 88.8W 920.1 919.7 77 .OS 53.8E 106.1 148.4 149.9 937.5 928.1 37.65 91.4W 931.7 931.3 77.05 53.5E 105.2 150.2 151.7 950.0 940.2 39.45 94.0W 943.8 943.4 77.15 53.2E 104.4 151.9 153.6 962.5 952.3 41. 25 96.5W 956.0 955.6 77.15 52.9E 103.5 153.7 155.4 975.0 964.4 43.15 99.1W 968.1 967.7 77.25 52.6E 102.7 155.5 157.2 987.5 976.5 45.1S 101.6W 980.3 979.9 77.3S 52.3E 101.8 157.3 159.1 1000.0 988.6 47.15 104.1W 991.5 991.1 77.3S 52.1E 100.9 159.2 161.0 1012.5 1000.6 49.25 106.6W 1003.6 1003.2 77 .45 51.9E 100.1 161.0 162.9 1025.0 1012.7 51.45 109.1W 1015.7 1015.3 77 .45 51.7E 99.2 162.9 164.9 1037.5 1024.7 53.65 111.6W 1027.8 1027.4 77.55 51.5E 98.3 164.8 166.9 1050.0 1036.8 55.9S 114. OW 1039.9 1039.5 77.55 51. 3E 97.4 166.7 168.9 1062.5 1048.8 58.35 116.4W 1050.9 1050.5 77 .55 51.1E 96.6 168.7 171.0 1075.0 1060.8 60.75 118.8W 1063.0 1062.6 77.65 51.0E 95.7 170.7 173.0 1087.5 1072 . 9 63.25 121.2W 1075.0 1074.6 77 .6S 50.8E 94.8 172.7 175.2 1100.0 1084.9 65.75 123.6W 1087.1 1086.6 77 .6S 50.7E 93.9 174.7 177.3 1112.5 1096.9 68.45 125.9W 1098.6 1098.1 77 .75 50.6E 93.0 176.8 179.5 1125.0 1108.8 71.15 128.3W 1110.6 1110.1 77 .75 50.5E 92.1 178.9 181.7 1137.5 1120.8 73.8S 130.6W 1122.6 1122.1 77 .75 50.4E 91.2 181.1 183.9 1150.0 1132.8 76.65 132.9W 1134.6 1134.1 77.85 50.4E 90.4 183.2 186.2 1162.5 1144.7 79.55 135.1W 1146.5 1146.1 77.85 50.3E 89.5 185.4 188.5 1175.0 1156.7 82.45 137.4W 1158.5 1158.1 77.8S 50.2£ 88.6 187.6 190.8 1187.5 1168.6 85.4S 139.6W 1170.5 1170.0 77.95 50.1E 87.7 189.9 193.2 1200.0 1180.5 88.5S 141.8W 1182.4 1182.0 77.95 50.0E 86.8 192.1 195.6 1212 . 5 1192.4 91.65 144.0W 1194.3 1193.9 77.95 49.9E 86.0 194.4 198.0 1225.0 1204.3 94.85 146.2W 1206.2 1205.8 78.05 49.8E 85.1 196.7 200.5 1237.5 1216.2 98.15 148.3W 1218.1 1217.7 78.05 49.7E 84.2 199.1 203.0 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ · - MARATHON Oil Company CLEARANCE LI5TING Page 7 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version #2 Kenai Gas Field,Kenai Peninsula, Alaska Last revised : 8-Apr-2003 Reference wellpath Object wellpath PMS5 <0 - 7570>"KBU42-7,Pad 41-7 Horiz MinIm TCyl M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 0.0 0.0 O.ON O.OE 0.2 0.2 78.45 27.7E 160.5 83.1 83.1 100.0 100.0 O.ON O.OE 100.6 100.6 78.1S 27.6E 160.5 82.9* 82.9* 200.0 200.0 O.ON O.OE 200.6 200.6 77.55 27.2E 160.6 82.1* 82.1* 250.0 250.0 O.ON O.OE 250.2 250.2 77.35 27.0E 160.8 81. 8* 81. 8* 262.5 262.5 0.05 O.OW 262.7 262.7 77.25 26.9E 160.8 81. 8* 81.8* 275.0 275.0 0.05 O.lW 275.2 275.2 77 .25 26.8E 160.7 81. 8* 81. 8* 287.5 287.5 0.15 0.3W 287.2 287.2 77 .35 26.8E 160.7 81. 8* 81. 8* 300.0 300.0 0.25 0.5W 299.7 299.7 77 .3S 26.7E 160.6 81.8 81.8 312.5 312.5 0.35 0.8W 312.2 312.2 77 .45 26.6E 160.4 81.8 81.8 325.0 325.0 0.45 1.2W 324.1 324.1 77 .65 26.5E 160.3 81.9 81.9 337.5 337.5 0.6S 1.6W 336.6 336.6 77 .8S 26.3E 160.1 82.1 82.1 350.0 350.0 0.75 2.0W 348.5 348.4 78.0S 26.2E 159.9 82.3 82.3 362.5 362.5 0.95 2.6W 361. 0 360.9 78.35 26.0E 159.7 82.5 82.5 375.0 374.9 1.25 3.2W 372.8 372.8 78.65 25.8E 159.5 82.7 82.8 387.5 387.4 1.4S 3.9W 385.3 385.3 79.05 25.6E 159.2 83.0 83.1 400.0 399.9 1. 75 4.6W 397.8 397.8 79.55 25.3E 159.0 83.4 83.4 412.5 412.4 2.05 5.4W 409.6 409.5 79.95 25.1E 158.6 83.8 83.8 425.0 424.8 2.35 6.3W 422.0 422.0 80.55 24.8E 158.3 84.2 84.3 437.5 437.3 2.65 7.2W 433.7 433.6 81.15 24.5E 158.0 84.7 84.8 450.0 449.7 3.05 8.2W 446.1 446.0 81. 75 24.2E 157.6 85.2 85.3 462.5 462.2 3.4S 9.3W 458.6 458.5 82.5S 23.9E 157.3 85.8 86.0 475.0 474.6 3.85 10.4W 470.2 470.1 83.2S 23.6E 156.8 86.5 86.6 487.5 487.1 4.25 ll.6W 482.7 482.5 84.05 23.3E 156.4 87.2 87.4 500.0 499.5 4.75 12.8W 494.3 494.1 84.95 23.0E 156.0 88.0 88.2 512.5 5ll.9 5.15 14.1W 506.8 506.5 85.85 22.6E 155.5 88.8 89.0 525.0 524.3 5.65 15.5W 519.2 518.9 86.95 22.2E 155.1 89.7 90.0 537.5 536.7 6.25 16.9W 530.8 530.5 87.95 21.9E 154.6 90.7 91.0 550.0 549.1 6.75 18.4W 543.3 542.9 89.0S 21. 5E 154.1 91.7 92.0 562.5 561. 5 7.35 20.0W 555.0 554.5 90.15 21.1E 153.6 92.7 93.1 575.0 573.9 7.95 21.6W 567.4 566.9 91. 35 20.7E 153.1 93.8 94.3 587.5 586.3 8.55 23.3W 579.8 579.2 92.65 20.3E 152.6 95.0 95.5 600.0 598.6 9.15. 25.1W 591.5 590.8 93.85 19.9E 152.0 96.2 96.7 612.5 6ll.0 9.85 26.9W 603.9 603.1 95.25 19.5E 151.5 97.5 98.1 625.0 623.3 10.5S 28.8W 615.4 614.5 96.55 19.1E 150.9 98.9 99.5 637.5 635.7 ll.25 30.7W 627.8 626.8 98.05 18.6E 150.4 100.2 100.9 650.0 648.0 ll.95 32.7W 640.1 639.1 99.55 18.2E 149.8 101.7 102.5 662.5 660.3 12.7S 34.8W 651.4 650.2 100.95 17.9E 149.2 103.3 104.1 675.0 672.6 13.45 36.9W 663.7 662.5 102.55 17.6E 148.5 104.9 105.9 687.5 684.8 14.25 39.1W 674.9 673.6 104.05 17.3E 147.9 106.6 107.7 700.0 697.1 15.15 41.4W 687.2 685.8 105.65 17.0E 147.2 108.4 109.6 712.5 709.4 15.95 43.7W 699.5 697.9 107.45 16.7E 146.5 llO .2 lll.6 725.0 721.6 16.8S 46.1W 710.7 709.0 109.05 16.5E 145.8 ll2.2 ll3.6 737.5 733.8 17.7S 48.5W 723.0 721.2 llO.75 16.4E 145.1 ll4.2 ll5.8 750.0 746.0 18.6S 51.0W 734.2 732.3 ll2 .35 16.3E 144.3 ll6.2 ll8.0 760.0 755.8 19.35 53.1W 744.0 741. 9 ll3.7S 16.3E 143.7 ll8.0 ll9.9 770.0 765.5 20.15 55.2W 753.7 751. 6 ll5.15 16.3E 143.1 ll9.7 121.8 780.0 775.3 20.95 57.3W 763.5 761. 2 ll6.6S 16.3E 142.4 121.6 123.8 790.0 785.0 21.75 59.5W 772.1 769.7 ll7 . 85 16.4E 141.7 123.4 125.9 800.0 794.7 22.5S 61.7W 781. 8 779.3 ll9.25 16.5E 141.1 125.4 128.0 812.5 806.9 23.55 64.5W 793.9 791.3 121.05 16.7E 140.2 127.8 130.6 825.0 819.0 24.65 67.3W 804.8 802.1 122.65 16.9E 139.3 130.3 133.1 All data is in feet unless otherwise stated. Casing d~nsions are not included. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level) . Total Dogleg for wellpath is 0.00 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ e . MARATHON Oil Company CLEARANCE LI8TING Page 8 Pad 41-7,KBU43-7X Your ref KBU 43-7X Version #2 Kenai Gas Field,Kenai Peninsula, Alaska Last revised : 8-Apr-2003 Reference we11path Object we11path PMS8 <0 - 7570>"KBU42-7,Pad 41-7 Horiz Minim TCy1 M.D. T.V.D. Rect Coordinates M.D. T.V.D. Rect Coordinates Bearing Dist Dist 837.5 831.2 25.88 70.0W 816.9 814.1 124.4S 17.3E 138.5 132.8 135.7 850.0 843.3 27.18 72.7W 828.2 825.2 126.18 17.6E 137.6 135.3 138.2 862.5 855.4 28.4S 75.5W 840.3 837.1 127.9S 18.1E 136.8 137.8 140.7 875.0 867.5 29.78 78.2W 852.3 849.1 129.68 18.5E 135.9 140.2 143.2 887.5 879.7 31. 28 80.8W 863.9 860.5 131. 38 19.0E 135.1 142.7 145.6 900.0 891.8 32.7S 83.5W 876.0 872.5 133.0S 19.6E 134.2 145.1 148.1 912.5 903.9 34.38 86.1W 887.5 883.8 134.68 20.2E 133.3 147.6 150.6 925.0 916.0 35.98 88.8W 899.6 895.8 136.38 20.9E 132.5 150.0 153.0 937.5 928.1 37.68 91.4W 911.6 907.7 137.98 21. 6E 131. 6 152.4 155.5 950.0 940.2 39.48 94.0W 923.0 918.9 139.48 22.3E 130.7 154.8 158.0 962.5 952.3 41. 28 96.5W 935.0 930.8 141.08 23.1E 129.8 157.2 160.4 975.0 964.4 43.18 99.1W 947.0 942.7 142.68 23.9E 129.0 159.6 162.9 987.5 976.5 45.1S 101.6W 958.5 954.0 144.08 24.8E 128.1 162.0 165.3 1000.0 988.6 47.18 104.1W 970.5 965.9 145.58 25.7E 127.2 164.5 167.8 1012.5 1000.6 49.28 106.6W 982.5 977.8 147.08 26.6E 126.3 166.9 170.2 1025.0 1012.7 51.4S 109.1W 993.9 989.1 148.48 27.6E 125.4 169.3 172.7 1037.5 1024.7 53.68 111.6W 1005.9 1000.9 149.88 28.6E 124.5 171. 7 175.1 1050.0 1036.8 55.9S 114. OW 1017.8 1012.7 151. 28 29.6E 123.6 174.1 177.6 1062.5 1048.8 58.38 116.4W 1029.8 1024.6 152.68 30.7E 122.7 176.5 180.1 1075.0 1060.8 60.78 118.8W 1041.0 1035.7 153.98 31.8E 121. 7 178.9 182.6 1087.5 1072 . 9 63.28 121.2W 1052.9 1047.5 155.28 32.9E 120.8 181.3 185.0 1100.0 1084.9 65.7S 123.6W 1064.9 1059.3 156.5S 34.1E 119.9 183.7 187.5 1112.5 1096.9 68.4S 125.9W 1076.3 1070.6 157.7S 35.3E 119.0 186.1 190.0 1125 . 0 1108.8 71.1S 128.3W 1088.2 1082.3 158.98 36.5E 118.1 188.6 192.5 1137.5 1120.8 73.88 130.6W 1100.1 1094.1 160.28 37.7E 117.2 191. 0 195.0 1150.0 1132.8 76.68 132.9W 1112.0 1105.9 161. 4S 38.9E 116.3 193.5 197.5 1162.5 1144.7 79.58 135.1W 1123.9 1117.6 162.7S 40.2E 115.4 195.9 200.0 1175.0 1156.7 82.48 137.4W 1135.7 1129.4 163.98 41.4E 114.5 198.3 202.5 All data is in feet unless otherwise stated. Casing dimensions are not included. Coordinates from slot #KBU43-7X and TVD from RKB (Glacier 1) (87.00 Ft above mean sea level). Total Dogleg for we11path is 0.00 degrees. Vertical section is from wellhead on azimuth 185.91 degrees. Calculation uses the minimum curvature method. Presented by Baker Hughes INTEQ H IL C Y ell Kenai Beluga Unit 43...7X Kenai, Alaska Prepared by: Tony Tykalsky Reviewed by: Lee Dewees Submitted to: Will Tank M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax M~I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 Phone (907) 274-5564 Fax (907) 2709-6729 Marathon Oil Company PO Box 190168 Anchorage, Alaska 99519 ATTN: Will Tank Will; Enclosed is the recommended drilling fluid program for Well KBD 43-7X to be drilled this year. The following is a brief synopsis of the program. Overview: KED 43-7X is a development well targeting the Lower Beluga formation of the Kenai Gas Field. At T.D.,3 1/2" casing will be run and cemented in place. The well will be completed with KCl brine. Gel/ Gelex spud mud will be used for the surface interval. A modified Flo-Pro fluid with sized calcium car- bonate is recommended for the intermediate interval. A Flo-Pro fluid will be used for the bottom inter- vals. Surface Interval: A standard fresh water Gel/Gelex spud mud will be used. Initial funnel viscosity should be in the 50 - 75 sec/qt range. Lower funnel viscosity to 45 - 60 sec/qt after gravel has been drilled. Lower fluid loss to < 10 cc' s API prior to running surface casing. Intermediate Interval: This interval will be drilled with a modified Flo-Pro fluid with sized calcium carbonate to bridge off the low pressure/high permeability intervals of the Sterling and Beluga formations. After drilling out the surface cement and 20 25 feet of new hole, the pits should be cleaned and the well displaced to a new fluid per the listed formula. Calcium carbonate concentration should be maintained throughout the entire interval. Mud weights should be kept as low as possible through aggressive use of solids control equipment. Fluid loss may be controlled prior to running casing if on-site personnel feel it is waranted. Production Interval: This interval will also be drilled with Flo-Pro fluid. Chloride concentrations should be maintained be- tween 25,000 & 30,000 PPM. Fluid loss should be maintained below 6 cc's API with additions of DualFlo. Completion: This program assumes the well will be completed with 6% KCl brine. Reference Wells: KED 42-7, KBD 24-6, KTD 32-7 NOTE: This mud program is referenced as a guidline only. Actual hole conditions will dictate required properties. Tony Tykalsky Project Engineer MI Drilling Fluids 13 3/8" 17 9 5/8" 12 1/4" 3 1/2" 8 1/2" 3 1/2" 8.1/2" 1500' 1500' Gel/Gelex Spud Well KBU 43-7X 9.2 6,471' 5347' Flo- Pro wI SafeCarb 8.6-9.2 +/- 9.0 10 8,485 ' Flo-Pro w/ SafeCarb 8.55 .. A Gel/Gelex system will be used for the surface interval. .. The surface hole fluid will be used to drill out cement and several feet of new hole. .. After drilling out the surface casing and new hole, displace the spud mud to a new FIo-Pro fluid with SafeCarb bridging material. .. The production interval will be drilled with a FloPro fluid. Well conditions (gas) may require weighting up the fluid to 10.0 ppg or higher based on offset wells. .. 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. M-I Drilling Fluids L.L.c. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax 7,325' Com 6% KCl 7320' 7200' M-I Bar 100 Ib 174 146 136 0 456 M-I Gel 100 lb 391 0 0 0 391 Gelex 21b 43 0 0 0 43 Soda Ash 501b 12 15 7 0 34 Caustic Soda 50 lb 17 29 14 0 60 Conqor 404 55 gal 0 7 5 0 12 SafeScav NA 55 gal 1 7 3 0 11 Sodium Bicarbonate 501b 17 15 14 0 46 Conqor 303 55 gal 0 0 0 10 10 FloVis 251b 0 233 108 4 345 Desco CF 251b 17 0 0 0 17 DualFlo 501b 0 0 136 0 136 Polypac Supreme 50 lb 21 0 0 0 21 Bioban BP-Plus lIb 0 233 108 0 341 Lubetex 55 gal 0 33 0 0 33 Greencide 25G 55 gal 0 0 2 0 2 KlaGard 55 GAL 0 25 0 0 25 KCI 501b 0 1224 569 441 1132 Safecarb 50 lb 0 1166 136 0 1302 SafeKleen 55 gal 0 1 1 1 3 Defoam X 5 gal 0 27 15 0 42 Engineer Service 1 day 4 10 10 4 28 M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Well KBU 43-7X Well Hole Size Depth PPG PV YP FL Comments KBU 42-7 17.5 1006 8.9 12 30 11.2 1760 9 12 19 11.6 LOT 15.6 12.25 3455 9.3 10 17 8.9 Drlg 1675' 4371 9.35 9 25 11 Trip OK drlg 915' 5205 9.4 14 11 5.5 100% 5590 9.3 14 18 7.6 Drlg ahead; lost 40 bbls (LCM Plug M & MI Seal) 100% losses @ 4890 more LCM (Plug M) Drlg to csg point, spot LCM pill, run csg; lost 50 bbls during cementing 8.5 6131 9.7 13 24 10.8 Drlg out, LOT 13.3 6733 10 15 19 8 7000 9.9 15 19 7.8 Drill ahead 7293 10.15 15 21 7.5 Drill ahead, increase ppg to 10.3 7570 10.6 22 22 6.6 Drlg to td; short trip; increase ppg to 10.6 7570 11 22 19 6.3 .0 KTU 32-7 12.25 108 8.45 1 0 N/A H20 & sweeps 1510 8.4 1 0 N/A Fill @ 157' pump sweep 8.5 1535 9.2 7 22 8.4 Drlg out, LOT 18.4, FloPro fluid 4054 9.3 8 18 10.5 Drlg 2519' in one day 5697 9.5 10 36 12.1 Drlg to csg pooint 5697 9.5 8 18 8.2 Lost 150 bbls while running 7" casing; no returns during cement job 6.125 6558 9.4 9 27 7 Drlg out, LOT 13.0 7249 9.8 11 34 6.8 Drlg ahead, short trip, raise ppg to 9.8 7530 10.6 12 35 6.4 Drlg ahead, inc raise to 10.6 8087 10.7 13 31 7.4 Drlg ahead 8328 10.8 14 31 7 Drlg ahead, trip for bit 8676 11.5 14 31 7.2 8864 11.5 14 25 7.4 Drlg to core point, short trip, circ out 400 units of gas 9117 11.55 13 26 6.6 Drlr to td. POH for logs, log well 9117 12 14 18 6.4 After logs, circ out gas, RIH, taking gas, increase ppg to 12.0 9117 11.5 14 12 7.6 Run liner, diff stuck, work free, reduce ppg to 11.5, cement liner KBU 24-6 17.5 1008 8.85 28 67 7.5 Gel/Gel ex spud mud 1525 8.65 12 26 11.4 Sweep hole prior to running surface casing 12.25 1818 8.75 7 27 6.2 Drlg out, LOT 18.4, FloPro fluid 3610 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 4645 9.6 9 20 7.8 Drlg ahead, increase ppg to 9.6 4982 9.7 9 22 10 Drlg ahead 5213 9.8 11 27 8 Drlg ahead 5505 9.6 12 17 9.8 Lower vis & yp for casing run 5505 9.3 7 14 7.8 8.5 6395 9.55 8 25 7.7 Drlg ahead, LOT 14.5 7420 9.6 9 27 7.5 Drl9 ahead 7500 10.15 10 24 8.1 Drlg ahaed increase ppg to 10.0 POH for logs 7500 10.3 11 25 6.2 LOG, RIH spot 16.0 ppg píll on bottom, run liner, condition & cement M-I Drilling Fluids L.L.C. DIIIL.I..ING 721 West First Avenue Anchorage, Alaska 99501 FL.UIDS (907) 274-5564 (907) 279-6729 Fax Wen KBU 43-7X Well KBU 43-7X =:> COMMUNICATION - The Field Mud Engineer will communicate daily. with the In- Town Project Engineer. The Project Engineer will then communicate dally' with the rig Drilling Engineer. Communications should be about, but not limited to, fluid proper- ties, nole aifficulties, possible changes to the mud program, and proposals to use products not included In the mud program. =:> Whole Mud losses to the Sterling & Bel a Sands - Refer to fluid formulas and the Optibridge charts for maintaining proper b 'ng material concentration in the mud system while drilling the intermediate and production intervals. =:> FLUID lOSS CONTROL - In the intermediate interval the API fluid loss NOT be controlled. In the production interval the API fluid will be maintained at I than 8 cc's at all times. In addition to sufficient fluid loss agent additions¡ this may r ire adequate dilution of the mud system in order to keep reactive dril solids to a ni- mum. It is larly important to maintain a low hardness «200 ppm Ca) for c- tive use of 0, tñerefore cement contamination should De completely treated as rapidly as possible prior to adding DualFlo to control or reduce fluid loss. NOTE: If additions of DualFlo do not ,ªppear to be lowering the fluid loss adequately, then switch to additions of Polypac Supreme SL after consultation with town. =:> lSRV - When drill" with a FloPro fluid, the low shear rate should main- tained around 40,0 ps. In addition to adequate additions of is Plus will also require kee' reactive drill solids to a minimum in order to reduce or eliminate false and unwan igh LSRV. =:> DRill SOLIDS - MBT - The MBT should be kept at less than 7.5 ppb in the produc- tion interval 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 water in that order and then blended into the active system over one or two circ tions as needed. =:> CORROSION - Conqor 404 additions should be made daily when drilling with FloPro fluid in order to maintain a Conqor 404 concentration of +/- 2000 PPM. =:> CORROSION - Monitor the dissolved oxygen concentration daily when any fluid is in the well. Check the source water weekly for DO. Maintain the DO reading at less than 3 with additions of SafeScav NA. =:> GREENCIDE 25G ADDITIONS - Greencide 25G additions should be made daily in the production interval. =:> SOLIDS VAN USAGE - The Solids Van should be used whenever drill solids become un-acceptably reduction of drill solids in the mud can be more economically. done with cen and dilution thend'ust with dumping and diluting. The weight of the drilling fluid al should not be the etermining condItion for when to use the Sol- ids Van. =:> WEIGHTING UP - All increases in mud weight should be accomplished with barite ad- ditions. In the production interval, insure chloride concentration is maintained at 30,000 to minimize the need for barite additions. M-I Drilling Fluids L.L.e. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Well KEU 43-7X MI Gel / Gelex / Soda Ash / Caustic Soda / MI Bar / Polypac Su- preme SL / M-I Seal/Sodium Bicarbonate Shale Shakers / Centrifuge Van ? Lost circulation, coal sloughing, · Treat drill water with Soda Ash to reduce hardness. · Build spud mud with 15 - 20 PPB M-I Gel · Lower funnel viscosity to 45 - 60 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 Poly pac Supreme SL prior to running surface casing. · Add 2 - 5 PPB of M -I Seal Fine to mud system if seepage losses becomes a problem.. · Condition mud prior to cementing casing to reduce yield point and gel strengths. · Estimated volume usage for interval- 1738 barrels. It Communicate daily with in town Project Engineer regarding mud properties, hole condi- tions, proposed program changes. M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Well KBU 43-7X Flo-Vis / KCI / Bioban BP-Plus / SafeCarb F, KlaGard / MI Bar / Caustic Soda / Conqor 404 / SafeScav NA / Lubetex Shale Shakers / Centrifuge Van Lost circulation, coal sloughing, drill solids build-up, gas kick, tight hole conditions, directional control · Isolate one pit with surface mud use this to drill out cement and 10 - 20 feet of new hole. · Clean other rig pits and build new Flo-Pro fluid using the following formula: .. Drill water; .25 ppb Soda Ash; 2 ppb HoVis; 21 ppb KCL; 2 ppb SafeCarb Fine; 18 ppb SafeCarb Medium; Caustic Soda for pH of 9.5 +; 4 ppb KlaGard; 4 lbs Bioban BP- Plus per 100 barrels fluid; Conqor 404 for 2000 ppm; SafeScav NA for DO reading of < 3 ppm It Displace gel mud to Flo-Pro fluid using a Safekleen spacer between fluids. Build additional volume as needed. .. Follow enclosed Optibridge charts for each zone of interest. . Ifrunning coals become a problem, treat with a 2 PPB addition ofVentrol401 and Asphasol D. .. Add 1-3% Lubetex to aid in sliding and directional control. · Estimated volume usage for interval- 2916 barrels. . Condition mud prior to running 9-5/8" casing. It Communicate daily with in town Project Engineer regarding mud properties, hole condi- tions, proposed program changes. M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Ma.rathon Oil Co. KBU 43·7X Kenai Gas Field Sterling A8 Sa.nd 19 1999-2001 M~ L.L.C - All Rights Reserved 0.8 - - 1x104 Calcium Carbonate added: Avg Error 0 -100 % CPS Range: Max Error 0 - 100 % CPS Range : 20 Iblbbl 1.58 % 11.17 % Wen KBU 43-7X Max Permeability: 2000 mDarcy Sand Control Device: D10 Target I Blend: 1.8 D50 Target I Blend: 44.7 D90 Target I Blend: 144.9 2.5 microns 42.4 microns 190.6 microns Brand Name B::Safe.carb 10 (F) , D=Safe-Carb 40 (M) E::Safe-Carb 250 (C) % BridQinQ AQent (lblbblWol % 1.3 6.38 18.1 93.62 0.0 0.00 ¡:; .S¡ 'S 0.7- :ê ø õ Q) N ¡¡j & () 'E ., !l. .~ '; :ï e ::J U 0.5--~-~ O.4---~- 0.2- 0.1 1~10-2 - - . '1x10-1 -. ·1x'1(f· - -1x101 - - - - 1,(102- Particle Size (microns) · Zone of interest - Sterling sands · Pore Pressure - 1.5 ppg - Maximum Porosity - 2000 mD · Measured Depth 4239: · Build additional volume as needed usin2: the blend listed below. · Optimum Calcium Carbonate Blend 18 ppb Safecarb Medium 2 ppb Safecarb Fine M-I Drilling Fluids L.L.c. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279·6729 Fax B 6.4% D 93.6% Marathon Oil Co. KBU 43-7X Kenai Gas Field Upper Beiuga © 1999·2001 M.I L.L.C . All Rights Reserved 1.0·- "1:>1104 0.9' c: o ~ 0.7 ~ IJJ Õ () N tï? OJ -¡:¡ i co il. () ~ co :¡ E 0.3 ;:¡ U 0.6·-"·-~~"-·-- --~.~-_. -".~ 0.5~--~ I í 01 " 1x10·2 1xW" Particle Size (microns) " " "1X103 " it Zone of interest - Upper Beluga Sands it Pore Pressure -1.5 ppg - Maximum Porosity -1000 mD . Measured Depth - 5702' . Build additional volume as needed using the blend listed below. .. Optimum Calcium Carbonate Blend 15 ppb Safecarb Medium 5 ppb Safecarb Fine M-l Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Wen KBU 43-7X Max Permeability: 1000 Sand Control Device: D10 Target I Blend: 1.3 D50 Target I Blend: 31.6 D90 Target I Blend: 102.5 2.0 microns 27.2 microns 173.7 microns Brand Name ¡:I;,Safe-Carb 10 (F) D;Safe-Carb 4Ð (M) E;Safe-Carb 250 (C) Bridc¡inc¡ Ac¡ent (lblbblWol % 4.7 23.30 15.3 76.70 0.0 0.00 D 76.7% Calcium Carbonate added: Avg Error 0 - 100 % CPS Range : Max Error 0 . 100 % CPS Range: 20 Iblbbl 2.53 % 15.50 % Wen KBU 43-7X Flo- Vis / DualFlo / KCl / Greencide 25G / Safecarb F, M, C / Ventrol40l / Conqor 404/ Caustic Soda / M-I Bar Shale Shakers / Desilter / Centrifuge Van Lost circulation, differential sticking, coal sloughing, drill solids build-up, gas kick, tight hole conditions 6471 -7400' 9.0 /i 8 -12 7400 - 8485' 9.2 -10.04 10 - 14 9.0 9.5 9.0-9.5 <5% +/- 5% 40,000 40,000 <6 <6 · Isolate one pit with surface mud use this to drill out cement and 10 - 20 feet of new hole. · Clean other rig pits and build new FloPro fluid using the following formula: · Drill water; .25 ppb Soda Ash; 2 ppb Flo Vis; 4 ppb DualFlo; 21 ppb KCL; 20 ppb Safecarb Fine; Caustic Soda for pH of 9.5+; 4 lbs Bioban BP-Plus per 100 barrels fluid; .25 ppb Greencide 25G; Conqor 404 for 2000 ppm; SafeScav NA for DO < 3 " Displace intermediate hole fluid to FloPro fluid using a H20 spacer (15 - 25 bbls). Build addi- tional volume as needed. (See following sheet for bridging concentrations) tI Ifrunning coals become a problem, treat with a 2- 3 PPB addition ofVentro1401. 4Þ Be prepared to weight up with barite additions for wen control (possible high gas pres- sure). .. Estimated volume usage for interval- 1063 barrels. .. Increase Conqor to 4000 PPM prior to running liner for added corrosion protection. .. Communicate daily with in town Project Engineer regarding mud properties, hole condi- tions, proposed program changes. M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Marathon Oil Go, Name: KBU 43-7X Kenai Gas Field Mid & Lower Beluga © 1999-2001 M~ L.L.C -All Rights Reserved 0,9'-- c o :s J:¡. :s fIJ 5 Q) N i:ii d> Õ 1: 01 0- ~ 0.4 '" "5 E ::! U 0.5 . 1x104 0.1 o 1x10'z Particle Size (microns) .. Zone of interest - Middle & Lower Beluga Sands .. Pore Pressure - 3.8 - 8.8 ppg - Maximum Porosity - 100 mD .. Measured Depths - 6482 & 7225' .. Build additional volume as needed using the blend listed below. .. Optimum Calcium Carbonate Blend 20 ppb Safecarb Fine M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Well KBU 43-7X Max Permeability : Sand Control Device : 100 mDarcy D10 Target I Blend: 6.4 050 Target I Blend: 10.0 090 Target I Blend: 32.4 0.9 microns 9.2 micron$ 23.5 microns Brand Name B=Safe..carb 10 (F) D=Safe..carb 40 (M) E=Safe..carb 250 (C) Bridqinq Aqent (lblbbl)/ol % 20.0 100.00 0.0 0.00 0.0 0.00 B 100.0% Calcium Carbonate added: Avg Error 0 -100 % CPS Range: Max Error 0 . 100 % CPS Range : 20 Iblbbl 3.16 % 13.33 % Wen KBU 43-7X HANDLING OF DRILLING FLUID PRODUCTS HEALTH AND SAFETY 1. Drilling crews should be instructed in the proper procedures for handling fluid products. 2. Personal Protective Equipment (PPE) charts should be posted in the pit room, the mud lab, and the office of the Drilling Forman. 3. PPE must be in good working order and be utilized as recommended by the PPE charts. 4. Product additions should be made with the intent to use complete unit amounts of products (sacks, drums, cans) as much as possible in order to minimize inventory of partial units. 5. Insure all MSDS sheets are up to date and readily available for workers to access for information. ENVIRONMENTAL 1. Insure that all product stored outside is protected from the weather. 2. Do not store partial units (sacks, etc) outside if possible. 3. Properly secure all products for shipment between job sites. 4. When transferring fluid and or cuttings from the rig to trucks, insure all hoses are properly secured. 5. When utilizing the centerfuge solids van, insure all hoses and connections between the van and the rig are secure. M-l Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax DRilLING FLUIDS Product Function M-I BAR Weighting Agent M-I GEL Viscosity control GELEX Bentonite Extender FLOVIS Viscosifier DUAL-FLO Modified Starch PO LYPAC Fluid Loss Reducer XCD Viscosifyer HEC Loss Circulation Mate- rial Safe-Carb F,M,C Bridging and weighting agent LOWATE Weighting agent Nut Plug Loss Circulation Mate- rial M-I Seal F, M, C Loss circulation Material Mix II F,M,C Loss circulation Material DESCO CF Dispersant SPERSENE CF Dispersant TANNATHIN Dispersant VENTROL 401 Surfactant SAL T (Solar) Densifier BROMIDE (NaBr) & Densifier Brine Solution POTASSIUM Shale Inhibitor CHLORIDE - Well KBU 43-7X M-l Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Product Function CAUSTIC SODA Alkalinity control CAUSTIC POTASH pH Modifier BORAX Inorganic Borate SAPP Sodium Pyrophosphate SODA ASH Alkalinity control SODIUM Alkalinity control BICARBONATE CITRIC ACID pH Adjuster MY ACIDE - AS Biocide GREEN CIDE 25G - Biocide DEFOAM X - Defoamer BUBBLE BUSTER Defoamer KLA-GARD Shale Control agent LUBE TEX Lubricant D-D CWT Detergent Concor 404 Corrosion Inhibitor SAFEKLEEN Drilling fluid additive AsphasolD Shale Inhibitor Soltex Shale Inhibitor SafeScav NA Oxygen Scavenger Well KBU 43-7X M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Wen KBU 43-7X HAZARDOUS MATERIALS IDENTIFICATION SYSTEM (HMIS) HAZARD RATINGS 4 - Severe hazard 3 - Serious hazard 2 - Moderate hazard 1 - Slight hazard o - Minimal hazard * An asterisk next to the health rating indicates that a chronic hazard is associated with the mate- rial. 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 M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax Well KBU 43-7X .. MI Project Engineer and Tech Service Engineer will coordinate 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 effi- ciency of the operation or avert trouble.. Proj ect Team Title Home Cellular Craig Bieber District Manager 907 345-1239 907 229-1196 Deen Bryan Tech Service 907373-2713 907 223-1634 Tony Tykalsky Project Engineer 907376-4613 907 227-2412 Gus Wik Warehouse Manager 907 776-8722 907 776-8680 Bob Williams Senior Engineer 907 248-5857 907252-4331 Floyd Faulkner Senior Engineer 907349-8147 907252-4331 ., M-I Drilling Fluids L.L.C. 721 West First Avenue Anchorage, Alaska 99501 (907) 274-5564 (907) 279-6729 Fax · 'M..') Marathon '.MARATHON Oil Company e Alaska Region Domestic Production P.O. Box 196168 Anchorage, AK 99519-6168 Telephone 907/561-5311 Fax 907/564-6489 April 16, 2003 Sarah Palin Commissioner State of Alaska Alaska Oil & Gas Conservation Commission 333 West ih Ave, Suite 100 Anchorage, AK 99501 Reference: Drilling Permit Application Field: Kenai Gas Field Well: Kenai Beluga Unit - KBU 43-7X Dear Ms. Palin 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 Kenai Beluga Unit. Please note that Marathon is requesting a waiver for 20 ACC 25.035 (c) (1) (b) requiring the vent line to be as large as the hole drilled and a wavier for 20 ACC 25.035 (e) (1) (b) requiring a two pipe ram stack. The requests are specified on page 11 of the attached drilling prognosis. If you require further information, I can be reached at 907-564-6310 or bye-mail at wjtank@marathon.com. Sincerely, #J&J~..~. Willard J. ~nk Senior Drilling Engineer Enclosures RECEIVED APR 1 6 2003 A\aska on & Gas Cons. Commission Anchorage ORIGiNAL Check No Check Date Bank Bank No Vendor N 1071068 04/10/2003 NCBAS 7780 5001123 r Marathon Oil Company P. O. Box 3128 Houston, TX 77253 ~/ ~~ê~ul~¥~ir~~Y~~LE DEPARTMENT Jackie Abert Phone: 713·296-4336 Gross Amount Discount Invoice/Pay Amount 100.00 100,00 100.00 100.0C Hndlg AL Invoice Number AL1 0000 Invoice Date Document No RemIt Comment 04/09/2003 1900010906 Fee for Permit To Drill TOTAL: RECEIVED APR 1 ) 2003 Alaska Oil & Gas r.ODS. Commission Anch"rage (FOLD ON PERFORATION BELOW AND DETACH CHECK STUB BEFORE DEPOSITING) II'. ~ [.~ ."~1-'i: III ~ I. ~"i-"'I"~':I ~ II ~ [e-I :,~, ~ II.~U II. ~:I:IIIi: 1:(1i ~¡ :'~tli ~{c'I :I.]II ~ II.~':I::II ~ 1"'1 [.].::¡ 1iI~: I ::I.I~I::IIII:J::: 1('1'1'.1{.] ~. ,~, I~ 1:1 ¡Ijl [Ii :ïïi:i :II~ ..i~[~ FORM 2501 REV. 5/00 ." j;íii ..' ..:t~~ 6~~R ,~;,):}!t ~,SKA ()ilL EL GAS COM..,ISSION .'. ...... . 3~·WEST'·7THAvE STtE tOO ANCHORAGE,,,K ?~50t,: ,. ... ....:::., Marathon Oil . Company .B~e3~~~. ... 56-389/412 7780 .........". AÇGOU~!ª:,,:eAY~I,;!: Ç:HEq~, ..,,' .:;":" ::iC·:.~:::·: ;.:::':.::...::... '" "'"::.¡: .;....... ,.:...~.:' :: :::.",:."'::" ,:::::.."::: n,.,,,,,,,,:.: ';:..:,,"'" :::::::::.:.::;":¡:: ."........:.... '-"""'" .. . '. '-"--'.~"--, -^-;,{-; -'-,:,- ;,..,,,, (' ......,..~y: "{;\',i" /:'/)·A~'»·>·"·" ;...... 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", ~ .., '. , ,", ~ ., ., ., " ,,-,,' ..". ,', , , . .~; ~~~:t~.;~~ ~~.- ~ _ = ~;;_'.'.e,::i::ij~i~;:;:::.:¡~¡~~.':::;~~liJ¡:::·::··i.:¡:¡1;;;;:;::;;~t~~ì~·:::::~~:~i:!:~~:: 'f ¡fH¡·;' .,~ ···~L'}U'~' ·r",;;;.;,"";' i,!¡¡:'¡ ii;;ij;¡.;H; "'';''=. ,',' ",:'," ...,.'. :"';--\~,":'-' ,':,' ";'" ,:',;':"{. , " " ;:" , " , .. ~,' ..,. ... ~TIONAL¢ITY BANI( Ashland, Ohlp .,n,:,'::....:.'. ';I~Ji~[.}iiíi~\.i:'li~¡iij':¡.1.t~lt~~'~í;~~I~~~]'~~;llï~,·.'~~~;'j'~':i'~4·~·~¡:i~,~'~':.:iï~..;'(;Î¡ftti".¡'~íi.,~;t~.'.¡ ï~.í~i.~~~1íii\~';a~~i~~t~,'Î~¡¡;í;¡[~:iíi~'~..:î\~.·¡'m~'" ';"",;, 111000 ~O ? ~O b8111 1:0 ~ ~ 2038., 51: 0 ~8 3 ~8 ~III · e TRANSMIT AL LETTER CHECK LIST CIRCLE APPROPRIATE LETTER/PARAGRAPHS TO BE INCLUDED IN TRANSMITTAL LETTER WELL NAME PTD# CHECK WHAT APPLIES ADD-ONS (OPTIONS) MULTI LATERAL (If API number last two (2) digits are between 60-69) "CLUE" The permit is for a new wellbore segment of existing well-, Permit No, API No. Production should continue to be reported as a function· of the original API number stated above. HOLE In accordance with 20 AAC 25.005(t), all records, data and logs acquired for the pilot hole must be clearly differentiated in both name (name on permit plus PH) and API number (50 70/80) from records, data and logs acquired for well (name on permit). Pll..OT (PH) SPACING EXCEPTION DRY DITCH SAMPLE Rev: 07/10/02 ajody\templates The permit is approved subject to full compliance with 20 AAC 25.055. Approval to peñorate and produce is contingent upon issuance of a conservation order approving a spacing exception. (Companv Name) assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the Commission must be in no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. P!I9A~ n....~ WELL PERMIT CHECKLIST COMPANY('7.. II 1""-.-. WELL NAMEf(N~ ~'~-7,x FIELD & POOL /=,11) t=;S 7 ~ "f'/ISÇC¡INIT CLASS /},.h /'/~./ ADMINISTRATION 1. Permittee attached. . . . . . . . . . . . . . . . . . . . . . . 2. Lease number appropriate. . . . . . . . . . . . . . . . . . . 3. Unique well name and number. . . . . . . . . . . . . . . . . 4. Well located in a defined pool.. . . . . . . . . . . . . . . . . 5. Well located proper distance from drilling unit boundary. 6. Well located proper distance from other wells.. . . . . . . . . APPR DATE 7. Sufficient acreage available in drilling unit.. . . . . . . . . . . ~JI}J--> ... J /..... / 8. If deviated, is wellbore plat included.. . . . . . . . . . . . . . ~ ~/O.s 9. Operator only affected party.. . . . . . . . . . . . . . . . . . . 10. Operator has appropriate bond in force. . . . . . . . . . . . . 11. Permit can be issued without conservation order. . . . . . . . N 12. Permit can be issued without administrative approval.. . . . . N 13. Well located wlin area & strata authorized by injection order#_ Y j( 4J.A. 14. All wells wlin ~ mile area of review identified. . . . . . . . " h N 15. Conductor string provided. . . . . . . . . . . . . . . . . . . œ;N 16. Surface casing protects all known USDWs. . . . . . . . . . N 17. CMT vol adequate to circulate on conductor & surf csg. . . . ' ~ 18. CMT vol adequate to tie-in long string to surf csg. . . . . . . . Y (bL/ 19. CMT will cover all known productive horizons. . . . . . . . . . ~ N 20. Casing designs adequate for C, T, B & permafrost. .. . . . . . N . . 21. Adequate tankage or reserve pit.. . . . . . . . . . . . . . . . . N q I ~l4ß'Ý fh 0... { 22. If a re-drill, has a 10-403 for abandonment been approved. . . rJ fir ò 23. Adequate wellbore separation proposed.. . . . . . . . . . . . :v N } 24. If diverter required, does it meet regulations. . . . . . . . . . ¥-. N \J..( ~ \J.ø.v. ~ttJ «.(~ B q 25. Drilling fluid program schematic & equip list adequate. . . . . N M ~ p1 tú 10, D ¡t' Pc¿ 26. BOPEs, do they meet regulation. . . . . . . . . . . . . . . . N ,./., I' f 27. BOPE press rating appropriate; test to 3500 psig. N m~P ~~17 p<;.., IYv.J,.,(.d,RÇ 28. Choke manifold complies w/API RP-53 (May 84). . . . . . . . N 29. Work will occur without operation shutdown. . . . . . . . . . . ~ 30. Is presence of H2S gas probable.. . . . . . . . . . . . . . . . Y 31. Mechanical condition of wells within AOR verified. . . . . . . . . N {It- QN ~ pA, ~ N N (Service Well Only) (Service Well Only) ENGINEERING APPR DATE 1iJGt: 4{ i1 I() 7. (Service Well Only) GEOLOGY APPR DATE '~ora~~ Rev: 07/12/02 32. Permit can be issued wlo hydrogen sulfide measures. . . . . 33. Data presented on potential overpressure zones. . . . . . . . 34. Seismic analysis of shallow gas zones. . . . . . . . . . . . . 35. Seabed condition survey (if off-shore). . . . . .. ...... 36. Contact namelphone for weekly progress reports. ...... GEOLOGY: RP~ PETROLEUM ENGINEERING: TEM PROGRAM: Exp _ Dev.:x Redrll_ Re-Enter _ Serv _ Wellbore seg_ GEOL AREA ¡¡-~ ...... UNIT#. ~ //¿ð ON/OFF SHORE Æ!2 N N N <.~.h ~/fC{ « f:. ð. /131 ~ 90 qL. ~~ e (.F. e RESERVOIR E GINEERING JDH COMMISS~ONE ·tJ ~ 5t' /£7" ~ DTS ()'" , I~ tì ~ ~ ~ SFD_ v WGA G:\geology\permits\checklist.doc UIC ENGINEER JBR Comments/Instructions: MJW ~ -- ~ c:::. ~