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Home My WebLink About216-0861. Operations Susp Well Insp Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Install Whipstock Perforate Other Stimulate Alter Casing Change Approved Program Mod Artificial Lift Perforate New Pool Repair Well Coiled Tubing Ops Other: ______________________ Furie Operating Alaska, LLC Development Exploratory 3. Address: Stratigraphic Service 6. API Number: 433 W. 9th Avenue, Anchorage AK 99501 7. Property Designation (Lease Number): ADL 389197 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured 8,160 feet 4,648 feet true vertical 7,301 feet N/A feet Effective Depth measured 8,041 feet 4,565 feet true vertical 7,197 feet 3,924 feet Perforation depth Measured depth See attached feet True Vertical depth See attached feet Tubing (size, grade, measured and true vertical depth) 3-1/2" L-80 4,599' 3,965' Packers and SSSV (type, measured and true vertical depth) Baker SCSSV 3-1/2" Self Closing 470' 469' 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: N/A 13a. Prior to well operation: Subsequent to operation: 13b. Pools active after work: 15. Well Class after work: Daily Report of Well Operations Exploratory Development Service Stratigraphic Copies of Logs and Surveys Run 16. Well Status after work: Oil Gas WDSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Authorized Name and Digital Signature with Date:Michael Duncan Contact Name:Michael Duncan Contact Email:m.duncan@furiealaska.com Authorized Title:Drilling Manager Contact Phone: 1,995' Burst Collapse 2,670 psi measured TVD Production Liner 8,122' Casing Structural 7,268'8,122' Plugs Junk measured N/A Length 381' 2,265' 381'Conductor Surface Intermediate 20" 13-3/8" N/A 5. Permit to Drill Number:2. Operator Name 4. Well Class Before Work: Kitchen Lights Unit: Sterling and Beluga Undefined Gas Pools KLU A-2A STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 216-086 50-733-20655-01-00 0 psi 9-5/8" 6,620 psi7,930 psi N/A 184 psiN/A 0 315 psi0 measured true vertical Packer Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureGas-Mcf MDSize 381' 5,380 psi2,265' 325-277 Sr Pet Eng: Sr Pet Geo: Sr Res Eng: WINJ WAG 2860 Water-BblOil-Bbl 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. (817) 240-3865 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) N/A 180 psi p k ft t Fra O s O 216 6.A G L PG , Form 10-404 Revised 10/2022 Due Within 30 days of Operations Submit in PDF format to aogcc.permitting@alaska.gov x e:Michael Duncan t the foregoing is true and correct 7/8/2025 By Grace Christianson at 10:04 am, Jul 08, 2025 BJM 9/25/25 June 30th, 2025 Bryan McLellan Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Furie Operating Alaska KLU A-2A (PTD 216-086) 10-404 Upper Completion Changeout Mr. McLellan, Enclosed is the 10-404 Report of Sundry Well Operations for the KLU A-2A well with attached wellbore schematic, daily well operations summary, and upper completion tally. The existing 4-1/2 upper completion was pulled using the Spartan 151 rig and a 3-1/2 monobore upper completion was run with GLMs, CIM, and SCSSV. If you have questions, please feel free to contact me at 817-240-3865. Michael Duncan Drilling Manager Furie Operating Alaska, LLC 1 6/14/2025 2 6/15/2025 3 6/16/2025 4 6/17/2025 5 6/18/2025 6 6/19/2025 Daily Well Work Summaries for KLU A-2A (PTD 216-086) DATEDAY SUMMARY Complete BOP test. R/D test equipment. Pull TWC. M/U landing joint to hanger and TDS. Pressure tubing to 300 psi. Cameron backed out lock down pins. Unseat hanger from wellhead. Pull "Pop-Loc" latch from seal bore w/90k overpull. Pull TBG Hanger to surface. Baker M/U control line to valve and opened valve. Circulate w/9.7 ppg brine at 4.5 BPM @100 psi while R/U casing equipment and control line spools to L/D tubing. Shut pumps off and monitor well - well static. Break out landing joint string w/TDS. Break L/D TBG Hanger, pup jts and landing string. Pull and lay down 142 jts of 4-1/2" tubing. Rig down tubing running equipment. R/U and run 3 1/2" JFE Lion tubing completion to 4,509' MD. M/U crossover to drill pipe. Trip in hole to determine space out. POOH. Make up landing jt to tubing hanger. Terminate contol lines on tubing hanger and test control lines. Trip in hole to land tubing hanger. Landed out early and engaged Pop lock. Pulled out w/20k over pull. Pull hanger to surface. Lost hanger seal ring . Redress tubing hanger. Remove 6' pup joint and reterminate control lines and test same. Trip in hole and land out tubing hanger. Lock down hanger. Test tubing and casing annulus. L/D landing joint and install BPV. N/D BOPs. Break out components of the BOP and set aside. N/D BOP. Remove rams from stack and clean cavaties. Break down stack and stage platform. Nipple up tree and production line. Test tree. Lay down all drill pipe in derrick. Skid rig over KLU A-2. Rig up for rig operations on A-2A. Rig up slick line equipment and test lubicator. Well pressure prior to setting PX plug was 623 psi. Run and set PX plug and junk catcher . Bleed off tubing and fill with 9.7 ppg kill fluid. Test tubing to 2500 psi. Pressure test tubing /casing annulus to 2,500 psi. Install BPV, N/D tree. Install riser and stab BOPs' on riser. Secure BOPs. Change out lower pipe ram to 2-7/8" to 5-1/2" VBRs. Install bell nipple, dresser sleeve. and pollution pan. R/U rest of maniford and test unit. Flush choke manifold and TDS. WELL NAME:KLU A-2 DATE: 6/17/2025 CASING SIZE 3.500 inches WEIGHT 9.20 ppf CASING ID 2.992 inches GRADE L80 THREAD JFE Lion CAPACITY 0.0087 bbls/ft DISPLACEMENT 0.0034 bbls/ft SHOE DEPTH feet Use premium . HOLE TD feet Total 48 XC clamps & 11 metal bands ran. MUD WT 8.45 ppg Joint Running Joint Depth BOUY FACTOR 0.90 Joint # Joint # Length Total Bottom Top REMARKS Bouyant Capacity Displmt in Hole on Rack feet feet feet feet weight bbls bbls 45,000 A Seal assy 17.88 17.88 4599.00 4581.12 45,148 0.2 0.1 1 1 30.98 48.86 4581.12 4550.14 45,405 0.4 0.2 X-Nip 1.08 49.94 4550.14 4549.06 45,414 0.4 0.2 2 2 31.52 81.46 4549.06 4517.54 45,674 0.7 0.3 Pup 11.91 93.37 4517.54 4505.63 45,773 0.8 0.3 #1 GLM 7.30 100.67 4505.63 4498.33 45,834 0.9 0.3 Pup 11.85 112.52 4498.33 4486.48 45,932 1.0 0.4 3 3 30.27 142.79 4486.48 4456.21 46,182 1.2 0.5 4 4 31.44 174.23 4456.21 4424.77 46,443 1.5 0.6 5 5 31.43 205.66 4424.77 4393.34 46,703 1.8 0.7 6 6 30.99 236.65 4393.34 4362.35 46,959 2.1 0.8 7 7 31.42 268.07 4362.35 4330.93 47,220 2.3 0.9 8 8 31.22 299.29 4330.93 4299.71 47,478 2.6 1.0 9 9 31.79 331.08 4299.71 4267.92 47,741 2.9 1.1 10 10 30.40 361.48 4267.92 4237.52 47,993 3.1 1.2 11 11 30.81 392.29 4237.52 4206.71 48,248 3.4 1.3 12 12 30.94 423.23 4206.71 4175.77 48,504 3.7 1.4 13 13 31.44 454.67 4175.77 4144.33 48,765 4.0 1.5 14 14 31.23 485.90 4144.33 4113.10 49,023 4.2 1.7 15 15 31.43 517.33 4113.10 4081.67 49,283 4.5 1.8 16 16 30.79 548.12 4081.67 4050.88 49,538 4.8 1.9 17 17 30.84 578.96 4050.88 4020.04 49,794 5.0 2.0 18 18 31.13 610.09 4020.04 3988.91 50,052 5.3 2.1 19 19 31.43 641.52 3988.91 3957.48 50,312 5.6 2.2 20 20 30.93 672.45 3957.48 3926.55 50,568 5.9 2.3 Pup 10.07 682.52 3926.55 3916.48 50,651 5.9 2.3 #2 GLM 7.30 689.82 3916.48 3909.18 50,712 6.0 2.3 Pup 10.01 699.83 3909.18 3899.17 50,795 6.1 2.4 21 21 30.93 730.76 3899.17 3868.24 51,051 6.4 2.5 22 22 30.88 761.64 3868.24 3837.36 51,306 6.6 2.6 23 23 30.83 792.47 3837.36 3806.53 51,562 6.9 2.7 24 24 30.84 823.31 3806.53 3775.69 51,817 7.2 2.8 25 25 31.15 854.46 3775.69 3744.54 52,075 7.4 2.9 26 26 31.46 885.92 3744.54 3713.08 52,335 7.7 3.0 27 27 30.21 916.13 3713.08 3682.87 52,586 8.0 3.1 28 28 30.95 947.08 3682.87 3651.92 52,842 8.2 3.2 29 29 30.84 977.92 3651.92 3621.08 53,097 8.5 3.3 30 30 31.30 1009.22 3621.08 3589.78 53,356 8.8 3.4 Top of PBR=4584' Furie KLU A-2. 3½ Upper Completion Run Tall y FINAL Off Bottom TORQUE - Max = 3950 Optimum = 3590 min=3240 Block Weight = Drift=2.867 Bottom of seal assy full length=17.88 length of swollow=14.95 3.500 Completion Run Tally KLU A-2 FINAL 3.5 completion tally 6/25/2025 9:46 AM Joint Running Joint Depth BOUY FACTOR 0.90 Joint # Joint # Length Total Bottom Top REMARKS Bouyant Capacity Displmt in Hole on Rack feet feet feet feet weight bbls bbls 31 31 31.31 1040.53 3589.78 3558.47 53,616 9.1 3.5 32 32 31.12 1071.65 3558.47 3527.35 53,873 9.3 3.6 33 33 31.03 1102.68 3527.35 3496.32 54,130 9.6 3.7 34 34 31.40 1134.08 3496.32 3464.92 54,390 9.9 3.9 35 35 31.05 1165.13 3464.92 3433.87 54,647 10.1 4.0 36 36 31.76 1196.89 3433.87 3402.11 54,910 10.4 4.1 37 37 31.75 1228.64 3402.11 3370.36 55,173 10.7 4.2 38 38 30.81 1259.45 3370.36 3339.55 55,428 11.0 4.3 39 39 30.87 1290.32 3339.55 3308.68 55,684 11.2 4.4 40 40 31.41 1321.73 3308.68 3277.27 55,944 11.5 4.5 41 41 30.79 1352.52 3277.27 3246.48 56,199 11.8 4.6 42 42 30.83 1383.35 3246.48 3215.65 56,454 12.0 4.7 43 43 30.95 1414.30 3215.65 3184.70 56,710 12.3 4.8 Pup 10.07 1424.37 3184.70 3174.63 56,794 12.4 4.8 #3 GLM 7.30 1431.67 3174.63 3167.33 56,854 12.5 4.9 Pup 10.01 1441.68 3167.33 3157.32 56,937 12.5 4.9 44 44 30.00 1471.68 3157.32 3127.32 57,186 12.8 5.0 45 45 31.26 1502.94 3127.32 3096.06 57,444 13.1 5.1 46 46 31.75 1534.69 3096.06 3064.31 57,707 13.4 5.2 47 47 31.79 1566.48 3064.31 3032.52 57,970 13.6 5.3 48 48 31.03 1597.51 3032.52 3001.49 58,227 13.9 5.4 49 49 30.84 1628.35 3001.49 2970.65 58,483 14.2 5.5 50 50 31.80 1660.15 2970.65 2938.85 58,746 14.4 5.6 51 51 30.80 1690.95 2938.85 2908.05 59,001 14.7 5.7 52 52 31.72 1722.67 2908.05 2876.33 59,264 15.0 5.9 53 53 30.96 1753.63 2876.33 2845.37 59,520 15.3 6.0 54 54 31.24 1784.87 2845.37 2814.13 59,779 15.5 6.1 55 55 30.95 1815.82 2814.13 2783.18 60,035 15.8 6.2 56 56 30.94 1846.76 2783.18 2752.24 60,291 16.1 6.3 57 57 31.05 1877.81 2752.24 2721.19 60,548 16.3 6.4 58 58 31.79 1909.60 2721.19 2689.40 60,811 16.6 6.5 59 59 30.84 1940.44 2689.40 2658.56 61,067 16.9 6.6 60 60 31.05 1971.49 2658.56 2627.51 61,324 17.2 6.7 61 61 30.25 2001.74 2627.51 2597.26 61,574 17.4 6.8 62 62 31.49 2033.23 2597.26 2565.77 61,835 17.7 6.9 63 63 31.32 2064.55 2565.77 2534.45 62,094 18.0 7.0 64 64 31.26 2095.81 2534.45 2503.19 62,353 18.2 7.1 65 65 30.33 2126.14 2503.19 2472.86 62,604 18.5 7.2 66 66 31.49 2157.63 2472.86 2441.37 62,865 18.8 7.3 67 67 31.46 2189.09 2441.37 2409.91 63,126 19.0 7.4 68 68 31.20 2220.29 2409.91 2378.71 63,384 19.3 7.5 69 69 31.20 2251.49 2378.71 2347.51 63,642 19.6 7.7 70 70 31.11 2282.60 2347.51 2316.40 63,900 19.9 7.8 71 71 31.50 2314.10 2316.40 2284.90 64,161 20.1 7.9 72 72 29.88 2343.98 2284.90 2255.02 64,408 20.4 8.0 73 73 31.48 2375.46 2255.02 2223.54 64,669 20.7 8.1 Pup 6.02 2381.48 2223.54 2217.52 64,719 20.7 8.1 #4 GLM 7.30 2388.78 2217.52 2210.22 64,779 20.8 8.1 Pup 6.01 2394.79 2210.22 2204.21 64,829 20.8 8.1 74 74 30.94 2425.73 2204.21 2173.27 65,085 21.1 8.2 75 75 29.88 2455.61 2173.27 2143.39 65,332 21.4 8.3 3.500 Completion Run Tally KLU A-2 FINAL 3.5 completion tally 6/25/2025 9:46 AM Joint Running Joint Depth BOUY FACTOR 0.90 Joint # Joint # Length Total Bottom Top REMARKS Bouyant Capacity Displmt in Hole on Rack feet feet feet feet weight bbls bbls 76 76 30.55 2486.16 2143.39 2112.84 65,585 21.6 8.5 77 77 30.81 2516.97 2112.84 2082.03 65,841 21.9 8.6 78 78 31.78 2548.75 2082.03 2050.25 66,104 22.2 8.7 79 79 30.94 2579.69 2050.25 2019.31 66,360 22.4 8.8 80 80 31.03 2610.72 2019.31 1988.28 66,617 22.7 8.9 81 81 31.04 2641.76 1988.28 1957.24 66,874 23.0 9.0 82 82 31.13 2672.89 1957.24 1926.11 67,132 23.3 9.1 83 83 31.76 2704.65 1926.11 1894.35 67,395 23.5 9.2 84 84 30.84 2735.49 1894.35 1863.51 67,650 23.8 9.3 85 85 31.79 2767.28 1863.51 1831.72 67,913 24.1 9.4 86 86 30.87 2798.15 1831.72 1800.85 68,169 24.3 9.5 87 87 31.79 2829.94 1800.85 1769.06 68,432 24.6 9.6 88 88 31.74 2861.68 1769.06 1737.32 68,695 24.9 9.7 89 89 30.81 2892.49 1737.32 1706.51 68,950 25.2 9.8 90 90 30.21 2922.70 1706.51 1676.30 69,200 25.4 9.9 91 91 30.85 2953.55 1676.30 1645.45 69,455 25.7 10.0 92 92 30.78 2984.33 1645.45 1614.67 69,710 26.0 10.1 93 93 31.44 3015.77 1614.67 1583.23 69,971 26.2 10.3 94 94 30.25 3046.02 1583.23 1552.98 70,221 26.5 10.4 95 95 30.58 3076.60 1552.98 1522.40 70,474 26.8 10.5 96 96 31.14 3107.74 1522.40 1491.26 70,732 27.0 10.6 97 97 30.84 3138.58 1491.26 1460.42 70,987 27.3 10.7 98 98 31.16 3169.74 1460.42 1429.26 71,245 27.6 10.8 Pup 6.01 3175.75 1429.26 1423.25 71,295 27.6 10.8 B CIM 7.30 3183.05 1423.25 1415.95 71,356 27.7 10.8 Pup 5.98 3189.03 1415.95 1409.97 71,405 27.7 10.8 99 99 31.03 3220.06 1409.97 1378.94 71,662 28.0 10.9 100 100 30.81 3250.87 1378.94 1348.13 71,917 28.3 11.1 101 101 30.79 3281.66 1348.13 1317.34 72,172 28.6 11.2 102 102 31.18 3312.84 1317.34 1286.16 72,430 28.8 11.3 103 103 30.78 3343.62 1286.16 1255.38 72,685 29.1 11.4 104 104 30.93 3374.55 1255.38 1224.45 72,941 29.4 11.5 105 105 30.83 3405.38 1224.45 1193.62 73,197 29.6 11.6 Pup 10.07 3415.45 1193.62 1183.55 73,280 29.7 11.6 #5 GLM 7.30 3422.75 1183.55 1176.25 73,340 29.8 11.6 Pup 10.03 3432.78 1176.25 1166.22 73,423 29.9 11.7 106 106 31.49 3464.27 1166.22 1134.73 73,684 30.1 11.8 107 107 30.75 3495.02 1134.73 1103.98 73,939 30.4 11.9 108 108 30.58 3525.60 1103.98 1073.40 74,192 30.7 12.0 109 109 30.58 3556.18 1073.40 1042.82 74,445 30.9 12.1 110 110 31.01 3587.19 1042.82 1011.81 74,702 31.2 12.2 111 111 31.16 3618.35 1011.81 980.65 74,960 31.5 12.3 112 112 31.14 3649.49 980.65 949.51 75,218 31.8 12.4 113 113 31.15 3680.64 949.51 918.36 75,476 32.0 12.5 114 114 30.56 3711.20 918.36 887.80 75,729 32.3 12.6 115 115 31.15 3742.35 887.80 856.65 75,987 32.6 12.7 116 116 31.20 3773.55 856.65 825.45 76,245 32.8 12.8 117 117 31.18 3804.73 825.45 794.27 76,503 33.1 12.9 118 118 30.61 3835.34 794.27 763.66 76,757 33.4 13.0 119 119 31.17 3866.51 763.66 732.49 77,015 33.6 13.1 120 120 31.16 3897.67 732.49 701.33 77,273 33.9 13.3 Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp AKAES 006019-0 2, SS bands Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp Cross collar clamp 3.500 Completion Run Tally KLU A-2 FINAL 3.5 completion tally 6/25/2025 9:46 AM Joint Running Joint Depth BOUY FACTOR 0.90 Joint # Joint # Length Total Bottom Top REMARKS Bouyant Capacity Displmt in Hole on Rack feet feet feet feet weight bbls bbls 121 121 30.76 3928.43 701.33 670.57 77,527 34.2 13.4 122 122 30.85 3959.28 670.57 639.72 77,783 34.4 13.5 123 123 30.69 3989.97 639.72 609.03 78,037 34.7 13.6 124 124 31.07 4021.04 609.03 577.96 78,294 35.0 13.7 125 125 31.21 4052.25 577.96 546.75 78,553 35.3 13.8 126 126 31.16 4083.41 546.75 515.59 78,811 35.5 13.9 127 127 30.76 4114.17 515.59 484.83 79,065 35.8 14.0 Pup 10.05 4124.22 484.83 474.78 79,149 35.9 14.0 C SCSSV 4.40 4128.62 474.78 470.38 79,185 35.9 14.0 Pup 10.03 4138.65 470.38 460.35 79,268 36.0 14.1 128 128 30.53 4169.18 460.35 429.82 79,521 36.3 14.2 129 129 30.28 4199.46 429.82 399.54 79,772 36.5 14.3 130 130 30.56 4230.02 399.54 368.98 80,025 36.8 14.4 131 131 30.68 4260.70 368.98 338.30 80,279 37.1 14.5 132 132 30.76 4291.46 338.30 307.54 80,533 37.3 14.6 133 133 30.57 4322.03 307.54 276.97 80,786 37.6 14.7 134 134 30.90 4352.93 276.97 246.07 81,042 37.9 14.8 135 135 31.48 4384.41 246.07 214.59 81,303 38.1 14.9 136 136 31.45 4415.86 214.59 183.14 81,563 38.4 15.0 137 137 31.48 4447.34 183.14 151.66 81,824 38.7 15.1 138 138 31.47 4478.81 151.66 120.19 82,085 39.0 15.2 139 139 30.25 4509.06 120.19 89.94 82,335 39.2 15.3 140 143 29.60 4538.66 89.94 60.34 82,580 39.5 15.4 Pup 1.64 4540.30 60.34 58.70 82,594 39.5 15.4 Hngr 0.95 4541.25 58.70 57.75 82,602 39.5 15.4 RKB 57.75 4599.00 57.75 0.00 83,080 40.0 15.6 2, SS bands 2, SS bands Cross collar clamp Cross collar clamp 2, SS bands 2, SS bands 2, SS bands 2, SS bands 2, SS bands 2, SS bands 2, SS bands 2, SS bands 2, SS bands 2, SS bands HO57636301 3, SS bands 2, SS bands 2, SS bands 2, SS bands 2, SS bands 26 total clamps 2, SS bands 2, SS bands 2, SS bands 41 total SS bands 3.500 Completion Run Tally KLU A-2 FINAL 3.5 completion tally 6/25/2025 9:46 AM Joint Running Joint Depth BOUY FACTOR 0.90 Joint # Joint # Length Total Bottom Top REMARKS Bouyant Capacity Displmt in Hole on Rack feet feet feet feet weight bbls bbls 3.500 Completion Run Tally KLU A-2 FINAL 3.5 completion tally 6/25/2025 9:46 AM 1 Gluyas, Gavin R (OGC) From:McLellan, Bryan J (OGC) Sent:Monday, June 16, 2025 10:44 AM To:Hunter Van Wyhe Subject:RE: [EXT] RE: KLU A-2A (PTD 216-086) Sundry #325-277 Approved Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Hunter Van Wyhe <h.vanwyhe@furiealaska.com> Sent: Friday, June 13, 2025 3:03 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: Re: [EXT] RE: KLU A-2A (PTD 216-086) Sundry #325-277 Bryan, Thank you for the time for today. As discussed, we will run a ~8.25" GR on SL to the top of the tie back receptacle followed by a ~2.6" wire grab to drift through seal bore following the decompletion to ensure we have access through the seal assembly. If all looks good we will run in with the new completion and not perform the scraper and polish mill runs on drillpipe. Have a great weekend, Hunter Van Wyhe Operations Engineer 433 W. 9th Avenue Anchorage AK 99501 Cell: (907) 378-3354 2 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Thursday, June 12, 2025 9:48 AM To: Michael Duncan <m.duncan@furiealaska.com> Cc: Hunter Van Wyhe <h.vanwyhe@furiealaska.com> Subject: [EXT] RE: KLU A-2A (PTD 216-086) Sundry #325-277 Michael, See my comments in green in our correspondence below, and the reference to Hilcorp’s NOV. Furie has conditional approval for the requested change. Condition of approval is to circulate the tubing and inner annulus with KWF of consistent density from s urface to surface after unseating the packer and tubing hanger, but before laying down tubing. This same condition also applies in the case where Furie is able to locate a tubing punch per the original plan in the approved sundry 325-277. In that case Furie will circulate the tubing and IA to KWF of consistent density before unseating the packer and tubing hanger. Regards Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 3 From: Michael Duncan <m.duncan@furiealaska.com> Sent: Wednesday, June 11, 2025 9:21 PM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Hunter Van Wyhe <h.vanwyhe@furiealaska.com> Subject: KLU A-2A (PTD 216-086) Sundry #325-277 Bryan - Please see the responses below in blue.  Do you know what type/density of fluid is in the IA? o 9.7 ppg NaBrCl 6% KCL brine  What is the density of the planned KWF you will pump down the tubing in revised step 3. o 8.4 ppg filtered seawater  Is there any recent history of sustained casing pressure on the IA? Please send wellhead pressure chart for last few months. o See attached KLU A-2A daily well casing report from 2025.  In step 12, instead of bleeding, why not just circulate 1.25 X wellbore volume of KWF through the choke so you have a known, consistent fluid on both sides? Having a mix of different fluids in the wellbore will just cause you fits throughout the workover. o In general, it is because I would like to do this work without circulating. Saving 3-4 hours is valuable. I see a need to keep the hole full for kill weight (secondary control after the plug), but if we can pull the tubing out without trouble, I would like to just run the new string in.  Furie will need to keep the hole full to monitor for any influx. That won’t be possible if you don’t have uniform fluid on both sides because it will U-tube up the tubing every time you fill the annulus. We consider it to be good oilfield practice to circulate KWF surface to surface before pulling tubing, so it will be a condition of approval. As a reference, look up on our website wellfile for well TBU M-35 (PTD 117-119), docket #OTH-22-019. You’ll see an NOV that Hilcorp received for not circulating out the wellbore fluids before pulling tubing. This was their second such incident involving a spill due to fluid imbalance, the first was on Wolf Lake Marathon 2, also discussed in the NOV. Take note of the corrective actions AOGCC directed the operator to implement: 4 Hopefully the attached table will work in leu of a wellhead pressure chart. Please let me know if that doesnt cover the information you seek and an additional chart is needed. Thank you, Michael From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Tuesday, June 10, 2025 3:18 PM To: Michael Duncan <m.duncan@furiealaska.com> Cc: Hunter Van Wyhe <h.vanwyhe@furiealaska.com>; Mike Stefanov <m.stefanov@furiealaska.com> Subject: [EXT] RE: KLU A-2A (PTD 216-086) Sundry #325-277 Michael,  Do you know what type/density of fluid is in the IA?  What is the density of the planned KWF you will pump down the tubing in revised step 3.  Is there any recent history of sustained casing pressure on the IA? Please send wellhead pressure chart for last few months.  In step 12, instead of bleeding, why not just circulate 1.25 X wellbore volume of KWF through the choke so you have a known, consistent fluid on both sides? Having a mix of different fluids in the wellbore will just cause you fits throughout the workover. Could you send a wellhead pressure chart? 5 Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Michael Duncan <m.duncan@furiealaska.com> Sent: Friday, June 6, 2025 11:18 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Cc: Hunter Van Wyhe <h.vanwyhe@furiealaska.com>; Mike Stefanov <m.stefanov@furiealaska.com> Subject: KLU A-2A (PTD 216-086) Sundry #325-277 Mr. McLellan - In the Sundry for the KLU A-2A, we submitted that we would punch the tubing to equalize downhole. (Section 5. Step 2) CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 6 We are struggling to find the punch we need, and I write to propose an alternative: 1. R/U Slickline. Set PX plug in sliding sleeve at 4,696' MD. 2. Bleed pressure from tubing to negative pressure test PX plug 3. Fluid pack well with kill weight fluid (sea water) 4. Set TWC in tubing hanger 5. ND Tree, NU BOP's 6. Test BOP's 7. Pull TWC 8. PU Landing joint, Sting in to tubing hanger 9. Sting into Top Drive, Pressure test to 500 psi 10. BOLDS, unseat tubing hanger carefully 11. Pick up enough to un-sting from polish bore assembly down hole. NOTE: there will be an imbalance of pressure. Once un-stung, the tubing (SPP) pressure is expected to climb to approximately 300 psi 12. Note pressure and bleed down tubing to tanks, note volume change 13. Verify well stable 14. LD Tubing hanger 15. TOOH After that we would proceed with the polish mill run and the tubing installation per procedure. Please let me know your thoughts. Thank you, Michael Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the 7 sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. 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If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. ***External Email*** Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. Confidentiality Notice: This email and its attachments (if any) contain confidential information of the sender. The information is intended only for use by the direct addressees of the original sender of this email. If you are not an intended recipient of the original sender (or responsible for delivering the message to such person), you are hereby notified that any review, disclosure, copying, distribution or the taking of any action in reliance of the contents of and attachments to this email is strictly prohibited. If you have received this email in error, please immediately notify the sender at the address shown herein and permanently delete any copies of this email (digital or paper) in your possession. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: Kitchen Lights KLU Undefined Beluga and Sterling 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,160'N/A Casing Collapse Structural Conductor Surface 2,670 psi Intermediate Production 6,620 psi Liner 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Michael Duncan Contact Email:m.duncan@furiealaska.com Contact Phone: (907) 378-3354 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Packers and SSSV Type: 9-5/8" Permanent (Sump Pkr); CSHP-NR (Gravel Pack Pkr)TRSCSSV: 4-1/2" SESX2000'EQ Packers and SSSV MD (ft) and TVD (ft): SCSSV: 1650' MD/1573' TVD. Pkrs: 6711' MD/5980' TVD, 6286' MD/5581' TVD, 5997' MD/5307' TVD, 5496' MD/3882' TVD, 4813' MD/4153' TVD, 4593' MD/3960' TVD 2,213' 8,122' Perforation Depth MD (ft): See attached schematic See attached schematic 2,265' 4-1/2" and 3-1/2" 7,268'9-5/8"8,070' 329' 20" 13-3/8" 5,380 psi1,995' Size Proposed Pools: 381' 381' L-80 TVD Burst 6,731' 7,930 psi MD STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 389197 216-086 433 W. 9th Avenue, Anchorage, AK 99501 50-733-20655-01-00 Furie Operating Alaska, LLC AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): June 15th, 2025 Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY Drilling Manager Michael Duncan KLU A-2ACO 723 7,301' 8,041 7,197 909 N/A Length m n P 2 66 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Michael Duncan t the foregoing is true and the proc te: 5/5/2025 325-277 By Grace Christianson at 11:08 am, May 05, 2025 BJM 5/7/25 10-404 Initial BOP test to 5000 psi, subsequent BOP test to 4500 psi. All annular tests to 2500 psi. VBRs must be tested on smallest and largest diameter pipe that will be run. X DSR-5/6/25A.Dewhurst 02JUN25*&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.06.03 08:04:42 -08'00'06/03/25 RBDMS JSB 060525 1 May 5th, 2025 Bryan McLellan Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Furie Operating Alaska KLU A-2A (PTD 216-086) 10-403 Upper Completion Changeout Mr. McLellan, Enclosed is a 10-403 sundry for an upper completion changeout to the KLU A-2A well with attached operations plan, wellbore schematic, and BOP information. The existing 4-1/2” upper completion will be pulled and replaced with a 3-1/2” upper completion with GLV’s, CIM, and SCSSV using the Spartan 151 rig. Operations are expected to commence approximately June 15th, 2025. If you have questions, please feel free to contact me at 817-240-3865. Michael Duncan Drilling Manager Furie Operating Alaska, LLC Mi h l D 2 KLU A-2A Upper Completion Changeout May 5, 2024 3 Contents 1.Well Information................................................................................................................................... 3 2. Drill Pipe Information............................................................................................................................ 3 3. Current Wellbore Schematic................................................................................................................. 4 4. Proposed Wellbore Schematic.............................................................................................................. 5 5. Pre-Rig Activity...................................................................................................................................... 6 6. Pull Upper Completion Assembly ......................................................................................................... 6 7. Run 3-1/2" Upper Completion Assembly.............................................................................................. 7 8. ND BOPE/RDMO.................................................................................................................................... 8 9. Mandatory Regulatory Compliance / Notifications.............................................................................. 9 10. MPSP...............................................................................................................................................11 11. BOP Schematic................................................................................................................................11 12. Choke Manifold Schematic.............................................................................................................12 13. Attachment 7: Rig Information.......................................................................................................14 1. Well Information Well Name KLU A-2A Drilling Rig Spartan 151 Slot Name Slot B (KLU A-2A) Planned Completion Type 3-1/2” monobore w/ GLM Target Reservoirs KLU Sterling/Beluga Surface Location (Governmental) 895.93’ FWL, 341.48’ FSL, Sec. 24, T10N, R11W, SM Surface Location (NAD 27) X=294331.49, Y=2583125.62 Work String 5” NC50 RT – Mean Sea Level (MSL) Spartan 151 114.1’ RT – Mud Line (ML) Spartan 151 202.1’ Water Depth Tidal Difference - +/- 20’ 88.00’ ft 2. Drill Pipe Information OD ID TJ OD WT (#/ft)Grade Conn 5” 4.276” 6.625” 19.5 S-135 NC 50 4 3. Current Wellbore Schematic 5 4. Proposed Wellbore Schematic 5 6 5. Pre-Rig Activity 1. R/U Slickline. Set PX plug in sliding sleeve at 4,696’ MD. 2. RIH with tubing punch. Punch tubing above plug to allow for circulating. 3. Fluid pack well. 4. Pressure test tubing hanger and casing hanger voids to 5,000 psi with Cameron test pump. Function test lockdown screws. 5. Install a BPV in the 4.5” tubing hanger. Install plug off tool. Pressure test the BPV from below to 3,500 psi by pumping down the inner annulus and monitoring for pressure at the tree cap pressure gauge; this is also a casing pressure test. Record tubing and casing pressures for 15 minutes. Pressure test the back pressure valve from above at 5,000 psi by pumping in through the tree cap. 6. Remove flowline from wing valve and choke. Purge chemical injection line with seawater. 6. Pull Upper Completion Assembly 7. Nipple down tree. Check the tree and associated valves. 8. Terminate control lines. Nipple down tubing head adapter. Bleed off 3/8” Chemical Injection line pressure and cap. Install 1/4 turn valve and pressure up to 5,000 psi on ¼” control line. Close valve and install cap. 9. Inspect hanger threads. Screw in 4-1/2” BTC pup joint to verify full make up. Pup joint should be as short as possible. If threads are not in good condition, a 4-1/2” spear may be necessary to pull the hanger. 10. Nipple up the BOPE. Ensure the Cameron service hand is supervising this operation while installing the test joint. Test to 5,000 psi. Test annular preventer to 2,500 psi. Drift riser to 13.625”, same as tubing head. OD test plug dimension: 13.507” +/- .008”. 11. With T-bar pull the combination BPV and plug off tool. Check tubing for pressure, by rotating the running tool to the right. Pull the plug off tool first, then pull the BPV. 12. Circulate seawater, about 302 bbls, down the 4-1/2” and up 9-5/8” annulus. 13. Make up the landing joint to the tubing hanger. Back out the tubing hanger lock down screws. Picking up the hanger. Pick up and slack off as necessary to avoid damaging the hanger. 14. Pull the tubing hanger to the rig floor. 15. Bleed off the subsurface safety valve control line. Disconnect the SSSV and CIM control lines below the tubing hanger. Then apply 5,000 psi the SSSV control line below the hanger, so the SSSV will remain open while pulling out of the hole. Chemical injection line will be cut and spooled up. The chemical injection line should have been purged with seawater prior to cutting it. What kind of fluid?What approximate depth to punch tubing? 7 16. Break the tubing hanger off. Lay down the upper 4-1/2” tubing completion string. Record number of clamps/bands recovered to surface. Keep track of the number of SS bands retrieved. 17. Monitor well. 18. Set wear bushing (ID on wear bushing is 12.50”). 19. Make a 9-5/8” scraper run on drillpipe to the top packer at 4,565’ MD. CBU. 20. Make a polish mill on drillpipe to the top PBR polish PBR. CBU. POH. 7. Run 3-1/2" Upper Completion Assembly 21. Confirm all required Upper Completion Assemblies are on the well location and that there is no visual external damage to any of the assemblies, pup joints or tubing. 22. Confirm all tally records for completion assemblies, serial numbers, pressure ratings and other relevant information for each GLM, CIV, TRSSSV, X-Nipple, and 4” seal assembly. 23. Function test the TRSSSV prior to running completion per Baker Hughes Procedure (confirm opening and closing pressures and visually confirm that flapper is opening/closing). 24. Ensure seal assembly has been redressed and is on the rig/well site. 25. RU tubing running equipment on the rig floor including torque turn equipment for JFE Lion 3-1/2” 9.2# L-80 connection. 26. MU seal stem assembly to the first joint of 3-1/2” 9.2 lb./ft. L-80 JFE Lion tubing. 27. MU 3-1/2” 9.2 #L-80 monobore completion with GLM’s (recommended depths on proposed completion diagram, can be adjusted slightly as needed in tubing tally), chemical injection mandrel, TRSSSV and seal stem. RIH while spooling 3/8” chemical injection and ¼” TRSSSV control lines. Pollard/Parker to install control line clamps. One clamp per joint. Make up control lines and test at 5,000 psi after connections are made. Maintain 2,500 psi pressure on chemical injection line and SSSV control line while running. 28. One joint prior to reaching the anticipated depth of the lower PBR of 3-1/2 x 9-5/8” Liner Hanger check and record pick-up and slack-off weights. 29. Rig up pump in sub on top of the 3-1/2” production tubing and break circulation at low pump rate. 30. Initiate circulation, confirm returns on the “back side” and start slacking off completion string while observing pressure on the pressure gauge in anticipation of the sudden pressure increase due to seal assy. entering 7” x 5” Liner Hanger x-over to lower PBR. 31. Be prepared to immediately shut off the pumps. 32. Once that tubing pressure increase is observed shut the pumps immediately and bleed- off any remaining pressure in tubing. That pressure increase is an initial positive indicator confirming that the seals of the 4” seal assy. are entering lower PBR. 8 33. Continue lowering completion string and carefully monitor the string weight on the weight indicator. It is anticipated to see an indication when each set of seals enters the lower PBR. 34. Once the Seal Stem locator reaches the final depth inside the Liner Hanger assembly set ~10-15k lbs down to confirm expected and correct position inside the Liner Hanger assembly. 35. Pick up to neutral weight + 2’ from full engagement. Mark pipe to establish space out. 36. PU install space out pups one joint below tubing hanger. 37. Terminate control lines and tie into tubing hanger. PT control lines to 5,000 psi. Rupture disc in chemical injection valve is set to shear out at 3,500 psi. 38. Install ¼” Swagelok fitting and ¼ turn valve. Pressure up to 5,000 psi and lock in pressure to keep SSSV open while landing the tubing hanger. 39. Land tubing hanger. RILDS. Pressure test tubing hanger void at 5,000 psi. 40. PT annulus to 2,500 psi per AOGCC requirement and record on chart for 15 minutes. 8. ND BOPE/RDMO 41. Install BPV. 42. ND 13-5/8” BOP. Install plug off tool in BPV. 43. Install tubing head adapter. Terminate control lines. 44. Confirm correct orientation of flow cross prior to tightening studs and nuts. NU and pressure test 4-1/16” 5K tree to 5,000 psi. 45. Retrieve BPV and plug off tool. 46. R/U SL. 47. Pull dummy GLV’s. Install live GLV’s. 48. Hook up gas lift to KLU A-2A. Displace gas down annulus to displace fluid in tubing. 49. R/U SL and pull PX plug at 4,696’ MD. 50. Return well to production. 9 9. Mandatory Regulatory Compliance / Notifications Regulatory Compliance Ensure that our drilling and completion operations comply with the below AOGCC regulations. If additional clarity or guidance is required on how to comply with a specific regulation, do not hesitate to contact the Anchorage Drilling Team. x BOPs shall be tested at 1-week intervals during completion operations. Ensure to provide AOGCC 48 hours’ notice prior to testing BOPs. x The initial test of BOP equipment will be to 250/5,000 psi and subsequent tests of BOP equipment will be to 250/4,500 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). o The highest reservoir pressure expected is 1,266 psi @ 6,499 TVD in the Beluga lower sand. MPSP is 909 psi with 0.055 psi/ft gas in the wellbore. x The wellhead is rated to 5,000 psi and the BOPS to 5,000 psi. x If the BOP is used to shut in on the well in a well control situation, ALL BOP components utilized for well control must be tested prior to the next trip into the wellbore. This pressure test will be charted same as the 14-day BOP test. x All AOGCC regulations within 20 AAC 25.033 “Primary well control for drilling: drilling fluid system”. x All AOGCC regulations within 20 AAC 25.035 “Secondary well control for primary drilling and completion: blowout prevention equipment and diverter requirements” x Ensure AOGCC approved sundry is posted on the rig floor and in Co Man office. Required AOGCC Notifications: x Well control event (BOPs utilized to shut in the well to control influx of formation fluids). x 48-hour notice prior to full BOPE test. x Any other notifications required in 10-403 conditions of approval. AOGCC Contact Information: x Jim Regg / AOGCC Inspector/ (O): 907-793-1236 / Email: jim.regg@alaska.gov x Bryan McLellan / Petroleum Engineer/ (O): 907-793-1226 / (C): 907-250-9193 / Email: bryan.mclellan@alaska.gov x Melvin Rixse / Petroleum Engineer/ (O): 907-793-1231 Email: melvin.rixse@alaska.gov Primary Contact for Opportunity to Witness: The initial test of BOP equipment will be to 250/5,000 psi and subsequent tests of BOP equipment will be to 250/4,500 psi for 5/5 min (annular to 50% rated WP, 2,500 psi on the high test for initial and subsequent tests). 10 x Test/Inspection notification standardization format: Test Witness Notification - Alaska Oil and Gas Conservation Commission (state.ak.us) x Notification/ Emergency Phone: 907-793-1236 (During normal Business Hours) x Notification/ Emergency Phone: 907-659-2714 (Outside normal Business Hours) BOP N/U and Test 1. N/D Tree master valve and adapter (BPV installed as part of pre-rig work), inspect landing threads in tubing hanger. Make dummy run to check threads. Install plug off tool. 2. Check the full drift of any spacer spools used several days prior to installation. 3. N/U 13-5/8" x 5M BOP as follows (top down): o 13-5/8" x 5M Shaffer spherical annular BOP. o 13-5/8” X 5M Shaffer SL Double ram. (2-7/8" X 5" VBR in top cavity, blind ram in bottom cavity). o 13-5/8" X 5M mud cross. o 13-5/8" X 5M Shaffer SL single ram. (2-7/8" X 5" VBR). o N/U bell nipple, install flowline. o Install (1) manual valve on kill side of mud cross. Manual valve used as inside or "master valve". o Install (1) manual valve on choke side of mud cross. Install an HCR outside of the manual valve. 4. Test BOPE. o Test BOP to 250/5,000 psi for 5/5 min. Test annular to 250/2,500 psi for 5/5 min. o Ensure to leave "A" wellhead section side outlet valves open during BOP testing so pressure does not build up beneath the back pressure valve with plug off tool. Confirm the correct valves are opened. o Test VBRs on 4.5" test joint (5,000 psi) See attached permit to drill. o Test Annular on 4.5" test joint (2,500 psi). o Ensure gas monitors are calibrated and tested in conjunction w/ BOPs. VBRs must be tested on the smallest and largest OD pipe to be run. Test on 3.5" and 4.5" test joints. -bjm 11 10.MPSP Interval: 7,270’-7,274’ MD (6,499’-6,503’ TVDKB) Estimated Reservoir Pressure at Top Perf: 1,266 psi *SIWHP March 2025 was 900 psi. Estimated reservoir pressure assumes a gas gradient from surface to top perforation depth. Gas Gradient (Based on KLU 3 Static Gradient Survey): 0.055 psi/ft MPSP = (1,266 psi – (0.055 * 6,499’ TVDKB) = 909 psi 11.BOP Schematic 12 12. Choke Manifold Schematic 13 14 13. Attachment 7: Rig Information 15151515151515151515151515151515151515151515 161666666666666666666666 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Yes No 9. Property Designation (Lease Number): 10. Field: Kitchen Lights KLU Undefined Beluga and Sterling 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 8,160'N/A Casing Collapse Structural Conductor Surface 2,670 psi Intermediate Production 6,620 psi Liner 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Hunter Van Wyhe Contact Email:h.vanwyhe@furiealaska.com Contact Phone: (907) 378-3354 Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other Conditions of Approval: Post Initial Injection MIT Req'd? Yes No APPROVED BY Approved by: COMMISSIONER THE AOGCC Date: Comm. Comm. Sr Pet Eng Sr Pet Geo Sr Res Eng Operations Engineer Hunter Van Wyhe KLU A-2ACO 723 7,301' 8,041 7,197 3,094 N/A Length Subsequent Form Required: Suspension Expiration Date: Will perfs require a spacing exception due to property boundaries? Current Pools: MPSP (psi): Plugs (MD): 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: Tubing Size: PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): March 25th, 2025 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL 389197 216-086 433 W. 9th Avenue, Anchorage, AK 99501 50-733-20655-01-00 Furie Operating Alaska, LLC Size Proposed Pools: 381' 381' L-80 TVD Burst 6,731' 7,930 psi MD 5,380 psi1,995' 7,268'9-5/8" 329' 20" 13-3/8" 8,070' See attached schematic 2,265' 4-1/2" and 3-1/2" Packers and SSSV Type: 9-5/8" Permanent (Sump Pkr); CSHP-NR (Gravel Pack Pkr)TRSCSSV: 4-1/2" SESX2000'EQ Packers and SSSV MD (ft) and TVD (ft): SCSSV: 1650' MD/1573' TVD. Pkrs: 6711' MD/5980' TVD, 6286' MD/5581' TVD, 5997' MD/5307' TVD, 5496' MD/3882' TVD, 4813' MD/4153' TVD, 4593' MD/3960' TVD 2,213' 8,122' Perforation Depth MD (ft): See attached schematic m n P 2 66 t _ N Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov Hunter Van Wyhe oregoing is true and the procedure approvedherein will notbe By Grace Christianson at 10:20 am, Mar 14, 2025 325-146 DSR-3/24/25 Perforate SFD 3/17/2025BJM 3/18/25 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.03.26 08:24:00 -08'00' 03/26/25 RBDMS JSB 032725 March 14th, 2025 Bryan McLellan Senior Petroleum Engineer Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Furie Operating Alaska KLU A-2A (PTD 216-086) 10-403 Add Beluga Perforations Mr. McLellan, Enclosed is a 10-403 sundry for adding Beluga perforations to the KLU A-2A well with attached wellbore schematic, summarized operations plan, and table of proposed perforations. Operations are expected to commence approximately March 25th, 2025. If you have questions, please feel free to contact me at 907-378-3354. Hunter Van Wyhe Operations Engineer Furie Operating Alaska, LLC HtVWh KLU A-2A Current Wellbore Schematic See perforation table attached for perforation intervals All Sterling perfs are isolated behind closed sliding sleeves per Hunter Van Whye 3/18/25. -bjm Perforation Table KLU A-2A Perforation Procedure Summary: 1. Ensure SCSSV is open, blocked in. 2. Rig up Eline. Pressure test PCE to 250 psi low and 3500 psi high. a. (Note: PCE must be tested each time it is broken apart.) 3. RIH perforate Beluga intervals. 4. RD Eline equipment. Turn well over to production. KLU A-2A MPSP Calculation: Interval: 7,766’-7,772’ MD (6,951’-6,957’ TVDKB) Estimated Reservoir Pressure at Top Perf: 3,476 psi Gas Gradient (Based on KLU 3 Static Gradient Survey): 0.055 psi/ft MPSP = (3,476 psi – (0.055 * 6,951’ TVDKB) = 3,094 psi Formation Top MD ft Base MD ft Top TVDKB Base TVDKB Length MD ft Beluga 5,667 5,671 4,992 4,997 4 Beluga 5,755 5,766 5,076 5,087 12 Beluga 5,775 5,779 5,095 5,100 4 Beluga 7,130 7,136 6,369 6,376 6 Beluga 7,165 7,169 6,402 6,406 4 Beluga 7,296 7,300 6,523 6,527 4 Beluga 7,522 7,526 6,730 6,734 4 Beluga 7,766 7,772 6,951 6,957 6 Total: 44 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov October 15, 2024 Mr. John Hendrix CEO & President Furie Operating Alaska LLC 433 W. 9th Avenue Anchorage, AK 99501 Subject: Docket Number: OTH-23-016 Safety Valve System Testing Kitchen Lights Unit A-2A (PTD 2160860) Dear Mr. Hendrix: The Alaska Oil and Gas Conservation Commission (AOGCC) is in receipt of the September 27, 2024, waiver request from Furie Operating Alaska, LLC (Furie) regarding well safety valve system performance testing at Kitchen Lights Unit A-2A. AOGCC and Furie technical staff met on September 25, 2024, regarding the production performance of the KLU wells and the challenges encountered in keeping the wells flowing, particularly KLU A-2A, and concerns about restoring production after well shut-ins.1 AOGCC regulation 20 AAC 25.265 requires the wells on Furie’s Julius R Platform be equipped with a well safety valve system consisting of a low-pressure detection device, actuated surface safety valve and actuated subsurface safety valve. Performance tests of the KLU well safety valve system components are required every May and November. Furie requests that AOGCC approve function testing the low-pressure detection device instead of performance testing all KLU A-2A safety valve system components in November 2024. Furie’s request is APPROVED. In support of this decision, Furie has demonstrated that the production characteristics of KLU A-2A are such that any shutdown could result in the inability to return the well to production. Also, AOGCC inspection records show that KLU A-2A has been tested 17 times totaling 51 component tests since the start of production with zero failures. The following approval conditions apply: 1. The SVS components of all wells that are online – except KLU A-2A – must be performance tested in November 2024. 2. Subsequent semi-annual testing of all online wells must occur every May and November. 1 Initial request from Furie requesting a waiver from AOGCC required safety valve system performance testing was dated April 26, 2023. Docket Number: OTH-23-016 KLU A-2A SVS Test Waiver Request October 15, 2024 3. Furie must provide at least 48-hour advance notice for AOGCC witness of KLU well safety valve system testing. Should you have any questions this approval, please contact Jim Regg at (907) 793-1236. Sincerely, Jessie L. Chmielowski Gregory C. Wilson Commissioner Commissioner cc: Hunter Van Wyhe (h.vanwyhe@furiealaska.com) AOGCC Inspectors Phoebe Brooks Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2024.10.15 14:23:43 -08'00' Gregory Wilson Digitally signed by Gregory Wilson Date: 2024.10.15 15:11:14 -08'00' 1 Furie Operating Alaska, LLC | 433 West 9 th Avenue, Anchorage, AK 99501 | 907.277.3726 Confidential Information Pursuant to AS 38.05.035(a)(8), AS 45.50.910 – 45.50.945, and Article 1, Sections 1 & 18 of the Alaska Constitution. September 27, 2024 Confidential Jim Regg Supervisor, Inspections Alaska Oil and Gas Conservation Commission (AOGCC) 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: KLU A-2A Safety Valve System Performance Testing Deferral Request Mr. Regg, Furie Operating Alaska, LLC (Furie) requests a consideration of a waiver regarding the frequency of well safety valve system (SVS) performance testing for well KLU A-2A pursuant to Alaska Administrative Code 20 AAC 25.265. Due to the production characteristics of the well (elevated water rate and declining reservoir pressure), it is uncertain if the well is capable of resuming flow post shut in for SVS testing, or if it gets shut in for any other reason. Julius R Platform (JRP) wells are scheduled for SVS testing in May and November of each year. The proposed SVS test schedule for well KLU A-2a is as follows: x Perform a function test of the well KLU A-2a surface safety valve system on or before November 30, 2024 excluding surface safety valve (SSV) and surface controlled subsurface safety valve (SSSV) actuation x Perform a performance test of the well KLU A-2a safety valve system prior to May 31, 2024 The proposed November 2024 SVS function test would confirm the automated shut in surface components function correctly without actually shutting in the well. Function testing would be conducted as normal but with control line pressure isolated to the SSSV & lockout installed on the SSV. This will test the low-pressure pilot trip pressure, PLC function test, Solenoid actuation, and surface pressure bleed off. All wells on the JRP are equipped with surface and subsurface safety valves along with automated shut in control systems. Testing of these safety systems requires the wells to be shut in briefly. Even these brief shut-ins have caused wells to permanently cease flowing, resulting in a reduction in ultimate recovery. The requested variance would be for a maximum of a 12-month interval in accordance with API Recommended Practice 14B (Design, Installation, Operation, Test, and Redress of Subsurface Safety Valve Systems) section 6.3. The RP states “SCSSVs shall be tested to the requirements in Annex A upon installation and at a maximum interval of every six months unless local 2 Furie Operating Alaska, LLC | 433 West 9 th Avenue, Anchorage, AK 99501 | 907.277.3726 Confidential Information Pursuant to AS 38.05.035(a)(8), AS 45.50.910 – 45.50.945, and Article 1, Sections 1 & 18 of the Alaska Constitution. regulations, conditions and/or documented historical evidence indicate a different testing interval not to exceed 12 months.” It is projected that the currently producing Lower Sterling interval from KLU A-2A may cease natural flow approximately June/ July 2025, approximately the time the May SVS performance test is performed. We appreciate your consideration on this matter and request a written response by October 15, 2024. Respectfully, Hunter Van Wyhe Operations Engineer Furie Operating Alaska, LLC py, 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov May 17, 2023 Mr. John Hendrix CEO & President Furie Operating Alaska LLC 433 W. 9th Avenue Anchorage, AK 99501 Subject: Docket Number: OTH-23-016 Safety Valve System Testing Kitchen Lights Unit Dear Mr. Hendrix: The Alaska Oil and Gas Conservation Commission (AOGCC) is reviewing Furie Operating Alaska LLC (Furie)’s request for a waiver or variance to the requirement to test a well safety valve system (SVS) at intervals “not to exceed 210 days between tests”. Your letter dated April 26, 2023 suggests that testing SVS results in adverse impacts to ultimate recovery from some wells and pools. For the Kitchen Lights Unit (KLU) operated by Furie, the pools are understood to be the Sterling Undefined Gas Pool, the Beluga Undefined Gas Pool and the Tyonek Undefined Gas Pool. An initial review has identified a couple regulatory clarifications are warranted. First, SVS tests are scheduled to occur twice per year at 6-month intervals with the specific test months established by AOGCC upon the start of production.1 The additional 30 days identified in regulation 20 AAC 25.265 is provided for contingencies that could prevent testing on a strict anniversary date. Refer to Industry Guidance Bulletin 10-004 (attached). Second item of clarification is that Furie’s request is for a waiver and not a variance since deferring tests does not rise to the standard of providing “at least an equally effective means of complying with the requirement” (i.e., testing every 6 months). AOGCC will be processing this request as a waiver. For AOGCC to complete this review and render a decision, Furie is requested to: - Write a summary of Furie’s operating philosophy regarding critical well safety systems on offshore platforms and how that compares to industry recommended practices published by the American Petroleum Institute. - Provide a copy of Furie’s operations and maintenance manual for SVS. - Describe how Furie would determine a SVS needs to be repaired or replaced without performance testing those systems. 1 Fixed SVS test months for KLU Julius R Platform are May and November. - Provide the schedule and reasons for planned shutdowns on the Julius R platform when SVS tests would occur. - Describe how a planned or unplanned shut down would have a different outcome than the brief closure for a SVS test. - Describe what steps Furie will take as part of its 2023 well workover program on the Julius R platform to address the existing issues and challenges for well completions in the Beluga, Sterling and Tyonek Undefined Gas Pools. Should you have any questions about the information request, please contact Jim Regg at (907) 793-1236. Sincerely, Brett W. Huber, Sr. Chair, Commissioner Attachment cc: AOGCC Inspectors Phoebe Brooks Samantha Carlisle Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.17 14:05:26 -08'00' Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov April 23, 2024 Mr. John Hendrix CEO & President Furie Operating Alaska LLC 433 W. 9th Avenue Anchorage, AK 99501 Subject: Docket Number: OTH-23-016 Safety Valve System Testing Kitchen Lights Unit Dear Mr. Hendrix: On March 12, 2024, Furie provided additional information in support of its request for a waiver from the Safety Valve System (SVS) testing requirements in 20 AAC 25.265, including information requested by the Alaska Oil and Gas Conservation Commission (AOGCC) in a letter dated May 17, 2023.1 Furie requests to waive required performance testing of the SVS components every 6 months with the following test schedule: - Function test every 6 months (actuate component only); - Performance test annually (actuate and close to confirm pressure seal). AOGCC’s review finds that there is currently insufficient evidence demonstrating SVS testing as the cause of Kitchen Lights Unit (KLU) well failures. Furie notes that following shutdowns, the four KLU wells struggle – and have even failed – to return to production. Before the AOGCC can complete its review, more documentation is necessary to understand the role of SVS testing in well failures. Specifically, the AOGCC requests responses and/or documentation addressing the following: 1. Based on information provided by Furie, there has been just one well failure that can be attributed to SVS testing. Missing from Furie’s information are the durations of well shutdowns that Furie uses as examples in support of its initial request. 2. AOGCC Inspectors confirm that SVS testing takes less than 20 minutes per well to complete. Please describe how a 20-minute shut down to validate critical production well safety systems can cause a producing well to fail. 3. No information has been provided about the performance of KLU 3 (PTD 2130150) specific to the well’s ability to recover from a well shutdown. 1 Initial request from Furie was dated April 26, 2023. KLU SVS Test Waiver Request Docket Number: OTH-23-016 April 23, 2024 4. SVS tests are routinely done on hundreds of wells in the Cook Inlet basin (onshore/offshore) in compliance with AOGCC rules – it is unclear what distinguishes KLU from the other wells in the basin. 5. What specific options have been assessed to mitigate the water and solids influx issues that have been identified as contributing factors to wells being unable to return to production or unable to sustain production? If deemed not feasible, please describe the reason for that determination. The feasibility of mitigating options must be assessed and understood before waiving industry-wide recognized best practices for critical well safety systems (i.e., well shut down devices that have both personnel and environmental safety implications). The AOGCC is aware of the immediate implications for Furie as this waiver request is being reviewed, notably that the next SVS tests are due May 2024. Regulation 20 AC 25.265 provides for additional 30 days as clarified in Industry Guidance Bulletin 10-004 – SVS tests must be completed no later than June 2024. Decisions about what tests must be performed and when they need to be performed will be addressed in June if this review approaches the test date. The AOGCC reserves the right to convene a hearing to consider this waiver request because depending on Furie’s responses it could have implications for a broader scope of wells beyond just Furie’s wells at KLU. Should you have any questions about the information request, please contact Jim Regg at (907) 793-1236. Sincerely, Brett W. Huber, Sr. Chair, Commissioner cc: AOGCC Inspectors Phoebe Brooks Samantha Coldiron Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.04.23 11:45:55 -08'00' 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ______________________ Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured feet feet true vertical feet feet Effective Depth measured feet feet true vertical feet feet Perforation depth Measured depth feet True Vertical depth feet Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 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 W DSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Contact Email: Contact Phone: 2. Operator Name: Senior Pet. Engineer: Senior Res. Engineer: CollapseBurstTVDLengthCasing Authorized Signature with date: Authorized Name: 5. Permit to Drill Number: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf measuredPlugs Junk measured STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 3. Address: 4. Well Class Before Work: Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureOil-Bbl measured true vertical Packer WINJ WAG Water-Bbl MD 15.Well Class after work: Exploratory Development ServiceStratigraphic 16.Well Status after work:Oil Gas WDSPL a GSTOR GINJ SUSP SPLUG 25.070, 25.071, & 25.283) WINJWAG tion: tion: Gas-Mcf Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureOil-Bbl Water-Bbl summary: olumes used and final pressure: Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Perforate Other Stimulate Alter Casing Change Approved Program Perforate New Pool Repair Well Re-enter Susp Well Other: ______________________ Development Exploratory Stratigraphic Service6.API Number: mber):8. Well Name and Number: onic data per 20AAC25.071):10. Field/Pool(s): ry: ured feet feet tical feet feet ured feet feet tical feet feet epth feet epth feet true vertical depth) d and true vertical depth) CollapseBurstTVD 5. Permit to Drill Number: Size measuredPlugs Junkmeasured 4. W ell Class Before W ork: measured true vertical Packer MD Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Senior Res Engineer: C Furie Operating Alaska, LLC 433 W. 9th Avenue, Anchorage AK 99501 216-086 50-733-20655-01-00 ADL 389197 KLU A-2A GR-CCL- Temperature Log 11OCT2021 Kitchen Lights Unit: Sterling and Beluga Undefined Gas Pools 8160 7301 N/A N/A 8041 7197 6711 5968 Conductor 381 20" 381 381 Surface 2265 13 3/8" 2265 1995 5380 psi 2670 psi Production 8122 9 5/8" 8122 7268 7930 psi 6620 psi 7196-7208, 7270-74 6430-6441, 6500-04 3-1/2" & 4-1/2" L-80 4580' 3942' Superior Com 4-1/2"SESX2000E 1653' 1538' N/A N/A 0 3250 7 180 psi 330 psi 0 1800 0 180 psi 400 321-531/321-431Hunter Van Wyhe Operations Engineer Hunter Van Wyhe h.vanwyhe@furiealaska.com (907) 378-3354 ✔ ✔ ✔✔ ✔ By Samantha Carlisle at 9:25 am, Oct 19, 2021 RBDMS HEW 10/19/2021 SFD 10/20/2021DSR-10/19/21BJM 20/22/21 Furie Operating Alaska, LLC | 433 W 9 th Avenue, Anchorage, AK 99501 | 907.277.3726 October 1ϱ, 2021 Alaska Oil and Gas Conservation Commission (AOGCC) 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Furie Operating Alaska KLU A-2A Add Beluga Perforations: 10-404 Sundry TO WHOM IT MAY CONCERN, Furie Operating Alaska (Furie) submits this completed 10-404 sundry for additional Beluga perforations to the KLU A-2A wellbore previously submitted and approved in AOGCC 10-403 sundry 321-431 and 321-531. 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R/U E-line. PT all pressure control equipment. Good test. RIH to shoot 2nd shot of second perforation interval. Shoot 2nd shot on 2nd perforation interval from 7196'-7202' MD. POOH. Break out tools. Confirm all shots fired. Secure well. RDMO KLU A-1. SUMMARY PJSM/Halliburton JSA. R/U E-line on KLU A-2A. PT pressure control equipment assembly with diesel to 3500 psi. Test good. RIH with ULTRA GR/CCL/7HPSHUDWXUH toolstring. POOH. Lay down tools. Secure well. LDFN. PJSM/Halliburton JSA.PT pressure control equipment assembly with diesel to 3500 psi. Startup triplex pump. Pump 5 bbl MeOH lead, 42 bbls SKL-400, 3 bbls MeOH tail. RIH DQGVKRRW1st perforation interval from 7270'-7274' MD. POOH. Break out tools. Confirm all shots fired. RIH to shoot 1st shot of 2nd perforation interval (note: 2nd perforation interval to be shot with 2x 6' guns). Shoot 1st shot on 2nd perforation interval from 7202'-7208' MD. POOH. Break out tools. Confirm all shots fired. Prepare tools for continued perforating operations tomorrow 10/13. Secure well. LDFN. AOGCC Sundry's 321-431/321-531 DĂŝůǇtĞůůtŽƌŬ^ƵŵŵĂƌŝĞƐ for KLU# A-2A DATEDAY Shoot 2nd shot on 2nd perforation interval from 7196'-7202' MD. Shoot 1st shot on 2nd perforation interval from 7202'-7208' MD. DQGVKRRW 1st perforation interval from 7270'-7274' MD. 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3. Address:Stratigraphic Service 6. API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9. Property Designation (Lease Number):10. Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): Casing Collapse Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other: Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: APPROVED BY Approved by:COMMISSIONER THE AOGCC Date: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name and Digital Signature with Date: AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Length Size TVD BurstMD Perforation Depth MD (ft): approval: Notify AOGCC so that a representative may witness Sundry Number: BOP Test Mechanical Integrity Test Location Clearance ection MIT Req'd? Yes No ption Required? Yes No Subsequent Form Required: AOGCC USE ONLY Contact Name: Contact Email: Contact Phone: e: certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. m eand ure with Date: Date for 15. Well Status after proposed work: Operations:OIL WINJ WDSPL Suspended proval:Date:GAS WAG GSTOR SPLUG esentative: GINJ Op Shutdown Abandoned nts: Proposal Summary Wellbore schematic13. Well Class after proposed work: ations Program BOP Sketch Exploratory Stratigraphic Development Service SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Tubing Grade:Tubing MD (ft):Perforation Depth TVD (ft): Tubing Size:pth MD (ft): quest: Abandon Plug Perforations Fracture Stimulate Reppair Well Operations shutdown Suspend Perforate Other Stimulate Pulll Tubing Change Approved Program Plugfor Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: er Casing ___________________ ame:4.Current Well Class:5. Permit to Drill Number: Exploratory Development Stratigraphic Service 6. API Num ber: g:8. W ell Name and Number: ation or Conservation Order governs well spacing in this pool? perforations require a spacing exception?Yes No esignation (Lease Number):10. Field/Pool(s): D (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): g Collapse PRESENT WELL CONDITION SUMMARY Length Size TVD Bur stMD Form 10-403 Revised 10/2021 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 2:30 pm, Oct 07, 2021 321-531 Furie Operating Alaska 433 West 9th Avenue, Anchorage Ak 99501 216-086 50-733-20655-01-00 CO 723 KLU A-2A ADL 389197 Kitchen Lights Unit: Sterling and Beluga Undefined Gas Pools 8160 7301 8041 7197 2201 Conductor 381' 20" 381' 381' Surface 2265' 13 3/8" 2265' 1995' 5380 psi 2670 psi Production 8122' 9 5/8" 8122' 7268' 7930 psi 6620 psi 7234-7238, 7168-7174, 6884-6478-6481, 6405-6410, 614 4 1/2"L-80 4580' Superior Completion Services Packers: 9 5/8" Permanent (sump packer), CSHP-NR (Gravel Pack Packers), SCSSV: 4 1/2" SESX2000EQ Packers at 6711 md, 5968 TVD, 6286 MD, 5578 TVD, 5497 MD,4824 TVD, 4814 MD, 4168 TVD, 4580 MD, 3942 TVD. SSSV at 1653 MD, 1558 TVD 10/07/2021 10/06/2021 Bryan Mclellan Petroleum Engineer, 10/7/2021 Daniel B. Robertson D.Robertson@FurieAlaska.com 907-529-5818 ✔✔ ✔ ✔ ✔ ✔✔ ✔ SFD 10/7/2021 :10/06/2021 10-404 DSR-10/7/21BJM 10/7/21 dts 10/8/2021 JLC 10/8/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.10.08 12:55:37 -08'00' RBDMS HEW 10/8/2021 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4. Current Well Class:5. Permit to Drill Number: Exploratory Development 3.Address:Stratigraphic Service 6.API Number: 7. If perforating:8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Will planned perforations require a spacing exception?Yes No 9.Property Designation (Lease Number):10.Field/Pool(s): 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): Casing Collapse 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.W ell Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16. Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 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: Perforation Depth MD (ft): TVD BurstMDLength Size Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): approval: Notify Commission so that a representative may witness Sundry Number: BOP Test Mechanical Integrity Test Location Clearance ection MIT Req'd? Yes No ption Required? Yes No Subsequent Form Required: COMMISSION USE ONLY Contact Name: Contact Email: Contact Phone: Date: e: certify that the foregoing is true and the procedure approved herein will not rom without prior written approval. gnature: me: Date for 15. Well Status after proposed work: Operations:OIL WINJ WDSPL Suspended proval:Date:GAS WAG GSTOR SPLUG Representative:GINJ Op Shutdown Abandoned nts: Proposal Summary Wellbore schematic13. Well Class after proposed work: ations Program BOP Sketch Exploratory Stratigraphic Development Service SSSV Type:Packers and SSSV MD (ft) and TVD (ft): pth MD (ft):Perforation Depth TVD (ft):Tubing Size:Tubing Grade:Tubing MD (ft): quest: Abandon Plug PerforationsFracture Stimulate Reppair Well Operations shutdown Suspend Perforate Other Stimulate Pulll Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: er Casing ___________________ ame:4.Current Well Class:5. Permit to Drill Number: Exploratory Development Stratigraphic Service 6. API Number: g:8. Well Name and Number: ation or Conservation Order governs well spacing in this pool? perforations require a spacing exception?Yes No esignation (Lease Number):10. Field/Pool(s): D (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): g CollapseTVDBurstMDLengthSize PRESENT WELL CONDITION SUMMARY Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 10:19 am, Aug 26, 2021 321-431 Furie Operating Alaska 433 W. 9th Avenue, Anchorage AK 99501 216-086 50-733-20655-01-00 CO 723 KLU A-2A ADL 389197 Kitchen Lights Unit: Sterling, Beluga Undefined Gas Pool 8160'7301'8041'7197'2201 psi Conductor 381' 20" 381' 381' Surface 2265' 13 3/8" 2265' 1995' 5380 psi 2670 psi Production 8122' 9 5/8" 8122' 7268' 7930 psi 6620 psi 7270-7274, 7988-8000 6500-6504, 7150-7154 4 1/2"L-80 4608 Superior Completion Services: Packers: 9-5/8" Permanent (Sump Packer); CSHP-NR (Gravel Pack Packers),SCSSV; 4-1/2" SESX2000'EQ SCSSV @ 1,650' MD / 1,573' TVD Pks @ 6,711' MD/5,980' TVD & 6,286' MD/5,581' TVD & 5,997' MD/5,307' TVD & 5,496' MD/3,882' TVD & 4,813' MD/4,153' TVD 09/15/2021 Hunter Van Wyhe Operations Engineer Hunter Van Wyhe Digitally signed by Hunter Van Wyhe Date: 2021.08.23 09:03:13 -08'00'8/23/2021 Hunter Van Wyhe h.vanwyhe@furiealaska.com (907)378-3354 ✔ ✔ ✔ ✔ ✔✔ ✔ 10-404 & SFD 8/26/2021 BJM 9/1/21 DSR-8/26/21SFD 8/23/2021 s dts 9/1/2021 JLC 9/2/2021 Jeremy Price Digitally signed by Jeremy Price Date: 2021.09.02 14:09:25 -08'00' RBDMS HEW 9/3/2021 Furie Operating Alaska, LLC | 433 W 9th Avenue, Anchorage, AK 99501 | 907.277.3726 August 23rd, 2021 Alaska Oil and Gas Conservation Commission (AOGCC) 333 West 7th Avenue, Suite 100 Anchorage, AK 99501 Re: Furie Operating Alaska KLU A-2A Add Beluga Perforations TO WHOM IT MAY CONCERN, Furie Operating Alaska (Furie) submits these additional Beluga perforations to the KLU A-2A wellbore. The perforation intervals are listed below; x 7,270-7,274 ft MD (6,500-6,504 ft TVD) x 7,988-8,000 ft MD (7,150-7,154 ft TVD) Enclosed is a completed 10-403 sundry form, perforation procedure and wellbore schematic. Work will be conducted on the Julius R production platform. If you have any questions or require further information, please contact me at (907) 378-3354. Sincerely, Hunter Van Wyhe Furie Operating Alaska, LLC Sincerely, Hunter Van Wyhe Furie Operating Alaska, LLC | 433 W 9th Avenue, Anchorage, AK 99501 | 907.277.3726 Perforating Procedure 1 MIRU E-line equipment. 2 PJSM with all hands involved in wireline operations. • Potential pressures, gas rates. • Contingency plans. • Emergency shut in procedure. • Co-ordinate with Platform Operators during job 3 Make up sufficient lubricator with two sets of WLV’s 4 Test lubricator and lines to 3,500 psi. Hold for 5 minutes. 5 R/U and perform dummy gauge run. Tag TD. Record fill observed and fluid level. Send results to Anchorage Office. 6 Secure well. Based off recorded fluid level, pump inhibited brine to slightly overbalance the well. 7 RIH with gun run #1. 8 Run correlation GR/CCL and send correlation log to Geologist to confirm on depth. Do not shoot before confirming. 9 Once properly correlated, perforate interval #1 from 7,988-8,000 ft MD. POOH. Confirm all shots fired. 10 RIH with gun run #2. Correlate and send correlation log to Geologist to confirm on depth. Do not shoot before confirming. 11 Perforate interval #2 from 7,270-7,274 ft MD. POOH 16 R/D E-Line equipment. Furie Operating Alaska, LLC | 433 W 9th Avenue, Anchorage, AK 99501 | 907.277.3726 THE STATE 01ALASKA COVERNOR MIKE DUNLL'AVY December 1, 2020 Crystal Smith Preparedness & Response Region Manager Dept. of Environmental Conservation Division of Spill Prevention and Response 555 Cordova Street Anchorage, AK 99501 Z►to - c l (o Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.olaska.gov John L. Hendrix CEO & President Furie Operating Alaska, LLC 188 W Northern Lights Blvd, Suite 620 Anchorage, AK 99503 Re: Request for determination that Furie Operating Alaska, LLC's wells are incapable of flowing oil to the ground surface Dear Ms. Smith and Mr. Hendrix: By letter dated November 5, 2020, Furie Operating Alaska, LLC (Furie) requested that the Alaska Oil and Gas Conservation Commission (AOGCC) make a determination that none of their operated wells is capable of flowing liquid hydrocarbons to the ground surface. AS 31.05.030(1) Under AS 31.05.030(1), the Commission is authorized to determine whether an operator of a natural gas exploration facility has demonstrated with reasonable certainty that its well or wells will not penetrate a formation capable of flowing oil to the ground surface. Such a determination results in the exemption of wells at the natural gas exploration facility from the requirements of AS 46.04.030 and AS 46.04.040. Furie has requested such a determination. Furie's current activities in the Kitchen Lights Unit (KLU) fit the definition of a "natural gas production facility" as defined in AS 46.04.050(b) and not the definition of "natural gas exploration facility found in AS 46.04.050(c) because Furie is engaged in regular production of natural gas from the Julius R. Platform in the Cook Inlet. Since Furie's operations do not involve a "natural gas exploration facility" the AOGCC cannot make a determination under AS 31.05.030(1). However, AOGCC provides this review of Furie's drilling and production operations to the Alaska Department of Environmental Conservation for its consideration. Crystal Smith and John L. Hendrix December 1, 2020 Page 2 of 2 KLU Exploration and Development Well Drilling History Furie's' initial exploration activities in the KLU were to search for oil and gas. During the exploration program, a total of six exploratory wells were drilled. The wells and their current status are listed below: Well Status2 KLU 1 Suspended KLU 2 Plugged and abandoned KLU 2A Suspended KLU 3 Converted to a development well and currently producing KLU 4 Suspended KLU 5 Plugged and abandoned In addition to the six exploratory wells listed above, Furie has drilled an additional four development wells. These wells and their current status are listed below: Well Status KLU A-] Producing KLU A-2 Plugged and abandoned KLU A -2A Producing KLU A-4 Producing Potential for Flowing Liquid Hydrocarbons to the Ground Surface After review of well records and production data, the AOGCC concludes that it is reasonably certain that none of the Furie-operated wells in the KLU are capable of flowing liquid hydrocarbons to the ground surface. Generally speaking, in the Cook Inlet Basin oil production is not possible from the Upper Tyonek and shallower formations. The only KLU well drilled deep enough to encounter the Lower Tyonek and deeper potentially oil-bearing formations was the KLU 1 exploration well, but data from that well do not indicate the presence of producible liquid hydrocarbons. KLU I was subsequently plugged with multiple downhole plugs making it incapable of flowing at all even if producible liquid hydrocarbons had been discovered. Likewise, even though they didn't penetrate potential oil-bearing formations, the KLU 2, 2A, 4, 5, and A-2 wells have also been rendered incapable of any production due to the setting of downhole and surface plugs in the wells. None of the four remaining wells, all of which are currently in production, has ever shown any production of liquid hydrocarbon, nor is there any data in the well records for these wells showing that they encountered any producible liquid hydrocarbons. The initial exploration well in the KLU (KLU 91) was drilled by Escopeta Oil Company, LLC, but Furie is now operator of this and all wells in the KLU. 4 The three wells listed as suspended have all the necessary downhole plugs and surface plugs that would be required to plug and abandon the well, but the casing has not been cut off below the mudline as required by AOGCC regulations so they cannot be classified as plugged and abandoned. Crystal Smith and John L. Hendrix December 1, 2020 Page 2 of 2 Conclusion After careful review of the production and well data for the KLU wells, the AOGCC concludes that it is reasonably certain that none of the wells that Furie operates is capable of flowing liquid hydrocarbons to the ground surface. Please contact Mr. Dave Roby (at dave.robyAn alaska.eov or 793-1232) if you have questions concerning this determination. Digitallysigned Jeremy by 1--y M. Digaally signed by pd« Jessie L. Date:3030.1z.01 Wnielllysignedby l 1:10C .12.01 ski M. PIICena3:o5ovoo' Daniel T. Dle20x12D1um,Jr. ChmlelowsklDare:zozo.lz.ol Seamount, Jr.Daleagl0.IIA1 n:zeoz onao' 1U19A1 -09'00' Jeremy M. Price Daniel T. Seamount, Jr. Jessie L. Chmielowski Commissioner, Chair Commissioner Commissioner cc: Laurie Silfven, DEC AND APPEAL NOTICE As provided in AS 31.05.080(a), within 20 days after written notice of the entry of this order or 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 reconsideration of the matter determined by it. If the notice was mailed, then the period of time shall be 23 days. An application for reconsideration must set out the respect in which the order or decision is believed to be erroneous. The Commission shall grant or refuse the application for reconsideration in whole or in part within 10 days after it is filed. Failure to act on it within 10 -days is a denial of reconsideration. If the Commission denies reconsideration, upon denial, this order or decision and the denial of reconsideration are FINAL and may be appealed to superior court. The appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days if the Commission otherwise distributes, the order or decision denying reconsideration, UNLESS the denial is by inaction, in which case the appeal MUST be filed within 40 days after the date on which the application for reconsideration was filed. If the Commission grants an application for reconsideration, this order or decision does not become final. Rather, the order or decision on reconsideration will be the FINAL order or decision of the Commission, and it may be appealed to superior court. That appeal MUST be filed within 33 days after the date on which the Commission mails, OR 30 days ifthe Commission otherwise distributes, the order or decision on reconsideration. As provided in AS 31.05.080(b), "[t]he questions reviewed on appeal are limited to the questions presented to the Commission by the application for reconsideration." In computing a period of time above, the date of the event or default after which the designated period begins to run is not included in the period; the last day of the period is included, unless it falls on a weekend or state holiday, in which event the period runs until 5:00 p.m. on the next day that does not fall on a weekend or state holiday. e A!::: ' FJR1E OPE fiATALASKA LLC RECEIVED HOV 0 6 2020 November 5, 2020 �+ Alaska Oil and Gas Conservation Commission AOGCC 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RE: Determination to Request that all FURIE's KLU wells are compliant with AS 31.05.030(1) Dear Chairman Price, Furie Operating Alaska LLC (FURZE) is requesting AOGCC's determination to eliminate the Alaska Department of Environmental Conservation (ADEC)'s requirement for an oil discharge prevention and contingency plan and corresponding proof of financial responsibility placed on Furie under previous ownership. Furie Operating Alaska, LLC submits this letter requesting a determination from AOGCC that all of the producing wells (Table 1) in FURIE's Cook Inlet Kitchen Lights Unit (KLU) produce only natural gas from the Beluga and Sterling formations, with no co -production of liquid hydrocarbons or oil. FURIE also requests determination that there are no wells currently capable of oil or liquid hydrocarbon production from the Tyonek or deeper formations based on the following: • Oil commodity economics are not favorable for the foreseeable future and FURIE has suspended plans to explore and develop deeper, potentially oil-bearing horizons. There are no oil-bearing strata nor oil shows identified within the Beluga and Sterling formations within the 4 producing wellbores (KLU #A-1, KLU #A -2A, KLU #3, and KLU #A-4). There are no other FURIE wells capable of hydrocarbon production. • All producing wells are plugged back to the base of the gas producing Beluga formation. There are currently no producible penetrations of the potentially oil bearing upper or lower Tyonek, nor the Hemlock -Sunfish formations in any of the above noted producing gas wells. There were no tests of liquid hydrocarbons below the top of the Tyonek in any FURIE wells. Three unsuccessful exploratory wells (KLU #4, KLU #2, KLU #1) were drilled, but not tested on company leases and are cemented back to sea floor (Table 2). Two wells (KLU #4, KLU #2) reached total depth within the base of the Beluga formation and did not penetrate deeper potentially oil bearing Tyonek or Hemlock formations. A third well (KLU #1) was a deep exploratory test that terminated in the Tyonek. KLU #1 did not encounter producible hydrocarbons and has been cemented. The open hole portion of the well was plugged back with cement from 15,298' to 13,108' MD, inside 9-7/8" casing shoe located at 13,383' MD. All perforations and productive intervals were cemented with top of uppermost cement plug at 325' MD, 122' below seafloor with 13-3/8" cap installed. All cement plugs were set in place per AOGCC P&A requirements. FURIE requests the AOGCC determination that we are natural gas producer only and, as such, are compliant with AS 31.05.030 and do not have any wells capable of flowing oil or liquid hydrocarbons to the ground surface. (a) AS 31.05.030 (1) that evidence obtained through evaluation demonstrates with reasonable certainty that all of the wells at a natural gas exploration facility will not penetrate a If the drilling of a well at an exploration facility exempted under this subsection does Penetrate a formation capable of flowing oil to the surface, the owner or operator shall submit an oil discharge prevention and contingency plan and proof of financial responsibility to the department to meet the requirements of AS 46.04.030 and 46.04.040. Finally, FURIE also requests a determination/confirmation that the FURIE KLU production platform and onshore facility produce and process natural gas only, with no capacity to produce or transport liquid hydrocarbons or oil. AS 46.04.050. Exemptions. (a) The provisions of AS 46.04.030 , 46.04.040, and 46.04.060 do not apply to an oil terminal facility that has an effective storage capacity of less than 5,000 barrels of crude oil or less than 10,000 barrels of non -crude oil. (b) The provisions of AS 46.04.030 and 46.04.040 do not apply to a natural gas production facility and a natural gas terminal facility; for purposes of this subsection, "natural gas production facility" and "natural gas terminal facility" mean a platform, facility, or structure that, except for storage of refined petroleum products in a quantity that does not exceed 10,000 barrels, is used solely for the production, compression, storage, or transport of natural gas. (c) The provisions of AS 46.04.030 and 46.04.040 do not apply to a natural gas exploration facility if the Alaska Oil and Gas Conservation Commission has determined under AS 31.05.030 (1) that evidence obtained through evaluation demonstrates with reasonable certainty that all of the wells at a natural gas exploration facility will not penetrate a formation capable of flowing oil to the ground surface. If the drilling of a well at an exploration facility exempted under this subsection does penetrate a formation capable of flowing oil to the surface, the owner or operator shall submit an oil discharge prevention and contingency plan and proof of financial responsibility to the department to meet the requirements of AS 46.04.030 and 46.04.040. For purposes of this subsection, "natural gas exploration facility" means a platform, facility, or structure that, except for storage of refined petroleum products in a quantity that does not exceed 10,000 barrels, is used solely for the exploration for natural gas. Additionally, we would like to reference the attached letter to Crystal Smith P&R Manager dated August 11,2020, Attachment A: Request for suspension of FURZE Operating Alaska's Oil Discharge Prevention and Contingency Plan, Cook Inlet Exploration Kitchen Lights Unit ADEC C -Plan (C - Plan No. 16 -CP -5184) and Relief from Financial Responsibility Requirements. If you have any questions or require further information, please contact Rick Dusenbery at (907) 331-9282, email at r.dusenbery( furiealaska.com or call me at (907) 365-9945. John. Hendrix CEO resident Fune O rating Alaska, LLC Jessie Chmielowski, Commissioner Dan Seamount, Commissioner Jody Colombie, AOGCC Special Assistant David Roby, Senior Petroleum Engineer Guy Schwartz, Senior Petroleum Engineer Table 1 FURIE Operating Alaska Well Location List and Status WO Name C..m sm. "IN RDI wrbae lautbn COwENaOeF1 L 9. s4lmA T.,MP 60.44'09'N/151'19'S0'W 1 MMB,n faordlru3H NA027 x Y ww. KLU AJ Pr44uFn 50733206820000 216-069 339'FSL, 891'iWl 24 ION IIW Seward 290315.65 153611130 AN 7. 84 NtU A -LL P r 561334065501-00 216066 $%' FM, 303'FSL 20 ION IIW Seward 290331.09 2536125.62 MK 04 MLU A -I aradanr 50733-2065600-00 216063 884'FWL, 342'FSL Z4 ION IIW Seward 29/31930 2536123.89 AK Ztt N4 KLU3 P W 50233206100000 213dIS 3N'FSL, 903'FWL 24 ION 11W Seward 290305.00 2536130.00 AK Za 14 UU4 5023320616-0000 113-088 122'FEL, 2A22'FNL 8 ION IIW Seward 309226.00 2508902.00 AN " KIUm 50733-206039100 212-142 1,503'FN42<20'FEL 35 ION IIW Seward 290842.27 2529019.06 AN Za N4 nut 50733 -20593O -OO 211039 241'FNL, 2,095'FWL 25 ION MIN Seward 295390.00 2535400.00 AN Zone N4 INIF A-2 N6A 50733-206$50000 216455 8%'FW4343'FSL 24 ION 21W Seward 290331.49 2536125.62 AN Zq 44 KWS a6A 500.733-206320000 210072 99' FEL, 2,105' FSL 22 9N I1W Seward 28W01.00 2506011.00 NK Z. N4 KLU2 14 50733-206030000 212479 1,521'/N1, 2.802'FWL 35 ION 1184 Seward 290840.19 2529001.9E AK 2. 44 WIN, CmmWtn llx./LeALI INNNOKNbtlmm W56'12-NII5IW2M lan 60.44'09'N/151'19'S0'W Facility Table 2 -Summary of Wells Awaiting P&A Status Well Status Comments KLU #4 (PTD: 213-088) Dryhole-noeconomic hydrocarbons % Drilled to a total depth of 9,163' MD/ 8,639' TVD. Formation at depth of TD: BELUGA. Wellbore cemented. Wellbore cemented, incapable of Top of uppermost cement plug at flow 196' MD, 4' below seafloor. All cement plugs set in place per AOGCC P&A requirements. W.O. 30" casing cut below mudline. KLU #2A (PTD: 212- Dry hole -no economic hydrocarbons Drilled to a total depth of 10,750' 147) encountered MDI 7,109' TVD. Formation at depth of TD: BELUGA; Wellbore Wellbore cemented, incapable of cemented. Top of uppermost flow cement plug at 227' MD, 15' below seafloor with 13-3/8" cap installed. All cement plugs set in place per AOGCC P&A requirements. W.O cut of 15' of 30" casing remaining above mudline. KLU #1 (PTD: 211-039) Dry hole -no economic hydrocarbons Drilledto a total depth of 15,298' encountered MD/ 15,298' TVD. Formation at depth of TD: Lower TYONEK. Wellbore cemented, incapable of flow Open hole plugged back with cement from 15,298'to 13,108' MD, inside 9 7/8" casing shoe located at 13,383' MD. Wellbore cemented. Top of uppermost cement plug at 325' MD, 122' below seafloor with 13-3/8" cap installed. All cement plugs set in place per AOGCC P&A requirements. W.O. 30" casing cut below mudline ATTACHMENT A 6 Aa EVIRIn , VIA HAND DELIVERY/EMAIL August 11, 2020 Alaska Department of Environmental Conservation Prevention, Preparedness & Response Program Division of Spill Prevention and Response 555 Cordova Street Anchorage, Alaska 99501-2617 Attn: Crystal Smith, P&R Region Manager Re: Request for suspension of FURIE Operating Alaska's Oil Discharge Prevention and Contingency Plan, Cook Inlet Exploration Kitchen Lights Unit ADEC C -Plan (C -Plan No. 16 -CP -5184) and Relief from Financial Responsibility Requirements Dear Ms. Smith: Thank you very much for the conference call with you and Graham Wood on August 3, 2020. We were pleased to Introduce some of the new FURZE Operating Alaska LLC management team and provide a brief overview of our company's status, current operations and priorities. FURZE Operating Alaska LLC is exclusively a producer of dry biogenic natural gas with no co -production of any oil or liquid hydrocarbons. The above referenced ADEC C -Plan No. 16 -CP -5184 was developed to address the C -Plan requirements for FURIE's multiyear Cook Inlet Exploration Drilling Program. This C -Plan was originally approved in February 2012, with 5 subsequent revisions, and last updated in July 2018. As a natural gas producer with no current plans to drill or develop oil prospects on our leases, FURZE requests exemption from the requirements of Oil Discharge Prevention and Contingency Plan (ADEC C -Plan No. 16 -CP -5184) as specified under Alaska Statute 46.04.050. Notwithstanding the foregoing, FURZE Operating Alaska will continue to adhere to all C -Plan, HSE and regulatory requirements pertaining to the safe operation of our existing Cook Inlet KLU natural gas production platform, pipelines and on -shore facilities. In support of our request, the company offers herein a brief summary of our corporate re -structuring and operations. Corporate Profile and Status - FURIE Operating Alaska LLC Chapter 11 debtor FURIE Operating Alaska LLC and related debtor companies, Cornucopia Oil & Gas Company LLC and Corsair Oil & Gas LLC, filed an amended plan of reorganization on June 7, 2020 in the U.S. Bankruptcy Court for the District of Delaware. The plan was accepted by the court on June 11, 2020 and set forth the proposed acquisition of the assets and existing equity interests of the debtors' assets by Anchorage based HEX Cook Inlet LLC (HEX -CI). The transaction closed on June 30, 2020 and HEX -CI Page I 1 Furie Operating Alaska, LLC 1 188 W Northern Lights Blvd, Suite 620, Anchorage, AK 995031907.277.3726 e� FUR & took control of the assets on July 1, 2020. Post -closing, FURIE Operating Alaska LLC remains as the designated corporate operating entity. FURZE Operating Alaska LLC has engaged a highly experienced team of professionals to manage company operations In a safe, expedient and socially responsible manner. In all circumstances, the company and management are mandated to protect the public's Interest and safety. The new management team is establishing itself as a prudent, diligent and environmentally responsible operator. In all aspects of our business, management is following best practices designed to optimize ultimate hydrocarbon recovery and create in-state employment, economic development and royalty revenue for Alaskans. Oil Discharge Prevention and Contingency Plan - ADEC C -Plan (C -Plan No. 16 -CP -5184) FURIE Operating Alaska LLC produces only non -associated biogenic dry natural gas from our operated Kitchen Lights Unit (KLU) platform. The dry gas is co-produced with varying amounts of relatively fresh formation water from the Beluga and Sterling formations through four existing gas production wells. The produced gas comprises 99.4% methane and is transported from the Cook Inlet offshore gas production platform via pipeline to our onshore gas processing and sales facility. There are no associated oil, condensate, or natural gas liquids produced with the natural gas (Attachment A). Oil commodity economics are not favorable for the foreseeable future and FURIE has suspended plans to explore and develop deeper, potentially oil-bearing horizons. There are no oil-bearing strata nor oil shows identified within the Beluga and Sterling formations within the 4 producing wellbores (KLU #A-1, KLU #A -2A, KLU #3, and KLU #A-4). All producing wells are plugged back to the base of the gas producing geluga formation. There are currently no producible penetrations of the potentially oil bearing lower Tyonek or Hemlock formations in any of the above noted producing gas wells. Three unsuccessful exploratory wells (KLU #4, KLU 112, KLU #1) were drilled on company leases and are cemented back to sea floor (Attachment Q. Two wells (KLU #4, KLU #2) reached total depth within the Beluga formation and did not penetrate deeper potentially oil bearing Tyonek or Hemlock formations. A third well (KLU #1) was a deeper test that terminated in the Tyonek. KLU #1 did not encounter producible hydrocarbons and has been cemented. The open hole portion of the well was plugged back with cement from 15,298' to 13106' MD, inside 9-718° casing shoe located at 13,383' MD. All perforations and productive intervals were cemented with top of uppermost cement plug at 325' MD, 122' below seafloor with 13-318' cap Installed. All cement plugs were set In place per AOOCC PSA requirements. FURIE Operating Alaska LLC is currently updating the 2020 Plan of Development as well as the 2020 Plan of Operations. In the past month post -closing, the company has identified several critical operational and commercial priorities that will be included in the updated plans: • Restoring gas production from the suspended KLU-A4 wellbore • Increasing gas production from the KLU #3, #A -2A, #A-1 wells • Completing the permitting and installation of produced water handing facilities on the KLU gas production platform Page 12 Furie Operating Alaska, LLC 1 188 W Northern Lights Blvd, Suite 620, Anchorage, AK 99503 907.277.3726 e;z? F"W"RIK • Completing thorough technical engineering, geoscience and HSE due diligence on all company owned assets, including pipelines, facilities producing, suspended and P&A wells • Completing several critical commercial and financial tasks relating to insurance, property taxes, gas marketing and operating efficiencies FURZE Operating Alaska LLC is requesting waiver of the existing DEC financial responsibility insurance requirements as the company is exclusively a producer of dry non -associated natural gas with no co -production of oil or liquid hydrocarbons. FURIE Operating Alaska LLC is not currently exploring for, developing or producing oil or gas liquids, and therefore does not operate any of the following operating structures that require proof of Financial Responsibility. The company requests a suspension of FURIE Operating Alaska's Oil Discharge Prevention and Contingency Plan (ODPCP, C -Pian) and Release from Financial Responsibility Requirements detailed below: • Oil Terminal Facility- facilities with storage capacity more than 5,000 barrels of crude or 10,000 of non -crude. 46.04.900 115) IASP). • Pipeline -structures used to transport oil or petroleum products between production facilities or to vessels. 46.04.900 119) (ASP). • Exploration Facility - platform, vessel, or other facility used to explore for oil resources. 46.04.900 (8) (ASP). • Offshore or Onshore Production Facility- drilling rig, drill site, flow station, gathering center, pump station, storage tank, well and related appurtenances. 46.04.900 (20) (ASPI The company currently has $1.63M in existing Bond/CD deposits on file with various Alaska State Agencies (Attachment B). These demonstrate that the company has financial capability and is committed to corporate responsibility as defined by State Law. Should you have any questions or require a technical presentation beyond the information presented here, please do not hesitate to contact the undersigned directly. Thank you for your consideration. Respectfully, Rick Dusenbery Chief Operating Officer FURIE Operating Alaska LLC Page 13 Furie Operating Alaska, LLC 1 188 W Northern Lights Blvd, Suite 620, Anchorage, AK 99503 1907.277.3726 �? F"WE Attachment A Kitchen Lights Unit Total Production by Well & Pool Initial Production to lune 30, 2010 Page 14 Furie Opemting Alaska, LLC 1 188 W Northern Lights Blvd, Suite 620, Anchorage, AK 99503 1907.277.3726 �� (M4RN�,P1 A'KA tt� Attachment B - Summary of Bond/CD Amounts FURZE Alaska Operating LLC Type of Bond Agency Bank Bond/CD Reference Amount 8 AOGCC AOGCC Northrim 3128440746 $6501000 Blanket Well Bond AOGCC Northrim 7101559313 $200,000 Statewide Oil and Gas SOA,DNR Northrim 7101550668 $500,OOD Bond Pipeline DR&R SOA, Div of Mining, Land and Northrim 7102128969 $228,375 Water Pipeline Survey SOA, Div of Minln& Land and Northrim 7102128977 5 50,000 Water TOTAL $1,628,375 Attachment C - Summary of Suspended Wells Awaiting Final P&A Status Well Status Comments KLU 1141PTD: 213488) Dry hale -no economic hydrocarbons Drilled to a total depth of 9,163' MD/ encountered 8,639' TVD. Formation at depth of TD: Wellbore cemented, incapable of flow BELUGA. Wellbore cemented, Top of uppermost cement plug at 196' MD, 4' below seafloor. All cement plugs set in place per AOGCC P&A requirements. W.O cut of 15' of 30" casing remaining above mudline. KLU g2A )PTD: 212-147) -. Dry hole -no economic hydrocarbons Drilled to a total depth of 10,750' MD/ encountered 1 7,109' TVD. Formation at depth of TD: Wellbore cemented, incapable of flow, BELUGA; Wellbore cemented. Top of uppermost cement plug at 227' MD, 15' below seafloor with 13-3/8" cap Installed. All cement plugs set In place per AOGCC P&A requirements. W.O cut of 15' of 30" casing remaining above mudline. KW 41 )PTD: 211-039) Dry hole -no economic hydrocarbons Drilled to a total depth of 15,298' MD/ encountered 15,298' TVD. Formation at depth of TD: Wellbore cemented, incapable of flow TYONEK. Open hole plugged back with cement from 15,298' to 13,108' MD, Inside 9 7/8" casing shoe located at 13,383' MD. Wellbore cemented. Top of uppermost cement plug at 325' MD, 122' below seafloor with 13-3/8" cap installed. All cement plugs set In place per AOGCC P&A requirements W.O cut of 15' of 30" casing remaining above mudline. Page 15 Furie Operating Alaska, LLC 1 188 W Northern Lights Blvd, Suite 620, Anchorage, AK 99503 1907.277.3726 1. Operations Abandon Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Performed: Suspend Perforate Other Stimulate Alter Casing Change Approved Program Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well Other: ______________________ Development Exploratory Stratigraphic Service 6. API Number: 7. Property Designation (Lease Number): 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): 11. Present Well Condition Summary: Total Depth measured feet feet true vertical feet feet Effective Depth measured feet feet true vertical feet feet Perforation depth Measured depth feet True Vertical depth feet Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 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 W DSPL Electronic Fracture Stimulation Data GSTOR GINJ SUSP SPLUG Sundry Number or N/A if C.O. Exempt: Contact Name: Authorized Title: Contact Email: Contact Phone: 2. Operator Name: Senior Pet. Engineer: Senior Res. Engineer: CollapseBurstTVDLengthCasing Authorized Signature with date: Authorized Name: 5. Permit to Drill Number: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Size 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) Gas-Mcf measuredPlugs Junk measured STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS 3. Address: 4. Well Class Before Work: Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureOil-Bbl measured true vertical Packer WINJ WAG Water-Bbl MD 15.Well Class after work: Exploratory Development ServiceStratigraphic 16.Well Status after work:Oil Gas WDSPL a GSTOR GINJ SUSP SPLUG 5.070, 25.071, & 25.283) WINJWAG tion: tion: Gas-Mcf Representative Daily Average Production or Injection Data Casing Pressure Tubing PressureOil-Bbl W ater-Bbl summary: olumes used and final pressure: Plug Perforations Fracture Stimulate Pull Tubing Operations shutdown Perforate Other Stimulate Alter Casing Change Approved Program Perforate New Pool Repair Well Re-enter Susp Well Other: ______________________ Development Exploratory Stratigraphic Service6.API Number: mber):8. Well Name and Number: onic data per 20AAC25.071):10. Field/Pool(s): ry: ured feet feet tical feet feet ured feet feet tical feet feet epth feet epth feet true vertical depth) d and true vertical depth) CollapseBurstTVD 5. Permit to Drill Number: Size measuredPlugs Junkmeasured 4. W ell Class Before W ork: measured true vertical Packer MD Form 10-404 Revised 3/2020 Submit Within 30 days of Operations Senior Res.Engineer: By Samantha Carlisle at 2:38 pm, Nov 05, 2020 Furie Operating Alaska, LLC 188 W. Northern Lights Blvd, Suite 620,Anchorage AK 99513 216-086 50-733-20655-01-00 ADL 389197 KLU A-2A None Kitchen Lights Unit: Sterling, Beluga Undefined Gas Pool 8160' 7301' N/A N/A 8041' 7197' Conductor 381 20" 381 381 Surface 2265 13 3/8" 2265 1995 5380 psi 2670 psi Production 8122 9 5/8" 8122 7268 7930 psi 6620 psi 6884-6900; 7168-71, 6140-6154; 6405-64, 4-1/2" L-80 4,608' MD 3,973' TVD Superior Com Permanent CSHR- SSSV@1650'MD SSSV@1573'TV N/A N/A 0 2200 0 175 350 0 4000 0 175 1100 320-388Rick Dusenbery Chief Operating Officer Rick Dusenbery r.dusenbery@furiealaska.com (907) 565-2001 ✔ ✔ ✔✔ ✔ See attached schematic drawing for a complete listing of all perforated intervals. SFD 11/6/2020 DSR-11/10/2020gls 12/9/20 SFD 11/6/2020RBDMS HEW 11/5/2020 188 W Northern Lights Blvd, Suite 620 | Anchorage, Alaska | 99501 | Office: 907-277-3726 November 5th, 2020 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RE: 10-404 Sundry to Add Beluga Perforations – PTD 216-086/Sundry 320-388 Well: KLU A-2A TO WHOM IT MAY CONCERN, Enclosed is ƚŚĞcompleted 10-404 sundry for KLU A-2A with attached wellbore schematic and daily summary of workover operations. Perforations were added to the Beluga formation in the KLU A-Ϯ wellbore from 6,884’-6,900’ MD, 7,168’-7,174’ MD and 7,234’-7,238’ MD. Operations were completed by November 3rd, 2020 and were conducted on the Julius R Production Platform. If you have any questions or require further information, please contact me at (907) 565-2001 or email at r.dusenbery@furiealaska.com. 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'/*,*$!& F7B6C;CA>7BBA$&#&A5AAI;DBG !**((*& C5IBD; +'$.+8FDEI:<FEJA:9 *+GGHJ7GHAB:8FJFA7FJHB:9 NCFHD(+!3 NBAJ $- J7F6I;FD5D>7BBA'=I2BCC:6H2CGI: C5IBD;=F2JFB: 4I2BGA:6H2DAB: ((*$- *+GBCH7GCHG:8FHHD7FIGH:9 NCDJI(+!3 NBAI -%(#*=GHBB: -$ '8&' +'++09=GHDB: WĞƌĨƐ ϲ͕ϴϴϰͲϲ͕ϵϬϬΖD;ϲ͕ϭϰϬΖͲϲ͕ϭϱϰΖdsͿ ϳ͕ϭϲϴΖͲϳ͕ϭϳϰΖD;ϲ͕ϰϬϱΖͲϲ͕ϰϭϬΖdsͿ ϳ͕ϮϯϰΖͲϳ͕ϮϯϴΖD;ϲ͕ϰϳϴΖͲϲ͕ϰϴϭΖdsͿ WĞƌĨƐWĞƌĨƐ ϲ͕ϴϴϰͲϲ͕ϵϬϬΖD;ϲ͕ϭϰϬΖͲϲ͕ϭϱϰΖdsͿ ϳ͕ϭϲϴΖͲϳ͕ϭϳϰΖD;ϲ͕ϰϬϱΖͲϲ͕ϰϭϬΖdsͿ ϳ ϮϯϰΖ ϳ ϮϯϴΖ D ;ϲ ϰϳϴΖ ϲ ϰϴϭΖ dsͿϳ͕Ϯϯϰ Ͳϳ͕Ϯϯϴ D;ϲ͕ϰϳϴ Ͳϲ͕ϰϴϭ dsͿ 1 11/2/2020 KLU A-2A 2 11/3/2020 KLU A-2A Safety meeting. Spot equipment. Unable to establish AC power in unit. Troubleshooting. Faulty inverter. Bypassing inverter. PJSM for perf operations. Shut in well. Rig up 2-3/8" x 4' gun. Function check GR. Stand up PCE. RIH with 2-3/8" x 4' gun. Gun Gamma Ray failure. Lost communication with tool. POOH. Swapped GR. RIH with 2-3/8: x 4' gun to perforate 7,234' - 7,238', On depth with SCSSV at 1,653'. Record up to correlate. Sent log to town. Adjusted log -6'. Shot 2-3/8" x 4' gun on depth of 7,234' - 7,238'. Clean break. POOH. Unit will not maintain 2nd gear. OOH. Return line iced up. Laying down lube to thaw line. Adjust unit position. Rig up gun 2. RIH with 2-3/8" x 6' gun to perforate 7,168' - 7,174'. Shot 2-3/8" x 6' gun on depth of 7,168' - 7,174'. Clean break. POOH. Unit unable to maintain 2nd gear. OOH. Rig up gun 3. RIH with 2-3/8" x 16' gun to perforate 6,884' - 6,900'. Shot 2-3/8" gun on depth of 6,884' - 6,900'. Clean break. POOH. Generator died. Troubleshooting problem. Possible fuel pump or bad fuel issue. Having to re-start several times. OOH. Laying down lubricator. Secured well. Turned over to production. Rig down. Standing by. Unable to perform crane operations due to excessive wind speeds. Wind window. Begin to spot equipment. Excessive wind speed. Unable to finish spotting equipment. Shut down due to wind speed Well KLU A-2A Wireline Operational Summary CONFIDENTIAL DAY DATE SUMMARY 1.Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdown Suspend Perforate Other Stimulate Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: ___________________ 2. Operator Name:4.Current Well Class:5.Permit to Drill Number: E xploratory Development 3.Address:Stratigraphic Service 6.API Number: 7.If perforating:8.W ell 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): Casing Collapse Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13.W ell Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15.W ell Status after proposed work: Commencing Operations:OIL WINJ WDSPL Suspended 16.Verbal Approval:Date:GAS WAG GSTOR SPLUG Commission Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: 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: Perforation Depth MD (ft): TVD BurstMDLength Size Perforation Depth TVD (ft): Tubing Size: PRESENT WELL CONDITION SUMMARY STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 COMMISSION USE ONLY Authorized Name: Tubing Grade: Tubing MD (ft): approval: Notify Commission so that a representative may witness Sundry Number: BOP Test Mechanical Integrity Test Location Clearance ection MIT Req'd? Yes No ption Required? Yes No Subsequent Form Required: COMMISSION USE ONLY Contact Name: Contact Email: Contact Phone: Date: e: certify that the foregoing is true and the procedure approved herein will not rom without prior written approval. gnature: me: Date for 15.W ell Status after proposed work: Operations:OIL WINJ WDSPL Suspended proval:Date:GAS WAG GSTOR SPLUG Representative:GINJ Op Shutdown Abandoned nts: Proposal Summary Wellbore schematic13. W ell Class after proposed work: ations Program BOP Sketch Exploratory Stratigraphic Development Service SSSV Type:Packers and SSSV MD (ft) and TVD (ft): pth MD (ft):Perforation Depth TVD (ft):Tubing Size:Tubing Grade:Tubing MD (ft): quest: Abandon Plug Perforations Fracture Stimulate Reppair Well Operations shutdown Suspend Perforate Other Stimulate Pulll Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter Susp Well Alter Casing Other: er Casing ___________________ ame:4.Current Well Class:5.Permit to Drill Number: Exploratory Development Stratigraphic Service 6. API Number: g:8.W ell Name and Number: ation or Conservation Order governs well spacing in this pool? perforations require a spacing exception?Yes No esignation (Lease Number):10. Field/Pool(s): D (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi):Plugs (MD):Junk (MD): g CollapseTVDBurstMDLengthSize PRESENT WELL CONDITION SUMMARY Form 10-403 Revised 3/2020 Approved application is valid for 12 months from the date of approval. By Samantha Carlisle at 11:50 am, Sep 21, 2020 320-388 Furie Operating Alaska, LLC 188 W. Northern Lights Blvd, Suite 620,Anchorage AK 99513 216-086 50-733-20655-01-00 CO 723 KLU A-2A ADL 389197 Kitchen Lights Unit: Sterling, Beluga Undefined Gas Pool 8160'7301'8041'7197'2201 psi Conductor 381' 20" 381' 381' Surface 2265' 13 3/8" 2265' 1995' 5380 psi 2670 psi Production 8122' 9 5/8" 8122' 7268' 7930 psi 6620 psi 6884-6900; 7168-7174; 723 6140-6154; 6405-6410; 64 4 1/2"L-80 4608 Superior Completion Services: Packers: 9-5/8" Permanent (Sump Packer); CSHP-NR (Gravel Pack Packers),SCSSV; 4-1/2" SESX2000'EQ SCSSV @ 1,650' MD / 1,573' TVD Pks @ 6,711' MD/5,980' TVD & 6,286' MD/5,581' TVD & 5,997' MD/5,307' TVD & 5,496' MD/3,882' TVD & 4,813' MD/4,153' TVD 09/28/2020 Rick Dusenbery Chief Operating Officer Rick Dusenbery Digitally signed by Rick Dusenbery Date: 2020.09.21 11:41:11 -08'00'09/21/2020 Rick Dusenbery r.dusenbery@furiealaska.com (403)473-2629 ✔ ✔ ✔ ✔ ✔✔ ✔ Julius platform) ( GAS Perfoffrate eline 10-404 DSR-9/21/2020 applies to add perfs DLB 09/22/2020 XCO 723 applies here. DLB X DLB gls 9/22/20 Comm. plies here.DLBli h DLB 9/22/2020 dts 9/22/2020 JLC 9/22/2020 RBDMS HEW 9/23/2020 proposed Beluga perfs below tubing tail.... gls THE STATE OfALASKA GOVERNOR MIKE DUNLEAVY Gordon J. Raines Operations Manager Furie Operating Alaska, LLC 188 W. Northern Lights Blvd., Suite 620 Anchorage, AK 99503 Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 w .00gcc.alaska.gov Re: Kitchen Lights Field, Sterling and Beluga Undefined Gas Pool, KLU A -2A Permit to Drill Number: 216-086 Sundry Number: 319-158 Dear Mr. Raines: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, Daniel T. Seamount, Jr. Commissioner a h DATED this Z- day of April, 2019. RgpMS�bJ APR 0 2 7019 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25 28 APR 01 2019 A- OGCC l:. 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ Operations shutdowl❑ Suspend ❑ Perforate ❑ Other Stimulate ❑ Pull Tubing ❑ CharTAppr ed Progrerr❑ Plug for Redrill ❑ Perforate New Pod ❑ Reeser Susp Well ❑ Alter Casing ❑ Other: uu1 zone Chang❑ 2. Operator Norma: 4. Current Well Class: 5. Permit to Drill Number Furte Operating Alaska LLC Exploratory ❑ Development Sbaligraphic ❑ Service ❑ 2131186 3. Address: 6. API Number: 186 W Northern Lights Blvd Ste 620; Anchorage AK 99503 50.733.20655.01-00 - 7. If perforating: 6. Well Name and Number: What Regulation or Conservation Order governs well spacing in the pod? Cons. Order 723 KLU A -2A Will planned perforations require a spacing exception? Yes No y 1" 9. Property Designation (Lease Number): 10. FieldlPlwl(s): ADL 389197 IGtchen U hts Bduga Undefined Gas ( obi ; Sterling(currant) 11. PRESENT WELL CONDITION SUMMARY Tota[ Depth MID (it): Total Depth TVD (it): Effective Depth MD: EBxtive Depth TVD: MPSP(psi): Plugs (MD): Junk(MD): 8160' 7301' 8041' 719T 2201 Length Size MD TVD Burst Collapse Structural 3B1 20" 381' 381' Conductor Surface 2266 133x8" 2265' 1994.5T 6380psi 2670Ps1 L'!'.' lediate Production 8772': 95W 8122 7268 7930 psi 66200 liner Perforation Depth MD(ft): Perlwation Depth TVD (ft)- Tubing Size: Tubing Grade: Tubing MO (ft): 66736701';6127-6276';53955486; 5950.5971'; 5573.586T; 4732- 41/2" L80 4608 47354803 48191; 40854260' Packers and SSSV Type: 9 SB" Permanent Sump pkr; CSHP-NR GP Packers Packers and SSSV MD (ft) and TVD (ft): Packers:6711 MD/ 59817 TVD; 6286 MD/ 55117' cw.:,v C.r...n F.,ry cr.ccV 41n^SFSx�rvinF(\ �L-.SSv 1aFn taR 11511 TVR TVD; 599T MD/ 530T TVD; 5496 MD/ 3867 TVD; 4813' MD/4153'TVD; 4593MD/3960'TVD 12-AthchmelLti Preposaf Six WellbaesrJwnatic x 13. Well Claes after proposed work Detailed Operations Program I.,I BOP Sketch I I Exploratory I I Stratigraphicl I Dead apment I .a I Service I I 14. Estimated Date for 4/1/19 15. Well Status after proposed work: Commencing Operations: OIL ❑ WINJ ❑ GAS ❑ WAG ❑ WDSPL ❑ Suspended ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval: Date: Commission Representative: GINJ Op Shutdown Aland-ood 1. I IICItlUy 1. tllllly lIIV1 ihI ftlleyunny iS UUtl 4,: Intl pI Vl.CV 41tl dppIVV VU IIV'I6111 WIII IIVI be deviated from without prior written approval. Authorized Name: Gordon J. Rains Contact Name: Gordon J. Raines Authorized Title: Operations Manager Contact Email: .faines furiealaska.com Contact Prons. 337-278.0594 4e- � - � 9 Authorized Signature: �•.�•� Date: 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 Dater: ROMSJ�APR 0 2 2019 Post Initial Injection MIT Req'd? Yes ❑ No ❑/ Spacing Exception Required? Yes ElNoQ Subsequent Form Required: / — Q N Approved by: COMMISSIONER /9 �/ 2— I I THECOMMISSION Dale I A L Fom 10403 Revised 4/2017 Approved application 19 tl /or 72 mi nthe from the date of approval. Submit Form and Allmhments in Duplicate g Procedure forA-2A 3/31/19 Well: KLU A -2a PTD: 216-086-0 API: 50733206550100 Tubing: 4-1/2 to 4515' MD by 3-1/2" to 6731' MD Minimum ID: 2.813"@4696,4806,5348,5490,6106,6279,6624&6703 Last PBTD 8,041 ft MD Objectives (1) Tag PBTD, (2) Apply high pressure gas from KLU 3 well (SITP 1650 psi) (3) Shift Sterling sleeve CLOSED at 5490' (4) Equalize pressure across Beluga sleeves (5) Shift Beluga sleeves OPEN at 6624' and 6703' (6) Flow well to test separator Procedure 1. Rig up 2.80" gauge ring. RIH to EOT. POOH. RIH with nipple brushes and thoroughly brush sleeve at 5490'— insure sleeves are in normal operating position by monitoring pressure on tubing. Tag fluid level and note SITP. 2. Utilizing the KLU 3 well and a properly rated high pressure hose, pressure up on KLU A -2A well and depress fluid level. Tag fluid level and note SITP. 3. Shift sleeve at 5490' closed. 4. Bleed the KLU A -2A tubing from 1650 psi to 1000 psi — chart and validate for 30 minutes. Assuing no pressure change, differential test confirms sleeve is closed. Utilizing the KLU 3 well and a properly rated high pressure hose, pressure up on "closed" Beluga sleeves to 1650 psi — confirm pressure across Beluga sleeves is equalized. 6. RIH and shift Lower Beluga sleeves open at 6624' and 6105' ft MD. 7. Initiate flow at 4 MMscf/D to test. Flow well for 6 hours or until pressure, gas rate and water rate stabilizes. Further rate incease TBD. 8. Record wellhead pressure, separator pressure, gas rate and water rate every 15 minutes. 9. Send well test information to Gordon Raines for distribution. 10. Complete and forward 10-404 form to AOGCC. Tubing 411212.75 ppf L-80 CSCB IPC Tubing Surface Casing 13.375 72 ppf @ 2255 Prod Casing 9.625 53.5 ppf P110 BTC @ 8122 MD 17267 TVD Cm„nMlinn Fluid 9.7 ppg NaBrCI / 60/6 KCl IInner Starllm , . , Perfs: 4735 - 4803' MD / 4095 - 4160' ND Est. BHP 1712 psi (Sept 2016) Est. BHF 90 F I...,e. Stmilm , Perfs: 5395 - 5486' MD / 4732 - 4819' ND Est. BHP 2104 psi (Sept 2016) Est. BHF 90 F 10.4 ppf NaBrCI 6% KCL Packer fluid , I ( 1 laerer Bnlyw ((• Parts, 6127 - 6276' MD / W3 - 5ND Est. BHP 2398 psi (Sept 2016) Est. BHF 108' F BCItg9 Parts: 6679 - 6709' MD / 5950 - 5971' ND) Est. BHP 2573 psi (Sept 2016) Est. BHF 109 F Lower Beluga (not perforated) 6873 - 6918 MD / 6132 - 6173' ND Est. BHP 2902 psi / 111 F 7168 - 7274' MD / 6405 - 6503' ND Est. BHP 3060 psi / 114 F KLU A -2A WSS .an I Rev. 10.14-18 Furie A -2A WBS Condor ST (PROPOSED) API: S0.733 20 6 55 01-0 0 PTD: 216-(16G / 316-387 TD: 8,160' MD 17,301' TVD ORlrlNAI FI F1/4TIONS RKB- CHF 52.4' RKB-ML 225 Sea Level MLLW 104' RKB 20" 0.875 @ 376 MD Cbernical iniectim matlrd @ 1890' (0.375 chem inj line) SCSSV - 3.813" SESX (021652 (0.25 cmlyd line) 4.5 X -ripple; 4514' 3.813' ID Q 4514 8625 Packer with 14' seals 94565 3.5 L-80 BTS -S Isdatim Tubing MSV -O slicing sleese CLOSED @ 4696 and 48N pm tto—to w�+l Screen, Prmeld HD 5.5 &Ga 316L, 20M P-110 LTC NU 8rd 9.625 GP Packer at 48W 3.5 L-80 BTS.81sdalim Tubing MSV -O slidng sleeve CLOSED @ 5346 // (C LOSED at 5498 Screen, Proweld HD 5.5 8 -Ga 316L, 204 P-110 LTC NU 8d 9.625 Packer with 10 seals M 549T 3.5 X -nipple at 5999 9825" Packer with 14' seals 9 6000 33L -8D BTS -8 Isolation Tubing / MSV -O slidng sleeve OPEN at 6106 CLOSED a16279(�mwso) Screen. Proweld HD 5.5 8Ga 316L, 2D# P-110 LTC NU Srd 9.625 Packer wiet 14' seals A 8286 3.5 L-60 BTS-8lsdatim Tubing r MSV -O Slicing Sleeves OPEN Q 6624; CLOSED at 5703 I4Mn toapr4 Screen, Proweld HD 5.5 8 -Ga 316L, 20N P-110 LTC NU 8d 9.625 Sump Packerat 6711' Mule Shm (End of IsdaBm Assembly 96711- Tubing 41/2' 12.75 ppf L-80CSCB IPC Tubing Surface Casing 13.375 72 ppf @ 2285 Prod Casing 9.625' 53.5 ppf P110 BTC @ 8122 MD /7267 TVD C meaf' n Fluid 9.7 ppg NaBrCI /6% KCL Uonar Starliee Perfs: 4735 - 4803' MD / 4095 - 4160' TVD Est. BHP 1712 psi (Sept 2016) Est. BFIT 90 F Lower Starline Parts: 5395 - 5486' MD / 4732 - 4819' TVD Est. BHP 2104 psi (Sept 2016) Est. BHT 90 F 10.4 ppf NaBrCI 6% KCL Packer fluid Liner Beluga Parts: 6127 - 6276' MD / 5773 - 5867' TVD Est. BHP 2398 psi (Sept 2016) Est. BHT 108' F Parts: 6679 - 6709' MD 15950 - 5971' ND) Est. BHP 2573 psi (Sept 2016) Est. BHT 109 F Lower Beluga (rat perforated) 6873 - 6918 MD / 6132 - 6173' TVD Est. BHP 2902 psi / 111 F 7168 - 7274' MD / 6405 - 6503' TVD Est. BHP 3060 psi / 114 F KLU A -2A WBS lm ,. Rev. 1414-18 Furie A -2A WBS Condor ST (current) API: 5473320655-01-00 PTD: 216-088/316-387 TD:8,169 MD / 7,301' TVD ORIGINAI FI EVATIONS RKB - CHF 52.4' RKB - ML 225 Sea Level MLLW 104' RKB 20" 0.875 @ 375 MD Chemical in lection mandrel @ 1640 (0.375 chem iN line) SCSSV - 3.813" SESX @ 1652' (0.75' Bawd line) 4.5 X -nipple: 4514' 3.813" ID @ 4514' 9.625' Packer with 14' seals at 4565 3S L-60 BTS -8 solation Tubing MSV -O sliding sleeve CLOSED @ 4698 and 4806' (slat aosn to arenl Screen, Proweld HO 5,5'8 -Ga 316L, 2011 P-110 LTC NU 8rd 9.625 GP Packer at 4814' 35 L-80 BTS -8 lsdation Tubing MSV -O sliding sleeve CLOSED@ //OPEN@254(SMA to oor4 Screen, Proweld HD 5.5 8 -Ga 316L, r 110 LT 9.625 Packer with 10 sees at 549T 3.5 X -nipple at 5949' 9.825" Packer with 14' seals N 6009 3.6' L-80 BTS-8lsolation Tubing MSV -O slidrg sleeve CLOSED @ 6105 and 6279Ismt oo—to�,l Screen, Proweld HD 5.5 8 -Ga 3161, 200 P-110 LTC NU aid 9.625 Packer with 14' seals M 62W 3.5 L-80 BTS -8 lsdation Tubing MSV -O Sliding Sleeves CLOSED @ 6624' and 6703' (,,wt dorm to o I Screen, Proweld HD 55 8 -Ga 316L. 20k P-110 LTC NU erd 9.625 Sump Packer at 6711' Mule Shoe (End of Isolation Assembly M 6711' L OF 7.4 �E •• /� . ��\I/��,s� THE STAVAlaska Oil and Gas ,4? OfA LAs/KA Conservation Commission 333 West Seventh Avenue GOVERNOR BILL WALKER Anchorage, Alaska 99501-3572 Main: 907.279.1433 ALA`s� Fax: 907.276.7542 www.aogcc.alaska.gov Marty Lemonswim MAY 2 3 L O l$ Project/Well Operations Manager Furie Operating Alaska, LLC 188 W Northern Lights Blvd., Suite 620 Anchorage, AK 99503 Re: Kitchen Lights Field, Sterling Undefined Gas; Beluga Undefined Gas Pool, KLU A2A Permit to Drill Number: 216-086 Sundry Number: 318-207 Dear Mr. Lemon: Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown,a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely, �I Hollis S. French Chair DATED this-2-'' day of May, 2018. pMS Ay 2 3 2018 RB • • RECfrT STATE OF ALASKA 18 2 • ALASKA OIL AND GAS CONSERVATION COMMISSION �`� 0 18 APPLICATION FOR SUNDRY APPROVALS 07's 512_3/0 8' 20 AAC 25.280 �S per,( ('� 1.Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Repair Well ❑ alieth3�Iifwn❑ Suspend ❑ Perforate 0. Other Stimulate ❑ Pull Tubing C] 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: Furie Operating Alaska,LLC Exploratory [] Development Q . 216-086 • 3.Address: 188 W.Northern Lights Blvd,Suite 620 Stratigraphic ❑ Service ❑ 6.API Number: Anchorage,Alaska 99503 50-733-20655-01-00 • 7.If perforating: 8.Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Conservation Order 723 • Kitchen Lights Unit#A2A - Will planned perforations require a spacing exception? Yes ❑ No 0 9.Property Designation(Lease Number): 10.Field/Pool(s) r--7i j 4[ems e/. , ,s ' �ti _ L f�cff ,4t _ 389197 A 572.4 KLU al Gas Poon S z-/- ;ice 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): 8160' • 7301' • 8041' 7197' 2201 Casing Length Size MD TVD Burst Collapse Structural 329' 20" 381' 381' Conductor Surface 2,213' 13-3/8" 2,265' 1,995' 5380 psi 2670 psi Intermediate Production 8,070' 9-5/8" 8,122' 7,268' 7930 psi 6620 psi Liner i Perforation Depth MD(ft): Perforation Depth TVD(ft): Tubing Size: Tubing Grade: Tubing MD(ft): 6679-6701',6127-6276' 5950-5971',5773-5867' 4-1/2" L-80 4608' 5395-5486',4735-4803' 4732-4819',4085-4260 Packers and SSSV Type: 9-5/8"Permanent(Sump Pkr); Packers and SSSV MD(ft)and TVD(ft): Pkrs:6711'MD/5980'TVD,6286'MD/5581'TVD, CSHP-NR(Gravel Pack Pkr) SCSSV: 1650'MD/1573'ND 5997'MD/5307'ND,5496'MD/3882'ND, TRSCSSV:4-1/2"SESX2000'EQ 4813'MD/4153'ND,4593'MD/3960'ND 12.Attachments: Proposal Summary IA Wellbore schematic Ll 13.Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch u Exploratory LI Stratigraphic u Development L.Li • Service ❑ 14.Estimated Date for 15.Well Status after proposed work: Commencing Operations: May 28,2018 OIL ❑ WINJ ❑ WDSPL ❑ Suspended ❑ 16.Verbal Approval: Date: GAS ❑✓ • WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Authorized Name: Marty Lemon Contact Name: Steve Tyler Authorized Title: Project/Well Operations Manager Contact Email: st ler .petroak.com Contact Phone: (907)677-5120 Authorized Signature: '�0 Date: S / /t`f r . COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 11 2. 0,1, Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: All 3 2018 RBDMS y Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No d Subsequent Form Required: APPROVED BY Approved by: dCZSC"\• COMMISSIONER THE COMMISSION Date: S 2_3 iie ISubmit Form and r! lif Form 10-403 Revised 4/2017 Approved applicat rG 79 the date of approval. Attachments in Duplicate • • 3601 C Street, Suite 1424 Anchorage,Alaska 99503 IPS Tel: 907.272,1232 Fax: 907.272.1344 Paugu cel g1404441.4 Almize, Email: info@petroak.com May 17, 2018 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage,AK 99501 RE: PTD 216-086; 10-403 for Kitchen Lights Unit Well#A-2A Dear AOGCC: Enclosed is the 10-403 for KLU#A-2A with attached the Wellbore Schematic,Summarized Operations Plan, Proposed Perforations. The KLU#A-2A is currently producing from the Beluga. Furie Operating Alaska, LLC hereby plans to move a Eline unit on the platform, run in below the sump pkr @ 6711' and perforate the lwr beluga . Return KLU #A-2A to production. If you have questions, please feel free to contact me at 907-223-0806. ,Zat•-"r, Marty Lemon P.E. Project/Well Operations Manager Alaska's Oil & Gas Consulting Company www.petroak.com . frs. A —zA 0 • Furie Operating Alaska '""807Seyt16 Kitchen Lights Unit#A-2A Condor Sidetrack As-Built 07Sept16 RKB-CHF: 52.4' RKB-ML:225' RKB-MSL=132' 20"0.875"@ 381'MD Chemical Injection Mandrel @ 1641' '- CIM SCSSV(Self Equalizing)@ 1654' SCssv ' Tubing above SCSSV equipped with non-conductive centralizers 9.7 ppg NaBrCI/6%KCI Packer Fluid 13-3/8"72#@ 2,265'MD 4.1/2""12.75#L-80 CSCB IPC Tubing 3.813"X@4,515' I. W.. Isolation Packer @ 4,565'MD Upper Sterling End of Tubing/Seal Assembly at 4,580'MO 3-1/2"1-80 BTS-8 Isolation Pipe k Perfs 4735-4803'MD(4095-4160'TVD) u 2.813"Iso Sleeves(4696'&4806')CLOSED Est BHP=1712 psi;BHT=90 deg F as r....u.l :1,r r;:: 5-1/2"2010P-110 Blank and 0.008"Ga 3161 Wire Wrapped Screen IIIIPAI Gravel Pack Packer @ 4,814'MO Lower Sterling 3-1/2"1.80 8TS-8lsolation Pipe > Perfs 5395-5486'MO(4732-4819'NO) . 11r2.813"Iso Sleeves(5348'&5490')CLOSED •r1u.nu• BHP=2104 psi;BHT=90 deg F ■:. ' ■c -u■ 5-1/2"ION P-110 Blank and 0.008"Ga 3161 Wire Wrapped Screen ■r u ►, =, Isolation Packer @ 5,497'MD , } 10.4 ppg NaBrCl/6%KCI Packer Fluid (--8111" t „t1 w14' 2.813"X @ 5,951'MD 1111 rNv� ,r E, „ Gravel Pack Packer @6000'MD Upper Beluga l-4 4/ 3-1/2”L-80 BTS-8 isolation Pipe Perfs 6127-6276'MD(5773-5867'TVD) 2.813"Iso Sleeves(6106'&6279')CLOSED 11 1)111...uom BHP=2398 psi;BHT=108 deg F n.■.uu)u 5-1/2"2011P-110 Blank and 0.008"Ga 3161.Wire Wrapped Screen / s„+S'l 011©O` Gravel Pack Packer @ 6,286'MD Beluga 3-1/2"1.80875-8Isolation Pipe j- Perfs 6679-6701'MD(5950-5971'TVD)- II.„r....n.. 2.813”Iso Sleeves(6624'&6703')OPENED BHP=2573 psi;BHT=109 degF •P I .1: E e �� u 5-1/2"2014P-110 Blank and 0.008"Ga 3161 Wire Wrapped Screen l�ii �, Sump Packer @ 6711'MD Mule Shoe(end of Iso Assy)@ 6731'MD Possible Future TTRC: Lower Beluga Perfs 6873-6918'MD(6132-6173'TVD) BHP=2902 psi;BHT=111 deg F • Possible Future TTRC: Lower Beluga Perfs 7168-7274'MD(6405-6503'TVD) BHP=3060 psi;BHT=114 deg F PBTD-8,041'MD/7,197'TVO TO:8,160'MO/7,301'TVD I"'"'''`"" °'' 1 ''"-'`'' 9-5/8"53.3#P-110 BTC Mod @8,122'MD/7,268'TVD 1 I, • i<I - A Furie Operating Alaska WB 07Sept16 Kitchen Lights Unit XA-2A Condor Sidetrack As-Built 07Sept16 RKB-CHF: 52.4' RKB-ML:225' RKB-MSL=132' r ( 20"0.875"@ 381'MD Chemical Injection Mandrel @ 1641' CIM SCSSV(Self Equalizing)@ 1653' scssv • Tubing above SCSSV equipped with non-conductive centralizers 9.7 ppg NaBrCI/6%KCI Packer Fluid 13-3/8"725 @ 2,265'MD 4-1/2""12.755 L-80 CSCB IPC Tubing 3.813"X @ 4,515' Isolation Packer @ 4,565'MD Upper Sterling End of Tubing/Seal Assembly at 4,580'MD 3-1/2"L-80 BTS-8 Isolation Pipe Perfs 4735-4803'MD(4095-4160'TVD) OMNI 2.813"Iso Sleeves(4696'&4806')CLOSED Est BHP=1712 psi;BHT=90 deg F 5-1/2"208 P-110 Blank and 0.008"Ga 316L Wire Wrapped Screen 010 '=, Gravel Pack Packer @ 4,814'MD Lower Sterling 3-1/2"L-80 BTS-81 solation Pipe Perfs 5395-5486'MD(4732-4819'TVD) u uunu■ 2.813"Iso Sleeves(5348'&5490')CLOSED BHP=2104 psi;BHT=90 deg F ■rr■■■■u■■ u-- u■ 5-1/2"205 P-110 Blank and 0.008"Ga 316E Wire Wrapped Screen Isolation Packer @ 5,497'MD L81/us1r 1 !fr 10.4 ppg NaBrCI/6%KCI Packer Fluid 2.813"X @ 5,951'MD ►� ►� 5.104‘ Gravel Pack Packer @6000'MD Upper Beluga 3-1/2"L-80 BTS-8 Isolation Pipe TL Perfs 6127-6276'MD(5773-5867'TVD) 2.813"Iso Sleeves(6106'&6279')CLOSED BHP=2398psi;BHT=108 deg F ••'••••"••.4.0111111101110. / t■■ 5-1/2"205 P-110 Blank and 0.008"Ga 316E Wire Wrapped Screen '�� -416. Gravel Pack Packer @ 6,286'MD i Beluga � 3-1/2"L-80 BTS-8 Isolation Pipe Perfs 6679-6701'MD(5950-5971'IVO) •■,�1 2.813"Iso Sleeves(6624'&6703')OPENED BHP=2573 psi;BHT=109 degF ••'r••••'1•• P M.411141.1.11.1. •■ ss_ !•■ 5-1/2"208 P-110 Blank and 0.0013"Ga 316E Wire Wrapped Screen Sump Packer @ 6711'MD Possible Future TTRC: Lower Beluga Mule Shoe(end of Iso Assy)@ 6731'MD Perfs 6873-6918'MD(6132-6173'TVD) Proposed Lwr Beluga Perforations below Sump Pkr. BHP=2902 psi;BHT=111 deg F See"KLU A-2A Additional Pert Picks Below Sump Pkr"for detailed depths. { Possible Future TTRC: Lower Beluga Perfs 7168-7274'MD(6405-6503'TVD) BHP=3060 psi;BHT=114 deg F PBTD-8,041'MD/7,197'TVD h, 9-5/8"53.35 P-110 BTC Mod @8,122'MD/7,268'TVD TD:8,160'MD/7,301'ND - I • • KLU #A2A Perforation Procedure Summery Ensure well is Shut-in and SCSSV is open, blocked in. MIRU Eline/Slickline unit and PCE. Pressure test PCE to 250 psi low and 2500 psi high. (Note: PCE must be tested each time it is broken apart.) PU/MU Dmmy gun assy on Slickline. RIH to 7200'. POOH. PU/MU Shifting tool. RI shift sldg slves at 6703', 6624', 6279' & 6106' closed. Bleed off SITP to test sleeves. RD Slickline. RU Eline. Pressure test PCE to 250 psi low and 2500 psi high. (Note: PCE must be tested each time it is broken apart.) RIH perforate Beluga interval below sump pkr. 6 plus gun runs. RD Eline equipment. Turn well over to production • • KLU#A-2A Addional Perf Picks Below Sump Pkr A-2A Additional Perfs to Add Below Existing Beluga Completion Top,TVD Top, MD Base, MD Length, Ft 6,403 6,407 7166 7170 4 Y6,410 6,413 7174 7177 3 6,466 6,470 7234 iL Q 7238 4 c E 6,500 6,503 7271 7274 3 o = o 3 6,704 6,706 7493 7496 3 .t° 0 6,713 6,717 7503 7507 4 a m 6,951 6,954 7766 7769 3 7,150 7,156 7989 7996 7 Totals: 31 Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Thursday, February 02, 2017 10:51 AM To: 'Gordon Raines'; Roby, David S (DOA); Schwartz, Guy L (DOA); Link, Liz M (DOA) Cc: Dave McCraine; Bruce Webb; John Stuart Subject: RE: Kitchen Lights Unit A -2A (PTD 216-086): Production Gordon thank you so much for your quick reply. I added a new Kitchen Light Beluga undefined gas pool code-- (Kitchen Lights, BLDG UND GAS -470510). All production of gas for the KLU A -2A well from the Beluga Formation needs to be reported under the BLUG UND GAS - 470510 code. Please resubmit all historic production reports for the KLU A -2A well so that the AOGCC records can be updated to reflect regular production from the Beluga Formation. If you have any questions on the resubmittal of historical production reports for KLU A -2A, please contact Liz Link at (907) 793-1241. Thank you, Patricia From: Gordon Raines [mailto:g.raines@furiealaska.com] Sent: Thursday, February 02, 2017 10:37 AM To: Roby, David S (DOA) <dave.roby@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov>; Link, Liz M (DOA) <liz.link@alaska.gov>; Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov> Cc: Dave McCraine <d.mccraine@furiealaska.com>; Bruce Webb <b.webb@furiealaska.com>; John Stuart <j.stuart@furiealaska.com> Subject: Re: Kitchen Lights Unit A -2A (PTD 216-086): Production Patricia, We are producing the KLU A -2A well from the Beluga (6679 — 6701') and the Upper Beluga (6127 — 6276'). Gordon Raines Production Manager Furie Alaska LLC Cell: 337-278-0594 g.raines@furiealaska.corn From: Dave McCraine <d.mccraine@furiealaska.com> Date: Thursday, February 2, 2017 at 1:31 PM To: Raines <g rainesPfuriealaska.com> Cc: "Roby, David S (DOA)" <dave.roby@alaska.gov>, Guy Schwartz <guv.schwartz@alaska.gov>, "Link, Liz M (DOA)" <liz.linl<@alaska.gov>, Patricia Bettis <patricia.bettis@alaska.gov> Subject: Re: Kitchen Lights Unit A -2A (PTD 216-086): Production Gordon, please see Patricia's e-mail below and respond. Thanks Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Patricia Bettis <patricia.bettis@alaska.gov> Date: Thursday, February 2, 2017 at 1:18 PM To: Dave McCraine <d.mccraineC@furiealaska.com> Cc: "Roby, David S (DOA)" <dave.rob�alaska.gov>, Guy Schwartz <guy.schwartz@alaska.g_ov>, "Link, Liz M (DOA)" <liz.link@alaska.gov> Subject: Kitchen Lights Unit A -2A (PTD 216-086): Production Good morning David, Please confirm that Furie is currently producing from the Beluga Formation, perforations 6679-6703' MD. If this is true, AOGCC will need to correct our database to show production from the Beluga Formation and not the Sterling Formation. Production from the Beluga Formation will be given a new undefined "pool" identification code for reporting purposes. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. Bettis, Patricia K (DOA) From: Gordon Raines <g.raines@furiealaska.com> Sent: Thursday, February 02, 2017 10:37 AM To: Roby, David S (DOA); Schwartz, Guy L (DOA); Link, Liz M (DOA); Bettis, Patricia K (DOA) Cc: Dave McCraine; Bruce Webb; John Stuart Subject: Re: Kitchen Lights Unit A -2A (PTD 216-086): Production Patricia, We are producing the KLU A -2A well from the Beluga (6679 — 6701') and the Upper Beluga (6127 — 6276'). Gordon Raines Production Manager Furie Alaska LLC Cell: 337-278-0594 g.raines@furiealaska.com From: Dave McCraine <d.mccraine@furiealaska.com> Date: Thursday, February 2, 2017 at 1:31 PM To: Raines <g.raines@furiealaska.com> Cc: "Roby, David S (DOA)" <dave.roby@alaska.gov>, Guy Schwartz <guy.schwartz@alaska.gov>, "Link, Liz M (DOA)" <liz.link@alaska.gov>, Patricia Bettis <patricia.bettis@alaska.gov> Subject: Re: Kitchen Lights Unit A -2A (PTD 216-086): Production Gordon, please see Patricia's e-mail below and respond. Thanks Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Patricia Bettis <patricia.bettis@alaska. ov> Date: Thursday, February 2, 2017 at 1:18 PM To: Dave McCraine <d.mccraine@furiealaska.com> Cc: "Roby, David S (DOA)" <dave.roby@alaska. ov>, Guy Schwartz <guy,schwa rtz@alaska.gov>, "Link, Liz M (DOA)" <liz.link@alaska.gov> Subject: Kitchen Lights Unit A -2A (PTD 216-086): Production Good morning David, Please confirm that Furie is currently producing from the Beluga Formation, perforations 6679-6703' MD. If this is true, AOGCC will need to correct our database to show production from the Beluga Formation and not the Sterling Formation. Production from the Beluga Formation will be given a new undefined "pool" identification code for reporting purposes. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AC)GCC), 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alasl<a. ov. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Thursday, February 02, 2017 10:19 AM To: 'd.mccraine@furiealaska.com' Cc: Roby, David S (DOA); Schwartz, Guy L (DOA); Link, Liz M (DOA) Subject: Kitchen Lights Unit A -2A (PTD 216-086): Production Importance: High Good morning David, Please confirm that Furie is currently producing from the Beluga Formation, perforations 6679-6703' MD. If this is true, AOGCC will need to correct our database to show production from the Beluga Formation and not the Sterling Formation. Production from the Beluga Formation will be given a new undefined "pool" identification code for reporting purposes. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.betIasK Dov. DATA SUBMITTAL COMPLIANCE REPORT 12/20/2016 Permit to Drill 2160860 Well Name/No. KLU A -2A Operator FURIE OPERATING ALASKA, LLC API No. 50-733-20655-01-00 MD 8160 TVD 7301 Completion Date 9//8/2016 Completion Status 2 -GAS REQUIRED INFORMATION Mud Log le-Q�-JWWW�� Samples No/ DATA INFORMATION Types Electric or Other Logs Run: USIT/CBL, LWD, Mud Logs, Sump packer correlation strip. Well Log Information: Log/ Electr Current Status 2 -GAS UIC No Directional Survey Yes Z (data taken from Logs Portion of Master Well Data Maint) Data Digital Dataset Log Log Run Interval OH/ Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments Log C 27645 Log Header Scans 0 0 2160860 KLU A -2A LOG HEADERS ED C 27645 Digital Data 400 8160 10/19/2016 Electronic Data Set, Filename: Furie_Randolph Yost_KLU#A2A_MD5MEM_TC_8053198. LAS ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yost _KLU#A2A_ FinalSurveyListing.pdf r ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yost_KLU#A2A_ FinalSurveyListing.txt ' ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yost_KLU#A2A_MD2MEM_ TC_8053198.cgm ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yost _KLU#A2A_MD2MEM_TC_8053198. cg m.m eta ' ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph 1 Yost_KLU#A2A_MD2MEM_TC_8053198.PDF . ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yo st_K L U#A2A_M D 2 M E M_TC_8053198. o f ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yost_KLU#A2A_MD5ME M_TC_8053198.cgm ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yost _K L U#A2A_M D 5 M E M_T C_8053198. cg m. m eta - ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yost KLU#A2A MD5MEM TC 8053198.PDF r ED C 27645 Digital Data 10/19/2016 Electronic File: Furie_Randolph Yost KLU#A2A MD5MEM TC 8053198.tif AOGCC Page 1 of 6 Tuesday, December 20, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/20/2016 Permit to Drill 2160860 Well Name/No. KLU A -2A MD 8160 TVD 7301 Completion Date 9/8/2016 ED C 27645 Digital Data ED C 27645 Digital Data ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C ED C 27645 Digital Data 27645 Digital Data 27645 Digital Data 27645 Digital Data 27645 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data 27801 Digital Data Operator FURIE OPERATING ALASKA, LLC API No. 50-733-20655-01-00 Completion Status 2 -GAS Current Status 2 -GAS UIC No 10/19/2016 Electronic File: Furie—Randolph Yost_KLU#A2A_TVD2 ME M_TC_8053198. cgm 10/19/2016 Electronic File: Furie—Randolph Yost _KLU#A2A_TVD2MEM_TC_8053198.cgm.m eta 10/19/2016 Electronic File: Furie—Randolph Yost KLU#A2A TVD2MEM TC 8053198.PDF' — 10/19/2016 Electronic File: Furie _Randolph Yost_KLU#A2A_ TVD2MEM_TC_8053198.tif . 10/19/2016 Electronic File: Furie—Randolph Yost_KLU#A2A_TVD5MEM_ TC_8053198.cgm , t^10/19/2016 / Electronic File: Furie Randolph Yost KLU#A2A TVD5MEM_TC 8053198.PDF . — 10/19/2016 Electronic File: Furie _Randolph Yost_KLU#A2A TVD5MEM TC 8053198.tif 150 8190 12/15/2016 Electronic Data Set, Filename: KLU A-2A.las . 12/15/2016 Electronic File: Canrig Furie KLU A -2A AM. Report 7-10-16.pdf 12/15/2016 Electronic File: Canrig Furie KLU A -2A AM Report 7-11-16.pdf 12/15/2016 Electronic File: Canrig Furie KLU A -2A AM Report 7-12-16.pdf 12/15/2016 Electronic File: Canrig Furie KLU A -2A AM Report 7-13-16.pdf 12/15/2016 Electronic File: Canrig Furie KLU A -2A AM Report 7-14-16.pdf 12/15/2016 Electronic File: Canrig Furie KLU A -2A AM Report 7-15-16.pdf 12/15/2016 Electronic File: Canrig Furie KLU A -2A AM Report 7-16-16.pdf 12/15/2016 Electronic File: Canrig Furie KLU A -2A AM . Report 7-9-16.pdf 12/15/2016 Electronic File: KLU A-2A.dbf 12/15/2016 Electronic File: klu a-2a.hdr 12/15/2016 Electronic File: KLU A-2A.mdx AOGCC Page 2 of 6 Tuesday, December 20, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/20/2016 Permit to Drill 2160860 Well Name/No. KLU A -2A Operator FURIE OPERATING ALASKA, LLC API No. 50-733-20655-01-00 MD 8160 TVD 7301 Completion Date 9/8/2016 Completion Status 2 -GAS Current Status 2 -GAS UIC No ED C 27801 Digital Data 12/15/2016 Electronic File: klu a-2Ar.dbf ED C 27801 Digital Data 12/15/2016 Electronic File: klu a-2Ar.mdx - ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A-2A_SCL.DBF ' ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A SCL.MDX' ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A TVD.DBF ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A TVD.mdx• ED C 27801 Digital Data 12/15/2016 Electronic File: Furie KLU A -2A - Final Well Report.doc ED C 27801 Digital Data 12/15/2016 Electronic File: Furie KLU A -2A - Final Well ' P Report.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: Furie LITHOLOGY SUMMARY.doc ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - Drilling Dynamics p l Log MD.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - Drilling Dynamics Log TVD.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - Formation Log MD.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - Formation Log ' TVD.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - Gas Ratio Log MD.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - Gas Ratio Log TVD.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - LWD Combo Log P MD.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - LWD Combo Log ' TVD.pdf ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - DRILLING , DYNAMICS LOG MD.tif ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - DRILLING DYNAMICS LOG TVD.tif ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - FORMATION LOG MD.tif AOGCC Page 3 of 6 Tuesday, December 20, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/20/2016 Permit to Drill 2160860 Well Name/No. KLU A -2A Operator FURIE OPERATING ALASKA, LLC API No. 50-733-20655-01-00 MD 8160 TVD 7301 Completion Date 9/8/2016 Completion Status 2 -GAS Current Status 2 -GAS UIC No ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - FORMATION LOG - TVD.tif ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - GAS RATIO LOG MD.tif ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - GAS RATIO LOG TVD.tif ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - LWD COMBO LOG _ MD.tif ED C 27801 Digital Data 12/15/2016 Electronic File: KLU A -2A - LWD COMBO LOG - TVD.tif ED C 27802 Digital Data 6568 6900 12/16/2016 Electronic Data Set, Filename: Furie_KLU- A2A_Packer _01 Aug 2016_Correlation_R01 _L010 Up_ConCu.las ED C 27802 Digital Data 6566 6901 12/16/2016 Electronic Data Set, Filename: Furie_KLU- A2A_ Packer _ 01Aug2016_Setting_R01_L012Up_ ' ConCu.las ED C 27802 Digital Data 7882 1630 12/16/2016 Electronic Data Set, Filename: Furie_KLU- A2A_USIT- MS I P_27Ju12016_Main_R01_L012Up_ConCu.las ED C 27802 Digital Data 7872 1660 12/16/2016 Electronic Data Set, Filename: Furie_KLU- A2A_US IT- - MSIP_27Ju12016_Press1000_R01_L014Up_Con CU.las ED C 27802 Digital Data 5028 3396 12/16/2016 Electronic Data Set, Filename: Furie_KLU- A2A_USIT- MSIP_ 27Ju12016_Press2000_R01_L017Up_Con Cu.las ED C 27802 Digital Data el 2/16/2016 Electronic File: 50-733-20655-01-00-9122016 25802 PM-4140-Furie Operating Alaska.pdf ED C 27802 Digital Data 12/16/2016 Electronic File: KLU A2A frac report.pdf ED C 27802 Digital Data 12/16/2016 Electronic File: Furie_KLU- A2A_Packer_01 Aug 2016_Correlation_R01 _1-010. Up_ConCu.dlis ED C 27802 Digital Data 12/16/2016 Electronic File: Furie_KLU- A2A_Packer_01Aug2016_Setting_R01_L012Up_ ' ConCu.dlis ED C 27802 Digital Data 12/16/2016 Electronic File: Furie_KLU- Q A2A_Packer 01Aug2016_FieldPrint.Pdf AOGCC Page 4 of 6 Tuesday, December 20, 2016 Permit to Drill 2160860 Well MD 8160 TVD 7301 ED C 27802 Digital Data ED C 27802 Digital Data ED C 27802 Digital Data ED C 27802 Digital Data Well Cores/Samples Information: Name DATA SUBMITTAL COMPLIANCE REPORT 12/20/2016 ie/No. KLU A -2A Operator FURZE OPERATING ALASKA, LLC API No. 50-733-20655-01-00 Completion Date 9/8/2016 Completion Status 2 -GAS Current Status 2 -GAS UIC No Interval Start Stop INFORMATION RECEIVED Completion Report Directional / Inclination Data Production Test Information Y / Mechanical Integrity Test Information Y / w Geologic Markers/Tops 0 Daily Operations Summary n COMPLIANCE HISTORY Completion Date: 9/8/2016 Release Date: 7/8/2016 Description Comments: Date Comments 12/16/2016 Electronic File: Furie KLU-A2A USIT- MS IP_27Jul2016_Main_R01 _L012Up_ConCu.dli s 12/16/2016 Electronic File: Furie_KLU-A2A_USIT- MSIP_27Jul2016_Press1000_R01_L014Up_Con CuAlis 12/16/2016 Electronic File: Furie_KLU-A2A_USIT- MSIP_27Jul2016_Press2000_R01_L017Up_Con Cu.dlis P 12/16/2016 Electronic File: Furie_KLU-A2A_USIT- MSIP 27Ju12016 FINAL.Pdf Sample Set Sent Received Number Comments Mud Logs, Image Files, Digital Date Y��yfj� Core Chips Y / Composite Logs, Image, Data Files D Core Photographs Y / Cuttings Samples Y /l./ Laboratory Analyses Y /u AOGCC' Page 5 of 6 Tuesday, December 20, 2016 DATA SUBMITTAL COMPLIANCE REPORT 12/20/2016 Permit to Drill 2160860 Well Name/No. KLU A -2A MD 8160 Compliance Reviewe Operator FURZE OPERATING ALASKA, LLC API No. 50-733-20655-01-00 Completion Status 2 -GAS Current Status 2 -GAS / � ! UIC No Date: 1 2 AOGCC Page 6 of 6 Tuesday, December 20, 2016 Schlumberger WIRELINE Product Delivery Customer: Furie Operating Alaska Dispatched To: Well No: APIN: KLU-AZA 50-733-20655-01-00 Transmittal #: 16DEC16-SP02 MEREDITH GUHL Date Dispatched: 16 -Dec -16 Dispatched By: Stephanie Pacillo Well / Product Hardcopy Digital Copy E -Delivery Date Delivered To: Makana Bender c/o Meredith Guhl Contents on CD N/A AOGCC Color Log Prints: 2 D4A0-00095 D4A0-00095 ----- Packer Setting Record 01 -AUG -2016 USIT-MSIP 27-JUL-2016 x x x x .9��+c1\ICI'9 DEC 7 6-2 A r%nr Digital Data N/A Contents on CD x Survey N/A Contents on CD CD 2 Contents on CD PACKER_ Graphics: PDF 1 cd x x x x Data: DLIS /ASCII USIT-MSIP Graphics: PDF 1 cd _ Data: DLIS /ASCII Please sign and email a copy to: Alaska PTSPrintCenter(a�slb.com VEE Alaska PTS Print Ce er Recei Guhl, Meredith D (DOA) From: Guhl, Meredith D (DOA) Sent: Friday, December 16, 2016 10:25 AM To: Dave McCraine Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: RE: KLU A -2A, PTD 216-086, Data Required Ah. The 24 hr summary doesn't say anything about a corrupt log, it just says you ran the log. Can you update the summary to reflect the issues please? Otherwise, on our end, it looks like you ran it and just didn't submit it. If there are issues like this in the future, please document it in an email to the AOGCC petroleum engineer and in the daily so the records reflect what happened. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. From: Dave McCraine[mailto:d.mccraine@furiealaska.com] Sent: Friday, December 16, 2016 10:18 AM To: Guhl, Meredith D (DOA) <meredith.guhl@alaska.gov> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: Re: KLU A -2A, PTD 216-086, Data Required That log was invalid. The data was corrupt. That is why we ran the Schlumberger log. Does it still need to be submitted? I am not sure I have a legitimate corrupt copy. Regards. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: "Guhl, Meredith D (DOA)" <meredith.guhl@alaska.gov> Date: Friday, December 16, 2016 at 1:14 PM To: Dave McCraine <d.mccraine@furiealaska.com> Cc: Patricia Bettis <patricia.bettis@alaska.gov>, Guy Schwartz <guy.schwartz@alaska.gov> Subject: RE: KLU A -2A, PTD 216-086, Data Required David, Also it was just noticed that an Expro CBL was run on July 20. Yet no paper or digital data for this log has been provided to the AOGCC. Regulations require all logs run to be supplied to the AOGCC in both paper and digital format. Please send the Expro CBL in both paper and digital format. Thanks, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. From: Dave McCraine [mailto:d.mccraine@furiealaska.com] Sent: Friday, December 16, 2016 9:59 AM To: Guhl, Meredith D (DOA) <meredith.guhl@alaska.gov> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: Re: KLU A -2A, PTD 216-086, Data Required I am checking with Schlumberger. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: "Guhl, Meredith D (DOA)" <meredith.guhl@alaska.gov> Date: Friday, December 16, 2016 at 11:54 AM To: Dave McCraine <d.mccraine@furiealaska.com> Cc: Patricia Bettis <patricia.bettis@alaska.gov>, Guy Schwartz <guy.schwartz@alaska.gov> Subject: RE: KLU A -2A, PTD 216-086, Data Required David, One of the zipped folders on the thumb drive you sent requires a password to open. Do you have that information? It is the zip file titled "Fuire KLU A2A finals.zipx". I am guessing this is the Schlumberger data associated with the Cement Evaluation log. Furie is not in compliance on this well until all data is received and readable. Please advise when you can provide either a password or additional data. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. From: Dave McCraine [mailto:d.mccraine@furiealaska.com] Sent: Tuesday, December 13, 2016 2:10 PM To: Guhl, Meredith D (DOA) <meredith.guhl@alaska.gov> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwa rtz@alaska.gov> Subject: Re: KLU A -2A, PTD 216-086, Data Required Importance: High I have it and will put it in FedEx tomorrow. My techinical help is out with the flue and I am unable to check the Schlumberger flash to confirm the packer setting files are complete. If they are not, I will get the Anchorage Schlumberger office get the missing formats to you. Regards Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: "Guhl, Meredith D (DOA)" <meredith.guhl@alaska.gov> Date: Monday, December 12, 2016 at 7:26 PM To: Dave McCraine <d.mccraine@furiealaska.com> 3 Cc: Patricia Bettis <patricia.bettis@a.aska.gov>, Guy Schwartz <guy.schwartz@alujKa.goy> Subject: RE: KLU A -2A, PTD 216-086, Data Required David, As of today the required data for KLU A -2A has not been supplied. The data was due by December 8. Please provide an ETA for the required data listed below. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AC)GCC), 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. From: Guhl, Meredith D (DOA) Sent: Friday, October 28, 2016 1:51 PM To: 'David McCraine' <d.mccraine@furiealaska.com> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwa rtz@alaska.gov> Subject: KLU A -2A, PTD 216-086, Data Required Hello David, A review was also completed of the 10-407 form and data supplied for KLU A -2A, PTD 216-086, completed 9/8/2016. During the review deficiencies were noted. Please supply the following data: 1. Frac Reports from vendor in both paper copy and digital format. Schwartz with any questions regarding this point. 2. LAS and DLIS files for BakerHughes logs 3. LAS and DLIS file for Schlumberger USIT log 4. TIF images of Canrig Mudlogs 5. LAS files for Canrig Mudlogs 6. EOW report from Canrig in both digital and paper format 7. Any show reports from Canrig 8. A complete Packer Setting log in PDF, LAS, DLIS and paper format and is not acceptable. Not the Frac Focus report. Contact Guy The log submitted is lacking a header page Please supply the required data by December 8, 2016. An operator has 90 days after well completion to submit data, which is why the data for KLU A -2A is not required as soon as the data for KLU A-2 is. Please send the data to my attention. If you have any questions, please contact Patricia Bettis or me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. FURIE Operating Alaska LLC December 14, 2016 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RE: 10-407 for KLU# A2 Kitchen Lights Unit —follow-up data PTD 216- -055 / Sundry 316-356 Dear AOGCC: a-8dt RECEIVED DEC 15 U Enclosed is the DLIS files for the Canrig and the Baker Hughes logs. Also included is the EOW report from Canrig in both paper and pdf format. Included is the Canrig Drilling Dynamics log Md and TVD. Enclosed are the digital copies supplied from Canrig and BakerHughes. These have all the logs and reports supplied by the respective companies. If you have questions, please feel free to contact me at 337-981-0270. Sincerely,, David McCraine Furie Operating Alaska, LLC Drilling Engineer Furie Operating Alaska LLC 14906 Ambassador Caffery Pkwy Suite #800 1 Lafayette, LA 1 70508 1 Office 337-806-9021 Schlumbepgup FracCAT Treatment Report Well : KLU#A-2A Field KLU Undefined Gas Pool Formation : Upper Sterling Prepared for 1899 lbs Client Furie Operating Alaska Client Rep : Jack Burman Date Prepared :08/23/2016 Prepared by 90.6 ft Name : Alexander Martinez Division : Schlumberger Phone :561-389-5006 Service Point : Kenai 2Teb2, t:� r 1. GE.0 1 ' ?016 ACCC Proppant • Pressure Total Proppant Pumped 76,800 lbs Total Proppant Around Screen 1899 lbs Total Proppant Below Crossover Port 74,893 lbs Total Proppant Around Blank 1320 lbs Proppant Reversed 1907 lbs Height of Proppant Around Blank 5.5" 90.6 ft Proppant in Perforations 71674 lbs % Proppant below X/O 98% Proppant Concentration in Perfs (MD) 1096 lbs/ft Screenout Pressure 3,222 Proppant Concentration in Perfs (TVD) 1054 lbs/ft Injected Fluids (Below• W1725 106.6 bbls I Total Slurry 836.9 bbis YF125ST 648.3 bbls I Total Fluid 754.3 bbls Injected Fluids (Above XO) I WF125 152.5 bbls Total Slurry 892.2 bbls YF125ST 653.1 bbls Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred Schlumberger o' f - MiniFrac & SRT Tr. Pressure Annulus Pressure Client: Furie Operating Alaska Well: KLU#A-2A Formation: Upper Sterling District: Kenai, AK Country: United States Furie Operating Alaska KLU#A-2A 08.23.2016 24 21 18 02:17:13 02:38:03 02:58:53 03:19:43 Time - hh:mm:ss 1 Spot Calibration Test 2 Shift tool to weight down, circulate 3 Calibration Test 4 Shutdown to monitor pressure 5 Step Rate Test ur 15 C A p 12 in m O z tr a 9 � c -0 3 D 6 3 0 Schlumbepgep Main Treatment Tr. Pressure Annulus Pressure Client: Furie Operating Alaska Well: KLU#A-2A Formation: Upper Sterling District: Kenai, AK Country: United States Furie Operating Alaska KLU#A-2A 08-23-2016 24 21 18 Time - hh:mm:ss 6 Load hole in reverse position 7 Shutdown, move tool to weight -down 8 Dropping rate to maintain prop con 9 Begin slowdown schedule 10 Screen out W 15 C � �A O 12 in m O m Z Cr �9 v Z 3 D 6 3 Schlumbepger Client: Furie Operating Alaska Well: KLU#A-2A Formation: Upper Sterling District: Kenai, AK Country: United States Section 1: Material Balance (Total Volumes) Material Balance Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Material Name Quantity Pumped 30/50 EconoProp 76,800 Ib M275, Microbiocide 18 Ib J891, Guar Polymer Slurry 239 gal J532, Borate Crosslinker 114 gal J318, Liquid Breaker Aid 54 gal J218, Breaker 1541b F103, Surfactant 46 gal J134,13reaker 25 Ib Section 1: Diagnostic: As Measured Pump Schedule Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) As Measured Pump Schedule 5.8 6.0 280 318 Step Step Slurry Slurry Pump Fluid 224 PMraax op Prop Prop # Name Volume Rate Time Fluid Name Volume Proppant Name Conc Conc Mass 18.0 (bbl) (bbl/min) (min) (gal) IPPA) (Ib) (PPA) Cross 1 Check 2 5.8 1.7 YF125ST 105 0 0 2 MiniFrac 44.8 6 7.61 YF125ST 1881 0 0 0 3 MF Cont 135.7 17.5 8 YF125ST 5699 0 0 4 MF Flush 57.4 18 3.2 WF125 2409 0 0 5 SRT 51.6 9.3 8.7 WF125 2167 0 0 0 Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Cross Check 5.8 6.0 280 318 57 MiniFrac 6.0 6.0 91 650 224 MF Cont 17.5 18.1 2639 P730 P13 MF Flush 18.0 18.1 2548 k713 341 5 ISRT 118.0 18.0 2121 P339 024 Average Treating Pressure: 2087 psi Maximum Treating Pressure: 3222 psi Minimum Treating Pressure: 9 psi Average Injection Rate: 14.3 bbl/min Maximum Injection Rate: 18.1 bbl/min Average Horsepower: 837.6 hhp Maximum Horsepower: 1200.4 hhp Maximum Prop Concentration: 0.0 PPA sehlumberoer Section 3: Diagnostic: Job Messages Client: Furie Operating Alaska Well: KLU#A-2A Formation: Upper Sterling District: Kenai, AK Country: United States Message ,. # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 Reset Executed Steps 0 0 0.0 0.0 0. 2 Reset Executed Steps 0 0 0.0 0.0 0. 3 0:13:48 START PUMPS 1 -18 0.0 0.0 0.0 4 1:03:38 PUMPS STARTED 58 38 0.0 0.0 0.0 5 1:03:47 PRIMING PUMP 1 63 41 0.0 2.6 0. 6 1:22:19 GOOD HIGH PT 7185 124 0.0 0.0 0. 7 1:29:09 RIG LINING UP FOR CIR RATE 1 -2 0.0 0.0 0.0 8 1:32:49 STARTING CIR RATES 49 -3 0.0 0.0 0.0 9 1:35:34 2 BPM CIR RATE 111 -1 0.0 0.0 0. 10 1 1:37:57 1 BPM CIR RATE 4 -2 0.0 0.0 0. 11 1:43:46 1000 Pann 14 938 0.0 0.0 0.0 12 1:45:06 strip test intial drag 45K over normal 25 k 200,000 and 185,000 190 842 0.0 0.0 0. 13 2:19:19 Start Cross Check Automatically 5 -2 0.0 0.0 0. 14 2:19:19 Start Diagnostic Automatically 5 -2 0.0 0.0 0. 15 1 2:19:19 Start Upper Sterli Automatically 5 -2 0.0 0.0 0. 16 2:19:19 Started Pumping 5 -2 0.0 0.0 0. 17 2:20:13 xI to open top good 18 -1 0.6 5.9 0. 18 2:21:48 Start MiniFrac Automatically 30 -1 10.0 6.0 0. 19 2:27:58 rig shifting tool 252 -2 44.8 0.0 0.0 20 2:28:35 Start MF Cont Manually 221 -1 44.8 0.0 0.0 21 1 2:32:40 Stage at Perfs: Cross Check 2551 1013 52.0 15.3 0. 22 2:33:14 Stage at Perfs: MiniFrac 2607 1164 62.0 18.0 0. 23 2:35:10 Stage at Perfs: MF Cont 2655 1253 96.9 18.0 0.0 24 2:39:49 Start MF Flush Automatically 2692 1239 180.6 18.0 0.0 25 2:42:43 Stage at Perfs: MF Flush 2331 1235 232.9 18.0 0. 26 2:42:58 Start SRT Automatically 781 1222 237.4 16.9 0.0 27 2:43:38 minifrac flushed 1125 897 237.8 0.0 0.0 28 2:51:45 Start SRT Manually 322 91 237.8 0.0 0. 29 2:54:42 1 bpm SRT 659 393 239.4 1.3 0. 30 2:55:46 2 BPM SRT 924 622 241.5 2.0 0.0 31 2:56:55 3 BPM SRT 1329 873 244.7 2.9 0.0 32 2:58:07 4 BPM SRT 1329 960 249.8 4.9 0. 33 2:59:04 5 BPM SRT 1752 956 254.4 4.9 0. 34 3:00:05 8.2 BPM SRT 1536 1013 262.7 8.2 0. 35 3:01:02 11.3 BPM SRT 1716 1037 273.2 11.3 0.0 36 3:01:25 Activated Extend Stage 1970 1075 278.6 14.7 0. 37 3:02:10 Stage at Perfs: SRT 1277 10131 289.q 4.3 0. 38 3:03:27 IHARD SHUTDOWN SRT 1 690 4531 289. 0.0 0.0 39 1 3:06:15 ICLOSURE 2850 1 248 1021 289. 0.0 0.0 schlu„ bege[ Client: Furie Operating Alaska Well: KLU#A-2A Formation: Upper Sterling District: Kenai, AK Country: United States Section 4: Propped Frac: As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) As Measured Pump Fluid Name Schedule Fluid Volume (gal) Proppant Name Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Cross Check 14. 9. 0 YF125ST 611 18 0 0 17.7 2 PAD 44.3 6 7.5 YF125ST 1867 18.0 0 0 2642 3 PAD Cont 146.5 17.7 8.5 YF125ST 6151 0 0 18.0 4 0.5 PPA 27.5 18 1.5 YF125ST 1136 EconoProp 30/50 0. 2648 52 5 1.0 PPA 24.9 18 1.4 YF125ST 1014 EconoProp 30/50 1."0. 18.0 91 6 2.0 PPA 25.S 18 1.4 YF125ST 1011 EconoProp 30/50 2.1 1 183 7 3.0 PPA 27.2 Iq 1.5 YF125ST 10191 EconoProp 30/50 3.11 2 286 8 3.0 PPA 12.7 18 0.7 YF125ST 4691 EconoProp 30/50 3. 0.9 147 9 4.0 PPA 12 18 0.7 YF125ST 425 EconoProp 30/50 4.1 0.9 172 10 5.0 PPA 12.5 18 0.7 YF125ST 424 EconoProp 30/50 5. 3.4 2185 11 6.0 PPA 11.6 16.7 0.7 YF125ST 393 EconoProp 30/50 6. 5.9 2357 12 1 7.0 PPA 12 14.8 0.8 YF125ST 391 EconoProp 30/50 6. 2.4 261 13 8.0 PPA 13.8 12. 1.1 YF125ST 420 EconoProp 30/50 9. 8 356 14 9.0 PPA 14.2 11.7 1.2 YF125ST 432 EconoProp 30/50 9. 7.9 372 15 10.0 PPA 14.7 11.2 1.3 YF125ST 430 EconoProp 30/50 10. 6. 4061 16 11.0 PPA 13. 11 1.2 YF125ST 389 EconoProp 30/50 10. 3. 401 17 12.0 PPA 13. 11 1.3 YF125ST 388 EconoProp 30/50 11 9. 415 18 12.0 PPA 128 11.3 11.3 YF125ST 349 EconoProp 30/50 13.7 4076 19 FLUSH 43. 3.8 15. WF125 1827 9 0.1 0 Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 Cross Check 9.3 0.0 1563 61 PAD 6.0 6.0 476 713 18 PAD Cont 17.7 18.1 2625 2787 224 5 PPA 18.0 18.0 2657 2673 2642 5 1.0 PPA 18.0 18.0 2644 2655 2629 0 PPA 18.0 18.0 2639 2652 2627 0 PPA 18.0 18.0 2667 2682 2648 0 PPA 18.0 18.0 2694 712 2678 0 PPA 18.0 18.0 2726 744 2711 10 5.0 PPA 18.0 18.0 760 777 743 11 .0 PPA 16.7 18.0 616 789 454 12 .0 PPA 14.8 15.1 2452 476 333 13 .0 PPA 12.4 13.9 2248 322 1528 2182 14 9.0 PPA 11.7 12.0 2195 236 2152 15 10.0 PPA 11.2 11.5 2154 194 2119 16 11.0 PPA 11.0 11.0 2174 200 2153 17 12.0 PPA 11.0 11.0 2189 206 2172 18 12.0 PPA 11.3 12.2 2412 F190 19 IFLUSH P.8 11.4 11245 P125 115 schlumbergep Client: Furie Operating Alaska Well KLU#A-2A Formation: Upper Sterling District: Kenai, AK Country: United States Average Treating Pressure: 2276 psi Maximum Treating Pressure: 3125 psi Minimum Treating Pressure: 9 psi Average Injection Rate: 13.7 bbl/min Maximum Injection Rate: 18.1 bbl/min Average Horsepower: 828.4 hhp Maximum Horsepower: 1229.0 hhp Maximum Prop Concentration: 13.7 PPA Section 5: Propped Frac: Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 4:37:34 Deactivated Extend Stage 9 -2 289.4 0.0 0.0 2 4:37:34 Start Cross Check Manually 9 -2 289.4 0.0 0. 3 1 4:37:34 Start Propped Frac Manually 9 -2 289.4 0.0 0. 4 1 4:37:43 Activated Extend Stage 9 -2 0.0 0.0 0.0 5 4:39:11 Stage at Perfs: SRT 1 -2 0.0 0.0 0. 6 4:48:07 Deactivated Extend Stage 17 -2 0.0 0.0 0. 7 4:48:07 Start PAD Manually 17 -2 0.0 0.0 0. 8 4:54:20 SPOTTING PAD 59 -2 33.7 5.9 0.0 9 4:54:55 Stage at Perfs: SRT 665 -2 37.2 6.0 0.0 10 4:56:08 Start PAD Cont Automatically 140 -2 44.3 1.1 0. 11 4:56:20 SHIFTING TOOL 24 -3 44.3 0.0 0. 12 5:00:18 Stage at Perfs: Cross Check 2740 1110 52.5 17.8 0.0 13 5:02:45 Stage at Perfs: PAD 2607 1194 96.6 18.0 0.0 14 5:07:59 Start 0.5 PPA Automatically 2657 1198 190.7 18.0 0. 15 5:07:59 Started Pumping Prop 2657 1198 190.7 18.0 0. 16 5:08:07 Activated Extend Stage 2672 1202 193.1 18.0 -0.0 17 1 5:09:30 Deactivated Extend Stage 2655 1204 218.0 18.0 0. 18 5:09:30 Start 1.0 PPA Manually 265N 1204 218.0 18.0 0. 19 5:10:52 Stage at Perfs: PAD Cant 2645 1199 242.5 18.0 1.0 20 5:10:54 Start 2.0 PPA Automatically 2624 1198 243.1 18.0 0.8 21 5:12:20 Start3.OPPAAutomatically 2640 1229 268.9 18.0 2. 22 5:12:23 Stage at Perfs: 0.5 PPA 2648 1228 269.8 18.0 2. 23 1 5:13:47 Stage at Perfs: 1.0 PPA 2679 1283 295.0 18.0 2.9 24 5:13:51 Start 3.0 PPA Automatically 2695 1290 296.2 18.0 3.0 25 5:14:33 Start 4.0 PPA Automatically 2718 1316 308.8 18.0 3. 26 5:15:13 Start 5.0 PPA Automatically 2726 1356 320.8 18.0 4. 27 5:15:14 Stage at Perfs: 2.0 PPA 2766 1353 321.1 18.0 5. 28 5:15:55 Start 6.0 PPA Automatically 2779 1400 333.4 18.0 5.7 29 1 5:16:03 Remark 2562 1409 335.8 18.0 6. 30 5:16:38 Start 7.0 PPA Automatically 2452 1400 345.0 15.0 6.6 31 5:16:50 Stage at Perfs: 3.0 PPA 2210 1412 348.0 15.0 6. 32 5:17:27 Start 8.0 PPA Automatically 2302 1449 356.9 12.71 7. 33 5:17:44 Stage at Perfs: 3.0 PPA 2283 14471 360.61 13.11 7.8 chemaepger Client: Furie Operating Alaska Well: KLU#A-2A Formation: Upper Sterling District: Kenai, AK Country: United States Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 34 5:18:35 Start 9.0 PPA Automatically 2247 1456 370.8 12.0 9.1 35 5:18:43 Stage at Perfs: 4.0 PPA 2228 1462 372.4 12.0 9.0 36 5:19:48 Stage at Perfs: 5.0 PPA 221q 1483 385.0 11.5 8.2 37 5:19:48 Start 10.0 PPA Automatically 221 1483 385.0 11.5 8. 38 5:20:31 Remark 2156 1495 393.0 11.0 10.1 39 5:20:42 RAMP RECOVER 11 BPM 2124 1503 395.1 11.0 10. 40 5:20:52 Stage at Perfs: 6.0 PPA 2169 1505 396.9 11.0 10. 41 5:21:07 Start 11.0 PPA Automatically 2179 1507 399.6 1111 10.3 42 5:21:58 Stage at Perfs: 7.0 PPA 2160 1529 409.0 111 10. 43 5:22:21 Start 12.0 PPA Automatically 216q 1538 413.2 11.0 10.9 44 5:23:14 Stage at Perfs: 8.0 PPA 220M 1561 422.9 11. 10.6 45 5:23:37 Start 12.0 PPA Automatically 221N 1570 427.1 111 10.9 46 5:23:42 Activated Extend Stage 219N 1572 428.0 11.0 11.0 47 5:24:33 Stage at Perfs: 9.0 PPA 225A 1591 437. 11. 11. 48 1 5:25:51 Stage at Perfs: 10.0 PPA 224N 1614 451.9 11. 11.6 49 5:27:05 Stage at Perfs: 11.0 PPA 241N 1649 465.7 11.1 13. 50 5:28:18 Stage at Perfs: 12.0 PPA 244 1683 479.6 11.1 11.8 51 5:34:51 Cut Prop 252N 1741 554.4 11.1 7. 52 5:34:54 Deactivated Extend Stage 2501 1737 554.9 11.4 5.1 53 5:34:54 Start FLUSH Manually 2501 1737 554.9 11.4 5.1 54 1 5:35:06 Stopped Pumping Prop 1494 1680 556.9 6.0 0. 55 5:36:44 RUDEC TO 4 BPM 919 1122 566.6 4.2 0.0 56 5:50:33 SCREEN OUT 2895 17551 597.1 0.0 0.0 57 5:51:08 IPICKING UP TO REVERSE 2652 16501 597. 0.0 0. Schlumbepger FracCAT Treatment Report Well : KLU#A-2A Field : KLU Undefined Gas Pool Formation : Lower Sterling Prepared for 2091 lbs Client : Furie Operating Alaska Client Rep : Jack Burman Date Prepared : 08/20/2016 Prepared by 117 ft Name : Alexander Martinez Division : Schlumberger Phone :561-389-5006 Service Point : Kenai Proppant • Pressure Total Proppant Pumped 74,379 lbs Total Proppant Around Screen 2091 lbs Total Proppant Below Crossover Port 74,379 lbs Total Proppant Around Blank 8042 lbs Proppant Reversed 0 lbs Height of Proppant Around Blank 3.5" 117 ft Proppant in Perforations 64246 lbs Height of Proppant Around Blank 5.5" 90.6 ft Proppant Concentration in Perfs (MD) 706 lbs/ft % Proppant below X/O 1000 Proppant Concentration in Perfs (TVD) 734 lbs/ft Screenout Pressure Na Injected Fluids (Below• WF125 144.1 bbls YF125ST 528.5 bbls Total Fluid 1 672.6 bbls Injected Fluids (Above XO) WF125 195.6 bbls YF125ST 528.5 bbls Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred Schlumberger Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States MiniFrac & SRT — Tr. Pressure Furie Operating Alaska KLU#A-2A Annulus Pressure 06.19-2016 Time - hh:mm:ss 1 Spot Calibration Test 2 Shift tool to weight down, circulate 3 Calibration Test 4 Shutdown to monitor pressure 5 Step Rate Test X 0 10 in 0 z Schlumbugur Main Treatment 07:00:06 Tr. Pressure Annulus Pressure i — blurry Kate Prop Con — BH Prop Con Time-hh:mm:ss m•sn•na Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States Furie Operating Alaska KLU#A-2A 08-20.2016 y� 16 14 12 10 6 Load hole in reverse position 7 Shutdown, move tool to weight -down 8 Dropping rate to maintain prop con 9 Begin slowdown schedule 6 4 2 0 nn•4c•nc 20 18 16 14 N r- 12 v z 0 i O M 10 D 0 0 m Z Q 8 3' a 6 4 2 0 Schlumberger Section 1: Total Material Balance Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States Material Balance: Total Used Material Name Quantity Pumped YF125ST 22197 gal WF125 8217 gal M275, Microbiocide 121b J891, Guar Polymer Slurry 246 gal J532, Borate Crosslinker 98 gal J318, Liquid Breaker Aid 50 gal F103, Surfactant 31 gal J218, Breaker 1871b Section 2: Diagnostic: As Measured Pump Schedule Stage Pressures & Rates As Measured Pump Schedule Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Slurry Slurry Pump 0.0 Fluid 0 Pox -10 Prop Ste Step Ste p 6.0 426 717 -10 MF Cont Prop p 15.1 2037 2304 Name Volume Rate Time Fluid Name Volume Proppant Name 1706 Conc Mass 115.0 (bbl) (bbl/min) (min) (gal) nc PPA) (PPA) (lb) CrossChe 1 0.0 0.0 0.0 YF125ST 0 0. 0.0 0 ck 2 MiniFrac 46.5 5.9 7.9 YF125ST 1955 0. 0.0 0 3 MF Cont 103.5 14.6 7.3 YF125ST 4378 0. 0.0 0 4 MF Flush 85.5 15.0 5.7 WF125 3638 01 0. 9 0 5 SRT 48.4 8. ji8.4 WF125 2031 0. 0.1 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 CrossCheck 0.0 0.0 0 10 -10 MiniFrac 5.9 6.0 426 717 -10 MF Cont 14.6 15.1 2037 2304 169 MF Flush 15.0 15.0 1837 2050 1706 5 ISRT 18.9 115.0 1241 1696 11 Schlumberger Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States Average Treating Pressure: 1576 psi Maximum Treating Pressure: 2304 psi Minimum Treating Pressure: -10 psi Average Injection Rate: 12.3 bbl/min Maximum Injection Rate: 15.1 bbl/min Average Horsepower: 531.7 hhp Maximum Horsepower: 843.6 hhp Maximum Prop Concentration: 0.0 PPA chlumbepgep Section 3: Diagnostic: Material Balance Material Balance Material Name Quantity Pumped YF125ST 6333 gal WF125 5669 gal M275, Microbiocide 6 Ib J891, Guar Polymer Slurry 150 gal J532, Borate Crosslinker 34 gal J318, Liquid Breaker Aid 15 gal F103, Surfactant 11 gal J218, Breaker 66 lb Section 4: Diagnostic: Job Messages Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States Message ,. # Time Message Treating pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 13:51:06 Reset Executed Steps 01 0 0.0 0.0 0. 2 13:51:06 Reset Executed Steps 0 0 0.0 0.0 0.0 3 14:07:51 low pt good 272 293 0.0 0.0 0. 4 14:10:38 leak on rig floor manifold -3 -26 0.0 0.0 0. 5 14:26:53 no leaks on rig floor 4027 45 0.0 0.1 0. 6 14:33:09 high pt good 8162 2 0.0 0.0 0. 7 14:43:47 Cir Rate 2 bpm 105 -20 0.0 0.0 0. 8 14:47:50 Cir rate 1 bpm 17 -25 0.0 0.0 0. 9 14:53:01 total 12 bls pump on circulation rates -2 -18 0.0 0.0 0.0 10 14:55:40 strip test 725 905 0.0 0.0 0. 11 14:59:01 55k intial drag 35 k drag strip test complete -3q-20 0.0 0.0 0. 12 15:15:45 I'd to ope to -8 -21 0.0 0.0 0.0 13 15:16:17 Start CrossCheck Automatically -1 -21 0.0 0.0 0.0 14 15:16:17 Start Diagnostic Automatically -1 -21 0.0 0.0 0. 15 15:16:17 Start Lower Sterli Automatically -1 -21 0.0 0.0 0. 16 15:16:17 Started Pumping -1 -21 0.0 0.0 0.0 17 15:16:19 Start MiniFrac Manually -9 -20 0.0 0.0 0. 18 15:16:41 returns on rig 29 -21 1.2 5.8 0.0 19 15:24:20 Start MF Cont Automatically 192 -21 46.5 0.2 0. 20 15:26:49 tool in set down position 17 -21 46.5 0.0 0. 21 15:28:43 Stage at Perfs: CrossCheck 2309 906 54.1 15.0 0.0 22 15:28:44 Stage at Perfs: MiniFrac 2304 902 54.3 15.0 0. 23 15:31:49 Stage at Perfs: MF Cont 2032 821 100.6 15.0 0. 24 15:35:07 Start MF Flush Automatically 2016 791 150.1 15.0 0.0 25 1 15:38:42 IStage at Perfs: MF Flush 1733,762 203.9 15.0 0. 26 1 15:40:50 IStart SRT Automatically 651 754 235.7 7.7 0. ch embepgep Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States � Time Message Log Treating Message Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 27 15:52:50 Pit 3 not filtered yet to put in Frac Tank 494 239 235.9 0.0 0. 28 16:01:56 1 bpm srt 907 651 237.6 2.0 0. 29 16:02:46 2 bpm SRT 947 616 239.3 2.0 0. 30 16:03:46 3 BPM SRT 1119 638 242.1 2.9 0. 31 16:04:53 4 BPM SRT 1031 638 246.7 4.8 0. 32 16:06:00 5 BPM SRT 990 622 252.1 4.8 0. 33 16:06:45 Activated Extend Stage 1168 638 257.7 7.9 0.0 34 16:07:59 10 BPM SRT 1717 627 269.4 10.9 0. 35 16:08:47 15 BPM SRT 1601 659 281.1 14.7 0. 36 16:10:14 RIG PICKING UP TO REVERSE 604 350 283.9 0.0 0.0 37 16:39:02 RIG TRYING TO PICKUP TO REVERSE HAVING ISSUES 22 25 283.9 0.0 0. 38 18:32:34 RIG FLOOR CALLS TO RIG DOWN -9 -24 283.9 0.0 39 18:32:44 OB COMPLETE -8 -3749 283.9 0.0 40 18:32:47 Deactivated Extend Stage -8 -3750 283.9 0.0 E�jo-' Schlumbepgep Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States Section 5: Propped Frac: As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) As Measured Pump Fluid Name Schedule Fluid Volume (gal) Proppant Name raax Pr op Conc (PPA) Prop Conc (PPA) Prop Mass (Ib) 1 PAD 46.5 6, 7.8 YF125ST 1953 31 0 0 0 2 PAD CONT 49.2 16.3 3.3 YF125ST 2061 18.1 0 0 71 3 0.5 PPA 24.3 18 1.4 YF125ST 1009 EconoProp 30/50 0.6 0.1 505 4 1.0 PPA 24.9 18 1.4 YF125ST 1012 EconoProp 30/50 1.1 0.3 94 5 2.0 PPA 25.9 18 1. YF125ST 1013 EconoProp 30/50 2 1.7 184 6 3.0 PPA 27 18 1.5 YF125ST 1011 EconoProp 30/50 3.1 2.7 286 7 3.0 PPA 19.5 If 1.1 YF125ST 719 EconoProp 30/50 3.6 3 2341 8 4.0 PPA 19.5 18 1.1 YF125ST 6881 EconoProp 30/50 4.q 0.7 296 9 5.0 PPA 19.4 If 1.1 YF125ST 6621 EconoProp 30/50 5.71 2.3 351 10 6.0 PPA 19.4 18 1.1 YF125ST 6331 Econo Prop 30/50 6.N 4.6 399 11 7.0 PPA 19.4 17.1 1.21 YF125ST 617 EconoProp 30/50 9.1 2.2 460 12 8.0 PPA 19.4 14.7 1.3 YF125ST 593 EconoProp 30/50 8.1 .5 497 13 9.0 PPA 19.4 13.4 1.5 YF125ST 572 EconoProp 30/50 9.N 4.4 540 14 10.0 PPA 19.4 13.2 1.5 YF125ST 553 EconoProp 30/50 10. 1.6 573 15 11.0 PPA 19.4 13.2 1.5 YF125ST 535 EconoProp 30/50 11.19 10.1 608 16 12.0 PPA 19.1 12.9 1.5 YF125ST 1 5181 EconoProp 30/50 12.7 5.6 623 17 12.0 PPA 62.9 12.6 5 YF125ST 1715 EconoProp 30/50 12.3 0 20367 18 Flush 56.4 3.9 23.21 WF125 25481 EconoProp 30/50 7.5 0.11 221 Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 PAD 3.0 5.0 554 50 301 PAD CONT 3.0 6.0 75 50 31 PAD 0 0.0 675 0 39 PAD CONT 16.3 18.1 2255 2538 71 5 0.5 PPA 18.0 18.0 2354 2384 322 1.0 PPA 18.0 18.0 2372 2385 346 0 PPA 18.0 18.0 2331 2344 304 0 PPA 18.0 18.0 2293 2304 284 1273 0 PPA 18.0 18.0 2282 2289 278 10 4.0 PPA 18.0 18.0 2277 2281 11 5.0 PPA 18.0 18.0 2279 2291 2272 12 6.0 PPA 18.0 18.0 2310 2352 2291 13 7.0 PPA 17.1 18.0 2236 2404 1958 14 8.0 PPA 14.7 15.0 1911 1964 1834 15 9.0 PPA 13.4 14.2 1709 1854 1671 16 10.0 PPA 13.2 13.2 1695 1723 1673 17 11.0 PPA 13.2 13.2 1743 1784 1714 18 12.0 PPA 12.9 13.2 1734 1785 1686 19 12.0 PPA 12.6 112.6 11800 11851 11710 0 IFlush P.9 112.6 11011 11858 schlu ,lbepoep Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States Average Treating Pressure: 1829 psi Maximum Treating Pressure: 2538 psi Minimum Treating Pressure: 0 psi Average Injection Rate: 13.6 bbl/min Maximum Injection Rate: 18.1 bbl/min Average Horsepower: 679.2 hhp Maximum Horsepower: 1097.1 hhp Maximum Prop Concentration: 12.7 PPA Section 6: Propped Frac: Material Balance Material Balance Material Name Quantity Pumped YF125ST 15864 gal WF125 2548 gal EconoProp 30/50 74379 Ib M275, Microbiocide 61b J877, Guar Polymer Slurry 96 gal J532, Borate Crosslinker 64 gal J318, Liquid Breaker Aid 35 gal F103, Surfactant 20 gal J218, Breaker 1211b eblembepoep Section 7: Propped Frac: Job Messages Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States # Time Message Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 6:39:19 Start PAD Manually 311 1 0.6 6.0 0. 2 6:39:19 Start Propped Frac Manually 311 1 0.6 6.0 0.0 3 6:47:07 Start PAD CONT Automatically 65q 1 46.6 6.0 0.0 4 6:48:32 RIG SHIFTING TOOL 104 2 47.0 0.0 0. 5 6:52:50 Start PAD Manually 60 74 47.0 0.0 0.0 6 6:53:27 Start PAD CONT Manually 73 750 47.0 0.0 0. 7 6:55:12 RIG TOOL SHIFTED TO WIEGHT DOWN 100 2405 47.0 0.0 0. 8 6:56:17 Stage at Perfs: CrossCheck 2107 2384 53.8 12.0 0.0 9 6:56:20 Stage at Perfs: PAD 218q 2385 54.4 13.1 0.0 10 6:58:40 Start 0.5 PPA Automatically 2331 2340 95.7 18.0 0. 11 6:58:40 Started Pumping Prop 2331 2340 95.7 18.0 0.0 12 6:58:58 Stage at Perfs: PAD CONT 2327 2329 101.1 18.0 0. 13 1 6:58:59 Stage at Perfs: PAD CONT 2330 2334 101.4 18.0 0.6 14 7:00:01 Start 1.0 PPA Automatically 2386, 2317 120.1 18.0 0. 15 7:01:24 Start 2.0 PPA Automatically 2341 2301 145.0 18.0 1.1 16 7:01:40 Stage at Perfs: 2.0 PPA 232 2293 149.8 18.0 1.7 17 7:02:51 Start 3.0 PPA Automatically 229 2280 171.1 18.0 2.1 18 7:03:01 Stage at Perfs: 3.0 PPA 229 2283 174.1 18.0 2. 19 1 7:04:21 Start 3.0 PPA Automatically 227 2270 198.1 18.0 3.1 20 7:04:25 Stage at Perfs: 3.0 PPA 228 2270 199.3 17.9 3. 21 7:05:26 Start 4.0 PPA Automatically 228 2263 217.6 18.0 3. 22 7:05:52 Stage at Perfs: 4.0 PPA 229 2262 225.4 18.0 4. 23 7:06:30 Start 5.0 PPA Automatically 227 2261 236.8 18.0 4. 24 7:07:22 Stage at Perfs: 5.0 PPA 229 2250 252.5 18.0 5.6 25 7:07:35 Start 6.0 PPA Automatically 228 2250 256.4 18.0 5. 26 7:08:27 Stage at Perfs: 6.0 PPA 231 2242 272.0 18.1 6.6 27 7:08:40 Start 7.0 PPA Automatically 2373 2252 275.9 18.0 6. 28 7:09:33 Stage at Perfs: 7.0 PPA 1972 2246 291.2 15.1 9. 29 7:09:49 Start 8.0 PPA Automatically 1972 2246 295.2 15.1 7.7 30 7:10:52 Stage at Perfs: 8.0 PPA 1836 2246 310.7 14.2 8. 31 7:11:09 Start 9.0 PPA Automatically 185 2238 314.7 14.2 8. 32 7:12:18 Stage at Perfs: 9.0 PPA 166 2237 330.1 13.2 9.6 33 7:12:36 Start 10.0 PPA Automatically 1673 22361 334.0 13.2 9. 34 1 7:13:47 Stage at Perfs: 10.0 PPA 172 22421 349.6 13.2 10.5 35 7:14:04 Start 11.0 PPA Automatically 172 2242 353.3 13.2 11. 36 7:15:17 Stage at Perfs: 11.0 PPA 177E 2242 369.4 13.2 11.6 37 7:15:33 Start 12.0 PPA Automatically 1754 2241 372.9 13.2 11.9 38 7:16:47 Stage at Perfs: 12.0 PPA 1724 2243 388.7 12.6 11. 39 7:17:02 Start 12.0 PPA Automatically 117371 2242 391.9 12.6 12.2 40 1 7:17:37 Activated Extend Stage 1734 2246 399.3 12.6 11. 41 7:18:19 Stage at Perfs: 12.0 PPA 1790 2243 408.1 12.6 12.1 42 7:19:52 Stage at Perfs: 12.0 PPA 1831 2242 427.7 12.6 11. 43 7:21:23 Stage at Perfs: 12.0 PPA 1829 2245 446.9 12.6 11. 44 7:21:56 Cut Prop 1847 2244 453.8 12.6 7.5 45 7:22:00 Deactivated Extend Stage 1 41 2248 454.7 12.6 4. 46 7:22:00 Start Flush Manually 1841 2248 454.7 12.6 4.9 47 7:22:15 Stopped Pumping Prop 39A 22331 457.8 10.8 0.1 schlumbepoep Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai, AK Country: United States I Time Message Log reating Message T Pressure (psi) Annulus Pressure (psi) Slurry Total Slur (bbl) Slur Rate (bbl/min) Pro Conc. (PPA) 48 7:42:30 Stage at Perfs: Flush 1104 2218 506.2 0.0 0. 49 8:00:22 RIG PICKING UP TO REVERSE 616 842 511.0 0.0 0.0 50 1 9:21:00 Started Pumping 1 -3777 -37301 511.01 0.01 0. Schlumberger FracCAT Treatment Report Well : KLU#A-2A Field : KLU Undefined Gas Pool Formation : Upper Beluga 0 Prepared for Client : Furie Operating Alaska Client Rep : Jack Burman Date Prepared 08/15/2016 Prepared by 3126 lbs Name : Alexander Martinez Division : Schlumberger Phone :561-389-5006 Service Point : Kenai Proppant • Pressure Total Proppant Pumped 60,021 lbs Total Proppant Around Screen 3126 lbs Total Proppant Below Crossover Port 58,100 lbs Total Proppant Around Blank 1348 lbs Proppant Reversed 1,921 lbs Height of Proppant Around Blank 3.5" 59.8 ft Proppant in Perforations 53,627 lbs % Proppant below X/O 97% Proppant Concentration in Perfs (MD) 360 lbs/ft Screenout Pressure 2,004 psi Proppant Concentration in Perfs (TVD) 380 lbs/ft Injected Fluids (Below• WF123 58.3 bbls YF123ST 456.5 bbls Treatment • (Above - • WF123 175.2 bbls YF123ST 468.7 bbls Total Slurry 709.2 bbls Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred chlumbe1_UGp Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai Country: United States MiniFrac & SRT FurieOperating Alaska KLLI#A-2A 08.15-2016 3000 re Y0 — Tr Pressu — Slurry Rate 2500 2000 4 1500 2 10 1000 5 5 500 0 0 >o:�s uy:z8: t3 10:01:53 10:35:13 11:08:33 Time - hh:mm:ss 1 Spot calibration test in reverse position 2 Shift to weight down circulate 3 Calibration Test 4 Shutdown to monitor pressure/batch up gel 5 Step rate test Schlumberger o. N co w Ir CL cc Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai Country: United States I i:as:ou tz:uu:30 12:17:10 12:33:50 12:50:30 Time - hh:mm:ss 6 Load hole in reverse position 7 Shutdown, move tool to weight -down circulate 8 Slow rate for prop rate 9 Begin slowdown schedule rting Alaska 20 16 14 v 12 O I 10 0 M 8 D Schlumberger Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai Country: United States Section 1: Total Treatment: Material Balance Material Balance Step Material Name Quantity Pumped YF123ST 20933 gal WF123 7361 gal EconoProp 30/50 60021 Ib M275, Microbiocide 181b J134 Enzyme Breaker 251b J891, Guar Polymer Slurry 199 gal J532, Borate Crosslinker 100 gal J218, Live Breaker 187 Ib F103, Surfactant 54 gal J318, Liquid Breaker Aid 40 gal Section 2: Diaqnostic: As Measured Pump Schedule Step Step Slurry Slurry Pump 1 Fluid 1.3 Drax Prop Prop 784.6 hhp Name Volume Rate Time Fluid Name Volume Proppant Name Cone Cone Mass P638 P33 (bbl) (bbl/mini (min) 11979 (gal) 5 IS RT (PPA) (lb) 1527 (PPA) 1 OpenTop 0.5 11 0.3 YF123ST 21 01 0 0 2 MiniFrac 18Q 13.1 17.q YF123ST 7560 01 0 3 MF Flush 68. 18.1 WF123 2869 0 0 4 SRT 4 8.6 8.61 WF123 1 2016 0 n Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 OpenTop 1.3 1.4 44 65 14 784.6 hhp MiniFrac 13.5 18.2 2018 2790 73 MF Flush 18.1 18.2 2423 P638 P33 OL__ .6 14.8 11527 11979 11 5 IS RT 0.6 0.0 1527 As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (Ib) 296.8 30.5 23417 0 Average Treating Pressure: 2032 psi Maximum Treating Pressure: 2790 psi Minimum Treating Pressure: 0 psi Average Injection Rate: 13.7 bbl/min Maximum Injection Rate: 18.2 bbl/min Average Horsepower: 784.6 hhp Maximum Horsepower: 1238.3 hhp Maximum Prop Concentration: 0.0 PPA Schlumbugep Section 3: Diagnostic: Job Messages Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai Country: United States # TimePressure Message. IL -„ Treating (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 Reset Executed Steps 0 0 0.0 0.0 0. 2 Reset Executed Steps 0 0 0.0 0.0 0.0 3 7:28:38 14:00 SAFETY MEETING 0 0 0.0 0.0 0.0 4 7:37:53 FILLING LINES AND PRIME UP 49 15 0.0 4.9 0. 5 8:05:30 High PT good 43 psi lost in 3 mins. 8227 3243 0.0 0.0 0.0 6 8:12:38 popoff inline and open to ann 13 -11 0.0 0.0 0.0 7 8:16:24 manifold set for cir rates 2 -10 0.0 0.0 0. 8 8:17:49 1 bpm Cir rate 20 -8 0.0 0.0 0. 9 8:20:47 1 bpm cir rates 77 -13 0.0 0.0 0.0 10 8:23:04 cmt pump down rig prep for strip test 4 -13 0.0 0.0 0. 11 8:32:03 50k intial drag 32k drag 1,000 psi on backside 544 461 0.0 0.0 0. 12 8:33:24 wait on crane to replace cutting box in high pressure zone 5 -10 0.0 0.0 0. 13 8:35:59 verify Pann with rig floor 11 -9 0.0 0.0 0. 14 8:47:25 crane moving 2nd box in High pressure zone 1 -9 0.0 0.0 0.0 15 8:58:31 Start OpenTop Automatically 1 -9 0.0 0.0 0. 16 8:58:31 Start Diagnostic Automatically 1 -9 0.0 0.0 0. 17 8:58:31 Start Upper Beluga Automatically 1 -9 0.0 0.0 0.0 18 8:58:31 Started Pumping 1 -9 0.0 0.0 0. 19 8:58:51 Activated Extend Stage 1 -9 0.0 0.0 0. 20 9:01:20 good xlink at open top 8.8 ph 1 -9 0.0 0.0 0.0 21 9:03:19 Deactivated Extend Stage 13 -9 0.5 2.7 0. 22 9:03:19 Start MiniFrac Manually 13 -9 0.5 2.7 0.0 23 9:11:39 Stage at Perfs: OpenTop 1036 -10 48.8 6.0 0.0 24 9:14:11 shut down to shift the tool to wieght down circulate 491 -9 58. 0.0 0 . 25 9:17:25 Stage at Perfs: MiniFrac 1903 506 60.1 5.9 0.0 26 9:24:38 Start MF Flush Automatically 2631 614 180.7 18.1 0. 27 9:24:48 cutxlinker 2622 613 183.7 18.2 0. 28 9:28:08 Stage at Perfs: MF Flush 2268 633 244.2 18.2 0.0 29 9:34:02 Remark 1025 518 248.5 0.0 0. 30 10:53:10 Start SRT Automatically 855 283 248.8 1.3 0.0 31 10:54:32 1bpm srt 1182 584 250.6 2.0 0.0 32 10:55:36 2 bpm srt 1114 556 252.8 3.2 0.0 33 10:56:41 3 bpm srt 1254 567 256.3 3.9 0.0 34 10:57:33 4 bpm srt 1190 564 259.7 4.7 0. 35 10:58:03 Activated Extend Stage 1256 572 262.1 4.7 0.0 36 10:58:30 5 bpm srt 1271 589 264.3 6.0 0.0 37 10:59:35 7.5 bpm srt 1401 601 271.8 7.1 0. 38 11:00:38 10 bpm srt 156 619 281.7 9.6 0.0 39 11:05:36 Rig picking up to Reverse position 96 453 296.8 0.0 0. 40 11:28:56 BOTTOMS UP, 2BPM 1, 91 296.8 0.0 0. 41 11:43:20 Deactivated Extend Stage -8 -13 296.8 0.0 0. 42 11:43:20 Start OpenTop Manually -8 -13 296.8 0.0 0. 43 11:43:20 Start Propped Frac Manually -8 -13 296.8 0.0 0.0 44 1 11:48:36 Start SRT Manually 1 -14 0.0 0.0 0. 45 1 11:48:36 Start Propped Frac Manually 1 -14 0.0 0.0 0.0 Schlumberger Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai Country: United States Section 4: Propped Frac: As Measured Puma Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) As Measured Pump Fluid Name Schedule Fluid Volume (gal) Proppant Name Pox Conc (PPA) Prop Conc (PPA) Prop Mass (Ib) 1 OpenTop 7.7 8.6 0 YF123ST 321 0 0 2 PAD 2q 5.9 4.2 YF123ST l00q 01 0 3 0.5 PPA I 24.A 6 4.1 YF123ST 998 EconoProp 30/50 2.5 0.5 60 4 1.0 PPA 24.91 10.4 2.8 YF123ST 1001 EconoProp 30/50 1 1 651 5 2.0 PPA 25.9 15.2 1.7 YF123ST 999 EconoProp 30/50 2.1 2 189 6 3.0 PPA 27 15 1.8 YF123ST 1001 EconoProp 30/50 3.1 3 2893 7 3.0 PPA 19.5 15 1.3 YF123ST 723 EconoProp 30/50 3.7 3 238 8 4.0 PPA 19.5 IN 1.3 YF123ST 6831 EconoProp 30/50 4.71 4.q 292 9 5.0 PPA 1 19. 1 1.3 YF123ST 6581 EconoProp 30/50 51 5. 353 10 6.0 PPA 19. 151 1.3 YF123ST 6361 EconoProp 30/50 6. 6.1 405 11 7.0 PPA 19.5 15 1.3 YF123ST 61 EconoProp 30/50 7.N 7. 4455 12 8.0 PPA 19. 15 1.31 YF123ST 5951 EconoProp 30/50 7.6 8.5 440 13 9.0 PPA 19. 12.8 1.51 YF123ST 5761 EconoProp 30/50 1 O.A 9. 5299 14 10.0 PPA 20.1 12 1.71 YF123ST 585 EconoProp 30/50 10.5 Ic 594 15 11.0 PAI 25.3 12 2.1 YF123ST 714 EconoProp 30/50 11 11 765 16 12.0 PPA 19.2 11 1.8 YF123ST 50 EconoProp 30/50 13. 13.5 646 17 12.0 PPA 18.6 8. 2.1 YF123ST 48 EconoProp 30/50 13. 13. 685 18 Flush 58. 12 WF123 247 0 0 Sch umbepgep Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai Country: United States 720penTop Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) -8 psi OpenTop .6 0.0 1527 -8 -8 Maximum Horsepower: 996.0 hhp B.6 0.0 1527 10 PAD 5.9 6.0 541 690 10 5 PPA 6.0 6.0 830 967 692 5 1.0 PPA 10.4 15.2 1923 2671 359 0 PPA 15.2 15.9 2359 2551 2223 0 PPA 15.0 15.1 2178 2218 2120 0 PPA 15.0 15.0 2126 2134 2117 0 PPA 15.0 15.0 2122 2134 2109 10 5.0 PPA 15.0 15.0 2094 2109 2082 11 6.0 PPA 15.0 15.0 2065 2087 2037 12 7.0 PPA 15.0 15.0 2028 2042 1996 13 8.0 PPA 15.0 15.0 1985 1992 1894 14 9.0 PPA 12.8 14.4 1694 1874 1592 15 10.0 PPA 12.0 12.0 1623 1636 1613 16 11.0 PPA 12.0 12.0 1624 1643 1600 17 12.0 PPA 11.0 12.0 1470 1599 1403 18 12.0 PPA P.5 11.9 1360 11946 19 Flush 0.5 10.0 11360 Ill Ill As Measured Totals Slurry Pump Time Clean Fluid Proppent (bbl) (min) (gal) (lb) 412.4 43.6 16009 60021 Average Treating Pressure: 1688 psi Maximum Treating Pressure: 2671 psi Minimum Treating Pressure: -8 psi Average Injection Rate: 11.8 bbl/min Maximum Injection Rate: 15.9 bbl/min Average Horsepower: 532.3 hhp Maximum Horsepower: 996.0 hhp Maximum Prop Concentration: 13.6 PPA Schlumberger Section 5: Propped Frac: Job Messages Client: Furie Operating Alaska Well: KUU#A-2A Formation: Sterling/Beluga District: Kenai Country: United States # Time Message Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 11:43:20 Deactivated Extend Stage -8 -13 296.8 0.0 0. 2 11:43:20 Start OpenTop Manually -8 -13 296.8 0.0 0.0 3 11:43:20 Start Propped Frac Manually -8 -13 296.8 0.0 0.0 4 11:48:36 Start SRT Manually 1 -14 0.0 0.0 0. 5 11:48:36 Start Propped Frac Manually 1 -14 0.0 0.0 0. 6 11:48:38 Start OpenTop Manually 11 -14 0.0 0.0 0.0 7 11:48:38 Start Propped Frac Manually 11 -14 0.0 0.0 0. 8 11:49:07 Start PAD Manually 1 -14 0.0 0.0 0. 9 11:49:53 RETURNS ON RIG FLOOR 44 -13 3.4 6.0 0.0 10 11:50:32 Stage at Perfs: SRT 48 -13 7.3 6.0 0. 11 11:51:16 POD ZERO ON PAD 52 -13 11.7 6.0 0.0 12 11:53:20 Start 0.5 PPA Automatically 705 -13 24.0 6.0 0.0 13 11:53:20 Started Pumping Prop 70 -13 24.0 6.0 0. 14 1 11:57:25 Start 1.0 PPA Automatically 97 -12 48.4 6.0 0. 15 11:57:55 Stage at Perfs: SRT 99 -13 51.4 6.0 0.5 16 11:59:14 SHIFTING 429 PSI ON SLACK DOWN 41 -13 55.9 0.0 0. 17 11:59:48 Stage at Perfs: SRT 44 -13 55.9 0.0 0. 18 11:59:49 Stage at Perfs: OpenTop 44 -13 55.91 0.0 0.0 19 12:01:36 Stage at Perfs: OpenTop 42 -13 55.9 0.0 0.1 20 12:03:19 Start 2.0 PPA Automatically 2511 679 73.3 16.2 0.9 21 12:03:56 Stage at Perfs: PAD 2361 675 82.8 15.1 2.0 22 12:05:02 Start 3.0 PPA Automatically 2209 604 99A 15.0 1. 23 12:06:50 Start 3.0 PPA Automatically 2130 620 126.4 15.0 2.8 24 12:07:31 Stage at Perfs: 0.5 PPA 2136 620 136.6 15.0 3. 25 12:08:08 Start 4.0 PPA Automatically 211q 633 145.9 15.0 3. 26 12:09:16 Stage at Perfs: 1.0 PPA 2096 650 162.9 15.0 4.6 27 12:09:26 Start 5.0 PPA Automatically 2122 650 165.4 15.0 4. 28 12:10:44 Start 6.0 PPA Automatically 2087 667 184.9 15.0 6. 29 12:11:04 Stage at Perfs: 2.0 PPA 2077 669 189.9 15.0 6.1 30 12:12:02 Start 7.0 PPA Automatically 2032 679 204.4 15.0 7. 31 12:12:23 Stage at Perfs: 3.0 PPA 2041 684 209.6 15.0 7. 32 1 12:13:20 Start 8.0 PPA Automatically 1984 700 223.9 15.0 6.9 33 12:13:41 Stage at Perfs: 3.0 PPA 1986 693 229.1 15.0 6. 34 12:14:38 Start 9.0 PPA Automatically 1877 696 243.3 14.2 7.7 35 12:15:01 Stage at Perfs: 4.0 PPA 1693 700 248.6 13.1 8.7 36 12:16:10 Start 10.0 PPA Automatically 1584 708 262.7 11.9 10. 37 12:16:36 Stage at Perfs: 5.0 PPA 1621 703 267.9 12. 10.3 38 1 12:17:51 Start 11.0 PPA Automatically 1617 712 282.9 121 10. 39 12:18:14 Stage at Perfs: 6.0 PPA 1643 716 287.5 12. 10.3 40 12:18:35 Activated Extend Stage 1630 717 291.7 12. 10.8 41 12:19:52 Stage at Perfs: 7.0 PPA 1583 720 307.1 121 10.8 42 12:19:57 Deactivated Extend Stage 1599 716 308.1 12.0 11. 43 1 12:19:57 Start 12.0 PPA Manually 1599 716 308.1 12. 11. 44 12:21:33 Remark 1457 742 325.6 10.7 13. 45 12:21:39 Stage at Perfs: 8.0 PPA 1462 734 326.6 10.7 13.2 46 12:21:43 Start 12.0 PPA Automatically 1462 742 327.3 10.7 13. 47 12:22:13 Activated Extend Stage 148q 738 332.7 11.0 13. chlumbepgep Client: Furie Operating Alaska Well: KLU#A-2A Formation: Sterling/Beluga District: Kenai Country: United States # Time Message g Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 48 12:23:27 Stage at Perfs: 9.0 PPA 153 750 346.8 11.2 5. 49 12:23:28 Remark 1529 748 346.9 11.3 5.0 50 12:24:11 Remark 159 753 355.01 11.2 0. 51 12:24:26 Remark 16191 756 357.8 11.2 -0.1 52 12:24:33 SWAP ON SIDE 1656 759 359.1 11.3 0. 53 12:26:31 Stopped Pumping Prop 855 769 379.1 6.0 -0.0 54 12:30:33 401 SLOW DOWNTO 1BPM 1012 768 394.2 2.5 0. 55 12:33:49 Remark 1061 7131 402.3 1.3 0. 56 12:34:03 SLOW TO i BPM OPEN CHOKE 1061 699 402.6 1.3 0. 57 12:35:53 SHUT DOWN 190 684 404.8 0.0 0.0 58 12:36:27 BACKSIDE CLOSED 1851 700 404.8 0.0 0. 59 12:37:35 PICKING UP TO REVERSE 1777 677 404.8 0.0 0.0 60 13:30:40 Started Pumping 11 -11 404.8 0.0 0. 61 13:30:42 Deactivated Extend Stage 11 -10 404.81 0.0 0.0 62 13:30:43 Start Flush Automatically 11 -10 404.8 0.0 0. 63 14:37:38 JOB END 15 -8 404.81 0.0 0. Sehlumbergep FracCAT Treatment Report Well : KLU#A-2A Field : KLU Undefined Gas Pool Formation :Sterling/Beluga cq� f o LIL; Prepared for L �J Client : Furie Operating Alaska Client Rep Jack Burman Date Prepared :08/10/2016 Prepared by Name : Alexander Martinez Phone : 561-389-5006 Division : Schlumberger Service Point : Kenai Proppant • Pressure Total Proppant Pumped 29,736 lbs I Total Proppant Around Screen 761 lbs Total Proppant Below Crossover Port 29,136 lbs Total Proppant Around Blank 5790 lbs Proppant Reversed 600 lbs Height of Proppant Around Blank 3.5" 120 ft Proppant in Perforations 22586 lbs Height of Proppant Around Blank 5.5" 90.6 ft Proppant Concentration in Perfs (MD) 1027 lbs/ft % Proppant below X/O 98% Proppant Concentration in Perfs (TVD) 1096 lbs/ft Screenout Pressure 3,532 psi Injected Fluids (Below• WF123 220.5 bbls YF123ST 238.1 bbls I Total Fluid 458.6 bbls Injected Fluids (Above XO) WF123 324.8 bbls I YF123ST 1 240.2 bbls Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred Client Well Furie Operating Alaska : KLU#A-2A 2 Shutdown to monitor pressure Schlumberger Formation Beluga Shutdown to monitor pressure Calibration Test & SRT Alaska Fimn — rr. Press prating 08-10-2016 - Slurry Rate -- Prop Con - BH Prop Can 4000 10 12 3 9 10 a 3000 1 Z 7 \ 6 4 6 2000 6 � 6 4 3. 4 3 1000 2 2 1 0 07:08:12 07:37:22 08:06:32 08:36:42 0 09:04:62 0 Time - hh:mm:ss 2 1 Calibration Test 2 Shutdown to monitor pressure 3 Step Rate Test 4 Shutdown to monitor pressure Client Well Furie Operating Alaska KLU#A-2A �� Formation Beluga Main Treatment Ririe Operating Alaska — Tr. Press KLU#A-2A — Slurry Rate 08.10-2016 — Prop Con — BH Prop Con 4000 10 12 �WL+ —� ] V .9 10 8 3000- 8 7 8 N y 1r 6 c 1 o - '°o d IL 2000 I 5 m n m 6 0 v 4 3 D 4 3 1000- /000 I 2 2 wi U 1 01 10:22:38 10:47:38 11:12:38 11:37:38 0 0 Time - hh:mm:ss 5 Load hole in reverse position 6 Shutdown, move tool to weight -down circulate 7 Swap to tank #2 :::8�� Begin �slowdo�wnschedule 3 Client Furie Operating Alaska�� Well KLU#A-2A Formation Beluga Section 1: Beluga (6679, Propped Frac: Schedule As Pump Schedule Step Step Slurry Slurry Pump Fluid # Name Volume Rate Time Fluid Name Volume (bbl) (bbl/min) (min) (gal) ]]� �f As Measured Pump PMraax Prop Prop Proppant Name Conc Conc Mass (PPA) (PPA) (lb) 1 PAD 47.1 4. 10.11 YF123ST 19951 O.Q 0.0 0 2 0.5 PPA 12.2 5. 2.4 YF123ST 502 EconoProp 30/50 1.1 0.0 20 3 1.0 PPA 12.4 6.2 2.2 YF123ST 511 EconoProp 30/50 1.2 0.4 24 4 2.0 PPA 13.0 8.(.1.6 YF123ST 512 EconoProp 30/50 2.1 0.4 76 5 3.0 PPA 13.5 8. 1.7 YF123ST 507 EconoProp 30/50 3.1 1.8 1441 6 3.0 PPA 7.8 8. 1.Q YF123ST 290 EconoProp 30/50 3.7 1.8 929 7 4.0 PPA 7.8 8. 1. YF123ST 279 EconoProp 30/50 4. 2.5 116 8 5.0 PPA 7.8 8.0 1. YF123ST 269 EconoProp 30/50 5. 3.2 1411 9 6.0 PPA 7.8 8. 1. YF123ST 260 EconoProp 30/50 6. 4., 162 10 7.0 PPA 7.8 B.C. 11 YF123ST 251 EconoProp 30/50 7.1 6. 183 11 8.0 PPA 7.8 8. 1. YF123ST 243 EconoProp 30/50 8A 8. 199 12 9.0 PPA 7.8 8.Q I.Q YF123ST 2351 EconoProp 30/50 9. 0. 213 13 10.0 PPA 7.7 8. 1. YF123ST 228 EconoProp 30/50 10. 9.1 2237 14 10.0 PPA 48.5 8. 6.1 YF123ST 135 EconoProp 30/50 13.1 0. 13601 15 Flush 63.7 6.2 15.7 WF123 2721 12.4 0.1 148 Step # Step Name Stage Pressures & Rates Average Slurry Maximum Slurry Average Treating Maximum Treating Minimum Treating Rate Rate Pressure Pressure Pressure (bbl/min) (bbl/min) (psi) (psi) (psi) 1 PAD 4.9 5.1 666 989 57 0.5 PPA 5.0 5.0 1044 1093 89 1.0 PPA .4 8.0 2370 322 24 2.0 PPA .0 8.0 281 296 248 5 .0 PPA .0 8.0 186 245 139 3.0 PPA .0 8.0 102 137 071 0 PPA .0 8.0 3039 3071 3005 5.0 PPA .0 8.0 2969 006 930 0 PPA .0 8.0 2881 930 834 10 .0 PPA .0 8.0 784 833 739 11 .0 PPA .0 8.0 2694 735 661 1509 12 .0 PPA .0 8.0 2624 2654 584 13 10.0 PPA .0 8.0 2547 P579 14 10.0 PPA .0 18.0 12280 504 11275 15 Flush P.2 18.0 12296 460 42 4 Client Furie Operating Alaska �� Well KW#A-2A Formation Beluga As Measured Totals Slurry Pump Time Clean Fluid Proppant (bbl) (min) (gal) (lb) 272.7 47.7 10159 29736 Average Treating Pressure: 2174 psi Maximum Treating Pressure: 3460 psi Minimum Treating Pressure: 57 psi Average Injection Rate: 6.8 bbl/min Maximum Injection Rate: 8.0 bbl/min Average Horsepower: 387.8 hhp Maximum Horsepower: 648.5 hhp Maximum Prop Concentration: 13.1 PPA Section 2: Beluga: Material Balance Material Balance: Material Name Below Crossover Quantity Pumped YF123ST 10000 gal WF123 9261 gal EconoProp 30/50 29136 Ib M275, Microbiocide 10 Ib J891, Guar Polymer Slurry 118 gal J532, Borate Crosslinker 43 gal F103, EZEFLO Surfactant 19 gal ,1218, Breaker 221b J318, Liquid Breaker Aid 779 gal Material Balance: Total Material Name Usage Quantity Pumped YF123ST 10088 gal WF123 13,642 gal EconoProp 30/50 32000 Ib M275, Microbiocide 18 Ib J891, Guar Polymer Slurry 144 gal J532, Borate Crosslinker 60 gal F103, EZEFLO Surfactant 23 gal ,1218, Breaker 221b J318, Liquid Breaker Aid 9 gal Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: Job End Date: State: County: API Number: Operator Name: Well Name and Number: Latitude: Longitude: Datum: Federal Well: Indian Well: True Vertical Depth: Total Base Water Volume (gal): Total Base Non Water Volume: 8/10/2016 8/23/2016 Alaska State Waters - Kenai Quadrangle 50-733-20655-01-00 Furie Operating Alaska Kitchen Lights Unit #A -2A 60.93670700 -151.15639300 NAD27 NO NO 7,301 94,414 0 Hydraulic Fracturing Fluid Composition: Y" FOCUS Chemical Disclosure Registry r •! rtoyfcyroH t c; •: :; OUGas Chemical Maximum Maximum Trade Name Supplier Purpose Ingredients Abstract Service Ingredient Concentration Ingredient Concentration Comments Number in Additive in HF Fluid (CAS #) (% by mass)" (% by mass)-- ass)"Water Water Schlumberger N/A Water (Including Mix 7732-18-5 72.68064 Water Supplied by Client)" M117 Schlumberger Clay Control Agent Listed Below J318 Schlumberger Breaker Aid Listed Below M275 Schlumberger Bactericide Listed Below J532 Schlumberger Crosslinker Listed Below S524-3050 Schlumberger Propping Agent Listed Below J891 Schlumberger Guar Slurry Listed Below J218 Schlumberger Breaker Listed Below F103 Schlumberger Surfactant Listed Below Ale Ceramic materials and wares, chemicals 66402-68-4 79.85616 21.81619 Potassium chloride 7447-40-7 16.89120 4.61457 Distillates, petroleum, hydrotreated light 64742-47-8 0.78627 0.21480 Guar gum 9000-30-0 0.72774 0.19881 1 otal water volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% *** If you are calculating a percentage of total ingredients do not add the water volume below the green line to the water volume above the green line Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) Sodium chloride 7647-14-5 0.52241 0.14272 2,2',2"-nitrilotriethanol 102-71-6 0.38406 0.10492 1, 2, 3 - Propanetriol 56-81-5 0.24180 0.06606 Sodium tetraborate decahydrate 1303-96-4 0.19745 0.05394 Diammonium peroxidisulphate 7727-54-0 0.17220 0.04704 Propan-2-ol 67-63-0 0.05228 0.01428 2-butoxyethanol 111-76-2 0.05228 0.01428 Alcohol, C11 linear, ethoxylated 34398-01-1 0.04802 0.01312 C12-15 alcohol ethyoxylated 68131-39-5 0.03010 0.00822 Amine treated smectite clay 68153-30-0 0.02022 0.00552 Diatomaceous earth, calcined 91053-39-3 0.00785 0.00214 1-undecanol 112-42-5 0.00418 0.00114 Silicon Dioxide 7631-86-9 0.00202 0.00055 Magnesium nitrate 10377-60-3 0.00157 0.00043 5-chloro-2-methyl-2h- isothiazolol-3-one 26172-55-4 0.00084 0.00023 Magnesium chloride 7786-30-3 0.00079 0.00021 2-methyl-2h-isothiazol-3- one 2682-20-4 0.00025 0.00007 Cristobalite 14464-46-1 0.00016 0.00004 Quartz, Crystalline silica 14808-60-7 0.00016 0.00004 Acetic acid, potassium salt 127-08-2 0.00016 0.00004 Acetic acid(impurity) 64-19-7 0.00003 0.00001 1 otal water volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% *** If you are calculating a percentage of total ingredients do not add the water volume below the green line to the water volume above the green line Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) 277(0(4S V1112 sa ADVANT/, .E Final Survey Listing NUG �Es INTEQ Operator Furie Operating Alaska Fields Kitchen Lights Unit API No 50-733-20655 Well KLU#A-2 Wellbore KLU A2A Rig Randolph Yost Job 7912806 OriginWell Latitude 60.9367 deg Longitude -151.1564 deg North Reference True Drill Depth Zero Rotary Table Vertical Datum is Mean Sea Level Vertical Datum to DDZ 107.000 ft Vertical Section North 0.000 ft Vertical Section East 0.000 ft Vertical Section Azimuth 45.6900 deg Vertical Section Depth 0.000 ft Grid Convergence 0.0000 deg Magnetic Declination 16.4800 deg Total Correction 16.4800 deg TVD Calculation Method Minimum Curvature D -Raw Calculation None Local Magnetic Field 55543 nT Local Magnetic Dip Angle 73.8800 deg Local Gravity Field 9.823 m/s^2 Tie MD Incl Azim North East TVD VS Temperature CRS LEN DLS ideg/1001deg/100ft Build Turn In ft deg deg ft ft ft ft degF ft ft deg/100ft U 107.000 0.00 0.00 0.000 0.000 107.000 0.000 200.000 0.50 357.67 0.405 -0.016 199.999 0.271 93.000 0.54 0.54 -2.51 300.000 3.94 3.50 4.272 0.176 299.909 3.110 100.000 3.44 3.44 5.83 366.170 9.49 28.15 11.357 2.890 365.611 10.002 66.170 9.27 8.39 37.25 418.000 6.67 29.73 17.740 6.400 416.921 16.971 77.0 51.830 5.46 -5.44 3.05 476.000 5.87 32.30 23.172 9.655 474.574 23.095 58.000 1.46 -1.38 4.43 506.000 5.62 32.65 25.705 11.267 504.423 26.019 30.000 0.84 -0.83 1.17 600.000 5.41 39.68 32.991 16.580 597.989 34.910 94.000 0.75 -0.22 7.48 664.000 6.07 40.93 37.870 20.723 661.668 41.282 82.4 64.000 1.05 1.03 1.95 696.000 6.37 43.07 40.445 23.044 693.479 44.742 82.4 32.000 1.18 0.94 6.69 727.000 6.59 45.40 42.950 25.485 724.281 48.239 85.1 31.000 1.11 0.71 7.52 758.000 7.57 47.49 45.579 28.257 755.044 52.058 85.1 31.000 3.27 3.16 6.74 790.000 8.75 47.54 48.646 31.606 786.720 56.598 85.1 32.000 3.69 3.69 0.16 822.540 9.86 47.49 52.200 35.486 818.831 61.857 85.1 32.540 3.41 3.41 -0.15 857.300 11.28 46.80 56.539 40.158 853.001 68.231 87.8 34.760 4.10 4.09 -1.99 889.560 12.58 46.56 61.114 45.009 884.563 74.898 87.8 32.260 4.03 4.03 -0.74 916.380 13.67 46.80 65.292 49.441 910.682 80.987 87.8 26.820 4.07 4.06 0.89 953.330 14.73 47.95 71.427 56.112 946.503 90.047 87.8 36.950 2.97 2.87 3.11 984.990 15.70 48.33 76.971 62.301 977.053 98.348 87.8 31.660 3.08 3.06 1.20 1010.110 15.96 48.81 81.505 67.438 1001.220 105.192 87.8 25.120 1.16 1.04 1.91 1048.420 16.53 49.12 88.541 75.523 1038.000 115.891 93.2 38.310 1.50 1.49 0.81 1079.970 18.02 49.27 94.663 82.614 1068.126 125.242 93.2 31.550 4.72 4.72 0.48 1104.450 19.07 49.11 99.751 88.507 1091.335 133.013 93.2 24.480 4.29 4.29 -0.65 1142.760 19.40 47.94 108.111 97.962 1127.506 145.618 93.2 38.310 1.32 0.86 -3.05 1173.870 20.04 46.83 115.219 105.686 1156.792 156.111 87.8 31.110 2.38 2.06 -3.57 1198.780 20.81 45.72 121.228 111.967 1180.135 164.803 385.2 24.910 3.46 3.09 -4.46 1294.690 24.93 46.66 147.007 138.877 1268.487 202.067 93.2 95.910 4.31 4.30 0.98 1389.140 27.26 47.50 175.286 169.306 1353.304 243.595 96.0 94.450 2.50 2.47 0.89 1483.890 29.83 47.07 206.002 202.565 1436.529 288.850 98.7 94.750 2.72 2.71 -0.45 1578.300 35.10 46.30 240.772 239.407 1516.157 339.502 98.7 94.410 5.60 5.58 -0.82 1672.810 39.53 46.63 280.219 280.936 1591.304 396.774 98.7 94.510 4.69 4.69 0.35 1766.170 42.40 46.93 322.125 325.537 1661.794 457.962 98.7 93.360 3.08 3.07 0.32 1861.240 48.11 45.93 368.666 374.419 1728.691 525.451 104.1 95.070 6.05 6.01 -1.05 1956.420 49.29 46.15 418.300 425.890 1791.509 596.953 104.1 95.180 1.25 1.24 0.23 2051.950 48.43 46.21 468.113 477.798 1854.358 668.894 104.1 95.530 0.90 -0.90 0.06 2147.980 49.36 46.68 517.970 530.238 1917.492 741.246 106.8 96.030 1.04 0.97 0.49 2228.270 48.51 46.93 559.406 574.370 1970.235 801.770 109.5 80.290 1.08 -1.06 0.31 S 2327.490 47.98 47.28 609.787 628.594 2036.310 875.765 87.8 99.220 0.60 -0.53 0.35 2364.890 47.48 48.33 628.375 649.097 2061.466 903.420 87.8 37.400 2.47 -1.34 2.81 2396.900 46.97 46.82 644.225 666.441 2083.206 926.902 90.5 32.010 3.81 -1.59 -4.72 2426.540 46.50 45.84 659.127 682.053 2103.520 948.484 90.5 29.640 2.88 -1.59 -3.31 2520.990 45.70 46.40 706.301 731.105 2169.012 1016.537 93.2 94.450 0.95 -0.85 0.59 2615.080 44.66 46.46 752.301 779.459 2235.333 1083.271 93.2 94.090 1.11 -1.11 0.06 2710.180 43.13 46.90 797.539 827.426 2303.862 1149.195 96.0 95.100 1.64 -1.61 0.46 2805.500 42.45 45.10 842.511 874.006 2373.814 1213.941 96.0 95.320 1.47 -0.71 -1.89 2900.060 41.90 43.57 887.915 918.374 2443.894 1277.406 98.7 94.560 1.23 -0.58 -1.62 2995.650 40.48 43.23 933.651 961.628 2515.827 1340.306 98.7 95.590 1.50 -1.49 -0.36 3089.080 38.28 43.76 976.655 1002.421 2588.040 1399.536 101.4 93.430 2.38 -2.35 0.57 3185.400 36.16 44.39 1018.514 1042.939 2664.737 1457.770 101.4 96.320 2.24 -2.20 0.65 3279.710 34.18 43.76 1057.534 1080.729 2741.827 1512.068 106.8 1 94.310 2.13 -2.10 -0.67 Page 1 AW AVM sH ADVANTi� E Final Survey Listing INTEQ Operator Furie Operating Alaska Fields Kitchen Lights Unit API No 50-733-20655 Well KLU#A-2 Wellbore KLU A2A Rig Randolph Yost Job 7912806 Tie MD Incl Azim North East TVD VS Temperature CRS LEN DLS I Build I Turn In ft deg deg ft ft ft I ft degF ft ideg/100ft1deg/100ft1deg/looft 3375.890 30.32 42.65 1094.917 1115.877 2823.154 1563.333 104.1 96.180 4.06 -4.01 -1.15 3471.030 27.29 42.98 1128.544 1147.024 2906.512 1609.110 106.8 95.140 3.19 -3.18 0.35 3566.000 23.38 43.42 1158.170 1174.829 2992.332 1649.702 109.5 94.970 4.12 -4.12 0.46 3661.230 19.50 42.13 1183.692 1198.488 3080.955 1684.459 109.5 95.230 4.10 -4.07 -1.35 3754.860 19.54 41.58 1206.994 1219.362 3169.204 1715.674 109.5 93.630 0.20 0.04 -0.59 3849.230 19.55 41.69 1230.590 1240.338 3258.136 1747.166 109.5 94.370 0.04 0.01 0.12 3944.840 19.55 41.32 1254.550 1261.539 3348.235 1779.075 112.2 95.610 0.13 0.00 -0.39 4041.040 19.59 41.15 1278.782 1282.779 3438.877 1811.200 112.2 96.200 0.07 0.04 -0.18 4133.950 19.91 41.14 1302.425 1303.436 3526.322 1842.497 112.2 92.910 0.34 0.34 -0.01 4228.380 20.10 40.79 1326.819 1324.615 3615.054 1874.692 112.2 94.430 0.24 0.20 -0.37 4322.770 20.31 41.69 1351.331 1346.106 3703.636 1907.193 112.2 94.390 0.40 0.22 0.95 4416.390 18.69 41.75 1374.657 1366.902 3791.883 1938.368 112.2 93.620 1.73 -1.73 0.06 4511.830 18.56 41.62 1397.420 1387.173 3882.325 1968.775 114.9 95.440 0.14 -0.14 -0.14 4606.350 18.80 41.69 1420.039 1407.294 3971.866 1998.973 112.2 94.520 0.26 0.25 0.07 4701.330 16.14 42.97 1441.131 1426.475 4062.457 2027.432 114.9 94.980 2.83 -2.80 1.35 4795.440 15.58 43.52 1459.867 1444.094 4152.984 2053.127 112.2 94.110 0.62 -0.60 0.58 4889.080 15.19 45.01 1477.659 1461.429 4243.269 2077.960 114.9 93.640 0.59 -0.42 1.59 4984.690 14.99 45.60 1495.166 1479.122 4335.582 2102.850 114.9 95.610 0.26 -0.21 0.62 5078.610 14.70 48.55 1511.552 1496.732 4426.368 2126.898 114.9 93.920 0.86 -0.31 3.14 5173.880 15.11 48.97 1527.705 1515.160 4518.433 2151.368 117.6 95.270 0.45 0.43 0.44 5268.220 15.39 49.21 1543.955 1533.913 4609.450 2176.138 117.6 94.340 0.30 0.30 0.25 5362.940 15.84 49.57 1560.550 1553.269 4700.674 2201.581 117.6 94.720 0.49 0.48 0.38 5456.520 15.99 49.71 1577.167 1572.822 4790.667 2227.181 120.3 93.580 0.17 0.16 0.15 5551.380 16.46 49.70 1594.309 1593.038 4881.749 2253.620 123.0 94.860 0.50 0.50 -0.01 5645.810 16.75 49.93 1611.721 1613.654 4972.241 2280.536 123.0 94.430 0.31 0.31 0.24 5740.290 17.10 50.13 1629.389 1634.734 5062.629 2307.962 123.0 94.480 0.38 0.37 0.21 5833.440 17.61 50.90 1647.055 1656.180 5151.538 2335.648 123.0 93.150 0.60 0.55 0.83 5929.880 18.03 50.93 1665.662 1679.089 5243.351 2365.039 125.7 96.440 0.44 0.44 0.03 6023.280 18.28 51.14 1683.963 1701.717 5332.101 2394.015 125.7 93.400 0.28 0.27 0.22 6118.380 18.60 51.03 1702.859 1725.122 5422.318 2423.962 125.7 95.100 0.34 0.34 -0.12 6212.730 18.89 50.98 1721.938 1748.687 5511.663 2454.152 128.4 94.350 0.31 0.31 -0.05 6306.250 19.18 50.70 1741.199 1772.336 5600.069 2484.530 128.4 93.520 0.33 0.31 -0.30 6402.260 19.55 50.72 1761.359 1796.976 5690.648 2516.243 128.4 96.010 0.39 0.39 0.02 6497.080 19.98 50.57 1781.692 1821.769 5779.881 2548.188 131.1 94.820 0.46 0.45 -0.16 6593.180 20.34 51.15 1802.597 1847.457 5870.094 2581.173 131.1 96.100 0.43 0.37 0.60 6687.500 20.60 51.10 1823.299 1873.137 5958.458 2614.010 133.8 94.320 0.28 0.28 -0.05 6782.800 21.23 50.98 1844.691 1899.590 6047.478 2647.882 133.8 95.300 0.66 0.66 -0.13 6878.280 21.36 51.29 1866.449 1926.590 6136.439 2682.401 133.8 95.480 0.18 0.14 0.32 6971.830 21.88 51.22 1888.021 1953.473 6223.407 2716.707 133.8 93.550 0.56 0.56 -0.07 7065.730 22.36 51.20 1910.172 1981.032 6310.396 2751.900 136.5 93.900 0.51 0.51 -0.02 7161.770 22.41 51.58 1932.995 2009.612 6399.199 2788.294 133.8 96.040 0.16 0.05 0.40 7256.350 22.74 51.93 1955.470 2038.128 6486.532 2824.399 136.5 94.580 0.38 0.35 0.37 7350.540 23.23 51.49 1978.262 2066.995 6573.243 2860.976 136.5 94.190 0.55 0.52 -0.47 7445.480 23.71 52.47 2001.548 2096.784 6660.329 2898.559 136.5 94.940 0.65 0.51 1.03 7540.750 24.37 52.20 2025.263 2127.505 6747.335 2937.108 136.5 95.270 0.70 0.69 -0.28 7636.270 25.05 52.22 2049.731 2159.060 6834.108 2976.780 139.2 95.520 0.71 0.71 0.02 7730.060 25.79 52.40 2074.344 2190.919 6918.817 3016.770 139.2 93.790 0.79 0.79 0.19 7824.820 26.41 52.54 2099.739 2223.979 7003.914 3058.167 139.2 94.760 0.66 0.65 0.15 7919.460 27.08 52.99 2125.508 2257.889 7088.429 3100.432 139.2 94.640 0.74 0.71 0.48 8014.390 27.52 53.62 2151.524 2292.800 7172.785 3143.587 136.5 94.930 0.55 0.46 0.66 8093.300 28.00 53.91 2173.248 2322.446 7242.613 3179.976 139.2 78.910 0.63 0.61 0.37 Projection to TD 8160.000 28.00 53.91 1 2191.694 2347.751 7301.506 3210.968 66.700 0.00 0.00 0.00 Column Legend: interpolatedTie I - .• Page 2 Guhl, Meredith D (DOA) From: Dave McCraine <d.mccraine@furiealaska.com> Sent: Tuesday, December 13, 2016 2:10 PM To: Guhl, Meredith D (DOA) Cc: Bettis, Patricia K (DOA); Schwartz, Guy L (DOA) Subject: Re: KLU A -2A, PTD 216-086, Data Required Importance: High I have it and will put it in FedEx tomorrow. My techinical help is out with the flue and I am unable to check the Schlumberger flash to confirm the packer setting files are complete. If they are not, I will get the Anchorage Schlumberger office get the missing formats to you. Regards Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: "Guhl, Meredith D (DOA)" <meredith.guhl@alaska.gov> Date: Monday, December 12, 2016 at 7:26 PM To: Dave McCraine <d.mccraine@furiealaska.com> Cc: Patricia Bettis <patricia.bettis@alaska.gov>, Guy Schwartz <guy.schwartz@alaska.gov> Subject: RE: KLU A -2A, PTD 216-086, Data Required David, As of today the required data for KLU A -2A has not been supplied. The data was due by December 8. Please provide an ETA for the required data listed below. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AC)GCC), 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.sov. From: Guhl, Meredith D (DOA) Sent: Friday, October 28, 2016 1:51 PM To:'David McCraine' <d.mccraine@furiealaska.com> Cc: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Subject: KLU A -2A, PTD 216-086, Data Required Hello David, A review was also completed of the 10-407 form and data supplied for KLU A -2A, PTD 216-086, completed 9/8/2016. During the review deficiencies were noted. Please supply the following data: 1. Frac Reports from vendor in both paper copy and digital format. Not the Frac Focus report. Contact Guy Schwartz with any questions regarding this point. 2. LAS and DLIS files for BakerHughes logs 3. LAS and DLIS file for Schlumberger USIT log 4. TIF images of Canrig Mudlogs 5. LAS files for Canrig Mudlogs 6. EOW report from Canrig in both digital and paper format 7. Any show reports from Canrig 8. A complete Packer Setting log in PDF, LAS, DLIS and paper format. The log submitted is lacking a header page and is not acceptable. Please supply the required data by December 8, 2016. An operator has 90 days after well completion to submit data, which is why the data for KLU A -2A is not required as soon as the data for KLU A-2 is. Please send the data to my attention. If you have any questions, please contact Patricia Bettis or me. Thank you, Meredith Meredith Guhl Petroleum Geology Assistant Alaska Oil and Gas Conservation Commission 333 W. 7th Ave, Anchorage, AK 99501 meredith.guhl@alaska.gov Direct: (907) 793-1235 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 Meredith Guhl at 907-793-1235 or meredith.guhl@alaska.gov. FURIE Operating Alaska LLC ECEN OCT 19 201E AOGCC DATA TRANSMITTAL October 14, 2016 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RE: 10-407 for KLU# A2A Kitchen Lights Unit,4G*4de4" Data PTD 216- -086 / Sundry 316-387 Dear AOGCC: 21 6086 27645 (l�l-1it'`c't-01p yyZZ✓1 % �� IV(r "11gh6 Enclosed is the 10-407 for KLU #A2A with attached wellbore diagram, daily well operations summary, directional survey, and casing/cement reports. A package with the LWD Triple Combo Logs, MD and TVD in 1:600 and 1:240 scale Is also being shipped. Also included in the package are the USIT/ CBL, the sump packer setting correlation run, and the mud logs in TVD and MD. Enclosed is a flash drive with each log electronically and a sepia of the triple combo. The hydraulic fracturing information is attached and submitted electronically on the flash drive. Furie Operating Alaska, LLC hereby transmits to you the above data and reports pursuant to our obligations to you under Permit to Drill No. 216-086. Furie Operating Alaska, LLC requests that the data and reports be held C -o l as marked on the attached and listed above, in accordance with AS ,31.05.035 and 20 AAC.25.537. P1 1 Please signify that you have received and accepted this data by stamping and returning a copy of this P � letter to me at the Lafayette address or by emailing me a copy to D.mccraine@furiealaska.com. If you have questions, please feel free to contact me at 337-981-0270 Sincerely, GUUU��iU David McCraine (/ t'iC w ' �. 10/2,16 /1/ Furie Operating Alaska, LLC ` 10 Drilling Engineer Xx6nvl-c Furie Operating Alaska LLC 14906 Ambassador Caffery Pkwy Suite #800 1 Lafayette, LA 1 70508 1 Office 337-806-9021 00-0 FURIE Operating Alaska LLC DATA TRANSMITTAL e"NT11YENqff A+— October 14, 2016 Alaska Oil and Gas Conservation Commission 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 RECEIVED OCT 17 2016 AOGCC RE: 10-407 for KLU# A2A Kitchen Lights Unit, Confidential Data PTD 216- -086 / Sundry 316-387 Dear AOGCC: Enclosed is the 10-407 for KLU #A2A with attached wellbore diagram, daily well operations summary, directional survey, and casing/cement reports. A package with the LWD Triple Combo Logs, MD and TVD in 1:600 and 1:240 scale Is also being shipped. Also included in the package are the USIT/ CBL, the sump packer setting correlation run, and the mud logs in TVD and MD. Enclosed is a flash drive with each log electronically and a sepia of the triple combo. The hydraulic fracturing information is attached and submitted electronically on the flash drive. Furie Operating Alaska, LLC hereby transmits to you the above data and reports pursuant to our obligations to you under Permit to Drill No. 216-086. Furie Operating Alaska, LLC requests that the data and reports be held Confidential, as marked on the attached and listed above, in accordance with AS 31.05.035 and 20 AAC.25.537. Please signify that you have received and accepted this data by stamping and returning a copy of this letter to me at the Lafayette address or by emailing me a copy to D.mccraine@furiealaska.com. If you have questions, please feel free to contact me at 337-981-0270. Sincerely, UUP-�t' David McCraine Furie Operating Alaska, LLC Drilling Engineer Furie Operating Alaska LLC 14906 Ambassador Caffery Pkwy Suite #800 1 Lafayette, LA 170508 1 Office 337-806-9021 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION RECEIVED OCT 17 2016 WELL COMPLETION OR RECOMPLETION REPORT AN 1a. Well Status: Oil LJ Gas X + SPLUG ❑ Other LJ Abandoned LJ SuspendedLJ 20AAC 25.105 20AAC 25.110 1b. Well Class: Development ®. Exploratory GINJ M WINJ WAG M WDSPL No. of Completions: _ 4 Service 11 Stratigraphic Test 2. Operator Name: Furie Operating Alaska, LLC 6. Date Comp., Susp., or Aband.: Comp 09/08/201 14. Permit to Drill Number / Sundry: P 216-086/316-387✓ 3. Address 4906 Ambassador Caffery Pkwy, Ste 800 7. Date Spudded: 15. API Number: Lafayette, LA 70508 7/9/16 50-733-20655-01-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 895.93 FWL& 343.48FSL; T10N;R11W; Sec 24 COMPLETION Top of Productive Interval: DATE 2623.74 FWL & 2047.72' FSL; T10N, R11 W, Sec 24 91$%ItP 7/13/16 Kitchen Lights Unit #A -2A 9. Ref Elevations: KB: 107' GL: BF: 17. Field / Pool(s): Kitchen Lights Unit - _ Total Depth: VERIFIED 2035.34FEL & 2534.7 FSL; T10N : R11 W: Sec 24 10. Plug Back Depth MD/TVD: 8041' MD/ 7197' TVD 18. Property Designation: ADL 389197 4b. Location of Well (State Base Plane Coordinates, NAD 27): -- --- 11. Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 294,331.49 y- 2,536,125.62 Zone- 4 8160'MD/ 7301' ND TPI: x- 296,088.46 y- 2,537,799.38 Zone- 4 12. SSSV Depth MD/ND: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 296717.41 y- 2538275.44 Zone- 4 8057'MD/ 7195' TVD 5. Directional or Inclination Survey: Yes (a ed) No LJ Submit electronic and printed information per 20 AAC 25.050 13. Water Depth, if Offshore: 107' (ft MSL) 21. Re-drill/Lateral Top Window MD/TVD: 2-328 / ZCp 3 (' ' J' 7 22. Logs Obtained: List all logs run and, pursuant to AS 31.05.030 and 20 AAC 25.071, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Types of logs to be listed include, but are not limited to: mud log, spontaneous potential, gamma ray, caliper, resistivity, porosity, magnetic resonance, dipmeter, formation tester, temperature, cement evaluation, casing collar locator, jewelry, and perforation record. Acronyms may be used. Attach a separate page if necessary USIT/ CBL LWD- (Triple ComboO Multiple Propogation Res Compensated Neutron Porosity Compensated Bulk Density, GR f/ 2284'- 8110'; 1;240 scale ND & MD, and 1:600 scale TVD & MD Mud Logs --Formation Log, Gas Ratio Log, Drilin Dynamics Log, and LWD Combo Lithology Log. Md & ND Sump packer correlation strip. 23. CASING, LINER AND CEMENTING RECORD WT. PER SETTING DEPTH MD SETTING DEPTH ND CASING GRADE HOLE SIZE AMOUNT FT TOP BOTTOM TOP BOTTOM CEMENTING RECORD PULLED 20" 94# X-56 0' 376' 0 376' Driven NA 0 13 /375" 72# N-80 0 2265' 0 1985' 17.5" Lead -900 sks-12.3 ppg & 2.33 Cu 0 Tail -411 sks-15.6 ppg & 1.19 Cu ft 9 5/8' 53.5 L-80 0 8122 0 7267 12.25 Lead -1255 sks-13.5 ppg & 1.76 C 0 Tail -526 sks-15.8 ppg & 1.19 Cu fl 24. Open to production or injection? Yes No H 25. TUBING RECORD If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4 1/2" 4565 3933 Lwr Beluga Perf: 6873'- 6701'M: 5950'- 5971' ND; 15 SPF .83' diamater holes 3 1/2" 6711 5980 Upper Beluga Perf: 6127'- 6246' MD: 5773'- 5867' ND; 15 SPF .83' diamater holes. 26. . Upper Beluga sleeves closed Was hydraulic fracturing used during completion? Yes No IN El Lwr Sterling Perf: 5395' - 5486' MD: 4732' -4819' TVD; 15 SPF .83' diamater holes. Sleeves closed -future completion. Frac packed with 74,379# Econoprop 30/50. Per 20 AAC 25.283 (i)(2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNTAND KIND OF MATERIAL USED Upper Sterling Perf: 4735'- 4803' MD: 4095'- 4160' ND; 15 SPF .83' diamater holes. Sleeves closed, fuure completion. Frac packed w/ 74893# Econoprop 30/50 6679'-6918 29,136# Econoprop 30/50 6127'- 6276' 58,100# Econoprop 30/50 27. PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): 9/13/16 FIOWIn Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: 9/13/16 2 Test Period 0 15254 437.83 3.58 46 NA Flow Tubing 461 Casing Press: 0 Calculated 24 -Hour Rate Oil -Bbl: 0 Gas -MCF: Water -Bbl: 43 Oil Gravity - API (corr): NA im Form 10-407 Revised 11/2015 CONTINUED ON PAGE 2 Submit ORIGINIAL only RBDMS OCT 19 2016 <' 28. CORE DATA Conventional Core(s): Yes ❑ No ® Sidewall Cores: Yes Do If Yes, list formations and intervals cored (MD/TVD, From/To), and summarize lithology and presence of oil, gas or water (submit separate pages with this form, if needed). Submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results per 20 AAC 25.071. 29. GEOLOGIC MARKERS (List all formations and markers encountered): 30. FORMATION TESTS NAME MD TVD Well tested? Yes 130 If yes, list intervals and formations tested, briefly summarizing test results. Attach Permafrost - Top NA Permafrost - Base NA separate pages to this form, if needed, and submit detailed test information, including Top of Productive Interval 4735' 4095' reports, per 20 AAC 25.071. Sterling 3595 3019 Beluga 5,720 5,050 Formation at total depth: 31. List of Attachments: Summary of Daily reports; Wellbore Schematic, Directional Survey; Cement Report Information to be attached includes, but is not limited to: summary of daily operations, wellbore schematic, directional or inclination survey, core analysis, paleontological report, production or well test results per 20 AAC 25.070. 32. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Contact: David McCraine Email: d.mccraine furiealaska.com Printed Name: �.r/ LC Title: Drilling Engineer c/ Signature: c riy/�,y Phone: 337-981-0270 Date: 10/14/16 INSTRUCTIONS General: This form and the required attachments provide a complete and concise record for each well drilled in Alaska. Submit a well schematic diagram with each 10- 407 well completion report and 10-404 well sundry report when the downhole well design is changed. All laboratory analytical reports regarding samples or tests from a well must be submitted to the AOGCC, no matter when the analyses are conducted. Item 1a: Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 1b: Well Class - Service wells: Gas Injection, Water Injection, Water -Alternating -Gas Injection, Salt Water Disposal, Water Supply for Injection, Observation, or Other. Item 4b: TPI (Top of Producing Interval). Item 9: The Kelly Bushing, Ground Level, and Base Flange elevations in feet above Mean Sea Level. Use same as reference for depth measurements given in other spaces on this form and in any attachments. Item 15: The API number reported to AOGCC must be 14 digits (ex: 50-029-20123-00-00). Item 20: Report measured depth and true vertical thickness of permafrost. Provide MD and TVD for the top and base of permafrost in Box 29. Item 22: Review the reporting requirements of 20 AAC 25.071 and, pursuant to AS 31.05.030, submit all electronic data and printed logs within 90 days of completion, suspension, or abandonment, whichever occurs first. Item 23: Attached supplemental records should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval (multiple completion), so state in item 1, and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27: Method of Operation: Flowing, Gas Lift, Rod Pump, Hydraulic Pump, Submersible, Water Injection, Gas Injection, Shut-in, or Other (explain). Item 28: Provide a listing of intervals cored and the corresponding formations, and a brief description in this box. Pursuant to 20 AAC 25.071, submit detailed descriptions, core chips, photographs, and all subsequent laboratory analytical results, including, but not limited to: porosity, permeability, fluid saturation, fluid composition, fluid fluorescence, vitrinite reflectance, geochemical, or paleontology. Item 30: Provide a listing of intervals tested and the corresponding formation, and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Item 31: Pursuant to 20 AAC 25.070, attach to this form: well schematic diagram, summary of daily well operations, directional or inclination survey, and other tests as required including, but not limited to: core analysis, paleontological report, production or well test results. Form 10-407 Revised 11/2015 Submit ORIGINAL Only Furie Operating Alaska Kitchen Lights Unit #A -2A Condor Sidetrack RKB-CHF: 52.4' RKB - ML: 225' Chemical Injection Mandrel @ 1641' SCSSV (Self Equalizing) @ 1653' 3.813"X@4,515' Upper Sterling - Perfs 4735-4803' MD (4095-4160' TVD) Est BHP=1712 psi; BHT= 90 deg F Lower Sterling - Perfs 5395-5486' MD (4732-4819' TVD) BHP=2104 psi; BHT= 90 deg F 7 10.4 ppg NaBrCI/6% KCI Packer Fluid 2.813" X @ 5,951' MD Upper Beluga Perfs 6127-6276' MD (5773-5867' TVD) BHP=2398 psi; BHT= 108 deg F Beluga Perfs 6679-6701' MD (5950-5971' TVD) BHP=2573 psi; BHT= 109 deg F Possible Future TTRC: Lower Beluga Perfs 6873-6918' MD (6132-6173' TVD) BHP=2902 psi; BHT= 111 deg F Possible Future TTRC: Lower Beluga Perfs 7168-7274' MD (6405-6503' TVD) BHP=3060 psi; BHT= 114 deg F TD: 8,160' MD/7,301' TVD As -Built 07Sept16 I<L4 A -zA 20" 0.875" @ 381' MD 1WB 075ept15 Tubing above SCSSV equipped with non-conductive centralizers 9.7 ppg NaBrCI/6% KCI Packer Fluid 13-3/8" 72# @ 2,265' MD 4-1/2"" 12.75# L-80 CSCE IPC Tubing Isolation Packer @ 4,565' MD End of Tubing/Seal Assembly at 4,580' MD 3-1/2" L-80 BTS -8 Isolation Pipe 2.813" Iso Sleeves (4696'& 4806') CLOSED 5-1/2" 20# P-110 Blank and 0.008" Ga 316L Wire Wrapped Screen Gravel Pack Packer @ 4,814' MD 3-1/2" L-80 BTS -B Isolation Pipe 2.813" Iso Sleeves (5348'& 5490') CLOSED 5-1/2" 20# P-110 Blank and 0.008" Ga 316L Wire Wrapped Screen Isolation Packer @ 5,497' MD Gravel Pack Packer @6000' MD 3-1/2" L-80 BTS -8 Isolation Pipe 2.813" Iso Sleeves (6106'& 6279') CLOSED 5-1/2" 20# P-110 Blank and 0.008" Ga 316L Wire Wrapped Screen Gravel Pack Packer @ 6,286' MD 3-1/2" L-80 BTS -8 Isolation Pipe 2.813" Iso Sleeves (6624'& 6703') OPENED 5-1/2" 20# P-110 Blank and 0.008" Ga 316L Wire Wrapped Screen Sump Packer @ 6711' MD Mule Shoe (end of Iso Assy) @ 6731' MD PBTD - 8,041' MD/7,197' TVD 9-5/8" 53.3# P-110 BTC Mod @8,122' MD/7,268' TVD I �iw ; t,5/ Day Date KLU A2A DRILLING & COMPLETION OPERATIONAL SUMMARY 1 7/9/16 L/D 3 12/" DP, PU 12 1/4" Directional BHA,TIH tag cmt @ 2278", Drill slide & Svy f 2278'- 3062' 2 7/10/16 Drill, Slide, & Svy f/3062'-3163', replace liner pump #2, Drill, Slide, & Svy f/ 3163'- 3355', wiper trip f/ 3355'- 2209', TIH to 3355', Drill, Slide, & Svy 3355'- 4421', sweeping hole every 200'w/ HVP. 3 7/11/16 Drill, Slide, & Svy f/4421'- 5869'w/690 gpm-2400 psi,TD rpm 80, MM rpm 152, WOB 10K, torq 12-15k, diff/pressure 150 psi ; sweeping hole w/ 30 bbl hi -vis pills every 200', Flow check each connection. 4 7/12/16 Drill & Svy f/ 5869' - 7323'w/690 gpm-2800 psi,TD rpm 100, MM rpm 152, WOB 12K, torq 20-25k, diff/pressure 200 psi; sweeping hole w/ 30 bbl hi -vis pills every 200', pumped weighted sweep @ 6656'w/10% increase in cuttings. Flow check each connection. 5 7/13/16 Drill and survey to 8160'. TD. CCHC @ 8160', Circ and condition. Backream first 3 stands out of hole f/8160' - 8076' @ 30/min a stand (/8160-7892'. POOH f/ 7892'- 7597', pulling 25-30K over, Pulled tight @ 7597 with 70K, hole swabbing, GIH to 7607. Backream out of hole 7607 7200'. 6 7/14/16 Backream f/ 7607'- 4250', L/D stand #35, washout in single & double TJ. 7 7/15/16 Backream OOH 4250'- 2395', CCHC, POOH L/D Baker Directional assy. 8 7/16/16 L/D H/O assy, install 9 5/8" csg rams, install test plug, run 9 5/8" csg ram test assy, test casing rams w/ H2O to 280 psi/ 2660 psi high. R/D test equipment, Rigging up casing equipment. 9 7/17/16 Ran 208 jts 9 5/8", 53.5#, L-80 BTC -RS Casing to 8122' MD w/ returns to 3722' and no returns f/ 3722' - 8122'. Attempt to establish circulation no success. RU cement head 10 7/18/16 Pump Lead / Tail primary cmt as per procedure, displace same, bump plug, BPVs held, test csg 3500 psi on 30 min. chart, L/D landing jts, install/ test pack -off 5000 psi, remove 9 5/8" csg rams, install 2 5/8" x 5" VBRs, clean solids & cmt f/ trip tank, wash & flush flowline, GIH w/ 5" DP, POOH L/D same. 11 7/19/16 L/D 5" DP, Pull wear bushing, N/D BOPs, L/D riser, NU 13 5/8 x 4 1/16" dry hole tree, RU Expro E -line equipment & lubricator. 12 7/20/16 R/U Expro Eline Spread & lubricator, Test lubricator, perform CBL from 7896'- 1500': TOC 6650', perform CBL w/ 1000 psi from 8000'- 1500': TOC 6635' ELM, RD Eline equipment. Remove diverter linees from platform, prepare rig to skid. CBL was corrupted and data is invalid. 13 7/25/16 Skid rig f/ KLU #3 to KLU #A2A. Service top drive and change out saver sub, dress shale shakers, rearrange pipe rack, performing general rig maintenance. 14 7/26/16 Install KLU #3 flowline. Offload & P/U 200 jts. 4" XT -39, 14#, S-135, IPC drill pipe racking back in derrick. Clear rig floor. Offload SLB E -line spread, spot same on upper cantilever. 15 7/27/16 Offload & & spot SLB e -line, MU grease head t/ pump in sub, R/U SLB ELU. Run SLB CBL. 16 7/28/16 R/D SLB e -line, N/U 13 5/8" riser, BOPs, accumulator lines, choke & kill lines, bell nipple and install zero discharge. P/U drift make-up & rack back 60 jts 4", XT -39, 14 ppf drill pipe, RU & test 4" DP to 200 psi - 3500 psi w/ H2O as per AOGCC, perform accumulator draw down test, R/D test assy. 17 7/29/16 L/D 4" test assy, Slip & Cut drill line, function. Strap brush & scraper assys, PU 8 1/2" bit, brush/scraper assys, GIH to 7954', tagged up w/ 10K dwn, wash f/ 7954'- 7966'. Displace hole as per MI procedure, 18 7/30/16 GIH f/ 6783't/ 7954', R/U & reverse -out 2 tubing volumes w/ 9.8 ppg KCL/NaCL, no solids returned at surface. POOH 1 std, R/U test csg 4000 psi in preparation for TCP opts, R/D test iron. WOW to subside. 19 7/31/16 WOW Offload pallet material. Filter 9.8 ppg completion fluid. Build 9.8 ppg completion Fluid. Clean DE press and back load 431 bbl trash fluid to MN Soveriegn. Circulate and filter 9.8 ppg NaCl/KCL fluid until NTU's reached 18. DE press plugged up.Clean DE press and build volume. 20 8/1/16 Cir. & filter. POOH. L/D clean out assembly. R/U Schlumberger E -line, set sump pkr. R/D E -line. Prep rig for frac work. Monitor well. 21 8/2/16 Waiting for approval for variance on air emissions permit. Off loading frac equipment and spot same on deck. R/U frac pump/engine. Pull wear bushing. P/U Bop test assembly. Move cutting boxes. Continue to offload & R/U frac equipment. Offload Schlumberger Frac equipment f/ workboats. Spot on deck and 22 8/3/16 start R/U same. M/U test lines, test same 4000 psi. Shell test choke manifold / BOP stack to 250/3500 psi. Test BOP's 250/3500. Repair bonnet fitting leak on choke HCR valve. Retest Pass. Conduct accumulater draw down test - failed. Clean sreens on pumps, retest full recharge 138 seconds - Pass. Lower manual IBOP unable to close - grease and function same. Test 250/3500 psi. Good test. R/D test assembly. Run wear bushing. 23 8/4/16 P/U TPC.TIH. Snap in/out sump packer. Space out. R/U test surface equipt. Fire TPC guns. Perforate Beluga 6679'-6701'. Well static. Rev out above packer 2 drill pipe volumes. Open bypass, 1/4 bbl/hr losses. Close packer bypass. Reverse cir. 2 drill pipe volumes. No fluid loss. Monitor well static. R/D surface equipment. Start POOH. 24 8/5/16 POOH t/ 3112'. Circulate well out on open choke. Static. Con't POOH t/ 1160'. Circulate out. Con't POOH & L/D TPC gun assembly. PJSM. P/U & M/U frac pack assembly. TIH w/ same. 3 mins. Per/stand. 25 8/6/16 TIH w/ 4" drill pipe and frac pack assembly f/ 5934't/ 6708' land locator in sump packer. Drop 2 1/8" steel setting ball.Test lines 6000 psi. Set packer observe sheer @ 1200 psi & 2600 psi. Push/Pull test. Relaese setting tool w/1500 psi.Pump 13 bbls MI pickle down DP displace w/50.5 bbls 9.8# fluid. Reverse out same. SLB test fluids. Transfer contaminated 8.6 KCL fluid to ISO on boats. 26 8/7/16 Transfer 480 bbls of 8.6# - 6% KCL contaminated fluid to MN Perseverance ISO tanks. Transfer 220 bbls of 8.6# - KCL contaminated fluid to MN Sovereign. Back load two 400 bbl tanks to MN Sovereign. Stand by at dock to load clean tanks for 07:30 am. 27 8/8/16 Monitor well on trip tank, static. Waiting on 400 bbl liquid tanks required for frac job to replace tanks sent in. MN Sovereign stand by to off load 400 bbl tanks. Weather SW Winds 20-25 mpn, seas 2-4'. Production and Rig crane operators have safety concerns off loading tanks in hig winds. WOW 28 8/9/16 Monitor well on trip tank - static. Repair stairway to production deck. Function Superior service tool. Off load 400 bbl tanks and rig up. Filter 8.6# - 6% KCL fluid to frac tanks. Gel up fluid and start lab test. 29 8/10/16 Pump 8.6# - 6% KCL fluid to 400 bbl tank. PJSM flush surface lines test same to 7000 psi. Establish cir psi 1 &2 bpm. Strip test. Pump & spot mini frac displace with slick water. Step rate test as per procedure. Perform frac job as per redesign. Induce sand out. Obtain screen out @ 3532 psi. P/U rev. clean 3 DP volumes. Test sleeve. POOH, retrieve wear bushing & R/U to test BOPs. 30 8/11/16 Test BOPs on 4" DP and all related equipment to 200 psi - 3500 psi, TIH V 6283'. Set plug in gp packer , shear out, space out to put guns on depth, set perforating packer 6049', R/U mainfold test 5k, fire guns. Monitor dp pressure increase t/ 240 psi, then dropped to 90 psi & increased to 165 psi. 31 8/12/16 SIDPP-260 psi bleed off open circ valve & reverse clean above TCP pkr. Gas fluid out 9.7#. Close circ valve open ball valve & monitor static, climbed to 410 psi in 1 hour. Close ball valve above pkr. Bleed DP to 0 psi. All gas. Rev clean. Some gas & gas cut fluid. Rev out 2 dp volumes. Close circ valve, open ball valve. Open bypass & rev. through open choke. Cleaned up. Close bypass monitor, slight flow, 20 psi 5 min, 30 psi 20 mins. dropped to 23 psi. Rev 2 dp vol. some gas in 1st B/U. Weight up to 10.4# NaBr/CI-6% KCI. Rev total hole volume w/10.4#. 32 8/13/16 Weight up to 10.4# NaBR/Nacl - 6% KCL & Filter same. Rev out above pkr. Rev out through bypass below pkr. No gas. Clean filter unit. Release pkr circ surface to surface. POOH 3 stds Monitor 30 mins static. TIH to btm perfs 6,276' no fill. Trip drill. Cir 2 B/U no losses and no gas. POOH w/10 stands. Monitor for 1 hr. POOH to 2982'. Monitor and circulate out. No gas. Finish POOH. Start to L/D TCP assembly. 33 8/14/16 Con't to L/D Perf guns, all shots fired. Service rig. P/U Packer plug retrieving tool & TIH. Obtain circ pressures. Spot 10 bbl HEC pill. Rev out clean. While circ. recoveredram block rubber seal over shaker. POOH 3 stds, retrieve wear bushing, set test plug with safety valve below test plug. PJSM monitor well at casing valve static. Open blind rams close same. Open rams close same. Open top rams close same. All ram seals in place and bonnet seals. Shell test against hydrill 250/3500 psi 5/mins each test w/water. Pull test plug. TIH to 3 stds. Circ 10 bbls, rev out dp capacity @ 5 bpm w/ 370psi. Set 10k down, P/U shear packer plug @ 35k over. Circ 2.5 bpm to confirm plug retrieved. Hold 5 mins. POOH above top perfs, monitor well 15 mins static. POOH L/D plug retrieving tool w/ plug. Install wear bushing. 34 8/15/16 R/U tongs & equipment. PJSM P/U & GIH w/ frac pack assembly. Clear rig floor of tongs & equipment. TIH on 4" dp with frac pack assembly, drift dp. P/U frac head. Snap in pkr w/20k down, snap out w/25k. Tagged PKR @ 6283 dpm. R/U manifold break circ with SLB cmt unit. Drop 2- 1/8" steel ball, test lines to 6000 psi. Pressure up t/2600 psi & set packer @ 5996 dpm. Push/Pull test. Release running tool.Establish rev/circ positions. Blow ball seat @ 4255 psi. Test lines 8000 psi.Strip test. Pump 180 bbls mini-frac, perform step rate test, rev out. Redesign frac. Rev out. Perform frac job, screen out @ 2,004 psi. Attempt to shift to rev positon, tool stuck, work same free, rev out 2 dp volumes. R/D manifold, well static. 35 8/16/16 Dump seals, well static.L/D frac head. Test sieve w/ 500 psi 10 mins. Good test. POOH f/ 6283' to wash pipe, L/D same. Service rig. P/U & TIH w/ isolation pkr assembly. Tagged 5996', snap in/out 30k over. Drop ball Set packer 900 psi, 2nd shear @ 2500 psi Packer set at 5494'. Test 1500 psi. POOH f/5494', L/D running tools. Clear rig floor and service rig. M/U packer plug, guns TCP packer. 36 8/17/16 P/U TCP TIH t/ 5494' tag isolation pkr. Set pkr plug. R/U E line lubricator & run correlation log, R/D same. R/Uand perforate 5395'- 5486' @ 15 SPF. Well on vaccum, close tester valve. Cycle circ valve reverse above pkr 2 dp volumes. Open pkr bypass losses 40bph, 12 bph & stablized @ 6 bph. Mix HEC pill, well started to flow, shut in on annular. Circ out with rig pump. Small abount of gas at surface. Pump 10 bbl HEC pill & spot in dp/csg.Montior on trip tank 6 bph down to 4 bph. Unseat packer R/D surface iron, 1.8 bph losses. POOH 2 stds 1.3 bph losses. POOH 37 8/18/16 POOH w TCP, Circ,POOH. TIH w/ packer plug retrieving tool,Estb circ rates, pump pill. Tag plug, reverse out, shear plug & pull same. L/O TIW, Monitor well 1.4 bph losses, POOH , L/D plug & retrieving tool.PJSM, R/U handling tools, P/U Frac pack BHA, R/D handling tools. 38 8/19/16 TIH f/ 709' to 5340', M/U Frac head. TIH t/ 5494' snap in isolation packer, 30k down. R/U SLB Frac iron. Set packer @ 4811'. Push/Pull test w/60k over pull. Release running tool, blow ball seat w/. 4200psi. Pump pickle, spot, reverse out same. Reverse out. cut fluid weight f/10.4# t/9.7# NaBR 6% KCL. PJSM Flush lines test to 3k & 7k psi. Estb circ rates. Perform mini-frac, attempt to shift to reverse position. Unable to shift to reverse position. Rotate drill pipe to release from packer. Rev out, P/U, test sleeves, good test. POOH, P/U, B/U tool. TIH. 39 8/20/16 Con't TIH w/ Superior back running tool, M/U iron, test same, perform frac pack, reverse out, R/D iron, test sleeves, good test. POOH L/D back up running tool. Pull wear bushing, R/U & Test BOPs. Perform accumulator draw down test. R/D Test equipment, pull test plug. 40 8/21/16 Run W/B, P/U TCP TIH t/ 4810'. Correlate TCP guns on depth. Set packer and perforate well. Rev out 2 drill pipe volumes. Monitor losses,7.2 bph, spot HEC pill. Unseat packer. R/D TCP head, manifold & iron. POOH 1 std. Well slight flow on back side. Circ out open choke & POOH. 41 8/22/16 POOH w/ TCP guns & packer. TIH w/ packer plug retrieving tool, circ, latch plug & POOH w/ same. P/U Frac pack assembly for Upper Sterling Zone, TIH t/ 4783', space out, snap in/out. Test lines 5000 psi, drop ball, set packer @ 4591' DPM. 42 8/23/16 Trouble shoot SLB frac pump comms. Flush & test lines 7000k, Perform mini frac, redesign. Pumps frac as per redesign. Attempt to shift tool to reverse position no success. Work pipe no success. R/U E -line make gauge ring run, tubing punch run guns did not fire. 43 8/24/16 L/D TBG punch, did not fire, M/U new TBG punch shoot holes 4,150'- 4,153'. POOH. GIH w/ RCT cut 4" DP @ 4,149', POOH R/D E -line, R/D lubricator. TIH w/ over shot & POOH w/ fish. Service Rig & Slip and cut drill line. Make 2 attempts to cut 4" DP, no success. 44 8/25/16 Trouble shoot Wire Line tool. Run #3 determined to be cancelled. R/D wire line, Release O/S, POOH. Service rig. M/U fishing BHA, TIH polish off 4", POOH, L/D Magnostar magnet. M/U pack -off and grapple. TIH t/ 4152' work over fish t/ 4161'. Test 300 psi good, R/U Coil tubing 45 8/26/16 R/U 1-1/2" Coil tubing, start testing BOPs, trouble shoot weight indicator, finish testing coil BOPs. Repair injector head weight indicator. Performed push / pull test. Test connection and iron 4,500 psi. Washing and circulating as needed t/4350' 46 8/27/16 Wash with coil tubing t/4611' coil depth. Circ, S/T with coil, Circ B/U, POOH w/ coil tubing & R/D same. Jar on fish, test sleeves, POOH w/ 4" drill pipe. 47 8/28/16 Redress over shot with new 4" grapple & pack off. TIH 4132', obtain parameters, TIH to 4152' work over fish. Jar on fish. No success moving fish. POOH redress grapple and pack off. Change out jars. TIH T/ 4152', P/U to space out, jar on fish. 48 8/29/16 Con't space out, Jar DN W/45k, R/U E -line & GIH W/2' string shot & CCL tool failed, POOH and change out CCL, GIH W/ 2' string shot and CCL. Turn 4" DP to left 1/2 round work torque down, Con't to turn drill pipe a total of 13 rounds left. W/ 7200 ft/lbs. Conference call agreement to make pipe back up to right 12.75 rounds, attempt to back out R/T, First attempt shot failed, second attempt shot low order fire, third attempt shot fired no back off. 49 8/30/16 Make back off with 19 rounds left hand rotation. POOH with packer setting tool, extension, ported sub and seal mandrel. P/U packer retrieve[ tool & TIH tag packer, latch packer, open unloader valve, work packer free. POOH close MSV -0 valve,POOH T/4426' working pipe up and down to relax packer element. Hole not taking proper fluid. 50 8/31/16 Monitor well, static with no pipe movement. POOH 118' reciprocate pipe, circulate out through open choke. Pressure up to 1,000 psi to 1,400 psi. Bleed off reciproate pipe. Continue to POOH to 3925' pumping fluid below pacer. Circulating as needed. Work pipe to wear packer element. 51 9/1/16 POOH slow W/ gravel pack packer & wash pipe, lay down same. Monitor well static. TIH W/ isolation packer and pack -off. 52 9/2/16 Run and set isolation packer, Circ B/U, POOH L/D drill pipe and drill collars, Wash stack and well head area, pull wear bushing. Test BOPs and all related equipment, 250/3500 psi. 53 9/3/16 Test BOPs, Run 4-1/2" production tubing, land out, P/U space out seals & hanger test SCSSV & CIM. R/U slick line run 2" blind box. 54 9/4/16 Continue slick line 2" blind box T/6711', POOH & M/U 2.813" x test tool GIH T/ 4627'-4638' jar up. POOH L/D X test tool. R/D lubricator, Test tubing to 3000 psi. Good Test. P/U hanger to surface C/O seals, circulate inhibited packer fluid around. Displace 4-1/2" tubing to 3955' & 1470 psi. Sting into packer & land out tubing hanger. Test 5k 15 mins. Test annulus 1500 psi 30 mins. Increase tubing pressure to 2200 psi with nitrogen, Close SCSSV, set BPV & L/D landing string 55 9/5/16 N/D BOPs & 13-5/8" riser. N/U 4-1/16" 5K tree, test same to 5000 psi. Pull dart & BPV. R/U slick line lubricator, R/U Nitrogen lines and choke manifold. Test lubricator to 3000 psi W/ methanol pump. Pressure up to 2200 psi down 4-1/2" tubing. Open SCSSV. Slick line w/ 2.50", 2.75" wire brush, retrieving gravel packer elements. 56 9/6/16 Continue slick line runs to clean out well bore of debris. GIH w/ 2.5" 3 prong wire grab and recover rubber debris. Make 2.75" GR run to 6724', sump packer and POOH. 57 9/7/16 GIH W/2.813" Shift tool T/6703' unable to open bottom sleeve. PU to 6624' unable to open bottom sleeve. Open sleeve @ 6624' drop down & open sleeve @ 6703' no change in tubing press. POOH, shift tool in opening pos. Open well on 1/4 choke returning fluid @ 200psi. bled back @ 45.9 bbls @ .7 bpm. Shut in well W/FTP 400psi. increased T/1400psi in 15 min. 58 9/8/16 Close valves on tree. N/D lubricator from tree. SCSSV holding. Prepare rig for demob 59 9/9/16 Rig prep. WOO 60 9/10/16 Rig prep. WOO 61 9/11/16 Rig prep. Monitor and troubleshoot SCSSV issues. Ensuring well will flow. 62 9/12/16 Rig prep. Monitor and troubleshoot SCSSV issues. Ensuring well will flow. 63 9/13/16 Rig prep. R/U SLB Nitrogen unit. Pressure up T/ 1300psi. 550 SCF per minute. Increase T/ 800 SCF per minute. At 2200 psi SCSSV open, verify W/ Slickline. pressure gradually increased to 2950 psi @ 13:20 hrs. R/D Nitrogen & flow well. 64 9/14/16 GR to 6580' SLM,6620 MD ( Sleeves @ 6624'& 6703' MD), POOH, GIH w/ 1.25" BHP gauge assy to 6612 SLM / 6664' MD, take 15 minute BHP reading, POOH taking 5 minute pressure readings at 1000' intervals on TOOH to surface. Close crown valve bleed off lubricator,unstab same, BHP Guage assy was lost in hole. Continue monitor & flowing A2A. Ensuring well is flowing. 65 9/15/16 Rig prep. Monitor and ensure A2A well flowing. P/U 1.5" JDC pulling tool. M/U & test Lubricator t/2500 psi. GIH w/ JDC pulling tool T/ 6680' SLM, 6732 MD. POOH. RD & remove JDC tool, no fish recovery, Monitor and ensure A2A well flowing. 66 9/16/16 Rig prep. Monitor and ensure A2A well flowing. 67 9/17/16 Rig prep. Monitor and ensure A2A well flowing. 68 9/18/16 Rig prep. Monitor and ensure A2A well flowing. 69 9/19/16 Rig prep. Monitor and ensure A2A well flowing. 70 9/20/16 Rig prep. Monitor and ensure A2A well flowing. 71 9/21/16 Rig prep. Monitor and ensure A2A well flowing. 72 9/22/16 Rig prep. Monitor and ensure A2A well flowing. 73 9/23/161 Rig prep. Monitor and ensure A2A well flowing. Final report. - incl Page 1 of 2 Page 2 of 2 BRIE OPERATING ALASKA, LLC CASING AND CEMENTING DETAIL CASfNG/LINER SIZE: 9-5/8" IN. CASING TYPE: 53.5#, L-80, BTC SET @ 8122 MD 7267 TVD DATE: 7/18/16 (CSG ON BTM) WELL INFORMATION AREA: Kitchens Lights Unit BLK: KLU MLLW 121 WELL # KLU A2A HOLE SIZE: 12.25 TOTAL DEPTH: 8160 MD 7301 TVD WATER DEPTH: 108 LAST CASING STRING: 9.625 IN. SET @ 8122 MD 7268 TVD RKB - Water: 121 RKB - ML: 225 LOG OF CASING/LINER STRING (BEGIN @ BOTTOM, LIST ITEMS IN ORDER RUN) # OF PIECES O.D. ITEM -.MAKE - DESCRIPTION #/FT THRD GRADE MAKE-UP LENGTH I DEPTH RKB TO TOP 1 9.625 Casing Shoe 979.37 BTC 232 1.53 8120.47 1 9.625 Float Shoe Joint 53.5# BTC L-80 39.15 8081.32 1 9.625 Casing Joint 53.5# BTC L-80 40.34 8040.98 1 9.625 Float Collar BTC 1.25 8039.73 1 9.625 Float Collar Joint 53.5# BTC L-80 37.62 8002.11 1 9.625 188 Casing Joints 53.5# BTC L-80 3481.29 4520.82 1 9.625 Pup Joint (Marker Jt) 53.5# BTC L-80 20.21 4500.61 1 9.625 119 Casing Joints 53.5# BTC L-80 4450.21 50.40 1 9.625 Hanger 2.75 47.65 1 9.625 Landing jt 53.5# L-80 37.70 9.95 1 9.625 Landing Pup Joint 53.5# L-80 20.21 -10.26 CASING INVENTORY JTS LENGTH TOTAL LENGTH OF STRING 207 8132.26 SUBTRACT NON -CASING ITEMS 1.76 5.53 ADD FULL JTS LEFT OUT 25 979.37 TOTAL 232 9106.10 TOTAL CSG DELIVERED W/O THRDS 9106.10 CEMENTING DETAILS TOTAL LENGTH OF STRING 1 8132.26 -- SUBTRACT CUT-OFF & LANDING JTS 64.91 ADD KB TO CUT-OFF LENGTH 54.94 CASING/LINER SETTING DEPTH 8122.29 -------------------------------------- CEMENTING COMPANY: Schlumberger STAGE # OF SX WEIGHT YIELD FT CEMENT TYPE &ADDITIVES 1 526 13.5 1.76 926 Class "G" w/ 0.20 gps D-47, 0.12 gps D-75, 0.12 gps D145A, 0.60 gps D168. 2 1255 15.8 1.19 1255 Class G w/.20 D-47_20 gps D -145A, .30 gps D-168 1 Solid Body on every joint from 6376'- 6027' 1 Solid Body on a ery joint from 4903'- 4628' CENTALIZER PLACEMENT MAKE TYPE NO. PLACEMENT Davis Lynch Bow Spring 10 1 Bow spring centralizer around csg collar f/ 8082' - 7732' Antelope Solid Body 38 1 Solid Body on every joint from 7374' - 6579' 1 Solid Body on every joint from 6376'- 6027' 1 Solid Body on a ery joint from 4903'- 4628' JOB DETAILS TIME CIRC PRIOR TO CEMENTING: 0 HRS. FULL RETURNS THROUGHOUT JOB? (Y/N) N EST. MUD LOSSES: 480+ BBL DISPLACED CEMENT WITH 569 BBL OF 8.6 ppg S/W BUMPED PLUG? (Y/N) Y BUMPED W/ 2700 PSI FLOATS HELD? (Y/N) Y ESTIMATED BBL CEMENT TO SURFACE 0 EST. TOP OF CEMENT ? CIP @ 06:10 HIS Cemented String Wt: N/A Weight Set on Slips: N/A COMMENTS Partial returns during cement job, 89 bbls returned to surface during cementing & displacement. SUPERVISOR(S): James Pritchard / Isaiah Del Toro 8122 MRI (VER. 1.0-�W) FURIE OPERATING ALASKA, LLG CASING AND CEMENTING DETAIL CASING/LINER SIZE: 13-5/8 IN. CASING TYPE: 72#, N-80, BTC #/FT SET @ 2265 MD 1994.57 TVD DATE: 6/25/16 (CSG ON BTM) WELL INFORMATION 1 13.375 Casinq Shoe AREA: Kitchens Lights Unit BLK: KLU MLLW 121 WELL# KLUA-2 HOLE SIZE: 17.5 TOTAL DEPTH: 2284 MD 2205 TVD WATER DEPTH: 108 LAST CASING STRING: 20 IN. SET @ 381 MD 381 TVD RKB - Water: 121 2184.16 1 RKB - ML: 225 LOG OF CASING/LINER STRING (BEGIN @ BOTTOM, LIST ITEMS IN ORDER RUN) 1.83 # OF PIECES O.D. ITEM - MAKE - DESCRIPTION #/FT THRID GRADE MAKE-UP LENGTH DEPTH RKB TO TOP 1 13.375 Casinq Shoe 2836.74 BTC 411 1.88 2263.12 2 13.325 Casing Joints 72 BTC N-80 78.96 2184.16 1 13.375 Float Collar BTC 1.83 2182.33 49 13.325 Casinq Joints 72 BTC N-80 2122.68 59.65 1 13.375 Pup Joint 72 BTC N-80 3.45 56.20 1 18.76 Hanger BTC 1.26 54.94 1 13.375 Landing Joint 72 BTC N-80 39.81 15.13 1 13.375 Pup Joint 72 BTC N-80 25.10 -9.97 CASING INVENTORY JTS LENGTH TOTAL LENGTH OF STRING 2274.97 SUBTRACT NON -CASING ITEMS 4.92 ADD FULL JTS LEFT OUT 15 556.69 TOTAL 0 2826.74 TOTAL CSG DELIVERED (W/O THRDS) 2836.74 CEMENTING DETAILS 10 IAL LENGTH OF STRING 2274.97 --- SUBTRACT CUT-OFF & LANDING JTS 64.91 ADD KB TO CUT-OFF LENGTH 54.94 CASING/LINER SETTING DEPTH 2265.00 ---------------------------------------- CEMENTING COMPANY- Schlumberqer STAGE # OF SX WEIGHT YIELD FT CEMENT TYPE &ADDITIVES 1 900 12.3 2.33 2273 Class G, w/ 0.05 gps D-47 (defoamer), 0.65 gps D-75 (extender) 2 411 15.6 1.19 589 Class G, w/ 0.2 gps D-47 (defoamer), 0.25 gps D-168 (fluid loss), 0.05 gps D-230 dis erant CENTALIZER PLACEMENT MAKE TYPE NO. PLACEMENT Davis Lynch Bow Spring 1 10' above casing shoe with 2 stop collars @ 2255' Antelope Solid Body 27 1 on every joint from 2184' to 1852', every other joint from 1770" to 278" JOB DETAILS TIME CIRC PRIOR TO CEMENTING: HRS. FULL RETURNS THROUGHOUT JOB? (Y/N) Y EST. MUD LOSSES: 0 BBL DISPLACED CEMENT WITH 325 BBL OF 9.4 ppg Mud BUMPED PLUG? (Y/N) Y BUMPED W/ 1500 PSI FLOATS HELD? (Y/N) Y ESTIMATED BBL CEMENT TO SURFACE 120 EST. TOP OF CEMENT 54.94'- wllhead CIP @ 23:00 hrs Cemented String Wt: NA Weight set on slips: NA COMMENTS 35 % excess cement was pumped. 1 hole was oauae. SUPERVISOR(S): James Pritchard / Dale Munger MRI (VER. 1.0-5130109) �< Uk 4--OZA Regg, James B (DOA) From: Brooks, Phoebe L (DOA) Sent: Monday, August 22, 2016 1:19 PM�� To: Furie Drilling Cc: Regg, James B (DOA) Subject: RE: Randolph Yost BOPE Test 8-20-16 Attachments: ADS Randolph Yost 08-20-16.xlsx Attached is a revised report changing the "I" fields to reflect "NA" (based on the quantity 0). Please update your copy. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 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 Phoebe Brooks at 907-793-1242 or phoebe.brooksGalaska.gov. From: Furie Drilling [mai Ito: furie-driIIing()furiealaska.com] Sent: Monday, August 22, 2016 4:52 AM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: John Stuart; Dave McCraine; yost@advanceddrillingsolutions.net Subject: Randolph Yost BOPE Test 8-20-16 Satch Bowe Rig Clerk Randolph Yost Rig 337-804-2513 furie-drilling@furiealaska.com STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: iim.regg c(D"alaska.gov AOGCC.Inspectors(a)•alaska.gov phoebe. brooks(d"alaska.gov Contractor: Advanced Drilling Solutions Rig No.: Randolph Yost DATE: 8/20/2016 Rig Rep.: Joey Beasley/ Mike McCullou(Rig Phone: 907-342-7205 Operator: Furie Operating Alaska Op. Phone: 907-250-1119 Rep.: Clay Clary E -Mail furie-drilling@furiealaska.com Well Name: KLU A -2A PTD # 2160860 Sundry # 316-387 Operation: Test: Test Pressure (psi): Drilling: Initial: Rams: 250/3500 Workover: X Explor.: Weekly: X Bi -Weekly: Annular: 250 / 3500 Valves: 250 / 3500 � MASP: 2201 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES. Test Result Test Result Quantity Test Result Location Gen. P Well Sign P Upper Kelly 1 P Housekeeping P Rig P Lower Kelly 1 P PTD On Location P Hazard Sec. P Ball Type 2 P Standing Order Posted P Misc. NA Inside BOP 1 P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 N/A NA Trip Tank P P Annular Preventer 1 13-5/8" 5M P Pit Level Indicators P P #1 Rams 1 2-7/8 X 5 VBR P Flow Indicator P P #2 Rams 1 Blind Shear FP ✓ Meth Gas Detector P P #3 Rams 1 2-7/8 X 5 VBR P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln. Valves i 4-1/16th 10M P Inside Reel valves 0 NA HCR Valves 2 4-1/16th 10M P - Kill Line Valves 2 4-1/16th 10M P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi) 3000 P CHOKE MANIFOLD: Pressure After Closure (psi) 1860 P Quantity Test Result 200 psi Attained (sec) 35 P No. Valves 18 FP ✓ Full Pressure Attained (sec) 208 P . Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 2 P Nitgn. Bottles # & psi (Avg.): 12 Bottles @ 2100 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 2 Test Time: 8.5 Hours Repair or replacement of equipment will be made within N/A days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Remarks: There is a retest of Test 11, Chart 7. Test failed when testing high, bleed off air and retested. Test passed. There is a retest of Test 3, Chart 2. Test failed when test low, due to over pressure. Bleed off and retested. Test passed. There /is a retest on Test 6, Chart 4. Test failed low & high. Flushed air out of lines and retested. Good Test. There were no leaks or repairs needed for these test to repair for these test to pass the retest. AOGCC Inspection I eSt7 24 hr Notice Yes Date/Time 08-16-16/06:30 Waived By Jim Regg Test Start Date/Time: 8/20/2016 15:30 (date) (time) Witness Test Finish Date/Time: 8/20/2016 23:59 C 6v+ -E Cas IX -LI -C40, Form 10-424 (Revised 11/2015) 2016-0820_BOP_RandolphYost_KLU_A-2A.xlsx 55 60 , Lt hp O BOO —1000 I r 50000 O hp CAR � hnn d, o o MErfR MQ MP_6 p-20 � CA M i --. .. '1 REM�GN TAKeN OFF rt M � OWN a��\\\i- �_.. i oog— p� 000! Op ooSl Op pad . 0002 OOSd 0002 -'--- ooso=-= ooss- 0£' — -- SZ WE 600 --2500- 2500 -- 1500 V o O 0 1000 Z' o •\� .�00 � s° ° - Op O h�° ° �: s ° I y l 1 aO ONv T N0. �M/C�jM"P� tNR. CMART FUr ON i _ s - M TAKEN OFF REMARKS I .a1 " LOCA TION M O /O� O O i 0. CIO 0 con OOS ° ��" o s �\ \ o 00 °° sd \. 000!` o° ` \ \oIr0 _ -oosz 000�-- \� _: — oos� - - _ 000s - t ooss= g2 02 60 0 Total Safety U.S., Inc. Sensor # 2 209 E. 51st Avenue D- :TOTAL SAFETY c��O• Anchorage, AK 99503 ■�;f Phone: (907) 743-9871 y Fax: (907) 743-9872 Calibrated from: Calibrated from: GAS DETECTION SYSTEM TEST SHEET Customer: W11all +i c. —•• Report Date: Date: Time: AFE/Job#: Rig/Location: - Drilling Company: Company Representitive: _ Telephone Number: Total Safety Technician: Current Site Activity: Type of System: Type of Test: Calibration Bump Test Sensor # 1 Sensor # 2 Sensor # 3 Type of Sensor: Type of Sensor: Type of Sensor: Location: Location: Location: Calibrated from: Calibrated from: Calibrated from: - Bumped at: Bumped at: Bumped at: Low alarm < 30 seconds: Low alarm < 30 seconds: Low alarm < 30 seconds: Battery Voltage: Battery Voltage: Battery Voltage: Comments: Comments: Comments: Sensor # 4 Sensor # 5 Sensor # 6 Type of Sensor: Type of Sensor: Type of Sensor: Location: Location: Location: Calibrated from: Calibrated from: Calibrated from: Bumped at: Bumped at: Bumped at: Low alarm < 30 seconds: Low alarm < 30 seconds: Low alarm < 30 seconds: Battery Voltage: Battery Voltage: Battery Voltage: Comments: Comments: Comments: Sensor # 7 Sensor # 8 Sensor # 9 Type of Sensor: Type of Sensor: Type of Sensor: Location: - Location: Location: Calibrated from: Calibrated from: Calibrated from: Bumped at: Bumped at: Bumped at: Low alarm < 30 seconds: Low alarm < 30 seconds: Low alarm < 30 seconds: Battery Voltage: Battery Voltage: Battery Voltage: Comments: Comments: Comments: Sensor # 10 Sensor # 11 Sensor # 12 Type of Sensor: Type of Sensor: Type of Sensor: Location: Location: Location: Calibrated from: Calibrated from: Calibrated from: Bumped at: Bumped at: Bumped at: Low alarm < 30 seconds: Low alarm < 30 seconds: Low alarm < 30 seconds: Battery Voltage: Battery Voltage: _ Battery Voltage: Comments: Comments: Comments: Total Safety Technician Date: White - Office Canary - Customer Pink - File Company Represenitive Date: * �— '&0"' Advanved Drilling Solutions Start Date/Time: 8/20/161530 hrs e v End Date/Time: 8/20/16 2359 hrs Test Station: DIM remote — aaut� Function Station: Rig Floor Remote BOP Test Form N0 T,,-,,i- LOW em ACCUMULATOR DRILL EQUIPMENT CHECKLIST INITIAL PRESSURE 3000 psi 1) DOES ALL EQUIP HOLD PRESSURE WITHOUT EXCESSIVE PUMP OPERATION? (Y) (N) CLOSING TIMES/END PRESS. 2) IS ACCUMULATOR FLUID CLEAN AND IS THE RESERVOIR FILLED TO THE PROPER LEVEL? ANNULAR 19 sec/2050 3) IS THE MAXIMUM ALLOWABLE CASING PRESSURE POSTED ON THE RIG FLOOR? (Y) (N) UPPER PIPE RAMS 8 sec/1950 4) ARE ACCUMULATOR AND REMOTE STATIONS PROPERLY TAGGED AS TO THEIR FUNCTION- LOWER UNCTIONiLOWER PIPE RAMS 6 sec/1925 5) IS THE FOLLOWING EXTRA EQUIPMENT ON LOCATION? Kill HCR 3 sec/1900 A. ANNULAR PACKING ELEMENT? (Y) (N) CHOKE HCR 2 sec/1880 B. ONE SET OF PIPE RAM SEALS (Y) (N) BLIND SHEAR RAMS 7 sec/1860 C. BONNET SEALS (Y) (N) FINAL PRESSURE 1860 psi 6) ARE ALL TESTS CONDUCTED W1 WATER (Y) (N) Seconds to Build 200 psi 35 sec Seconds to Recharge 208 sec Nitrogen Backup Bottles 12 bottle/2100 psi 'BOP TEST CHARTS SIGNED DATED 8/20/2016 FIELD: Kitchen Lights Unit LEASE: KLU WELL. A2_A RIG: Randolph Yost IG SUPRVISOR'S SIGNATURE Com ny Representative Sign e //Drillers Sig/niature C/e�mentters Signature (Y) (N) LOW TEST HIGH TEST REMARKS P, F, or TEST NUMBE PRESSURE TIME PRESSURE TIME RECORD ALL ITEMS TESTED, FAILED TESTS d REPAIRS FIP 1 250 psi 5 min 3500 psi 5 min Bottom 2 7/8 x 5" variable bore pipe rams. Lower top drive manual valve, TIW #1. Test OK P 2 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, upper top drive remote valve, Manual choke and kill valves, TIW #2, high pressure to low, burno up same Test ok P 3 250 psi min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, choke and kill HCR's valves, I -BOP Failed due to over pressure. Bleed off and retested Test OK FP a 1 250 psi _5 5 min 1 3500 psi 5 min I Top 2 7/8 x 5" variable bore pipe rams,choke and kill hoses, CMV #1 and #2. Test OK P 5 250 psi 5 min 3500 psi 5 min I Top 2 7/8 x 5" variable bore pipe rams, Choke manifold valves #3, #4, #6, #7, and #9 Test OK P 6 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, choke manifold valves #5, #8, #10, #13 and #18. Test failed on low and high, Flushed lines and retested. Test OK FP 7 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, choke manifold valves #11, #12, #14, body test hydraulic chokes A and B, body test manual choke, est OK P 6 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, choke manifold valves #15, #16 and #17, Test OK P 9 N/A N/A 2200 psi 4 min Pressured hydraulic chokes A and B up to 2300 psi and monitored same, no pressure loss, bled 1000 psi off with Choke A and 1000 psi with choke B and verifyed working correctly Test OK P 10 250 psi 5 min 3500 psi 5 min Annular with 4" pipe, Test OK P 11 250 psi 5 min 3500 5 min Blind shear rams and 4" IBOP, Observed low pressure line eratic, bleed off and restart test .Observed pressure loss on high test bleed off and reflushed lines. FP ACCUMULATOR DRILL EQUIPMENT CHECKLIST INITIAL PRESSURE 3000 psi 1) DOES ALL EQUIP HOLD PRESSURE WITHOUT EXCESSIVE PUMP OPERATION? (Y) (N) CLOSING TIMES/END PRESS. 2) IS ACCUMULATOR FLUID CLEAN AND IS THE RESERVOIR FILLED TO THE PROPER LEVEL? ANNULAR 19 sec/2050 3) IS THE MAXIMUM ALLOWABLE CASING PRESSURE POSTED ON THE RIG FLOOR? (Y) (N) UPPER PIPE RAMS 8 sec/1950 4) ARE ACCUMULATOR AND REMOTE STATIONS PROPERLY TAGGED AS TO THEIR FUNCTION- LOWER UNCTIONiLOWER PIPE RAMS 6 sec/1925 5) IS THE FOLLOWING EXTRA EQUIPMENT ON LOCATION? Kill HCR 3 sec/1900 A. ANNULAR PACKING ELEMENT? (Y) (N) CHOKE HCR 2 sec/1880 B. ONE SET OF PIPE RAM SEALS (Y) (N) BLIND SHEAR RAMS 7 sec/1860 C. BONNET SEALS (Y) (N) FINAL PRESSURE 1860 psi 6) ARE ALL TESTS CONDUCTED W1 WATER (Y) (N) Seconds to Build 200 psi 35 sec Seconds to Recharge 208 sec Nitrogen Backup Bottles 12 bottle/2100 psi 'BOP TEST CHARTS SIGNED DATED 8/20/2016 FIELD: Kitchen Lights Unit LEASE: KLU WELL. A2_A RIG: Randolph Yost IG SUPRVISOR'S SIGNATURE Com ny Representative Sign e //Drillers Sig/niature C/e�mentters Signature (Y) (N) kLLk A -2A, Regg, James B (DOA) From: Regg, James B (DOA) Sent: Monday, August 15, 2016 2:31 PM�� (► ��(tv To: Turie Drilling' Cc: Brooks, Phoebe L (DOA) Subject: RE: BOPE Test Reports & Charts 8-11-16 for Randolph Yost Thank you. I appreciate the thoroughness of the test documentation and remarks. Based on the charts (and remarks provided), I am going to show no test failures for the 8/11/16 BOPE test in our database. Copy of charts and test report will be attached to this email and sent our files. 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 lim.regg@alaska.gov. From: Furie Drilling [mailto:furie-drillina(a)furiealaska.com] Sent: Monday, August 15, 2016 1:10 PM To: Regg, James B (DOA) Subject: Re: BOPE Test Reports & Charts 8-11-16 for Randolph Yost Here you go, Mr. Jim. Brian Vines Rig Clerk Randolph Yost Rig 337-804-2513 furie-drilling@furiealaska.com FURI F From: Jim Regg <jim.regg@alaska.gov> Date: Monday, August 15, 2016 at 12:36 PM To: FurieDrilling <furie-drilling@furiealaska.com> Subject: RE: BOPE Test Reports & Charts 8-11-16 for Randolph Yost Missing Chart #3 (Tests 7, 8,9) 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. From: Furie Drilling [mailto:furie-drillin4Ca)furiealaska.com] Sent: Friday, August 12, 2016 8:52 AM To: DOA AOGCC Prudhoe Bay; Regg, James B (DOA); Brooks, Phoebe L (DOA) Cc: John Stuart; Dave McCraine Subject: BOPE Test Reports & Charts 8-11-16 for Randolph Yost Clay Clary Randolph Yost Rig 907-250-1119 furie-drilling@furiealaska.com FUME STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report Submit to: iim.regg(a)alaska.gov AOGCC.Inspectors(d.alaska.gov phoebe. brooks(c)alaska.gov Contractor: Advanced Drilling Solutions Rig No.: Randolph Yost ' DATE: 8/11/2016 Rig Rep.: Joey Beasley/ Mike McCullouc Rig Phone: 907-342-7205— Operator: Furie Operating Alaska Op. Phone: 907-250-1119 Rep.: Clay Clary E -Mail furie-drilling@furiealaska.com Well Name: KLUA2A - PTD # 2160860 - Sundry # 316-387 Operation: Drilling: Test: Initial: Test Pressure (psi): Rams: 250/3500 " MISC. INSPECTIONS: Test Result Location Gen. P Well Sign Housekeeping P Rig PTD On Location P Hazard Sec. nding Order Posted P Misc. Workover: X - Weekly: X Annular: 250/3500 - TEST DATA Test Result P P P NA Explor.: Bi -Weekly: Valves: 250/3500 _ MASP: 2201 FLOOR SAFETY VALVES: Quantity Test Result Upper Kelly 1 P Lower Kelly 1 P Ball Type 2 P - Inside BOP 1 P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 N/A NA Trip Tank P P Annular Preventer 1 13-5/8" 5M fy--- P Pit Level Indicators P P #1 Rams 1 2-7/8 X 5 VBR Fi— P Flow Indicator P P #2 Rams 1 Blind Shear P Meth Gas Detector P P #3 Rams 1 2-7/8 X 5 VBR P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln. Valves 1 4-1/16th 10M P Inside Reel valves 0 NA HCR Valves 2 4-1/16th 10M P Kill Line Valves 2 4-1/16th 10M P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi) 3050 P CHOKE MANIFOLD: Pressure After Closure (psi) 1900 P - Quantity Test Result 200 psi Attained (sec) 14 P No. Valves 18 P Full Pressure Attained (sec) 169 P Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 2 P Nitgn. Bottles # & psi (Avg.): 12 @ 2200 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 2 Test Time: 9.0 - Hours Repair or replacement of equipment will be made within days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Remarks: Note: on test charts there is a re -test of test #3 and test #10. There were no leaks or repairs that needed to be made for these test to pass the re -test. Co rep Clay Clary made the decision to re -test due to the slight reduction at end of HP on test #3 and both low psi and hi psi test on #10 test." I c. r-eS , Ids C. J, 2E�1 811 s; _- AOGCC Inspection 24 hr Notice Yes Date/Time 3-08-16 / 16:04 hrs Waived By Jim Regg Test Start Date/Time: 8/11/2016 00:00 hrs (date) (time) Witness Test Finish Date/Time: 8/11/2016 09:00 hrs Form 10-424 (Revised 11/2015) BOPE Test Report 8-11-16.xlsx t ov C-� \/Oo 00 \ \ 0Sc' 000 ` 00S \� \\ 00n.\\_ nOp� _ 3500-�-------- X3000 �— \ \ \ �O i 2500 �\ �ZQO0j s° i i5pO ° oO �. 00 CHART N0. MG MP -6000 -IHR (METER I- --- CHART rui rra:' -T TAKEN OFF ALucATICN kLN -/�O REMARK, Jl-lfo i. o o a �. Y s� A o o�,� d oo °ops o�c�V A� �4 poor , 0O oQ/ c: % od - --- ------------ I A OA ° ° app \ v °°Y, 'V 0 ASO °� \ ° o}\ \ \ °° \ \ \ \ IIK� /0 - �� \ i 1 iLo oc 600c) -IHR U N o po CHART No. Mp 600 N o I fff 1 a o A! I - TARE P M o c5 CD CHPR� `t��N o o w �o o IU7 �ocnno�a hh i i \ V c \ \x 0 °0� V �v °s pZ ' -\\ ° °a °°SA i O s \ 6 /CHART NO. MC METER CHART PUT ON, TAKEN OFF REMARKS 0092 Door � PQJ �:r Cf� Advanved Drilling Solutions Start Date/Time: 8/11/16 02:00 hrs u End Date/Time: 8/11/16 09:00 hrs Test Station: Ric Floor remote Function Station: Accumulator unit 60P Test Form ACCUMULATOR DRILL LOW TEST INITIAL PRESSURE 3050 psi HK3H TEST CLOSING TIMES/END PRESS. REMARKS P, F. TEST NUMBE PRESSURE TIME PRESSURE TIME RECORD ALL ITEMS TESTED, FAILED TESTS Is REPAIRS or F!P 1 250 psi 5 min 3500 psi 5 min Bottom 2 7/8 x 5" VBR'S, Lower manual top drive valve, 4" TIW #1. (Test OK) P 2 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" VBR'S, Manual choke & kill valves, Upper remote top drive valve, TIW #2. (Test OK) P 3 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" VBR'S, Choke and Kill HCR's valves, TIW #1, 4" IBOP. (Test OK) 4 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" VBR'S, Choke and Kill hoses, CMV #1 and #2. (Test OK) P 5 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" VBR'S, Choke manifold valves #3, #4, #6, 97, and #9. (Test OK) P 6 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" VBR'S, Choke manifold valves #5, #8, #10, #13 and #18. (Test OK) P 7 250 psi 5 min 3500 psi 1 5 min Top 2 7/8 x 5" VBR'S, Choke manifold valves #11, #12, #14, body test hydraulic chokes A& B, body test manual choke (Test O P a 250 psi 5 min 3500 psi 5 min Top 2 7/8 x5" VBR'S, Choke manifold valves #15, #16 and #17. (Test OK) P 9 N/A N/A 2200 psi N/A Pressured hydraulic chokes A and B up to 2300 psi and monitored same, no pressure loss, bled off to 1800 psi with Choke B & bled off to 1400 psi with choke A, bled to 0. (Test OK) P 10 250 psi 5 min 3500 psi 5 min Annular with 4" Drill pipe. (Test OK) -F- 11 250 psi 5 min 3500 psi 5 min Retest of #3 as per Company man, Top 2 7/8 x 5" VBR'S, Choke and Kill HCR's valves, 4" IBOP. (Test OK) P 12 250 psi 5 min 3500 psi 5 min Retest of #10 as per Company man, Annular with 4" Drill pipe. (Test OK) P 13 250 psi 5 min 3500 psi 5 min Blind shear rams (Test OK) P ACCUMULATOR DRILL EQUIPMENT CHECKLIST INITIAL PRESSURE 3050 psi 1) DOES ALL EQUIP HOLD PRESSURE WITHOUT EXCESSIVE PUMP OPERATION? (Y) (N) CLOSING TIMES/END PRESS. 2) IS ACCUMULATOR FLUID CLEAN AND IS THE RESERVOIR FILLED TO THE PROPER LEVEL? ANNULAR 19 sec/2050 3) IS THE MAXIMUM ALLOWABLE CASING PRESSURE POSTED ON THE RIG FLOOR? (Y) (N) UPPER PIPE RAMS 6 sec/ 1900 4) ARE ACCUMULATOR AND REMOTE STATIONS PROPERLY TAGGED AS TO THEIR FUNCTION t LOWER PIPE RAMS 7 sec/1800 5) IS THE FOLLOWING EXTRA EQUIPMENT ON LOCATION? Kill HCR 2 sec/1800 A. ANNULAR PACKING ELEMENT? (Y) (N) CHOKE HCR 2 sec/1800 B. ONE SET OF PIPE RAM SEALS (Y) (N) BLIND SHEAR RAMS 6 sec/1725 C. BONNET SEALS (Y) (N) FINAL PRESSURE 1725 psi 6) ARE ALL TESTS CONDUCTED W/ WATER (Y) (N) Seconds to Build 200 psi 14 s Seconds to Recharge�bcttleIFOO Nitrogen Backup Bottles 'BOP TEST CHARTS SIGNED DATED 8/11/2016 FIELD: Kitchen Lights Unit LEASE: N/A WELL: KLU-A2-A RIG: Randolph Yost SUPERrVISOR'S SIG ATURE ompany ntetive Signature 1 � era na Cerne ters Signature (Y) (N) j P2 (Y) (N) Total Safety U.S., Inc. 209 E. S1st Avenue Anchorage, AK 99503 °Doll TOTAL SAFETY® Phone: (907) 743-9871 Fax: (907) 743-9872 ' GAS DETECTION SYSTEM TES SHEET Customer:�' Onshore: _ Offshore: Report Date: -1 I- Time: AFE/Job#: ©Q M Rig/Location: L —IT— Drilling Company: fqDs Company Representitiv : CIqK CjqeTelephone Number: :4 Total Safety Technician: ,> ; Current Site Activity: pp , Type of System: 1)�S W,,e feu1 Type of Test: Calibration X Bump Test Sensor # 1 Sensor # 2 Sensor # 3 Type of Sensor: ' Type of Sensor:Type of Sensor: Location: 4 Eloc, - Location: Location: h�F Calibrated from: Calibrated from: ® Calibrated from: Bumped at: ac Bumped at: ao Bumped at: a Low alarm < 30 seconds: 1�ZZ Low alarm < 30 seconds: 77E3--- Low alarm < 30 seconds: Battery Voltage: r �/ Battery Voltage: 3,to i/' Battery Voltage: , Comments: Comments: Comments: Sensor # 4 Sensor # 5 Sensor # 6 Type of Sensor: S' e of Sensor: Sensor: Location: p'• Loca ' n: Location: Calibrated from: ® Calibrat from: Calibrated from. Bumped at: 34-0 Bumpedat: Bumped at: Low alarm < 30 seconds: Low alarm < ds: Low alarm < 3 econds: Battery Voltage: Battery age: Battery V ge: _ Comments: Co ents: Com ts: Sensor # 7 Sensor # 8 Sensor # 0 e of Sensor: a of Sensor: Type of Sensor: 1 L Loca Loca n: Location: Calibrate romp Calibrate rom: Calibrated from: G7 Bumped at: Bumped at: Bumped at: Low alarm < 30 nds: Low alarm < 30 se Low alarm < 30 seconds: Battery Vo ge: Battery Volta _ Battery Voltage: r Com nts: Comments: Comments: Sensor # Sensor # 1 Sensor # Q Type of Sensor: - Type of Sensor: �„C (_ Type of Sensor: Location: Location: �, . Location: Calibrated from: '90 Calibrated from: Calibrated from Bumped at: C! Bumped at: Lio Bumped at: 0 Low alarm < 30 seconds: ,S Low alarm < 30 seconds: Low alarm < 30 seconds: Battery Voltage: Battery Voltage: Battery Voltage: V Comments: Comments: Comments: Total Safety Technician g=) ) -1 � Date: t Cora )any Re�presenitive White - Office Canary - Customer Pink - File Date: Regg, James B (DOA) From: Brooks, Phoebe L (DOA) Sent: Monday, August 01, 2016 2:41 PM To: Furie Drilling Cc: Regg, James B (DOA) Subject: RE: BOPE Test Randolph Yost 7-28-16 Attachments: ADS Randolph Yost 07-28-16 revised.xlsx Attached is a revised report as follows: - Trailing zero on PTD # - Operation is Workover (running completion; operation in this case is discontinuous from drilling) - Test is Initial - MASP is 2201 per Sundry 316-387 Please update your copy or let me know if you disagree. Thank you, Phoebe Phoebe Brooks Statistical Technician II Alaska Oil and Gas Conservation Commission Phone: 907-793-1242 Fax: 907-276-7542 CONFIDENTIALITY NOTICE: 'phis 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 Phoebe Brooks at 907-793-1242 or phoebe.brooks@alaska.gov. From: Furie Drilling [ma ilto:furie-drilling @furiealaska.com] Sent: Friday, July 29, 2016 12:57 PM To: Regg, James B (DOA); DOA AOGCC Prudhoe Bay; Brooks, Phoebe L (DOA) Cc: Yost IADC; Yost Maint Subject: BOPE Test Randolph Yost 7-28-16 Brian Vines Rig Clerk Randolph Yost Rig 337-804-2513 furie-drilling@furiealaska.com C`moo FURIE STATE OF ALASKA t z tc t I OIL AND GAS CONSERVATION COMMISSION y (� BOPE Test Report Submit to: iim.regg(@alaska.gov AOGCC.Inspectors(oalaska.gov phoebe. brooks(a)alaska.gov Contractor: Advanced Drilling Solutions Rig No.: Randolph Yost DATE: 7/28/2016 Rig Rep.: Joey Beasley / Brice Beech Rig Phone: 907-342-7205 Operator: Furie Operating Alaska Op. Phone: 907-250-1119 Rep.: Clay Clary / Isaiah Del Toro E -Mail furie-drilling(atmealaska.com Well Name: KLU A -2A PTD # 2160860 Sundry # 316-387 Operation: Test: Test Pressure (psi): Drilling: Initial: Rams: X 200/3500 Workover: X Explor.: Weekly: Bi -Weekly: Annular: 200/3500 Valves: 200/3500 - MASP: 2201 MISC. INSPECTIONS: TEST DATA FLOOR SAFETY VALVES: Test Result Test Result Quantity Test Result Location Gen. P Well Sign P . Upper Kelly 1 P Housekeeping P Rig P Lower Kelly 1 P PTD On Location P Hazard Sec. P Ball Type 2 P ending Order Posted P Misc. NA Inside BOP l P FSV Misc 0 NA BOP STACK: Quantity Size/Type Test Result MUD SYSTEM: Visual Alarm Stripper 0 N/A NA Trip Tank P P Annular Preventer 1 13-5/8" 5M P Pit Level Indicators P P #1 Rams 1 2-7/8 X 5 VBR P Flow Indicator P P #2 Rams 1 Blind Shear FP Meth Gas Detector P P #3 Rams 1 2-7/8 X 5 VBR P H2S Gas Detector P P #4 Rams 0 NA MS Misc 0 NA #5 Rams 0 NA #6 Rams 0 NA Quantity Test Result Choke Ln. Valves 1 4-1/16th 10M P Inside Reel valves 0 NA HCR Valves 2 4-1/16th 10M P Kill Line Valves l 4-1/16th 10M P Check Valve 0 NA ACCUMULATOR SYSTEM: BOP Misc 0 NA Time/Pressure Test Result System Pressure (psi) 3000 P CHOKE MANIFOLD: Pressure After Closure (psi) 1650 P Quantity Test Result 200 psi Attained (sec) 21 P No. Valves 18 P Full Pressure Attained (sec) 235 P Manual Chokes 1 P Blind Switch Covers: All stations Yes Hydraulic Chokes 2 P Nitgn. Bottles # & psi (Avg.): 12 @ 2200 P CH Misc 0 NA ACC Misc 0 NA Test Results Number of Failures: 1 - Test Time: 8.0 Hours Repair or replacement of equipment will be made within N/A days. Notify the AOGCC of repairs with written confirmation to: AOGCC.Inspectors@alaska.gov Remarks: Initial low test on Blind shear rams was a false start, bled off and restarted test. Blind Shear rams leaked on high test. Bleed off, functioned, circulate out air and retested on high, Pass. AOGCC Inspection 24 hr Notice Yes Date/Time 7/26/16 @ 06:18 Waived By Jim Regg Test Start Date/Time: 7/28/2016 15:00 (date) (time) Witness Test Finish Date/Time: 7/28/2016 23:00 Form 10-424 (Revised 11/2015) ADS Randolph Yost 07-28-16 revised.xlsx oc �„ A �..v --7 j ems•.' \ -ti 4 f 7 77 n F of ter. �. a ?, €+a P� € ° P" 000 S , t F �. .t t^ C 705, 3v i s �j r{ r q ' , _� ✓". f ; ki r ; r' �+. ♦ .., C% ti u t w w J r Wcov/ ......... . ..... .. No. Mil -6000 -HR pin 0"� zed ......... . ..... .. , c. 1 5 l i c _ ,x 1 s , G �i sP J r .. I f ; f 1 �I i �.� .. x OS� BOP Test Form Advanved Drilling Solutions Qw y O HIGH TEST CLOSING TIMES/END PRESS. Start Date/Time: 7/28/16 1500 hrs 4 pc End Date/Time: 7/28/16 2 hrs � Test Station: Rig Floor remote PRESSURE Function Station: Accumulator unit BOP Test Form ACCUMULATOR DRILL LOW TEST INITIAL PRESSURE 3000 psi HIGH TEST CLOSING TIMES/END PRESS. REMARKS P, F, or TEST NUMBEF PRESSURE TIME PRESSURE TIME RECORD ALL ITEMS TESTED, FAILED TESTS 8 REPAIRS F1P 1 250 psi 5 min 3500 psi 5 min Bottom 2 7/8 x 5" variable bore pipe rams, Upper top drive remote valve. Test OK P 2 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, Manual choke and kill valves, TIW #1, high pressure to low, bump up same. Test ok P 3 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, choke and kill HCR's valves, TIW #2. Test OK P 4 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, lower manual top drive valve, choke and kill hoses, CMV #1 and #2. Test OK P 5 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, Choke manifold valves #3, #4, #6, #7, and #9. Test OK P 6 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, choke manifold valves #5, #8, #10, #13 and #18. Test OK P 7 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, choke manifold valves #11, #12, #14, body test hydraulic chokes A and B, body test manual choke Test OK P 8 250 psi 5 min 3500 psi 5 min Top 2 7/8 x 5" variable bore pipe rams, choke manifold valves #15, #16 and #17, Test OK P 9 N/A N/A 2200 psi 4 min Pressured hydraulic chokes A and B up to 2200 psi and monitored same, no pressure loss, bled 1000 psi off with Choke A and 1000 psi with choke B and verifyed working correctly. Test OK P 10 250 psi 5 min 3500 psi 5 min Annular with 4" pipe, Test OK P 11 250 psi 5 min Blind shear rams and 4" IBOP, Observed low pressure line eratic, bleed off and restart test .Observed pressure loss on high test bleed off and reflushed lines FP 12 250 psi 5 min 3500 psi 5 min Retest #11, Blind shear rams, 4" IBOP, test OK P ACCUMULATOR DRILL EQUIPMENT CHECKLIST INITIAL PRESSURE 3000 psi 1) DOES ALL EQUIP HOLD PRESSURE WITHOUT EXCESSIVE PUMP OPERATION? (Y) (N) CLOSING TIMES/END PRESS. 2) IS ACCUMULATOR FLUID CLEAN AND IS THE RESERVOIR FILLED TO THE PROPER LEVEL? ANNULAR 23 sec/2050 3) IS THE MAXIMUM ALLOWABLE CASING PRESSURE POSTED ON THE RIG FLOOR? (Y) (N) UPPER PIPE RAMS 6 sec/1900 4) ARE ACCUMULATOR AND REMOTE STATIONS PROPERLY TAGGED AS TO THEIR FUNCTION-, LOWER PIPE RAMS 6 SECA800 5) IS THE FOLLOWING EXTRA EQUIPMENT ON LOCATION? Kill HCR 1 sec/1800 A. ANNULAR PACKING ELEMENT? (Y) (N) CHOKE HCR 1 sec/1800 B. ONE SET OF PIPE RAM SEALS (Y) (N) BLIND SHEAR RAMS 6 sec/1725 C. BONNET SEALS (Y) (N) FINAL PRESSURE 1725 psi 6) ARE ALL TESTS CONDUCTED W/ WATER (Y) (N) Seconds to Build 200 psi 24 sec Seconds to Recharge 210 sec Nitrogen Backup Bottles 12 bottle/2100 psi 'BOP TEST CHARTS SIGNED DATED 7/28/2016 FIELD: Kitchen Lights Unit LEASE: N/A WELL: KLU-A2-A RIG: Randolph Yost RIG SUPERVISOR'S SIGNATURE Company Representative Signature Drillers Signature Cementers Signature (Y) (N) (Y) (N) Total Safety U,S., Inc. 209 E. 51st Avenue , Anchorage, AK 99503 r ❑v■� Lo TOTAL SAFETY� Phone: (907) 743-9871°� r Fax: (907) 743-9872 Type of Sensor: GAS DETECTION SYSTEM TEST SHEET Location: i { J j Location: �� Customer: v d Onshore:_ Offshore: Report Date: - Time: _ r AFE/Job#: 11; c 01t, Rig/Location: Drilling Company: jq J, Company Representiti . " 441 Telephone Number: Cry_ dlsv-- -1l J Cf Total Safety Technician: 3y ��. Current Site Activity:r ; S r Type of System: 04,' i to u Type of Test: Calibration BuAlp Test Sensor # 1 Sensor # 2 Sensor # 3 Type of Sensor: Type of Sensor: Type of Sensor: -I . S' Location: i { J j Location: �� Location: �, eee - Calibrated from: J Calibrated from: Calibrated from: Bumped at: - Bumped at:.C) - Bumped at: Low alarm < 30 seconds: tlzS - Low alarm < 30 seconds: `t16 S Law alarm < 30 seconds: YZ7 Battery Voltage:,,f Battery Voltage: i✓ Battery Voltage: �f Comments: Comments: Comments: Sensor # 4 Sensor # S Sensor # 6 Type of Sensor: ; Ty of Sensor: Type of Sensor: Location: �; _ LocatI _ Location: Calibrated from: Calibrate am: Calibrated from: Bumped at: ¢} Bumped at: Bumped at: Low alarm < 30 seconds: tC - Low alarm < 30 onds: Low alarm < 3 seconds: Battery Voltage: Battery Vol e: Battery V age: Comments: Comm s: Com nts: Sensor # 7 Sensor # 8 Sensor # CJ Typ of Sensor: e of Sensor: Type of Sensor: Locatio _ Locatio . �' Location:Icalibrated m: Calibrated fro e'' Calibrated from Bumped at: Bumped at: Bumped at:EEE (j Low alarm < 30 sec s: Low alarm < secon Low alarm < 30 seconds: Battery Volt ag Battery V age: Battery Voltage: Commen Com ents: Comments: Sensor# Sens or# )` Sensor# I, Type of Sensor: (� - Type of Sensor: Type of Sensor: Location:( Location: ct�-- - Location: Calibrated from: 41 Calibrated from: Calibrated from: Bumped at: 1 Bumped at: Bumped at:j Low alarm < 30 seconds: S Low alarm < 30 seconds: ow alarm < 30 seconds: J^ Battery Voltage: 3, S -V Battery Voltage:; Battery Voltage:,Sv' Comments: Comments:comments: r7 Total Safety Technician Date: White - Office Canary - Customer Pink - File Compo a resenifiv Date: THE S'L'ATE 01ALASKA GOVERNOR BILL WALKER David McCraine Drilling Engineer Furie Operating Alaska, LLC 4906 Ambassador Caffery Pkwy, Suite 800 Lafayette, LA 70508 Re: Kitchen Lights Field, Undefined Gas Pool, KLU A -2A Permit to Drill Number: 216-086 Sundry Number: 316-387 Dear Mr. McCraine: Alaska Oil and Gas ,Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov 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, )0 -- Daniel T. Seamount, Jr. Commissioner --7-?- DATED this Z-7 day of July, 2016. RBDMS � L-- JUL 2 9 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION JUL 2 6 2016 APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 AQGGG 1. Type of Request: Abandon Plug Perforations Fracture Stimulate Repair Well Operations shutdownLi Suspend Perforate B Other Stimulate 8 Pull Tubing Change Approved Program Plug for Redrill Perforate New Pool Re-enter SuspWell Alter Casin Other: g a 2. Operator Name: 4. Current Well Class: 5. Permit to Drill Number: Furie Operating Alaska LLC Exploratory 8 Development Stratigraphic Service ® 216-086 3. Address: 6. API Number: 4906 Ambassador Caffery Pkwy Suite #800 50-733-20655-01-00 7. If perforating: 8. Well Name and Number: What Regulation or Conservation Order governs well spacing in this pool? Conservation Order 723 . KLU A -2A - Will planned perforations require a spacing exception? YesLi No 9. Property Designation (Lease Number): Field/Pool(s): ADL 389197 ' TKLUUndefined Natural Gas Pool , 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 8160' 7301' • 8041 7197' - 2201 Casing Length Size MD TVD Burst Collapse Structural 381' 20" 381' 381' Conductor Surface 2,265' 13-3/8" 2,265' 1994.57' 5,380 psi 2,670 psi Intermediate Production 8122' 9-5/8" 8122' 726' 7,930 psi 6,620 psi Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): 6679-6701', 6127-6276', 5950-5971',5773-5867', 4-1/2" L-80 4608' 5395-5486,47- 803' 4732-4819',4085-4260' Packers and SS e: Packers: 9-5/8" Permanent (Sump Packer), CSHP Packers and SSSV MD (ft) and TVD (ft): Packers: 6711' MD/5980' TVD, 6286' MD/5581' Superior Completion Services NR (Gravel Pack Packers) ' SCSSV: 1650' MD/1573' TVD TVD, 5997' MD/5307' TVD, 5496' MD/3882' TVD, 4813, MD/41531 TVD 4sq'.v Mn/iQF;n'T\/Q 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch 1X1 Exploratory Stratigraphic Development 1X1 - Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 27 -Jul -16 OIL ❑ WINJ GAS ®- WAG ® WDSPL Suspended GSTOR ® SPLUG 16. Verbal Approval: Date: Commission Representative: GINJ Op Shutdown Abandoned 8 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact David McCraine Email d.mccraine@furiealaska.com Printed Name Title David McCraine Drilling Engineer Signature Phone Date ✓ G� f�337-981-0270 / 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 �\ CJcU f0 a a� V l G 1 Post Initial Injection MIT Req'd? Yes No Spacing Exception Required? Yes No Subsequent Form Required: ® APPROVED BY Approved by: 21f, COMMISSIONER �� I THE COMMISSION Date: 1 J Form 10-403 AttachSubmit Form and '7112d 1112015 Approved application is valid for 12 months from the date of approval. Attachments in Duplicate " RBDMS [-,-'JUL 7 9 2016 ORIGINAL C�.• FUR/E Operating Alaska LLC July 22, 2016 Alaska Oil & Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage, Alaska 99501 Re: 10 -403 Sundry to Fracture Stimulate — PTD 16-086 Well: Kitchen Lights Unit #A-2 A TO WHOM IT MAY CONCERN: RECEIVED JUL 26 2016 AOGCC Furie Operating Alaska, LLC (FOA) submits 10 — 403 Sundry to Fracture Stimulate the KLU #A -2A for approval. The submittal is in duplicate. Enclosed is the proposal summary, wellbore schematic, log sections, detailed operations program and BOP sketch. The data includes the perforations and completion intervals. Also included are the responses to AOGCC regulation 20 AAC 25.83. Furie plans to do remedial work and will submit the CBL before completion work begins. If you have any questions or require further information please contact Furie Drilling Engineer, David McCraine, at (337) 981-0270. Sincerely, David McCraine Drilling Engineer 4906 AMBASSADOR CAFFERY PKWY SUITE # 800. LAFAYETTE, LA 70508 1 OFFICE: 337.981.0270 ell FURZE Operating Alaska LLC Completion Proposal Summary For KLU # A -2A Kitchen Lights unit # A -2A is a developmental sidetrack well off of the Julius R monopod in the Cook Inlet. The objectives are the upper and lower Sterling encountered in the KLU #3. KLU # A -2A is a directional well drilled with the jackup Randolph Yost. Upon reaching TD of 8160'M/7301' TVD, Furie ran 9 5/8" 53.5 ppf L-80 BTC casing and cemented it in place, and ran a CBL prior to nippling down and setting a dry hole tree. Estimated TOC per the CBL is being analized. 0,nc, (I-Ztx_j . Initially Furie will RIH with a 4" 14# S-135 XT -39 workstring, displace to 9.8± ppg water based mud and cleanout to PBTD at 8,041' MD/7,197' TVD. Block squeeze perforations and proposed circulating squeeze plan will follow. A CBL log will then be run to confirm the required isolation has been obtained. Furie then plans to displace the wellbore to 9.8 ppg NaCl with 6% KCl to complete four intervals with frac packs (20-25# Crosslinked guar carrier and 30-50 mesh Econoprop) for sand control (5-1/2" Blank Pipe and 0.008" ga wire wrapped screens, with 3-1/2" Isolation tubing equipped with sliding sleeves). Two intervals are in the Beluga, two are in the Sterling. Proposed Completion Intervals: Beluga: 6,679-6,701' MD/5,950-5,972' TVD 6,127-6,276' MD/5,430-5,471' TVD Sterling: 5,395-5,486' MD/4,732-4,819' TVD 4,7255 4,803' MD/4,�95-4,160' TVD The well will then be equipped with 4-1/2" 12.75# L-80 CSCB IPC tubing with self - equalizing SCSSV (1/4" control line) and downhole chemical injection (3/8" control line). Non -Metallic cross coupling clamps will be used to keep the tubing from the casing wall and enhance thermal flow characteristics. A 4-1/16" 5M tree will then be installed. Basic Info: Surface Location: X-294,331.49 & Y- 2,536,125.62 Bottom Hole Location: X-296,421.23 & Y- 2,538,094.65 Total Depth 8160'MD / 7301' TVD a) Formation Depths: Sterling - 3639' MD/ 2879' TVD — potential gas zones Beluga — 5758' MD/ 5082' TVD — potential gas zones Property Lease: ADL389197 eo%o�, - FURZE Operating Alaska LLC b) Maximum Anticipated Surface Pressure: MASP = Bottom hole Pressure — Gas gradient 2201 psi = (2796 psi - BHP deepest zone)- (.lpsi/ft* 5950' — TVD deepest zone) c) Casing program for KLU # A -2A: Casin 9 5/8" Depth 8122'MD/ 7268' TVD Hole Size 121/4" Weight (ppf) 53.5 Grade L-80 Connection BTC - RS Plain end weight. d) Well Control Equipment: 13 5/8" 5M annular and 13 5/8" l OM three ram BOP e) Furie plans to run LEL and H2s gas detection. KLU A -2A Completion Procedure Furie Operating Alaska - Kitchen Lights 2016 Program Status: Well drilled, 9-5/8" 53.5# Mod Buttress casing installed to 8,122' MD/7,197' TVD and cemented; plug bumped with inhibited bay water. Cement in 9-5/8" Casing evaluated with CBL prior to TA. Proposed Perforations and Completion Brine Density: Beluga: 6,679-6,701' MD/5,950-5,971' TVD; Est BHP 2,796 psi, 109 deg F 6,127-6,276' MD/5,773-5,867' TVD; Est BHP 2,693 psi, 108 deg F Completion Brine: 9.8 ppg NaCL w/6% KCl for these two zones and initial displacement Sterling: 5,395-5,486' MD/4,732-4,819' TVD; Est BHP 2,088 psi, 96 deg F 4,725-4,803' MD/4,985-4,160' TVD; Est BHP 1,712 psi, 90 deg F Completion Brine: 9.6 ppg NaCL w/6% KCl for these two zones and packer fluid Proposed Completion: 4-1/16" 5M Tree 4-1/2" 12.75# L-80 CSCB IPC tubing 1. N/U BOPS's. Test to 200-300 psi low, 3500 psi high per approved procedure. 2. TIh picking up 4" drill pipe. 3. Displace to a ± 9.8 ppg mud. 4. Be prepare to perforate and squeeze to isolate the zones as needed. 5. Run CBL across zones to confirm isolation. 6. TIH with brushes/scrapers; picking up 4" XT39 and 3-1/2" NC38 Drillpipe as required; displace hole to filtered 9.8 ppg NaCl with 6% KCl completion fluid. Capture and disppose of waste fluids. Filter brine to 2 micron using DE and Pod Filters. POOH, Rack back Magnostar tool and run on subsequent runs. ! 0 7. Rig up E/L, Install Sump Packer at 6711' MD. 8. RIH to perforate lower Beluga interval 6679-6701' MD with 7" tubing conveyed perforator (15 SPF BHC's) with DST Tools. Perforate hydrostatically overbalanced; C&C and POOH. 9. RIH with Frac Pack Assembly (5-1/2" 20# P110 Blank and 0.008" ga wire wrapped screen, 3-1/2" isolation tubing with two sliding sleeves, packer with service tool) and set packer at 6,286' MD. Test DP Workstring to 3500-3700 psi for 5 min (175 psi maximum drop over 5 minutes). Test surface iron and frachead to 6,800-7,000 psi `/ (175 psi maximum drop over 5 minutes), Confirm Surface Casing pressure, isolate same. Set the DP pop-off at 6,500 (±200) psi and trips staggered at 6,200 and 6,300 psi; set the annulus pop-off at 3,000 (±200) psi. Perform mini frac and Step Rate Test; Frac Pack lower interval interval with 30-50 mesh Econoprop. Reverse out and dispose of excess slurry. Pressure test isolation assembly to 1000 psi. Check and confirm Surface Casing pressure, record on daily report. POOH. -40. Run packer plug on TCP guns, perforate second Beluga interval 6127-6276' MD with 7" tubing conveyed perforator (15 SPF BHC's) with DST Tools. Perforate hydrostatically overbalanced; C&C and POOH. 11. RIH and recover packer plug. 12. RIH with Frac Pack Assembly (5-1/2" 20# P110 Blank and 0.008" ga wire wrapped screen, 3-1/2" isolation tubing with two sliding sleeves, packer with service tool) and set packer at 6,001' MD. Test DP Workstring to 3500-3700 psi for 5 min (175 psi Z�,r maximum drop over 5 minutes). Test surface iron and frachead to 6,800-7,000 psi s (175 psi maximum drop over 5 minutes), Confirm Surface Casing pressure, isolate same. Set the DP pop-off at 6,500 (±200) psi and trips staggered at 6,200 and 6,300 psi; set the annulus pop-off at 3,000 (±200) psi. Perform mini frac and Step Rate Test; Frac Pack second interval interval with 30-50 mesh Econoprop. Reverse out and dispose of excess slurry. Pressure test isolation assembly to 1000 psi. Check and confirm Surface Casing pressure, record on daily report. POOH. V13. RIH and Install Isolation Packer assembly (Packer to be installed at 5496' MD; \ potential a -line gamma correlation run if tag off depth). Adjust brine density from 9.8 f.. ppg to 9.6 ppg NaCl with 6% KCl. (Note: this will not underbalance the lower zones, 'tqb ' but will reduce the hydrostatic overbalance on the upper zones, minimizing 5completion brine losses.) 14. Run packer plug on TCP guns, perforate Lower Sterling Interval 5395-5486' MD with 7" tubing conveyed perforator (15 SPF BHC's) with DST Tools. Perforate hydrostatically overbalanced; C&C and POOH. 15. RIH and recover packer plug. 16.RIH with Frac Pack Assembly (5-1/2" 20# P110 Blank and 0.008" ga wire wrapped screen, 3-1/2" isolation tubing with two sliding sleeves, packer with service tool) and set packer at 4,813' MD. Confirm Surface Casing pressure, isolate same. Test DP Workstring to 3500-3700 psi for 5 min (175 psi maximum drop over 5 minutes). Test �lu�Y' surface iron and frachead to 6,800-7,000 psi (175 psi maximum drop over 5 minutes), j Confirm Surface Casing pressure, isolate same. Set the DP pop-off at 6,500 (±200) psi and trips staggered at 6,200 and 6,300 psi; set the annulus pop-off at 3,000 (±200) psi. Perform mini frac and Step Rate Test; Frac Pack third interval with 30-50 mesh Econoprop. Reverse out and dispose of excess slurry. Pressure test isolation assembly to 1000 psi. Check and confirm Surface Casing pressure, record on daily report. POOH. 17. Run packer plug on TCP guns, perforate Upper Sterling Interval 4725-4803' MD with 7" tubing conveyed perforator (BHC's) with DST Tools. Perforate hydrostatically overbalanced; C&C and POOH. 18. RIH and recover packer plug. 19. RIH with Frac Pack Assembly (5-1/2" 20# P110 Blank and 0.008" ga wire wrapped screen, 3-1/2" isolation tubing with two sliding sleeves, packer with service tool) and set packer at 4,593' MD. Confirm Surface Casing pressure, isolate same. Test DP Workstring to 3500-3700 psi for 5 min (175 psi maximum drop over 5 minutes). Test surface iron and frachead to 6,800-7,000 psi (175 psi maximum drop over 5 minutes). hp Set the DP pop-off at 6,500 (±200) psi and trips staggered at 6,200 and 6,300 psi; set 9, ei� the annulus pop-off at 3,000 (±200) psi. Perform mini frac and Step Rate Test; Frac Pack upper interval interval with 30-50 mesh Econoprop. Reverse out and dispose of excess slurry. Pressure test isolation assembly to 1000 psi. Check and confirm Surface Casing pressure, record on daily report. 20. Displace to inhibited packer fluid after final frac pack reversing operations are complete and integrity of system is established. POOH. 21. Pull wearbushing and wash wellhead profile. Rig up to run 4-1/2" tubing. Make up tubing hanger assembly to landing string; make dummy run and land in tubing hanger; make up three pins to mark. Back out pins and POOH w/ hanger. Confirm hanger in correct position. Replace hanger seals if required, rack back. 22. Complete rig up of control line spoolers and rig up of sheave in derrick. 23. Run new 4-1/2" 12.75# P-110 CSCB IPC production tubing to SCSSV-CIM target depth of 1650' (2,950' in hole). Install tubing centralizers 18" below coupling on connection below SCSSV-CIM. These centralizers will facilitate SCSSV-CIM assembly entry into tubing hanger and into 9-5/8" Casing. Be aware of set down weight while RIH. 24. Make up SCSSV-CIM assembly. Install SCSSV line and test connection by pressuring up to 5000 psi. Install chemical injection line and test by pressuring up line to 2000 psi. Commission chemical injection lines by pressuring up in 500 stages to burst rupture disk in valve (4000 psi surface pressure) before RIH. Pressure up to hold open SCSSV with 2500 psi while RIH to upper gravel pack packer at 4593' MD. 25. Pick up hanger and terminate control lines and pressure test. Band tubing in pup joint area below hanger as required. Continue to RIH with 4-1/2" CSCB Landing String. 26. Rig up nitrogen unit on pipe rack while RIE with tubing. Be sure to utilize plywood or similar to protect rig deck from leaking liquid nitrogen. 27. Space out tubing (neutral to locator 1 foot high), land tubing. Pressure up tubing to 500 psi, close SCSSV and bleed off 200-250 psi to test SCSSV. Re -open SCSSV with 3500 psi on control line. 28. Rig up slickline lubricator; test to 3500 psi. GIH with x -test tool and set in x -nipple above upper GPP at ±4,543. Test tubing to 3000 psi for 15 min; chart. V29. Hold safety meeting for displacing tubing to nitrogen. Pick up seals out of packer and displace tubing with nitrogen to 500' above end of tubing (monitor returns, target is P 62.3 bbls fluid recovery to surface; record actual on daily report). Slack off and land tubing; make up hanger pins. Test void to 5000 psi. Test backside to 1500 psi for 30 minutes; chart. 30. Close SCSSV, bleed nitrogen as required, set BPV. N/D BOP's, N/U Tree, set plug off tool and test tree to 5000 psi. 31. Terminate control lines, install and test tree as required. Tie in SCSSV and CIM lines as required. 32. Measure for flowline jumper and install when able. Displace chemical injection control line contents as required and displace to methanol. 33. Rig up slickline lubricator with BO shifting tool; test to 3500 psi. Pressure up with nitrogen to equalize SCSSV, open same; apply 3500 psi to SCSSV control line. Bleed off nitrogen pressure as directed to equalize sliding sleeves at Lower Beluga formation. 34. GIH and shift open both sliding sleeves (down to open) in lower zone GP assy. 35. Flow well to platform test separator; route aqueous fluid for disposal as required. 36. Skid Rig. Furie Operating Alaska Kitchen Lights Unit #A -2A Condor Sidetrack RKB-CHF: 52.4' RKB - ML: 225' PROPOSED COMPLETION Chemical Injection Mandrel @ 1634' SCSSV (Self Equalizing) @ 1650' 3.813" X @ 4,543' Upper Sterling Perfs 4725-4803' MD (4085-4160' TVD) BHP=1712 psi; BHT=90 deg F Lower Sterling Perfs 5395-5486' MD (4732-4819' TVD) BHP=2088 psi; BHT= 96 deg F 9.8 ppg NaCl/6% KCI Packer Fluid 2.813" X @ 5,951' MD Upper Beluga Perfs 6127-6276' MD (5773-5867' TVD) BHP=2693 psi; BHT= 108 deg F Beluga Perfs 6679-6701' MD (5950-5971' TVD) BHP=2796 psi; BHT=109 deg F Possible Future TTRC: Lower Beluga Perfs 6873-6918' MD (6132-6173' TVD) BHP=2902 psi; BHT=111 deg F Possible Future TTRC: Lower Beluga Perfs 7168-7274' MD (6405-6503' TVD) BHP=3060 psi; BHT= 114 deg F TD: 8,160' MD/7,301' TVD -B 22 1,16 20" 0.875" @ 381' MD Tubing above SCSSV equipped with non-conductive centralizers 9.6 ppg NaCl/6% KCI Packer Fluid 13-3/8" 72# @ 2,265' MD 4-1/2"" 12.75# L-80 CSCB IPC Tubing Gravel Pack Packer @ 4,593' MD End of Tubing/Seal Assembly at ^'4,608' MD 3-1/2" L-80 BTS -8 Isolation Pipe 2.813" Iso Sleeves (4699'&4806') CLOSED 5-1/2" 20# P-110 Blank and 0.008" Ga 316L Wire Wrapped Screen Gravel Pack Packer @ 4,813' MD 3-1/2" L-80 BTS -8 Isolation Pipe 2.813" Iso Sleeves (5352' & 5489') CLOSED 5-1/2" 20# P-110 Blank and 0.008" Ga 316L Wire Wrapped Screen Isolation Packer @ 5,496' MD Gravel Pack Packer @ 5,997' MD 3-1/2" L-80 BTS -8 Isolation Pipe 2.813" Iso Sleeves (6112' & 6279') CLOSED 5-1/2" 20# P-110 Blank and 0.008" Ga 316L Wire Wrapped Screen Gravel Pack Packer @ 6,286' MD 3-1/2" L-80 BTS -8 Isolation Pipe 2.813" Iso Sleeves (6677'& 6704') CLOSED 5-1/2" 20# P-110 Blank and 0.008" Ga 316L Wire Wrapped Screen Sump Packer @ 6711' MD Mule Shoe (end of Iso Assy) @ 6716' MD PBTD - 8,041' MD/7,197' TVD 9-5/8"53.3# P-110 BTC Mod @8,122' MD/7,268' TVD , olp- _T _U Jim I ie BJET ed - f _� T F� in i r -F _.I AN!"S J4 J.4-1 If -f-- J'I il tt! -01 1 Lf M D "n jr- T if I ik� J M I 4 �T CTI J A Jj Ll Ill I H J i J J I I I I f j ]JA jI J-111 t -i r ILLL j T ItT Tlij it 4 IL L -:-,c IJ L 1-14 - 1 J-777 7 4! T -3 9 J 77 I' . . . . . . . . . . . . J. j X terl j ag 5395.; 486 TIM EE 541M ¢It _"i. j;;p _j 1: ell 01 4 A Jj Ll Ill I H J i J J I I I I f j ]JA jI J-111 t -i r ILLL ItT Tlij it 4 IL L -:-,c IJ L 1-14 - 1 J-777 7 4! T -3 9 J 77 I' . . . . . . . . . . . . J. j X terl ag 5395.; 486 TIM 541M ¢It _"i. j;;p _j 1: a 0 0 , i _ , W r ti II I , too W .. 1- A J '. Mr I - _J-.,-- IIII - _I 1 fl - I J I _. 7 II�� L i' �1� - 7 - =' - tdifi LN I - I I I f l II II I'll IIIlII I I jj _-1 _ JAf -- J -- 1I , r 1 tl. 4725_,1 j t Di IrI .r' �_.I:"I,' -414 ISI' A 1 ' Ups5 17 7F {A I -. ingi Pte© I sed I- 'poirs �4' 480 In le 1 I_li 1_ �`I I P i i If - 1 f 1 1-7- I i IL11 II Q. 111 I -J I -� ( I ! J III I �- Imo- j I - I�� l - I I "_^ i _I ---- _ '; �I 11 c � I -- II J„ i I�-(; f I I i� _ _ Regulations 20 AAC 25.283 s onse Section (a)(1). An affidavit showing that all owners, No other owners oroators within a landowners, surface owners, and one-half mile radiu the current operators within a one-half mile radius of wellbore. the current or proposed wellbore trajectory have been provided notice of An affidavit h been submitted with operations. the drillin lication Section (a)(2). A plat showing the well location and No water wells within one-half mile identifying any water wells located within radius. a one-half mile radius of the well's surface location and further identifying Refer to: any well penetrations (all well types) Attachment A - KLU A -2A Top of within one-half mile of the current or Beluga and proposed wellbore trajectory and Attachment B — KLU A -2A Top of fracturing interval and the sources of the Sterling information used in identifying such wells. Section (a)(3). Identification of freshwater aquifers and Offshore Well; no water wells within the geologic name and depth (MD and one half mile radius. TVD) to the bottom of all freshwater aquifers within the one-half mile radius. See Attachment C — KLU A -2A Freshwater Aquifers in Vicinity. Section (a)(4). A plan for baseline water sampling of No water wells within '/ mile of current water wells prior to hydraulic fracturing. wellbore trajectory; no sampling Water sampling consists of collection of required. baseline water data pre -fracture, within a one-half mile radius of the current or proposed wellbore trajectory. Section (a)(5). See below table for casing sizes and Detailed casing and cementing specifications. See section (a)(6) for information. cementing information. Hole Tubular epth TVD, OD (in) ID (in) Weight (ppq Grade Conn IYP Collapse Cement T ft (psi) (psi) Top (ft) JU707 380 20 18 .376 166.56 X-56 XLC- SE995 13.375 12.347 72 N-80 BTC 5380 3100 219 301 9.625 8.535 53.5 L - 80 BTC - 7930 6620 UNK Sundry Application to Fracture, KLU #A -2A, Furie Operating Alaska Sundry Application to Fracture, KLU #A -2A, Furie Operating Alaska 20 AAC 25.283 Response Section (a)(6). An assessment of each casing and cementing See Section (a)(5) for casing sizes and operation performed to construct or repair the well specifications. with sufficient supporting information, including cement evaluation logs and other evaluation logs Refer to Attachment D for KLU A -2A 13-3/8" approved by the commission, to demonstrate that Casing and Cementing Details, Attachment E casing is cemented below the base of the for KLU A -2A 9-5/8" Casing and Cementing lowermost freshwater aquifer and according to 20 Details, and Attachment F KLU A -2A 9-5/8" AAC 25.030 and that all hydrocarbon zones CBL (NOT PRESENT). penetrated by the well are isolated; Section (a)(7). 20" — Riser WQ Seals tested to 2,000 psi Pressure test information if available and plans to 13-3/8" — 2,700 psi for 30 minutes on 06/29/16 pressure test the casings and tubing installed in 9-5/8" — 3,500 psi for 30 minutes on 07/18/16 the well; 4-1/2" Tubing to be tested to 3000 psi for 30 minutes with test plug. Section (a)(8). See Section (a)(5) for casing sizes and Accurate pressure ratings and schematics for the specifications. wellbore, wellhead, BOPE, and treating head. Refer to Attachments G — KLU A -2A Wellhead + Tree Schematic, Attachment H — KLU A -2A Completion BOPE Schematic and Attachment I — KLU A -2A Treating Head Schematic Section (a)(9). Data for the fracturing zone and confining zones Fracturing Zones: Beluga and Sterling including lithologic description, geological name, Sandstones measured depth (MD) and true vertical depth Confining Zones: Interbedded Shales (TVD), measured and true vertical thickness, and estimated fracture pressures for the fracturing Refer to Attachment J — Proposed Fracturing zone and confining zones. and Confining Zone Details and Attachment K - Predicted Formation Pressures and Fracture Geometry Section (a)(10). The location, orientation, and a report on the See Attachment L - KLU #3 Casing and mechanical condition of each well that may Cement Details (CBL submitted prior). No transect the confining zones and information issues apparent. sufficient to support a determination that such wells will not interfere with the containment of the Maximum anticipated frac half-length is 60.4 hydraulic fracturing fluid within the one-half mile feet; KLU A-3 is +2000 feet away and will not radius of the proposed wellbore trajectory; be impacted by frac pack operations at KLU A -2A. For Estimated Hydraulic and Propped Fracture Lengths, Refer to Attachment K. Sundry Application to Fracture, KLU #A -2A, Furie Operating Alaska Regulation e Section (a)(11). The location, orientation, and geological datas known or suspected faults and fractures thatt are +2500 ft away from KLU A- 72Aand transect the confining zones, and informationractures in danger of contact by short (Refer to Attachment K) sufficient to support a determination that anyfaults and fractures will not interfere withttachment M — Plan and containment of the hydraulic fracturing fluid within the one- half mile radius of the proposed wellbore Structural Cross Section Showing Local trajectory; Faults Section (a)(12). A detailed scope of the proposed hydraulic fracturing program including, but not limited to, the Please refer to Attachments N, O, P and Q for the preliminary frac pack design pumping procedure by stage where applicable, with a chemical disclosure based on the total modeling of the separate intervals. amounts and volumes per well including; Additional details to be provided in final (post job) Schlumberger submittal. Section (a)(12)(A). The estimated total volumes planned; Estimated total fluid volume injected for stage: up to 24,555 gal (584 bbls). Estimated total fluid volume injected for well: up to 83,050 gal (1,977 bbls). Refer to Attachment R - Frac Pack Volume Section (a)(12)(B). Summary — KLU A-2A. The trade name, generic name, and purpose of all base fluid(s) and additives to be used. The Refer to Attachment S, Schlumberger Prejob Disclosure Report estimated or maximum rate or concentration of each additive shall be provided in appropriate measurement units; Section (a)(12)(C). The chemical ingredient name and the Chemical Abstracts Service (CAS) Registry, as published by Refer to Attachment S, Schlumberger Prejob Disclosure Report. the Chemical Abstracts Service (a division of the American Chemical Society, see www.cas.org), for each base fluid and each additive used. The actual or maximum concentration of each chemical ingredient in each base fluid and additive used shall be provided in percent by mass. In addition, the actual or maximum concentration of each chemical ingredient in the hydraulic fracturing fluid shall be provided in percent by mass. Freeze-protect fluids pumped before and/or after hydraulic fracturing should not be included; Section (a)(12)(D). Proppant: The estimated weight or volume of inert substances, including proppants and other Econoprop 30/50: up to 75,500 lbs/stage; 256,800 lbs estimated total for well L.substances injected; KLU A-2A. Refer to Attachment R. Sundry Application to Fracture, KLU #A -2A, Furie Operating Alaska Regulation Section (a)(12)(E). The maximum anticipated treating pressure and information sufficient to support a determination that the well is appropriately constructed for the proposed hydraulic fracturing program. Upper Beluga Zone (Worst Case): Estimated Treatment Details Annulus Fluid Density (ppg) 9.8 Maximum Treating Fluid Density (ppg) 13.4 Proposed Pump Rate (bpm) 18 Applied Annulus Pressure (psi) 0 Estimated Resulting Annular Net Pressure from Ti Screenout si 422 Maximum Treating Pressure (psi) (Including 1000 psi Overpressure for Annular Pack) 3,280 Proposed Surface Iron Test Pressure (psi) 7,000 Response Refer to the below Estimated Treatment Details, String Pressure Ratings, and Packer Pressure Rating tables. Listed data is from Upper Beluga proposed treatment (i.e. maximum rate and pressures), with estimated worst case data (no annulus net pressure above hydrostatic). For additional information refer to Attachment T — Predicted Maximum Pressure During Frac Pack Fracturin Strin Pressure Ratings Item Depth Tubing Annulus Differential Equipment % Surface Iron (ft MD) Surface Pressure (psi) Pressure (psi) Pressure (psi) Rating (psi) Loading 3,280 NA 3,280 15,000 32.0% 3-1/2" NC38 3,000 4,100 1,284 2 816 21,636 ° 13.0 /o _T (80% RBW) 4" XT 39 5,997 4,900 2,704 2,196 17,820 12.39% (80% RBW) Packer Pressure Rating Pressure Pressure Differential Below (psi) Above( si) Pressure (E 4,910 2,704 2,206 Section (a)(12)(F). The desired height and length of the proposed fracture(s), including the calculated MD and TVD of the top of the fracture(s) accompanied by a description of the methods and assumptions used to determine designed fracture height and length; Equipment Rating (psi 10,0000 % Loading 20.6% Refer to Attachments N, O, P and Q (Figures 3, 4, 5 & 6) for the preliminary frac pack geometry of the separate intervals. This fracture modeling uses properties (young's modulus, poisson's ratio) estimated from 2013 KLU #3 frac packs to estimate formation Properties. Sundry Application to Fracture, KLU #A -2A, Furie Operating Alaska 4 Regulation Section (a)(13). Response A detailed description of the plan for post fracture wellbore cleanup and fluid recovery Reversed out fluid and proppant to be through to production operations. captured and transported back to shore for proper disposal. Well will be flowed back to platform facilities via permanent flowline. Frac fluids and other non-produced fluids will be transported to shore via existing bulk pipeline. Aqueous Section (b) fluids to be disposed of properly. When hydraulic fracturing through production Utilizing drillpipe fracturing string. Not casing or through intermediate casing, the applicable. casing must be tested to 110% of the maximum anticipated pressure differential to which the basing may be subjected. If the casing fails the pressure test it must be repaired or the operator must use a temporary casing string (fracturing string). Section (c) When hydraulic fracturing through a fracturing string, the fracturing string must be into The drillpipe fracturing string will be tested to stung a liner or run on a packer set not less than 100 ft +110% of the anticipated maximum surface injection pressure. This test will occur MD below the cement top of the production or intermediate casing and tested to less after setting the packer when the service tool is not than 110% of the maximum anticipated pressure differential picked up above the packer and the packer setting ball seat is sheared out (nominal to which the fracturing string may be subjected. shear-out pressure is 4200 psi). The drillpipe fracturing string test will be a five minute hold period at between 3500-3700 psi at surface (5% or 175 psi maximum allowable pressure drop in the 5 minute hold) before increasing pressure to shear the seat. Refer to Attachment T - Predicted Maximum Pressure During Frac Pack Section (d) A pressure relief valve(s) must be installed — A pressure relief valve will be placed between on the treating lines between pumps and wellhead the pumps and the fracture head and will be to limit the line pressure to the test pressure P determined set for —6,500 ±200 ( )psi to be 500 psi below the surface iron test pressure of in 7,000 in (a)(12)(E) of this section; the well psi. must be equipped with a remotely controlled shut-in device unless the operator The fracture head will have dual hydraulically requests and obtains a waiver from the commission. remote-operated valves for shut-in purposes (Refer to Attachment I — KLU A-2A Treating Head Schematic Sundry Application to Fracture, KLU #A -2A, Fude Operating Alaska Regulation Section (e) The placement of all hydraulic fracturing fluids shall be confined to the approved formations during hydraulic fracturing. Regulation Section (f) If the surface casing annulus is not open to atmospheric pressure, then the surface casing pressures shall be monitored with a gauge and pressure relief device while hydraulic fracturing operations are in progress; the annular space between the fracturing string and the intermediate or production casing must be continuously monitored; the pressure in such annular space may not exceed the pressure rating of the lowest rated component that would be exposed to pressure should the fracturing string fail. Response Only the approved formation will receive fracturing fluids. Attached Stimplan models (Attachments N, O, P and Q, Figures 3 and 4) documents that the confining layers limit upward/downward extension of the fracture. Response Surface casing annulus will not be open to atmospheric pressure. Surface casing pressure will be checked before and after fracturing operations. Pressure in the fracturing string by production casing annulus will be continuously monitored through the job. If any sign of a leak is detected, the job will be shut down immediately. A mechanical pressure relief valve will be installed and set to a pressure lower than the casing test pressure of 3500 psi. Sundry Application to Fracture, KLU 4A -2A, Furie Operating Alaska Attachment A - n C G- KLU A2 A (CONDOR) 5222 , ry BELUGA PENETRATION POINT 5,600K I ST 2 2278 FEET FROM KLU #3 ....... ... KLU Q fsj4CB SRST RN -499 9 ha LU -4926 KLU 47 er 54 O qKLU �I , s coo TOP BELUGA 100, Cl Shell Scale —43 Go - -------- Attachment B - Top of 47 fJNJ TOP STERLING 100, Cl M KLU h, A 1 1 :•KLU #3, KLU #A2 50-733-20610-00-00 1 1 1 11 1 1, 11 11 voovv -� xoomEgon I • �, ST ��IilYilam"' �SCI ' SS 'Image50-733-20449-00-00 111 III � 1 !�� a .'!11 �� •11 •� 1`. �. r ��.. -'� --ter Aw .. .• v �•/f 1! ■ �� 1!: M 11 �wie X44 - f!I 11 a1r1 �, �� 1 � �� ■�� 'r� 111 t11 � � .. •. ^ 11 11 !�' Iw"..ee /f 11 �.. 1� c I Fri, ~ —.jam�� ` ir , 0 $i 111 �r.�..i.I.4' 111 111 Pow ' moll" `� .. w•'�••�•� �i+i�A..1t _�"'�`z`a"'�ur� �1rl�rc i � � • g�-�:.. � � All ii, �,t4i_ +AIS y ,-.re vim- Z!�� rtllr 111 � _� • e 9. 7 40" � J'_ .i --+.y i! e�,e _ -.. .111 ,"!1 1I�-a 1 i i xf! 6111 • 1I� '-'"1 1 6500 .—:� _mow r�` '� --•� ! � **_ [i5�, t • si�c" 7500 _ - r T :011 11 11 # NFL ILLa .111 :111 r �'� :lit illl _ _ !'.�" yyyi, - • 111 • 111 ��-,reoril� 1'�'�i41� M KLU h, Detail FURIE OPERATING ALASKA, LL CASING AND CEMENTING DETAIL CASING/LINER SIZE: 13-5/8 IN. CASING TYPE: 72#, N-80, BTC SET @ 2265 MD 1994.57 TVD DATE: 6/25/16 (CSG ON BTM) WELL INFORMATION AREA: Kitchens Lights Unit BLK: KLU MLLW 121 WELL# KLUA-2 HOLE SIZE: 17.5 TOTAL DEPTH: 2284 MD 2205 TVD WATER DEPTH: 108 LAST CASING STRING: 20 IN. SET @ 381 MD 381 TVD RKB - Water: 121 LOG OF CASING/LINER STRING (BEGIN @ BOTTOM, LIST ITEMS IN ORDER RUN) RKB - ML: 225 # OF PIECES O.D. MAKE-UP DEPTH RKB ITEM - MAKE - DESCRIPTIC)N at/CT Tann 1 1 13 375 11-lnaf ( i., o l v Iv -25U 16.9b 1 2184.16 13.375 Pu Joint o l - Ivuu 6 Z1ZZ.3.45 1 188..76 Han er 72 BTC N- 80 7A 1 13.375 Landin Joint BTC 1.26 1 13.375 Hup Joint 72 BTC N-80 39.81 72 BTC N-80 25.10 rACIWf'- INVCKI'MOV G JTS CUT-OFF & LANDING SUBTRACT 64.91 ADD KB TO CUT-OFF LENGTH 54.94 JTS LENGTH CASING/LINER SETTING DEPTH 2265.00 ---------------------------------------' TOTAL LENGTH OF STRING 2274.97 SUBTRACT NON -CASING ITEMS 4.92 ADD FULL JTS LEFT OUT 15 556.69 TOTAL 0 2826.74 TOTAL CSG DELIVERED (W/O THIRDS)?R3R 7A CEMENTING DETAILS STAGE # OF SX 1 900 2 411 CEMENTING COMPANY - II LL/J (mass U, wi U.US gps U-47 (defoamer), 0.65 gps D-75 (extender) b I 1 19 I 589 (Class G, w/ 0.2 gps D-47 (defoamer), 0.25 gps D-168 (fluid loss), 0.05 gps D-230 (disperant) CENTALI7FR PI erI:eeFUT MAKE I TYPE Davis Lynch Bow Spring NO. 1 I PLACEMENT 10' above casing shoe with 2 stop collars @ 2255' 1 on every joint from 2184' to 1852', every other joint from 1770" to 278" Antelope Solid Body 27 JOB DETAILS TIME CIRC PRIOR TO CEMENTING: HRS. FULL RETURNS THROUGHOUT JOB? (Y/N) Y EST. MUD LOSSES: 0 BBL DISPLACED CEMENT WITH 325 BBL OF _ 9.4 ppg Mud BUMPED PLUG? (Y/N) Y BUMPED W/ 1500 PSI FLOATS HELD? (Y/N) Y ESTIMATED BBL CEMENT TO SURFACE 120 EST. TOP OF CEMENT 54.94 CIP @ 23:00 hrs Cemented String Wt: NA Weight set on slips: NA SUPERVISOR(S): James Pritchard / Dale Munger MRI (VER. 1.0-5/30/09) Details FURIE OPERATING ALASKA, LL CASING AND CEMENTING DETAIL CASING/LINER SIZE: 95/81, IN. CASING TYPE: 53.5 # L-80 BTC SET @ 8122' MD 7267' TVD TVD DATE: 7/16/16 (CSG ON BTM) WELL INFORMATION AREA: Kitchen Lights unit BLK: MLLW 104 WELL # KLU A2A HOLE SIZE: 12 1/4" TOTAL DEPTH: 8160' MD 7301' TVD WATER DEPTH: 104' MLLV� LAST CASING STRING: 13 3/8" IN. SET @ 2265 MD 1965' TVD RKB - Water: 121' LOG OF CASING/LINER STRING (BEGIN @ BOTTOM, LIST ITEMS IN ORDER RUN) RKB - ML: 225 # OF #/FT 1 1 9.625" 1 9.625" 88 Casing Joints si.b 1 9.625" Pu Joint Marker Jt 3481F44 1 9.625" 119 CasingJoints CASING/LINER SETTING DEPTH -------------------------------- 1 9.625" Han er 5.53 -------' --------- CASING INVENTORY 7 JTS SUBTRACT CUT-OFF & LANDING JTS ADD KB TO CUT-OFF LENGTH 64.91 54.94 OTALLENGTHOFSTRING 207 I LENGTH 8132.26 CASING/LINER SETTING DEPTH -------------------------------- 8122.29 ' SUBTRACT NON -CASING ITEMS 5.53 -------' --------- ADD FULL JTS LEFT OUT ETIDELIVERED 7CS 25 979.37 TOTAL 232 9106.10 (W/O THRDS) CEMENTING DETAILS f10R ICL1—L1n —11M. u.,_ 3TH RKB TOP 8120.47 8081.32 8040.98 8039.73 8002.11 4520.82 4500.61 50.40 47.65 9.95 -10.26 csg 1 Solid Body on every joint from 7374'- 6579' 1 Solid Body on every joint from 6376'- 6027' 1 Solid Body on every joint from 4903'- 4628' JOB DETAILS TIME CIRC PRIOR TO CEMENTING: 0 HRS. FULL RETURNS THROUGHOUT JOB? (Y/N) N EST. MUD LOSSES: 480 BBL DISPLACED CEMENT WITH 569 BBL OF 8.6 Seawater BUMPED PLUG? (Y/N) BUMPED W/ PSI FLOATS HELD? (Y/N) Yes ESTIMATED BBL CEMENT TO SURFACE EST. TOP OF CEMENT CIP @ 6:10 Cemented String Wt: NA Weight set on slips: Mandrel hanger 4c U SUPERVISOR(S): James Pritchard/ Isaiah Del Toro MRI (VER. 1.0-5130109) Attachment H KLU A -2A BOP SchemL_ic RKB , 8.00 ---------- , i RKB to Deck 67.00 Proposed length of inner barrel to Flowline 25.00 , — ft Stick in RKB Bottom section Bellnipple28.33 i------------------------------ --------------------------- A--. i , B/NIPPLE LENGTH 12.00 � , , 12.00 , , , , , , TOP of ANNULAR Flange 40.33 , , ANNULA _ , Shaffer 13.5/8x5K top studded BX160 4.51 Bottom flange 13.5/8x5K BX 160 L— , , 13 5/8" BX159 10m by 13 5/8" BX160.SLn DSA ____-___ MyY`ame Cameron Type U 13.5/8 x 10K i� ♦ , 2 7'8"x 5" .:. ' ve5 55R 46.66 ------------- A �° , , Bind Shear �(' C i Kill lige Choke Lll1e Cameron Type U 13.5/8x10K + ISR Shear Rams cw booster - - ♦ , 3.47 Cameron Type U 13.5/8 x 10K VBR 52.16 Flanges 13.3/8x10K BX159 _-- ILNi 13 5/8 Riser , 6.54 , , .................................................................. JL .. _!.............. RKB To Unihead 63.50 ................................ - Fastlock Adapter 3.10 ttachment I --,T-LU A -2A Treatina HF d Schemati Customer: Furie Rig: NA Rig Phone: Area: A aka Well: N/A Contact OCSG: NIA AFE: N/A Ship Date: Head Type: Primary Job 4: N/A Revision: Drawn By: .larnh EnY Date _ a/2aLV Workstring vera II Lena HANGER FLOW BLOCK: W/4-318" ACME PIN X 3" 15M WP THREAD W/LIFT NIPPLE 3-1/2" SHANK a 6-1/2" OD DONUT I %\ 3" 1502 Thread Serial Number: 16183 Length: 5.37' PLUG VALVES: 3" 15M WP MSI W/4-3/8" ACME BOX X BOX Serial Number: 38897 Actuator: Hydraulic Length: 2.35' _ N/A NA Concentric N11 ANN) T 0 0 L R1 N T A L S IF 17 RR, A SUPERIOR ENERGY SERVICES COMPANY tion T e: 4-3/8" ACME .UB:4-3/8 of Pin: N/A Box OD: 3.00" e U Tor ue: 8000 ke U Tor ue: W- 9000 e U Tor ue: 10000 ion T e: 4-3/8"ACMEof Box: N/A: Pin ID: 5.75" SUB: 4-3/8 ACME PINX 4-3/8" ACME PIN Connection Taj e: 4-3/8" ACME C ross Over Tensile of Pin: N/A Serial Number: 20775 Pin ID: 3.09' Length: 37 Min Make U Tor ue: 8000 Rec. Make U Tor ue: 9000 Max Make U Tor ue: 10000 PLUG VALVES: 3" 15M WP MSI W/4-318" ACME BOX X BO Connection T e: 4-3/8" ACME 38896 --f Tensileof Box: N/A Serial Number: Box OD: s �� Actuator: Hydraulic Length: 2.35' SUB: 4-3/8" ACME PIN X 3-112" IF MOD PIN Serial Number: 21270 Length: 1.16' PUP JOINTS: 3-1/2" 13.301f S-135 X 6' LG W/ 3-1/2" API IF CONN Serial Number: 77390 Length: 6.08' Connection Type: 4-3/8" ACME Tensile of Box: 260,000 15K Box OD: 5.75' Min Make U Tor ue: 8000 Rec. Make U Tor ue: 9000 Max M ake U Tor ue: 1000D ConnectionT e: 4-3/8" ACME Tensile of Pin: 260,000 15K Pin ID: 3.oa' Connection T e: 3-X" IF Tensile of Pin: NA Pin ID: 2 78" Min Make U Tor ue: 10000 Ree. Make U Tor ue: 11500 Max M ake U Tor ue: 12100 Connection T e: 3-%" IF Tensile of Box: NA Box OD: 4.75" Customer: Furie Rig: NA Rig Phone: NrA Area olacka OCSG: NIA Well AFE: NIA Contact: N/A Ship Date: N/A �•"��* NA Concentric Head Type:Back Up Job #: N/A Revision: Connection T e: Drawn By Fnr Tensile of Box: N/A r I ]I E ANN) T 0 0 L RFNTA1.S —Jacnh Date: 6L29/1R Workstring: __IF Overall Lenath:_ A SUPERIOR ENERt3Y SERVICES COMpANy 20.80' HANGER FLOW BLOCK: W/4-3/8" ACME PIN X 3" 15M WP THREAD W/LIFT NIPPLE 3-1/2" SHANK 8 6-1/2" OD DONUT 3" 1502 Thread Serial Number: 16106 Length: 6.38' PLUG VALVES: 3" 15M WP MSI W/4-3/8" ACM E BOX X BOX Serial Number: 38898 Actuator: Hydraulic Length: 2.35' pmmlEi Connection T e: 4-3/8" ACME Tensile of Pin: N/A Pin ID: 3.00" Min Make U Tor ue: 8000 Rec. Make U Tor ue: 9000 Max Make U Tor ue: 10000 Connection T e: 4-3/8" ACME Tensile of Box: N/A Box OD: 5.75" SUB: 4-3/8" ACME PIN X 4-3/8" ACME PIN Connection T e: 4-3/8" ACME Crossover Tensile of Pin: N/A Serial Number: 39492 Pin ID: 3.00" Length: 1.78 Min Make U Tor ue: 8000 Rec. Make U Tor ue: 9000 Max Make U Tor ue: 10000 PLUG VALVES: 3" 15M WP MSI W/4-318" ACME BOX X BO Connection T e: 4-318" ACME N/A _ Te�sileofBox: Serial Number: 38895 ��I Box OD Itet,. Actuator: Hydraulic Length: 2.35' SUB: 4-3/8" ACME PIN X 3-1/2" IF MOD PIN Serial Number: 21924 Length: 2.21' 0 PUP JOINTS: 3-1/2" 13.30# S-135 X 6' LG W/ 3-1/2" API IF CONN Serial Number: 21895 Length: 5.73' I Connection Tvoe I of Pin: 3.00" Wtion T e: 3-%" IFof Pin: NA2.71"e U Tor ue: 10000ke U Tor ue: 11500e U Tor ue: 12100ion T e: 3-%" IFf Box: NA: 4.73- Appendix J - Proposed Fracturing and Confining Zone Details MD TVD True Proposed Proposed Fracturing Confining Thickness Vertical Fracturing Fracturing Zone and Zone and of Proposed Thickness of Zone (MD) Zone (TVD) Description Description Fracturing Proposed Zone (ft) Fracturing Zone (ft 6679- 5950-5972' Beluga Beluga 6701' MD TVD Sandstone Interbedded 22 22 Shale Upper Upper 6127- 5430-5571' Beluga Beluga 6276' MD TVD Sandstone Interbedded 149 141 Shale 5395- 4732-4819' Lower Lower Sterling 5486' MD TVD Sterling Interbedded 91 87 Sandstone Shale 4725- 4085-4160' Upper Upper Sterling 4803' MD TVD Sterling Interbedded 78 75 Sandstone Shale Appendix K - Predicted Formation Pressures and Fracture Geometry Estimated Reservoir Fracturing n g Estimated Confining Estimated Estimated Zone Pressure Zone Zone Hydraulic Propped (psi) Fracturing pressure Fracturing Frac Half Frac Half Pressure (psi) Length (ft) Length (ft) si Beluga 6679- 2,796 3,588 psi 3,688 psi Above 32.6 31 6701' MD 3,717 psi Below Upper Beluga 2,693 3,356 3,527 psi Above 6127- 3,616 psi Below 40.2 38.6 6276' MD Lower 5395 Sterling ,088 2 751 2,924 psi Above 46.7 45.7 2,992 psi Below 5486' MD Upper Sterling 4725- 1,712 2,307 2,502 psi Above 60.4 58.0 2,562 psi Below 4803' MD 7"-9-5/8" and Cementing Details CONFIDENTIAL MAIr - .. _3-3/3" Casing and v—AL.■ LFMJLLILLNU KCVUKT DATE FIELD API NUMBER RIG AFE PERMIT NUMBER 5/26/13 Kitchen Lights Unit 733-20610-00-00 SPARTAN 1512033-003 213-015 COUNTY STATE REPORT NO. DEPTH - MD/TVD PROGRESS Kenai Pen. Bro. AK 38 PROJECTED DEPTH SUPERVISOR 10393 110391 PHONE NUMBER DAYS SINCE SPUD 0 10,500' MD 30,500'TVD LAST CASING / DEPTH Keith Matt/James Graham 907-690-3260 30 7" / 10,011' SHOE TEST (PPG) LAST BOP TEST RKB/MUD LINE Run 7" 35 # P-110 L7C 7" 35# 12'5 5/22/13 202• 523 c at 10011', 15 s m 260 i, finish circulatin with 8 vols/ minute @ 1020 inm mudline hanger 269'. Break si, fu4retumsCR/down Weathertordf FQ I?m uYdril for gement headgistring circulation Eorerast Displace cement, bump plug, release pressure, open ports on Hanger, circulate out 13 3/8" head and lines. HOURS & 9 7/8" annulus, spot sugar pill, close annular and pump 5 bbls, shut in and -waft cement 6 hrs. START END DETAILS OF OPERATIONS HRSDUR 0:00 11:00 11:00 12:00 12:00 15:00 15:00 20:00 11.00 Pick up and run 7" casin . Ran 118 its 7" 35# P-110 LTC casing, 4986.61', Ran 88its 7" 35# 0-125 LTC casing, 4307.55'. Total 7" is 9294.16'. Total displacement 417 bbls. 1.00 Chan a out 7" —billtools with 9-7/8tools. " 3.00 Pick u and run 9-7/8" casing. Ran 17 jts 9-7/8" 62.8#-125 h urn 523 casing, 683.49'. Total displacement 461 bbls includingthe 7"). Landed casing in the hanger at 269. Top of han er is at 266.45'. 7" Shoe is at 10011, 4.67' marker Y is at 6922' from surface. 5.00 Circulatin bottoms up. Sta a up mud um s, 15 strokes er 240 minute, i, increasing pumps @ 10 spm intervals, full returns while pumping, @ 8 bbls/minute had 1020 i. 20:00 23:00 3.00 Ri down Weatherford circulatin tool make u -over 23:00 0:00 x subs for cement head, 'LO cement head and lines for same. Held re 'ob safe[ meetin with crews. 1.00 Pum 40 bbs s acer with ri um swapover to BJ cement , unit dro bottom lu um 5 bb water load to wi er lu test lines to 3500 si mix & um 1834 sacks class G cement + 15%bwoc BA -90 +0.005 lbs/sack Static Free + 0.8 %bwoc R-3 + 1.4 % bwoc, FL -63 bwoc, CD -32 + 1 als/100 sack, FP -6L +0.5 %bwoc, Sodium Metasilicate + 11%. 721 bbl slu @ 12.0 NO ACCIDENTS, INJURIES OR SPILLS REPORTED Safet Topics Discussed: Runnin casin ,cementing same. Compl with all a livable rules and re ulations. Workin around High Pressure Lines. 24.00 MUD RECORD IN TIME 21:00 DEPTH 10393 WEIGHT 11.1 VISC. 68 CASING RECORD OUT SIZE GRADE WT CONN SHOE DEPTH PUMP NO. 1 PUMP DATA 30" 1.5" Wall X5256 456 PPF Tencom FID 369' MAKE 2 3 13 3/8" N-80 72# GD GD EMSCO BTC 1903' MODEL PZ10 PZ10 F81600 9-7/8" -125 62.8# H dril 523 NA STROKE 10" IV' 7" P-110/ -125 PV 21 YP 24 35# 12" LTC 10011' LINER SIZE 6,5 6 5 6 SPM KLU#3 DDR 38 CONFIDENTIAL KLUp3 DDR 39 FURIE 0 Pe-f-at,"P, g A I a s kq L L C CONFIDENTIAL � f FUME CONFIDENTIAL AAI. ., — . v■ 49-L-Al�l�7 KCYVKI DATE FIELD API NUMBER RIG AFE PERMIT NUMBER 4/30/13 Kitchen Lights Unit 733-20610-00-00 SPARTAN 151 2013-003 213-01B COUNTY STATE DEPTH - MD/TVD PROGRESS PROJECTED DEPTH SUPERVISOR Kenai Pen. Bro. AK 1950'/1950' PHONE NUMBER 0 10,230' MD 10,230' TVD Frank Johnson/Tommy Sikes 907-690-3260 LAST CASING /DEPTH SHOE TEST (PPG) LAST BOP TEST SUMMARY lRun 13 3/8" casing to 1903', landing hanger @ 269', rig up baker circulating head and circulate hole clean, cement 13 3/8" casing. Forecast Rig down cementers, and diverter system, HOURS REPORT NO. 12 DAYS SINCE SPUD 4 RKB/MUD LINE 202' DETAILS OF OPERATIONS START END HRS OUR 0:00 9:00 9.00 15:00 6.0 20:30 5.50 20:30 0:00 3.50 Continue to ick u 13 3/8" Float 'oint and install centralizers as er nmg— mntinue to ick up 13 3/8" casing, triWholeinstallingcentralizers as er m ram9:00 Picking up 13 3/8hangerointwelding stra s as er programlandin han er at 269' below rotary table15:00 Ri ing u circulatinghead, Circulate hole cleanassemblindul t g"S H w r working on dee wel Conducted re -cement job meeting with all ersonnel involved on rig floor and cement 13 yani casin . 24.00 NO ACCIDENTS INJURIES OR SPILLS REPORTED Safe Topics Discussed: Proper PPE while working on Texas Deck, Radio and flag ing communications, cold weather conditions MUD RECORD IN OUT CASING RECORD PUMP DATA SIZE GRADE Wi CONN SHOE DEPTH PUMP NO. 1 TIME 21:00 30" 1.5 Wall X5256 456 PPF Tencom FID 2 DEPTH 1950 13 3/8" N-80 72# 369' MAKE GD GD _ BTC 3 EMSCO FURZE Ope, 7tinp Alaska LLC CONFIDENTIAL n.r•. DATE aroma".■ V1nkiI_1.11rV KCi-UKI FIELD API NUMBERRIG AF PERMIT NUMBER 5/- COUNTY STATE REPORT NO. Kitchen Lights Unit 733-20610-00-00 SPARTAN 151 2013-003 MD/ DEPTH - MD/TVD 213-015 Kenai Pen. Bro. AK PROGRESS PROJECTED DEPTH 13 1950'/1950' SUPERVISOR PHONE NUMBER DAYS SINCE SPUD 0 10 230' MD LAST CASING /DEPTH 10,230' TVD Keith Matt/Tomm Sikes 907-690-3260 5 Y 13 3/B" / 1903' SHOE TEST (PPG) LAST BOP TEST RKB/MUD LINE SUMMARY Finished cementing 13 3/8" casing, lay down grout strip s, 202' g pick up annular, make rough cut on casing and lay down, nipple down bell nipple, annular. Forecast Finish nipple down, cut Flange off on 30 drive pipe, make final cut on 13 3/8" HOURS casing and weld on 13 3/8" casing head. DETAILS OF OPERATIONS START END HRS OUR 0:00 2:30 2.50 Mix and um 25bbi sweep, drop bottom lug with 5bbls, shut down and load to lu ,test BJ fines to 2500psi., mix and um 529bb1 lead cement at 12.-1 1/2.13 field 1410 sacks class G Cement + 0.005 lbs/sack Static Free + 2%bwoc Calcium Chloride + 0.4 % bwoc CD -32 + 1 al/100 sack FP -6L +2.2 % bwoc Sodium Metasilicate + 106.9% Fresh Water Mix and um Sibbls tail cement at 15.8 pg /yield 1.15 sacks class G Cement + 0.5% bwoc FL -63 + 0.005 lbs/sack Static Free + 0.25% bwoc 3.7 Calcium Chloride +0.5% bwoc CD -32 + 1 gals/100 sack FP -6L+ 43.7% Fresh Water Dro to lu , Pum 4bb15 tail cement at 2!)-022, displace and bump plug with 277bbis mud at 9.5 holding. pg., pressure up toM ats, got back ibbl float Full returns, calculated 37 bbls cement returned to surtace Cement in place at 0230 hrs. Estimated to of is 2:30 11:30 cement 3 289' via rout stringCement fell from 289' to 344' due to 27bbl volume required to kee hole full 9.00 La down dual grout sMng, start ny,,li down diverter discharge lines while monitoring well on tri tank, while waitin o ri in down diverter system at report time 11:30 12:30 1.00 12:30 17:00 4.50 Ri down stra s on conductor and diverter system, rig down cement head on 13 3/8" casing. 17:00 20:00 3.00 Break and remove bolts on annular to space. s ool, rig u and Ick u annular to make rough cut on 13 3/8" casing. Cut hole in 13 3/8" casing and drain, make rough cut on 13 3/B" 20:00 0:00 4.00 casing and lay down same. Set annular back down on spool, nipple down bell nipple and annular and set on upper deck. E-mailed AOGCC with BOPE ins ection request at 1430hrs. NO ACCIDENTS INJURIES OR SPILLS REPORTED Safe To ics Discussed: Proper PPE while working on Texas Deck, 24.00 Radio and Flagging communications, cold weather conditions MUD RECORD CASING RECORD IN OUT TIME 21:00 SIZE GRADE VJT PUMP DATA CONN SHOE DEPTH PUMP NO. 1 30" DEPTH 1950 2 3 1.5" Wall X5256 456 PPF Tencom FID 369' MAKE GD 133/8" _ N-80 72# ...,�� GD EMSCO BTC ionx� KLU 2lPi #2fi31A1 dee' ocily "_ KLUA4�abt ( BIU oi�ST KLJAW _. . ._ _.. �� ICLUA2 sbtC A2tC _. W v115 0 665 ft----�.0 I 1 $ IINIEf S If 3m1$If kid �p OO 0 3553It ►�.� 3553 f'-------4023 It ', t Nine: 1762.0 1775.0 1781.0 178f;0 1 0� ;rosslme: 33220 KLU #2 3198.0 KLU #3 796.0 1795.0 1797.0 1799.0 8 T5m330.0 3379.0 436.0 3456.0 1803.0 3535 ARCO SCI ST#2 318040 3476 0 3496 0 180 04.0 , -- d<�60 X66.0 Alp 2808 r`.. .. _ j� •� j �>� ii l// �. 0 90G Mor p REDACTED M. Guhl 1/12/2017 Attachment N CLU A -2A Beluga 66i..-6701' MD Frac Pack Design Modeling 050 FRACTURING, LLC. e To: Mr. Jack Burman July 18, 2016 Exploitation Technologies 07022016 Houston, Texas 77069 Re: Kitchen Lights Unit A -2A - "Beluga 6,679 ft. - 6,701 ft. MD" Sand Preliminary Frac Pack Design Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand was evaluated for a frac pack stimulation treatment in order to get a moderately conductive fracture to enhance production from this estimated 50 and reservoir. Reservoir properties for this well are an estimated reservoir pressure of 2,796 psi, an average porosity of 28%, an estimated permeability of 50 md, and an estimated BHT of 109°F. The result indicates a Folds -Of - Increase (FOI) of approximately 1.40 for a 30 ft. propped frac pack half-length with a conductivity of 6 - 8 lbs./sq.ft. �— Optimal Half -Length and Conductivity: Using the above reservoir properties, propped frac pack half -lengths (0 to 100 ft.) and conductivities (4 to 8 lbs./sq.ft.) were evaluated using a flowing BHP of 2,596 psi to determine the design propped frac pack half-length and conductivity. As can be seen in Figure 1, the optimum propped frac pack half-length is about 30 ft. with a conductivity of 6 - 8 lbs./sq.ft. With this, a FOI of 1.40 could be seen. Thus, a fracture half-length of 30 ft. length was chosen to ensure good production and was used as initial design goals. a U. m io V A U Figure 1 - Predicted FOI vs Propped Frac Pack Half -Lengths Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand 4.000 Ibtft"2 3221.1 and -ft 6.000 IbMA2 6"23—d- 442.3and-ft- - 8.000 Ib/ft^2 9663.4 and-fr- 20 en 60 80 100 Fracture 112 Length (ft) Stress Profile: A closure pressure of 3,588 psi (0.60 psi/ft.) was used and was based a reservoir pressure of 2,796 psi and a Poisson's Ratio of 0.25. The modulus in the pay sand was estimated to be 0.20 - 0.25 x 106 psi and in the bounding shale was 0.30 x 106 psi and was based on the frac packs around the same depths. Leak -Off Profile: The leak -off coefficients that were used are estimated to be 0.0075 - 0.010 ft./sq.rt. minute (this gives a fluid efficiency of 25% for the mini -frac) in the pay sand and in the adjacent layers estimated to be 0.001 ft./sq.rt. minute and was based on the frac packs around the same depths and perms. Proppant Selection: With this being an gas zone having a reservoir temperature of 109°F with a possible fines migration problem and a closure pressure estimated to be 3,588 psi, 30/50 mesh Carbo -Lite is recommended. Fracturing Fluid Selection: Since the bottomhole temperature is around 109°F, a 20# Borate Gel is recommended. Gel crosslink times should be halfway down the workstring (1-1/2 minutes with a 3-1/2" drill pipe) and break times should be around 60 minutes to 50 cp at 170 sec -1. Page 2 Preliminary Frac Pack Treatment Design: The preliminary design is shown in Table 1. The proppant schedule starts out with a 0.5 ppg stage and goes up to a maximum concentration of 12.0 ppg. The design injection rate is 6 bpm through the entire job and reduced for the annular pack (based on the results of the mini -frac rate may be increased for the frac pack). The resultant treatment calls for 6,500 gals. of gel and 30,300 lbs. of 30/50 mesh Carbo -Lite. The predicted point of the TSO is at the beginning of the 3.0 ppg stage going into the fracture. Prior to this point, the model predicted net BHTP (BHTP - closure P) is 142 psi with a corresponding average fracture width of 0.26 inches. Throughout the remainder of the treatment, the predicted net pressure increased to 540 psi (Figure 2) and was coupled with an average width increase of 0.95 inches. The resultant frac pack dimensions are a propped half-length of 31 ft., a maximum height at the wellbore of 72 ft., and an average conductivity of 9,450 and -ft (avg. in-situ conc. = 7.60 lbs./sq.ft.). These are shown in Figures 3 - 6 with the model 1/0 included in Attachment A Table A-1. Table 1 - Preliminary Frac Pack Design Schedule Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand 7 9 6 =_. 47 _ 3L•.3 31 2 r- Constant PPG Steps Schedule -_ -_--_ ---, W Fluid Ramp e-61unp Ramp I osh2n -Pan . �I Flou' Back Rate •BF0.1; ® - r' (0- Blessed -- -- Slurry Fluid Proppant Conc - - Volume Volume (PPC,) Rate �sr•:f (Vol Proppant pump Time Cum Time- Stage 1 PA -Gal 1.500M�W 'R7 -Gal Start Entl (BPRiI Fr _�;r) (hiLbs)min (min} Fluid Type Proppant T Type 2 0.5110.50 0.00 000 fi 0 O.Q000 O D 8.D 6 0 20P Borate Carbo EconoProp 250 F Lo g Tern13030 3 0.522GD 050 0.0 O.000O U 3 2.0 8.0 204 Borate Carbo EconoProp 250 F Lo g Term 30-50 4 0.5452.W 1.00 2.00 60 0.01*0 G 5 2.1 101 204 Borate Carbo EconoProp 250 F Lo Tenn 30-50 5 0.5673.W 5.0 0 OOW 1 0 2.2 123 204 Borate Carbo EconoProp 250 F Lo g Term 3D-50 5 2 6693.00 300 6.0 O.000D 1 5 22 145 204 Borate Carbo EconoProp 250 F. Lo g Term 30-50 1.53'0i2.W 12.00 6.D 0 OOW 15 0 _ 10.6 251 204 Borate Carbo EconoProp 250 F Lo g Term 30-50 12 QD 60 OOODD 120 6.1 312 204 Borate Caron EconoProp 250 F. Lo g Term 30-50 7 9 6 =_. 47 _ 3L•.3 31 2 r- Constant PPG Steps Schedule -_ -_--_ ---, W Fluid Ramp e-61unp Ramp I osh2n -Pan . �I Flou' Back Rate •BF0.1; ® - Figure 2 - Preliminary Frac Pack Design - Nolte -Smith Plot Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand Lu Time (min) Figure 3 - Preliminary Frac Pack Design - Frac Pack Penetration Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand Alaska - Beluga - 6679 - 6701 ft. HIMIMMEMI 3500 3600 3700 3800 3900 4000 MD ft At Closure 6640 6660 6680 6700 6720 6740 20 40 60 80 100 Fracture Penetration (ft) Page 4 VI IL Lu Time (min) Figure 3 - Preliminary Frac Pack Design - Frac Pack Penetration Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand Alaska - Beluga - 6679 - 6701 ft. HIMIMMEMI 3500 3600 3700 3800 3900 4000 MD ft At Closure 6640 6660 6680 6700 6720 6740 20 40 60 80 100 Fracture Penetration (ft) Page 4 E Y Figure 4 - Preliminary Frac Pack Design - Width Profile Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand Alaska - Beluga - 6679 - 6701 ft. 0 0 0 a 0 0 0 N 6640 MD ft 6660 6680 6700 6720 6740 Figure 5 - Preliminary Frac Pack Design - Conductivity Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand t•racture Penetration (ft) Figure 6 - Preliminary Frac Pack Design - In -Situ Concentration Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand Fracture Penetration (ft) Figure 7 is a plot of predicted surface injection pressures using a 3-1/2" string and Figure 8 is a plot of bottomhole injection pressures based on a closure pressure of 3,588 psi. Figure 7 - Preliminary Frac Pack Design - Predicted Injection Pressures Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand 0 0 N Time (min) Page 6 Figure 6 - Preliminary Frac Pack Design - Predicted Bottomhole Injection Pressures Kitchen Lights Unit A -2A, "Beluga 6,679 ft. - 6,701 ft. MD" Sand 0 i ociu a -Do ia-O/VITT. 4 10 �n Time (min) Recommended Pre -Frac Testing: The following testing program is recommended: (1) A 2,520 gal. 20# Borate Gel mini -frac at 6 bpm to evaluate fluid efficiency, closure pressure, and to calibrate the design model for final treatment design. For the mini -frac fluid only, the breaker needs to be increased to get a break time of 30 minutes at BHT. Increasing the breaker in the mini -frac helps to insure that the gel has broken to when the main frac pack is pumped. (2) A 1,365 gal. slickwater step -rate test to flush the crosslink gel away from the near wellbore region, determine extension pressure, and possibly confirm closure stress at rates of 1, 2, 3, 4, 5, 7.5, & 10 bpm in one -minute step increments. Jack, if you need anything else, please give me a call. Regards, Ron Vandersypen Attachment A Table A-1 STIMPLAN (TM) , NSI , Tulsa,OK - www.nsitech.com Frac Summary *Alaska - Beluga - 6679 - 6701 ft. Filename:G... Beluga at 6679 - 6701 ft MD.STP; 18 -Jul -2016 Well ID: Alaska - Beluga - 6679 - 6701 ft. Perforated Interval:MD Top 6679.0 Bottom 6701.0 (ft) Formation Temperature (EIF) 109 Notes FORMATION LAYER DATA - Multi -Layer Height Growth Depth (ft) Stress (psi) Gradient Modulus Toughness Loss Coef. Spurt Top Bottom Thickness Top Bottom (psi/ft) 5726.8 5781.5 5781.5 5793.5 5793.5 5813.2 5813.2 5822.8 5822.8 5825.2 5825.2 5830.6 5830.6 5865.3 5865.3 5875.5 5875.5 5894.5 5894.5 5901.6 5901.6 5910.0 5910.0 5914.1 5914.1 5918.9 5918.9 5925.5 5925.5 5949.2 5949.2 5975.4 5975.4 0.605 0.25 FORMATION: Perforated Height (ft) TEMPERATURE: PRESSURE: DEPTH: (MMpsi) (psi*sgrt(in)) (ft/sgrt(min)) (gaU100ft^2 54.7 3546.6 3580.0 0.610 0.30 12.0 3480.0 3487.2 0.600 0.20 19.7 3586.6 3598.6 0.610 0.30 9.6 3498.6 3504.3 0.600 0.20 2.4 3604.4 3605.9 0.610 0.30 5.4 3505.9 3509.1 0.600 0.20 34.7 3609.1 3630.3 0.610 0.30 10.2 3530.3 3536.4 0.600 0.20 19.0 3586.4 3598.0 0.610 0.25 7.1 3548.0 3552.3 0.600 0.20 8.4 3602.3 3607.4 0.605 0.25 4.1 3557.4 3559.9 0.600 0.20 4.8 3609.9 3612.8 0.605 0.25 6.5 3562.8 3566.7 0.600 0.20 23.8 3616.8 3631.2 0.605 0.25 26.2 3581.1 3596.8 0.600 0.20 3646.8 0.605 0.25 Perforated Height (ft) Permeability (md) Bottom Hole (OF) Reservoir Pressure (psi) Closure Pressure (psi) Well Depth (ft) Fluid Pressure Gradient (psi/ft) 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 20.5 50.000 109 2796.0 3587.8 5950.1 0.442 0.00100 0.01000 0.00100 0.01000 0.00100 0.01000 0.00100 0.01000 0.00750 0.01000 0.00750 0.01000 0.00750 0.01000 0.00750 0.01000 0.00750 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 Attachment A Table A-1 Perforations Top (ft) 5950.1 Bottom (ft) 5970.6 Initial Top (ft) 5950.1 Bottom (ft) 5970.6 3-D SIMULATOR StimPlan 1-D PROGRAM CONTROL Step Size (ft) 1.5 Time Step (min) 1.1 Calculated Results from 3-D Simulator - StimPlan 1-D Pumping Schedule - Design - Pad Licensed To: NSI Fracturing - Version 7.10 Half Length 'Hydraulic' Length (ft) 32.6 Propped length (ft) 31.0 PRESSURE: Max Net Pressure (psi) 540.0 Surface Pres -End of Pad (psi) 1357.6 Surface Pres -Start of Flush (psi) 153.6 Surface Pres -End of Job (psi) 1698.3 Maximum Hydraulic Horsepower 254.7 TIME: Max Exposure to Form. Temp. (min) 1.1 Time to Close 10.0 RATE: Fluid Loss Rate during pad (BPM) 4.61 EFFICIENCY: At end of pumping schedule 0.38 PROPPANT: Average In Situ Conc.(lb/ft^2) 7.60 Average Conductivity (md-ft) 9449.6 Fcd (KfW/k/Xf) 1.52 HEIGHT: Max Fracture Height (ft) 71.8 WIDTH: Avg width at end of pumping (in) 0.95 VOLUMES: Total Fluid Volume (M -Gal) 6.5 Total Proppant Volume (M -Lbs) 30.3 (TM). NSI Technologies, Tulsa, ®K Licensed To: NSI Fracturing - Version 7.10 WELL ID: Alaska - Beluga - 6679 - 6701 ft. DEPTH: Well Depth (ft) 5950.08 PRESSURE: Reservoir Pressure (psi) 2796.0 Closure Pressure (psi) 3587.8 TEMPERATURE: Bottom Hole Temperature 109.0 Attachment A (OF) * * Pumping Schedule Design - Pad Table A-1 S1 Vol Fl Vol Conc (PPG) Rate Fluid Prop Cum Proppant Pump Time (M -Gal) (M -Gal) Start End (BPM) Type Type (M -Lbs) (min) 1.50 1.50 0.0 0.0 6.00 6 10 0.0 6.0 0.51 0.50 0.5 0.5 6.00 6 10 0.3 2.0 0.52 0.50 1.0 1.0 6.00 6 10 0.8 2.1 0.55 0.50 2.0 2.0 6.00 6 10 1.8 2.2 0.57 0.50 3.0 3.0 6.00 6 10 3.3 2.3 2.67 2.00 3.0 12.0 6.00 6 10 18.3 10.6 1.54 1.00 12.0 12.0 6.00 6 10 30.3 6.1 Total Slurry 7.9 Total Fluid 6.5 Total Proppant 30.3 Avg. Cone 4.7 Total Pump Time 31.2 min Pad % 19.1 Pump Schedule Assumes Prop Cone Increases Linearly With CLEAN FLUID Volume Proppant Data Proppant ID No. 10 30-50 Carbo EconoProp, 250 F, Long Term Specific Gravity 2.69 Damage Factor (1.0 = No Damage) 0.70 Proppant Stress 0 2 4 8 16 KfW @ 2 #/sq ft and -ft) 4800 4400 3500 1750 300 Fluid Data Fluid ID No. 6 204 Borate Specific Gravity 1.02 Data @Wellbore @FormTmp 0.33 hr 0.66 hr 1.0 hr 1.5 hr vis(cp @ 170 1/sec) 251.5 465.7 168.1 125.8 97.4 79.8 non -Newtonian n' 0.58 0.58 0.63 0.67 0.69 0.70 K(lb/sec/ft^2)x1000 44.56 82.50 23.04 14.04 9.81 7.63 Friction Data Q (BPM) P/dL (psi/10011) 1.0 0.6 Pipe Friction Data 7.0 4.3 13.0 10.5 19.0 18.2 Attachment A 25.0 27.3 Measured Depth (ft) 6679.0 Table A-1 Time History * NSI STIMPLAN 3-D Fracture Simulation Alaska - Beluga - 6679 - 6701 ft. Time Pen Pres Rate Prop S1 Vol Efficiency Loss Hght W -Avg (min) (ft) (psi) (BPM) (PPG) (M -Gal) (BPM) (ft) (in) 0.7 8.6 199 6.00 0.0 0.2 0.48 2.9 27 0.31 1.1 10.1 199 6.00 0.0 0.3 0.51 2.7 27 0.41 1.2 11.7 200 6.00 0.0 0.3 0.49 3.8 27 0.37 1.3 13.2 201 6.00 0.0 0.3 0.48 4.8 29 0.33 1.5 14.8 216 6.00 0.0 0.4 0.45 4.0 32 0.32 1.8 16.3 215 6.00 0.0 0.5 0.43 4.1 36 0.29 2.2 17.9 209 6.00 0.0 0.6 0.40 4.4 39 0.27 2.8 19.4 200 6.00 0.0 0.7 0.37 4.4 43 0.27 3.5 21.0 191 6.00 0.0 0.9 0.35 4.4 46 0.27 4.2 22.5 182 6.00 0.0 1.1 0.33 4.5 50 0.27 5.2 24.1 175 6.00 0.0 1.3 0.31 4.6 53 0.28 6.0 25.3 166 6.00 0.0 1.5 0.30 4.6 56 0.27 7.1 26.0 161 6.00 0.5 1.8 0.29 4.8 57 0.28 8.0 27.6 158 6.00 0.5 2.0 0.27 4.8 61 0.28 9.0 29.1 153 6.00 1.0 2.3 0.26 5.0 64 0.28 10.2 29.2 148 6.00 1.1 2.6 0.25 5.0 64 0.29 10.8 29.3 146 6.00 2.0 2.7 0.25 4.9 64 0.29 10.8 29.5 145 6.00 2.0 2.7 0.25 4.8 65 0.29 11.1 31.0 146 6.00 2.0 2.8 0.25 4.9 68 0.27 12.0 32.6 142 6.00 2.0 3.0 0.24 5.2 72 0.26 13.3 32.6 140 6.00 2.8 3.3 0.23 5.1 72 0.28 Screen Out in Stage 2.0 at Time = 13.3 min at 30.2 ft 14.4 32.6 144 6.00 3.0 3.6 0.23 4.7 72 0.30 15.5 32.6 159 6.00 3.5 3.9 0.24 4.0 72 0.33 16.6 32.6 177 6.00 4.5 4.2 0.24 3.7 72 0.37 17.7 32.6 198 6.00 5.5 4.5 0.26 3.4 72 0.41 Screen Out in Stage 3.0 at Time = 17.7 min at 29.4 ft 18.8 32.6 220 6.00 6.5 4.7 0.27 3.3 72 0.45 Screen Out in Stage 3.0 at Time = 18.8 min at 29.2 ft 19.9 32.6 243 6.00 7.5 5.0 0.28 3.1 72 0.49 Screen Out in Stage 4.0 at Time = 19.9 min at 26.8 ft Page 11 Attachment A Table A-1 21.0 32.6 270 6.00 8.4 5.3 0.29 3.0 72 0.54 Screen Out in Stage 4.0 at Time = 21.0 min at 25.6 ft 22.1 32.6 297 6.00 9.3 5.6 0.30 2.9 72 0.58 23.2 32.6 324 6.00 10.2 5.8 0.32 2.8 72 0.62 24.3 32.6 351 6.00 11.0 6.1 0.33 2.7 72 0.67 25.4 32.6 380 6.00 11.8 6.4 0.34 2.6 72 0.71 Screen Out in Stage 4.0 at Time = 25.4 min at 24.7 ft 26.5 32.6 409 6.00 12.0 6.7 0.35 2.5 72 0.76 27.6 32.6 438 6.00 12.0 7.0 0.35 2.4 72 0.80 Screen Out in Stage 5.0 at Time = 27.6 min at 23.3 ft 28.7 32.6 469 6.00 12.0 7.2 0.36 2.4 72 0.84 29.8 32.6 501 6.00 12.0 7.5 0.37 2.3 72 0.89 31.2 32.6 540 6.00 12.0 7.9 0.38 2.3 72 0.95 33.7 32.6 497 0.00 0.0 7.9 0.35 2.2 72 0.89 36.3 32.6 454 0.00 0.0 7.9 0.33 2.1 72 0.83 39.0 32.6 410 0.00 0.0 7.9 0.30 2.0 72 0.77 40.2 32.6 389 0.00 0.0 7.9 0.28 1.9 72 0.75 41.2 32.6 367 0.00 0.0 7.9 0.28 1.9 72 0.74 GEOMETRY SUMMARY * At End of Pumping Schedule Alaska - Beluga - 6679 - 6701 ft. Distance Pressure W -Avg Q Sh-Rate Hght (ft) Bank Prop (ft) (psi) (in) (BPM) (1/sec) Total Up Down Prop Fraction (PSF) 4 540 1.52 3.0 1 72 25 26 72 0.00 8.08 8 540 1.52 2.1 0 72 25 26 72 0.00 8.93 9 540 1.52 1.9 0 72 25 26 72 0.00 9.36 11 540 1.52 1.7 0 72 25 26 72 0.00 9.60 12 540 1.52 1.5 0 72 25 26 72 0.00 9.75 14 540 1.50 1.3 0 70 24 25 70 0.00 9.76 16 540 1.48 1.1 0 69 24 25 69 0.00 9.67 17 540 1.45 0.9 0 67 23 24 67 0.00 9.58 19 540 1.41 0.7 0 64 21 22 64 0.00 9.40 20 540 1.33 0.5 0 58 18 19 58 0.00 8.84 22 540 1.21 0.4 0 49 14 15 49 0.00 8.23 23 540 0.98 0.3 0 34 6 8 35 0.57 8.74 25 438 0.75 0.2 0 32 5 7 32 1.00 7.10 26 379 0.63 0.2 1 31 4 6 31 1.00 6.26 27 270 0.43 0.2 1 29 3 5 29 0.99 3.95 Page 12 Attachment A Table A-1 28 242 0.38 0.0 2 29 3 5 29 0.79 2.81 29 242 0.38 0.1 1 29 3 5 29 1.00 3.94 29 218 0.35 0.1 1 29 3 5 29 1.00 3.48 29 218 0.35 0.1 1 29 3 5 29 1.00 4.00 30 196 0.31 0.1 2 29 3 5 29 1.00 3.74 32 136 0.12 0.1 14 18 0 0 18 0.60 0.67 33 136 0.15 0.0 1 16 -1 -1 16 0.00 0.00 FLUID SUMMARY * At End of Pumping Schedule Alaska - Beluga - 6679 - 6701 ft. Stage Fluid Prop Pos Concentration Fl Vol Ex Tim Temp Viscosity Fall No Gone ID ID (ft) Initial Now Design (M -Gal) (min) (OF) (cp) Frac 1 1 1 1 33 0.0 0.0 0.0 0.2 0.7 109 8000.00 1 1 1 1 33 0.0 0.0 0.0 0.3 0.6 109 8470.00 1 1 1 1 33 0.0 0.0 0.0 0.3 0.6 109 8090.00 1 1 1 1 33 0.0 0.0 0.0 0.3 0.6 109 8090.00 1 1 1 1 33 0.0 0.0 0.0 0.4 0.3 109 6560.00 1 1 1 1 33 0.0 0.0 0.0 0.5 0.0 109 1043 0.00 1 1 1 1 33 0.0 0.0 0.0 0.6 0.0 109 7000.00 1 l 1 1 33 0.0 0.0 0.0 0.7 0.0 109 7680.00 1 1 1 1 33 0.0 0.0 0.0 0.9 0.0 93 7890.00 l l l 1 33 0.0 0.0 0.0 1.1 0.0 109 4690.00 1 1 1 1 33 0.0 0.0 0.0 1.3 0.0 99 1060 0.00 1 1 1 1 33 0.0 0.0 0.0 1.5 0.0 88 6520.00 2 1 1 1 33 0.5 44.8 0.0 1.5 0.0 88 6520.00 2 1 1 1 33 0.5 44.8 0.0 1.7 0.0 86 6520.00 2 1 1 1 31 0.5 44.8 0.0 1.8 0.0 83 653 0.00 2 1 1 1 31 0.5 44.8 0.0 1.9 0.0 83 1010 0.00 2 1 l 1 31 0.5 44.8 0.0 2.0 0.0 82 1004 0.00 2 l 1 1 31 0.5 44.8 0.0 2.0 0.0 82 1004 0.00 3 1 1 1 30 1.0 44.8 0.0 2.2 0.0 81 9860.00 3 1 1 1 29 1.0 44.8 0.0 2.3 0.0 77 9260.00 3 1 1 1 29 1.0 44.8 0.0 2.5 0.0 76 9150.00 3 1 1 1 28 1.0 44.8 0.0 2.5 0.0 76 9060.00 4 1 1 1 27 2.0 44.8 0.0 2.6 0.0 75 8990.00 4 l 1 1 27 2.0 44.8 0.0 2.7 0.0 75 8960.00 4 1 1 1 27 2.0 44.8 0.0 2.7 0.0 75 9000.00 4 1 1 1 27 2.0 44.8 0.0 2.8 0.0 75 8960.00 Page 13 Attachment A Table A-1 4 1 1 1 26 2.0 44.8 0.0 3.0 0.0 73 873 0.00 4 1 1 1 25 2.0 44.8 0.0 3.1 0.0 73 8670.00 5 1 1 1 24 3.0 44.8 0.0 3.3 0.0 73 8600.00 5 1 1 1 24 3.0 44.8 0.0 3.3 0.0 72 8570.00 5 0 1 1 23 3.0 31.6 1.7 3.6 0.0 72 851 0.00 5 0 1 1 22 3.0 16.4 2.4 3.6 0.0 71 8460.00 6 0 1 1 22 3.5 7.5 5.2 3.8 0.0 71 8460.00 6 0 1 l 21 4.5 10.5 5.1 4.1 0.0 71 8400.00 6 0 I 1 19 5.5 13.6 5.0 4.3 0.0 71 8380.00 6 0 1 1 18 6.5 16.9 5.0 4.5 0.0 71 835 0.00 6 0 1 1 17 7.5 20.1 5.1 4.7 0.0 70 8330.00 6 0 1 1 16 8.4 23.4 5.1 5.0 0.0 70 8320.00 6 0 1 1 15 9.3 27.3 5.1 5.2 0.0 70 8320.00 6 0 1 1 13 10.2 30.7 5.2 5.4 0.0 70 8320.00 6 0 1 1 12 11.0 34.1 5.3 5.6 0.0 70 8320.00 6 0 1 1 10 11.7 36.0 5.4 5.8 0.0 70 8320.00 7 0 1 1 10 12.0 18.9 8.1 5.9 0.0 70 8320.00 7 0 l l 9 12.0 17.1 8.7 6.1 0.0 70 8320.00 7 0 1 1 7 12.0 15.7 9.4 6.2 0.0 70 8320.00 7 0 1 1 5 12.0 14.6 10.0 6.4 0.0 70 8320.00 7 0 1 1 3 12.0 13.6 10.6 6.6 0.0 70 8320.00 7 0 1 1 1 12.0 12.8 11.2 6.9 0.0 70 8320.00 PR®PPANT SUMMARY * At End of Pumping Schedule Alaska - Beluga m 6679 - 6701 ft. Lb/Sq-Ft Lost to Embedment ............ 2.000 Distance KfW Prop Concentration(Total lb/sq foot) (ft) (md-ft) Prop ID 3.5 1 10058 8.34 7.8 10939 8.89 9.3 11594 9.30 10.9 12008 9.56 12.4 12232 9.71 14.0 12260 9.72 15.5 12162 9.66 17.1 11994 9.56 18.6 11585 9.30 Page 14 Attachment A Table A-1 20.2 10801 8.80 21.7 10323 8.50 23.3 9956 8.27 24.7 8223 7.18 25.6 6209 5.91 26.8 3423 4.16 28.4 2269 3.43 292 2695 3.70 292 2646 3.67 29.4 2942 3.85 30.2 2116 3.00 31.8 529 1.09 32.6 159 0.33 9.69 Average Conductivity (md-ft) 9386 PROPPANT SUMMARY * At Fracture Closure Alaska - Beluga - 6679 - 6701 ft. Lb/Sq-Ft Lost to Embedment ............ 2.000 Distance KfW Prop Concentration jotal lb/sq foot) (ft) (md-ft) Prop ID 3.5 9636 1 8.07 7.8 10466 8.59 9.3 11124 9.00 10.9 11591 9.30 12.4 11954 9.53 14.0 12427 9.82 15.5 12588 9.93 17.1 12186 9.67 18.6 12217 9.69 20.2 12017 9.57 21.7 11453 9.21 23.3 10665 8.72 24.7 8403 7.29 25.6 6256 5.94 26.8 3436 4.16 28.4 2272 3.43 29.2 2697 3.70 Attachment A 29.2 2647 3.67 29.4 2943 3.85 30.2 2117 3.00 31.8 529 1.09 32.6 159 0.33 Average Conductivity (md-ft) Table A-1 9450 Attachment O - _.LU A -2A Upper Beluga 6127-6276' MD Frac Pack Design Modeling 050 FRACTURING, LLC. e To: Mr. Jack Burman July 18, 2016 Exploitation Technologies Houston, Texas 77069 07032016 Re: Kitchen Lights Unit A -2A - "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand Preliminary Frac Pack Design Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand was evaluated for a frac pack stimulation treatment in order to get a moderately conductive fracture to enhance production from this estimated 50 and reservoir. Reservoir properties for this well are an estimated reservoir pressure of 2,693 psi, an average porosity of 28%, an estimated permeability of 50 md, and an estimated BHT of 108°F. The result indicates a Folds -Of -Increase (FOI) of approximately 1.41 for a 35 ft. propped frac pack half- length with a conductivity of 6 - 8 lbs./sq.ft. Optimal Half -Length and Conductivity: Using the above reservoir properties, propped frac pack half -lengths (0 to 100 ft.) and conductivities (4 to 8 lbs./sq.ft.) were evaluated using a flowing BHP of 2,493 psi to determine the design propped frac pack half-length and conductivity. As can be seen in Figure 1, the optimum propped frac pack half-length is about 35 ft. with a conductivity of 6 - 8 lbs./sq.ft. With this, a FOI of 1.41 could be seen. Thus, a fracture half-length of 35 ft. length was chosen to ensure good production and was used as initial design goals. Figure 1 - Predicted FOI vs Propped Frac Pack Half -Lengths Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand Wt -2 3239.1 md•ft Ib/ft^2 6478.3 and -ft IbMA2 9717.4 md.fY rrauture itz LengEn (n) Stress Profile: A closure pressure of 3,356 psi (0.62 psi/ft.) was used and was based a reservoir pressure of 2,693 psi and a Poisson's Ratio of 0.25. The modulus in the pay sand was estimated to be 0.20 - 0.25 x 106 psi and in the bounding shale was 0.30 x 106 psi and was based on the frac packs around the same depths. Leak -Off Profile: The leak -off coefficients that were used are estimated to be 0.0075 - 0.010 ft./sq.rt. minute (this gives a fluid efficiency of 28% for the mini -frac) in the pay sand and in the adjacent layers estimated to be 0.001 ft./sq.rt. minute and was based on the frac packs around the same depths and perms. Proppant Selection: With this being an gas zone having a reservoir temperature of 108°F with a possible fines migration problem and a closure pressure estimated to be 3,356 psi, 30/50 mesh Carbo -Lite is recommended. Fracturing Fluid Selection: Since the bottomhole temperature is around 108°F, a 20# Borate Gel is recommended. Gel crosslink timPQ chnidrl ho h,Ia.,.,,, &L-_ workstring (1-1/2 minutes with a 3-1/2" drill pipe) and break times should be around 60 minutes to 50 cp at 170 sec -1. Preliminary Frac Pack Treatment Design: The preliminary design is shown in Table 1. The proppant schedule starts out with a 0.5 ppg stage and goes up to a maximum concentration of 12.0 ppg. The design injection rate is 18 bpm through the entire job and reduced for the annular pack (based on the results of the mini -frac rate may be increased for the frac pack). The resultant treatment calls for 15,000 gals. of gel and 75,500 lbs. of 30/50 mesh Carbo -Lite. The predicted point of the TSO is at the beginning of the 2.0 ppg stage going into the fracture. Prior to this point, the model predicted net BHTP (BHTP - closure P) is 89 psi with a corresponding average fracture width of 0.29 inches. Throughout the remainder of the treatment, the predicted net pressure increased to 422 psi (Figure 2) and was coupled with an average width increase of 1.40 inches. The resultant frac pack dimensions are a propped half-length of 39 ft., a maximum height at the wellbore of 141 ft., and an average conductivity of 9,566 and -ft (avg. in-situ conc. = 7.83 lbs./sq.ft.). These are shown in Figures 3 - 6 with the model 1/0 included in Attachment A Table A-1. Table 1 - Preliminary Frac Pack Design Schedule Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand l"dEll t%'. AIaSRa - U Er BEIu a - Bb2 i - 6 %OS R. r ro Blessed Slurry, Fluid Proppant Conc Pines Stage `lolume IM Volume (PPC) Rate t:.ecc (VAI Proppant Pump Time Cum Time 1 -Gal 3.000 161 -Oaf Stan `4000 0.00 Eotl 0.00 (BPM) Frac NDr,) (M -Lbs) lmin min Fluid T• ( ) Type Proppant Type 2 1.022 1 000 050 0.50 180 ISO 0.0000 0.0 4 0 4 0 20# Borate Cabo EtonoPmp. 250 F Lo g Term 30-50 3 1.045 1.000 1.00 1.00 16.0 O.OfK)0 0.D 0.5 1.4 54 20# Borate Carbo EconoProp. 250 F Lo Tem, 30-50 4 1.086 1.000 200 200 18.0 0.0000 1.0 2.0 1.4 68 20# Borale Carbo EconoProp. 250 F Lo g Term 30-50 5 1 134 1 000 3.00 300 18.0 00000 30 1.4 8 2 2G# Borate Carbo EconoProp. 250 F Long Term 30-50 6 8.008 8 000 3.D0 12.00 18.0 D.0000 45 0 1 5 6.7 20# Borate Carbo EconoProp. 250 F Lol�g Term 30-50 7 3.071 2000 12.Ne 12.00 1 B.0 00000 240 10 6 20 3 20# Borate Carbo EconoProp 250 F. Log Term 30-50 4.1 244 200 Borate Carbo EccnoProp 250 F Lo Term 30-50 554 150 Lrru'-i 5.0 75.5_ 244 r Constant FPO Steps - - -- -- - 1 Schedule , F Fluid Ramp r Slurry Ramp Design oil Flo'.+: Back Rate +BPi.tj ® Page 3 t t t Figure 2 - Preliminary Frac Pack Design - Nolte -Smith Plot Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand �v LU Time (min) Figure 3 - Preliminary Frac Pack Design - Frac Pack Penetration Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand MD Alaska - Upper Beluga - 6127 - 6276 ft ft 6100 6150 6200 6250 6300 Alaska - Upper Beluga - 6127 - 6276 ft. At Closure 50 100 150 200 Fracture Penetration (ft) Page 4 - -vcry It. 1 1 f f/ YAR -'-4 �v LU Time (min) Figure 3 - Preliminary Frac Pack Design - Frac Pack Penetration Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand MD Alaska - Upper Beluga - 6127 - 6276 ft ft 6100 6150 6200 6250 6300 Alaska - Upper Beluga - 6127 - 6276 ft. At Closure 50 100 150 200 Fracture Penetration (ft) Page 4 Figure 4 - Preliminary Frac Pack Design - Width Profile Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand Alaska -tipper Beluga - 6127 - 6276 ft. 0 Ip aNd MD ft 6150 6200 6250 6300 Max Width 2.27 in -1.2 -0.8 -0.4 -0.0 0.4 08 1.2 Figure 5 - Preliminary Frac Pack Design - Conductivity Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand Fracture Penetration (ft) 3600 3800 At MD ft 6150 6200 6250 6300 Max Width 2.27 in -1.2 -0.8 -0.4 -0.0 0.4 08 1.2 Figure 5 - Preliminary Frac Pack Design - Conductivity Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand Fracture Penetration (ft) Figure 6 - Preliminary Frac Pack Design - In -Situ Concentration Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand Fracture Penetration (ft) Figure 7 is a plot of predicted surface injection pressures using a 3-1/2" string and Figure 8 is a plot of bottomhole injection pressures based on a closure pressure of 3,356 psi. Figure 7 - Preliminary Frac Pack Design - Predicted Injection Pressures Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand Time (min) Page 6 Figure 8 - Preliminary Frac Pack Design - Predicted Bottomhole Injection Pressures Kitchen Lights Unit A -2A, "Upper Beluga 6,127 ft. - 6,276 ft. MD" Sand i ime (min) Recommended Pre -Frac Testing: The following testing program is recommended: (1) A 7,560 gal. 20## Borate Gel mini -frac at 18 bpm to evaluate fluid efficiency, closure pressure, and to calibrate the design model for final treatment design. For the mini -frac fluid only, the breaker needs to be increased to get a break time of 30 minutes at BHT. Increasing the breaker in the mini -frac helps to insure that the gel has broken to when the main frac pack is pumped. (2) A 1,995 gal. slickwater step -rate test to flush the crosslink gel away from the near wellbore region, determine extension pressure, and possibly confirm closure stress at rates of 1, 2, 3, 4, 5, 7.5, 10, & 15 bpm in one -minute step increments. Jack, if you need anything else, please give me a call. Regards, Ron Vandersypen Attachment A Table A-1 STIMPLAN (TM) , NSI , Tulsa,OK - www.nsitech.com Frac Summary *Alaska - Upper Beluga - 6127 - 6276 ft. Filename:G... Upper Beluga at 6127 - 6276 ft MD.STP; 18 -Jul - 2016 Well ID: Alaska - Upper Beluga - 6127 - 6276 ft. Perforated Interval:MD (ft) Top 6127.0 Bottom 6276.0 Formation Temperature (017) 108 Notes FORMATION LAYER DATA - Multi -Layer Height Growth Depth (ft) Stress (psi) Gradient Modulus Toughness Loss Coef Spurt Top Bottom Thickness Top Bottom (psi/ft) (MMpsi) (psi*sqrt(in)) (ft/sgrt(min)) (gal/100ft^2 5348.3 5356.7 8.3 3376.7 3382.0 0.630 0.30 2800.0 0.00100 0.00000 5356.7 5360.8 4.2 3332.0 3334.6 0.620 0.25 2800.0 0.00750 0.00000 5360.8 5367.1 6.3 3384.5 3388.4 0.630 0.30 2800.0 0.00100 0.00000 5367.1 5381.5 14.4 3338.5 3347.4 0.620 0.25 2800.0 0.00750 0.00000 5381.5 5382.8 1.3 3397.4 3398.2 0.630 0.30 2800.0 0.00100 0.00000 5382.8 5398.1 15.3 3348.2 3357.7 0.620 0.25 2800.0 0.00750 0.00000 5398.1 5412.0 13.8 3407.7 3416.4 0.630 0.30 2800.0 0.00100 0.00000 5412.0 5414.2 2.3 3366.5 3367.9 0.620 0.25 2800.0 0.00750 0.00000 5414.2 5416.5 2.3 3417.9 3419.3 0.630 0.30 2800.0 0.00100 0.00000 5416.5 5428.7 12.2 3369.3 3376.9 0.620 0.25 2800.0 0.00750 0.00000 5428.7 5430.5 1.7 3426.9 3428.0 0.630 0.30 2800.0 0.00100 0.00000 5430.5 5445.9 15.5 3378.0 3387.6 0.620 0.25 2800.0 0.00750 0.00000 5445.9 5449.1 3.2 3437.5 3439.5 0.630 0.30 2800.0 0.00100 0.00000 5449.1 5457.7 8.5 3389.5 3394.8 0.620 0.25 2800.0 0.00750 0.00000 5457.7 5468.1 10.4 3444.8 3451.4 0.630 0.30 2800.0 0.00100 0.00000 5468.1 5484.0 15.9 3351.4 3361.3 0.620 0.20 2800.0 0.01000 0.00000 5484.0 5486.7 2.7 3411.3 3412.9 0.620 0.25 2800.0 0.00750 0.00000 5486.7 5503.4 16.7 3363.0 3373.3 0.620 0.20 2800.0 0.01000 0.00000 5503.4 5506.0 2.7 3473.4 3475.1 0.630 0.30 2800.0 0.00100 0.00000 5506.0 5547.6 41.6 3425.0 3450.8 0.620 0.25 2800.0 0.00750 0.00000 5547.6 5551.2 3.6 3500.8 3503.1 0.630 0.30 2800.0 0.00100 0.00000 5551.2 5556.7 5.5 3403.1 3406.5 0.620 0.20 2800.0 0.01000 0.00000 5556.7 5571.6 14.9 3456.5 3465.8 0.620 0.25 2800.0 0.00750 0.00000 Page 8 Attachment A 5571.6 5574.2 5574.2 5578.5 5578.5 5587.4 5587.4 5594.2 5594.2 5600.5 5600.5 5603.1 5603.1 5609.5 5609.5 5617.4 5617.4 5619.7 5619.7 5629.9 5629.9 Surface Pres -Start of Flush (psi) FORMATION: TEMPERATURE: PRESSURE: DEPTH: 2.6 3515.7 3517.4 0.630 0.30 4.3 3467.3 3469.9 0.620 0.25 9.0 3520.0 3525.7 0.630 0.30 6.8 3475.6 3479.8 0.620 0.25 6.2 3529.8 3533.7 0.630 0.30 2.6 3483.8 3485.4 0.620 0.25 6.4 3535.4 3539.4 0.630 0.30 7.9 3489.4 3494.3 0.620 0.25 2.3 3544.3 3545.7 0.630 0.30 10.2 3495.7 3502.0 0.620 0.25 3552.0 0.630 0.30 Perforated Height (ft) Permeability (md) Bottom Hole (EIF) Reservoir Pressure (psi) Closure Pressure (psi) Well Depth (ft) Fluid Pressure Gradient (psi/ft) Perforations Top (ft) Bottom (ft) Initial Top (ft) Bottom (ft) 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 2800.0 141.0 50.000 108 2693.0 3356.3 5430.5 0.442 5430.5 5571.5 5430.5 5571.5 3-D SIMULATOR StimPlan 1-D PROGRAM CONTROL Step Size (ft) Automatic Time Step (min) Automatic Calculated Results from 3-D Simulator - StimPlan 1-D Pumping Schedule - Design - Pad Licensed To: NSI Fracturing - Version 7.10 Half Length 'Hydraulic' Length (ft) 40.2 Propped length (ft) 38.6 PRESSURE: Max Net Pressure (psi) 422.0 Surface Pres -End of Pad (psi) 2007.2 Surface Pres -Start of Flush (psi) 1713.0 Surface Pres -End of Job (psi) 2342.3 Maximum Hydraulic Horsepower 1054.0 TIME: Max Exposure to Form. Temp. (min) 0.5 ,.. Table A-1 0.00100 0.00750 0.00100 0.00750 0.00100 0.00750 0.00100 0.00750 0.00100 0.00750 0.00100 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 0.00000 Attachment A Conc (PPG) Rate Fluid Prop Cum Proppant Pump Time Table A-1 Start Time to Close 20.9 RATE: Fluid Loss Rate during pad (BPM) 11.84 EFFICIENCY: At end of pumping schedule 0.48 PROPPANT: Average In Situ Conc.(lb/ft^2) 7.83 0.5 Average Conductivity (md-ft) 9565.5 0.5 Fed (KfW/k/Xo 1.24 HEIGHT: Max Fracture Height (ft) 141.1 WIDTH: Avg width at end of pumping (in) 1.40 VOLUMES: Total Fluid Volume (M -Gal) 15.0 3.5 Total Proppant Volume (M -Lbs) 75.5 (TM). NSI Technologies, Tulsa, OK Licensed To: NSI Fracturing - Version 7.10 WELL ID: Alaska - Upper Beluga - 6127 - 6276 ft. DEPTH: Well Depth (ft) 5430.45 PRESSURE: Reservoir Pressure (psi) 2693.0 Closure Pressure (psi) 3356.3 TEMPERATURE: Bottom Hole Temperature ) 108.0 * * Pumping Schedule Design - Pad Sl Vol FI Vol Conc (PPG) Rate Fluid Prop Cum Proppant Pump Time (M -Gal) (M -Gal) Start End (BPM) Type Type (M -Lbs) (min) 3.00 3.00 0.0 0.0 18.00 6 10 0.0 4.0 1.02 1.00 0.5 0.5 18.00 6 10 0.5 14 1.04 1.00 1.0 1.0 18.00 6 10 1.5 1.4 1.09 1.00 2.0 2.0 18.00 6 10 3.5 1.4 1.13 1.00 3.0 3.0 18.00 6 10 6.5 1.5 8.01 6.00 3.0 12.0 18.00 6 10 51.5 10.6 3.07 2.00 12.0 12.0 18.00 6 10 75.5 4.1 Total Slurry 18.4 Total Fluid 15.0 Total Proppant 75.5 Avg. Conc 5.0 Total Pump Time 24.3 min Pad % 16.3 Pump Schedule Assumes Prop Cone Increases Linearly With CLEAN FLUID Volume Proppant Data Proppant ID No. 10 30-50 Carbo EconoProp, 250 F, Long Term Attachment A Table A-1 Specific Gravity 2.69 Damage Factor (1.0 = No Damage) 0.70 Proppant Stress 0 2 4 8 16 KfW @ 2 4/sq ft and -ft) 4800 4400 3500 1750 300 Fluid Data Fluid 1D No. 6 20# Borate Page 11 Specific Gravity 1.02 Data @Wellbore @FormTmp 0.33 hr 0.66 hr 1.0 hr 1.5 hr vis(cp @ 170 I/sec) 251.5 465.7 168.1 125.8 97.4 79.8 non -Newtonian n' 0.58 0.58 0.63 0.67 0.69 0.70 K(lb/sec/ft^2)x1000 44.56 82.50 23.04 14.04 9.81 7.63 Friction Data Q (BPM) P/dL (psi/100ft) 1.0 0.6 7.0 4.3 Pipe Friction Data 13.0 10.5 19.0 18.2 25.0 27.3 Measured Depth (ft) 6127.0 Time History * NSI STIMPLAN 3-D Fracture Simulation Alaska - Upper Beluga - 6127 - 6276 ft. Time Pen Pres Rate Prop S1 Vol Efficiency Loss Hght W -Avg (min) (ft) (psi) (BPM) (PPG) (M -Gal) (BPM) (ft) (in) 0.5 3.7 86 18.00 0.0 0.4 0.64 6.0 141 0.38 0.8 4.5 86 18.00 0.0 0.6 0.66 5.4 141 0.49 0.9 5.3 86 18.00 0.0 0.7 0.65 7.8 141 0.45 0.9 6.1 86 18.00 0.0 0.7 0.63 10.2 141 0.41 0.9 6.9 86 18.00 0.0 0.7 0.62 12.2 141 0.37 1.0 7.7 87 18.00 0.0 0.7 0.60 14.5 141 0.34 1.0 8.5 87 18.00 0.0 0.7 0.59 15.4 141 0.31 1.1 9.3 86 18.00 0.0 0.8 0.55 12.4 141 0.30 1.2 10.1 86 18.00 0.0 0.9 0.53 11.5 141 0.29 1.3 10.9 86 18.00 0.0 1.0 0.52 11.4 141 0.29 1.4 11.7 87 18.00 0.0 1.1 0.51 11.4 141 0.29 1.5 12.5 87 18.00 0.0 1.2 0.49 11.6 141 0.28 1.7 13.3 87 18.00 0.0 1.3 0.48 11.7 141 0.28 Page 11 Attachment A Table A-1 1.8 14.1 87 18.00 0.0 1.4 0.47 11.8 141 0.28 1.9 14.9 87 18.00 0.0 1.5 0.46 12.0 141 0.28 2.1 15.7 87 18.00 0.0 1.6 0.45 12.1 141 0.28 2.2 16.5 87 18.00 0.0 1.7 0.44 12.2 141 0.28 2.3 17.3 87 18.00 0.0 1.8 0.44 12.2 141 0.28 2.5 18.1 87 18.00 0.0 1.9 0.43 12.4 141 0.27 2.7 18.9 87 18.00 0.0 2.0 0.42 12.4 141 0.28 2.8 19.7 87 18.00 0.0 2.2 0.41 12.4 141 0.28 3.0 20.5 87 18.00 0.0 2.3 0.41 12.6 141 0.28 3.2 21.3 87 18.00 0.0 2.4 0.40 12.7 141 0.28 3.4 22.1 87 18.00 0.0 2.5 0.39 12.7 141 0.28 3.5 22.9 88 18.00 0.0 2.7 0.39 12.9 141 0.28 3.7 23.7 88 18.00 0.0 2.8 0.38 13.0 141 0.28 3.9 24.5 88 18.00 0.0 2.9 0.38 13.2 141 0.28 4.0 25.0 88 18.00 0.0 3.0 0.37 11.8 141 0.28 4.2 25.8 88 18.00 0.5 3.1 0.37 13.3 141 0.28 4.3 26.6 88 18.00 0.5 3.3 0.37 13.4 141 0.28 4.5 27.4 88 18.00 0.5 3.4 0.36 13.6 141 0.28 4.7 28.2 88 18.00 0.5 3.6 0.36 13.6 141 0.28 4.9 29.0 88 18.00 0.5 3.7 0.35 13.7 141 0.28 5.2 29.8 88 18.00 0.5 3.9 0.35 13.8 141 0.28 5.4 30.6 88 18.00 0.6 4.1 0.34 13.8 141 0.28 5.6 31.4 88 18.00 1.0 4.2 0.34 13.9 141 0.28 5.8 32.2 88 18.00 1.0 4.4 0.33 14.0 141 0.28 6.0 33.0 88 18.00 1.0 4.5 0.33 14.1 141 0.28 6.2 33.8 89 18.00 1.0 4.7 0.33 14.1 141 0.28 6.5 34.6 89 18.00 1.0 4.9 0.32 14.1 141 0.28 6.7 35.4 89 18.00 1.0 5.1 0.32 14.2 141 0.29 6.9 36.2 89 18.00 2.0 5.2 0.31 14.3 141 0.29 7.2 37.0 89 18.00 2.0 5.4 0.31 14.3 141 0.29 7.4 37.8 89 18.00 2.0 5.6 0.31 14.4 141 0.29 7.7 38.6 89 18.00 2.0 5.8 0.30 14.4 141 0.29 7.9 39.4 89 18.00 2.0 6.0 0.30 14.4 141 0.29 8.2 40.2 90 18.00 2.3 6.2 0.30 14.2 141 0.29 Screen Out in Stage 2.0 at Time = 8.2 min at 39.0 ft 9.3 40.2 101 18.00 3.0 7.1 0.30 12.2 141 0.34 Screen Out in Stage 2.0 at Time = 9.3 min at 38.2 ft 10.5 40.2 118 18.00 3.3 7.9 0.31 10.2 141 0.39 Page 12 Attachment A Table A-1 11.6 40.2 137 18.00 4.3 8.8 0.33 9.2 141 0.46 Time History * NSI STIMPLAN 3-D Fracture Simulation Alaska - Upper Beluga - 6127 - 6276 ft. Time Pen Pres Rate Prop Sl Vol Efficiency Loss Hght W -Avg (min) (ft) (psi) (BPM) (PPG) (M -Gal) (BPM) (ft) (in) 12.7 40.2 158 18.00 5.4 9.6 0.35 8.5 141 0.53 Screen Out in Stage 2.0 at Time = 12.7 min at 37.4 ft 13.8 40.2 180 18.00 6.4 10.5 0.36 7.9 141 0.60 14.9 40.2 203 18.00 7.4 11.3 0.38 7.5 141 0.68 16.1 40.2 227 18.00 8.3 12.1 0.40 7.1 141 0.76 17.2 40.2 252 18.00 9.2 13.0 0.41 6.8 141 0.84 Screen Out in Stage 3.0 at Time = 17.2 min at 36.6 ft 18.3 40.2 278 18.00 10.1 13.8 0.42 6.5 141 0.92 19.4 40.2 304 18.00 11.0 14.7 0.44 6.2 141 1.01 20.5 40.2 330 18.00 11.8 15.5 0.45 6.0 141 1.10 21.7 40.2 358 18.00 12.0 16.4 0.46 5.8 141 1.18 22.8 40.2 385 18.00 12.0 17.2 0.47 5.6 141 1.27 24.3 40.2 422 18.00 12.0 18.4 0.48 5.4 141 1.40 Screen Out in Stage 4.0 at Time = 24.3 min at 35.8 ft 27.6 40.2 388 0.00 0.0 18.4 0.45 5.2 141 1.29 31.0 40.2 354 0.00 0.0 18.4 0.41 4.8 141 1.18 34.7 40.2 321 0.00 0.0 18.4 0.37 4.5 141 1.08 36.7 40.2 304 0.00 0.0 18.4 0.35 4.3 141 1.03 38.6 40.2 287 0.00 0.0 18.4 0.33 4.2 141 0.98 40.6 40.2 270 0.00 0.0 18.4 0.32 4.1 141 0.92 42.5 40.2 253 0.00 0.0 18.4 0.30 4.0 141 0.88 44.5 40.2 236 0.00 0.0 18.4 0.28 3.9 141 0.83 45.2 40.2 219 0.00 0.0 18.4 0.28 3.8 141 0.82 GEOMETRY SUMMARY * At End of Pumping Schedule Alaska - Upper Beluga - 6127 - 6276 ft. Distance Pressure W -Avg Q Sh-Rate Hght (ft) Bank Prop (ft) (psi) (in) (BPM) (1/sec) Total Up Down Prop Fraction (PSF) 1 422 1.75 8.9 1 141 0 0 141 0.00 8.81 3 422 1.75 8.0 1 141 0 0 141 0.00 8.85 4 422 1.75 7.8 1 141 0 0 141 0.00 9.05 5 422 1.75 7.6 1 141 0 0 141 0.00 9.05 Page 13 Attachment A Table A-1 6 422 1.75 7.3 1 141 0 0 141 0.00 9.05 7 422 1.75 7.1 1 141 0 0 141 0.00 9.32 7 422 1.75 6.9 1 141 0 0 141 0.00 9.33 8 422 1.75 6.6 1 141 0 0 141 0.00 9.34 9 422 1.75 6.4 1 141 0 0 141 0.00 9.60 10 422 1.75 6.2 1 141 0 0 141 0.00 9.51 11 422 1.75 5.9 1 141 0 0 141 0.00 9.50 11 422 1.75 5.7 0 141 0 0 141 0.00 9.48 12 422 1.75 5.5 0 141 0 0 141 0.00 9.47 13 422 1.75 5.2 0 141 0 0 141 0.00 9.47 14 422 1.74 5.0 0 141 -0 -0 141 0.00 9.32 15 422 1.73 4.8 0 139 -1 -1 139 0.00 9.24 15 422 1.71 4.5 0 138 -1 -1 138 0.00 9.17 16 422 1.70 4.3 0 137 -2 -2 137 0.00 8.98 17 422 1.68 4.1 0 136 -3 -3 136 0.00 8.89 18 422 1.67 3.9 0 134 -3 -3 134 0.00 8.79 19 422 1.65 3.7 0 133 -4 -4 133 0.00 8.59 19 422 1.63 3.4 0 131 -5 -5 131 0.00 8.50 20 422 1.61 3.2 0 130 -6 -6 130 0.00 8.36 21 422 1.59 3.0 0 128 -7 -7 128 0.00 8.16 22 422 1.56 2.8 0 126 -7 -7 126 0.00 8.05 23 422 1.54 2.6 0 124 -8 -8 124 0.00 7.86 23 422 1.52 2.4 0 122 -9 -9 122 0.00 7.65 24 422 1.49 2.3 0 120 -10 -10 120 0.00 7.52 25 422 1.47 2.1 0 118 -11 -11 118 0.00 7.38 25 422 1.44 2.0 0 117 -12 -12 117 0.00 7.15 26 422 1.41 1.8 0 114 -14 -14 114 0.00 7.01 27 422 1.38 1.6 0 111 -15 -15 111 0.00 6.79 28 422 1.35 1.5 0 109 -16 -16 109 0.00 6.49 29 422 1.31 1.3 0 106 -18 -18 106 0.00 6.32 29 422 1.27 1.2 0 103 -19 -19 103 0.00 6.07 30 422 1.23 1.0 0 99 -21 -21 99 0.00 5.81 31 422 1.19 0.9 0 96 -23 -23 96 0.00 5.46 32 422 1.14 0.8 0 92 -24 -24 92 0.00 6.12 33 422 1.09 0.7 0 88 -26 -26 88 0.00 6.21 33 422 1.04 0.5 0 84 -29 -29 84 0.00 6.10 34 422 0.98 0.4 0 79 -31 -31 79 0.00 4.95 35 422 0.92 0.3 0 74 -33 -33 74 0.00 5.81 Page 14 Attachment A Table A-1 36 422 0.85 0.3 0 69 -36 -36 69 0.87 7.22 37 422 0.77 0.2 0 62 -39 -39 62 1.00 7.38 37 252 0.41 0.1 1 55 -43 -43 55 1.00 4.38 38 157 0.20 0.1 3 44 -49 -49 44 1.00 2.65 39 98 0.11 0.1 16 37 -52 -52 37 1.00 1.35 40 85 0.11 0.1 34 35 -53 -53 35 0.00 0.00 FLUID SUMMARY * At End of Pumping Schedule Alaska - Upper Beluga - 6127 - 6276 ft. Stage Fluid Prop Pos Concentration Fl Vol Ex Tim Temp Viscosity Fall No Gone ID ID (ft) Initial Now Design (M -Gal) (min) (EIF) (cp) Frac 1 l 1 1 40 0.0 0.0 0.0 0.4 0.4 108 6640.00 1 1 l 1 40 0.0 0.0 0.0 0.6 0.3 108 5630.00 1 1 1 1 40 0.0 0.0 0.0 0.7 0.2 108 5630.00 1 1 1 1 40 0.0 0.0 0.0 0.7 0.2 108 5820.00 1 l 1 1 40 0.0 0.0 0.0 0.7 0.2 108 5820.00 1 1 1 1 40 0.0 0.0 0.0 0.7 0.2 108 5820.00 1 1 1 1 40 0.0 0.0 0.0 0.7 0.1 108 5500.00 1 1 1 1 40 0.0 0.0 0.0 0.8 0.1 108 5330.00 1 1 1 1 40 0.0 0.0 0.0 0.9 0.1 108 5170.00 1 1 1 1 40 0.0 0.0 0.0 1.0 0.1 108 3070.00 1 1 1 1 40 0.0 0.0 0.0 1.1 0.1 108 5090.00 1 1 1 1 40 0.0 0.0 0.0 1.2 0.1 108 5140.00 1 1 1 1 40 0.0 0.0 0.0 1.3 0.1 108 5240.00 1 1 1 1 40 0.0 0.0 0.0 1.4 0.1 108 5240.00 1 1 1 1 40 0.0 0.0 0.0 1.5 0.0 108 5290.00 1 1 1 1 40 0.0 0.0 0.0 1.6 0.0 108 5340.00 1 1 1 1 40 0.0 0.0 0.0 1.7 0.0 108 5340.00 1 1 1 1 40 0.0 0.0 0.0 1.8 0.0 108 5340.00 1 1 1 1 40 0.0 0.0 0.0 1.9 0.0 108 5390.00 1 1 1 1 40 0.0 0.0 0.0 2.0 0.0 108 5480.00 1 1 1 l 40 0.0 0.0 0.0 2.2 0.0 108 5480.00 1 1 1 1 40 0.0 0.0 0.0 2.3 0.0 108 5480.00 1 1 1 1 40 0.0 0.0 0.0 2.4 0.0 108 553 0.00 1 1 1 1 40 0.0 0.0 0.0 2.5 0.0 108 558 0.00 1 1 1 1 40 0.0 0.0 0.0 2.7 0.0 108 5630.00 1 1 1 1 40 0.0 0.0 0.0 2.8 0.0 108 6010.00 1 1 1 1 40 0.0 0.0 0.0 2.9 0.0 108 6010.00 Page 15 Attachment A Table A-1 1 1 1 1 40 0.0 0.0 0.0 3.0 0.0 107 5800.00 2 1 1 1 40 0.5 44.8 0.0 3.0 0.0 100 3970.00 2 1 1 1 39 0.5 44.8 0.0 3.1 0.0 99 4130.00 2 1 1 l 39 0.5 44.8 0.0 3.3 0.0 98 6990.00 2 1 1 1 38 0.5 44.8 0.0 3.4 0.0 95 7140.00 2 1 1 1 39 0.5 44.8 0.0 3.6 0.0 96 1145 0.00 2 1 1 1 38 0.5 44.8 0.0 3.7 0.0 94 1213 0.00 2 1 1 1 38 0.5 44.8 0.0 3.9 0.0 92 1182 0.00 2 1 1 l 38 0.5 44.8 0.0 4.0 0.0 92 1172 0.00 3 1 1 l 38 1.0 44.8 0.0 4.1 0.0 92 1172 0.00 3 1 1 1 38 1.0 44.8 0.0 4.2 0.0 90 1146 0.00 3 1 1 1 37 1.0 44.8 0.0 4.4 0.0 88 1112 0.00 3 1 1 1 37 1.0 44.8 0.0 4.5 0.0 88 1099 0.00 3 1 1 1 37 1.0 44.8 0.0 4.7 0.0 87 1091 0.00 3 1 1 1 37 1.0 44.8 0.0 4.9 0.0 86 1067 0.00 3 1 1 1 37 1.0 44.8 0.0 5.1 0.0 85 1053 0.00 4 1 1 1 36 2.0 44.8 0.0 5.2 0.0 83 1014 0.00 4 1 1 1 36 2.0 44.8 0.0 5.4 0.0 83 1014 0.00 4 0 1 1 35 2.0 21.9 1.4 5.6 0.0 81 9930.00 4 0 1 l 35 2.0 17.1 1.6 5.8 0.0 81 9890.00 4 0 1 1 34 2.0 13.9 1.8 5.9 0.0 80 9710.00 4 0 1 l 34 2.0 11.7 2.0 6.1 0.0 80 9680.00 5 0 1 1 34 3.0 20.4 2.1 6.2 0.0 79 9500.00 5 0 1 1 33 3.0 15.4 2.5 6.9 0.0 78 9340.00 5 0 1 1 31 3.0 10.5 3.3 7.1 0.0 76 9120.00 6 0 1 1 30 3.4 4.9 7.8 7.6 0.0 75 8980.00 6 0 1 1 28 4.3 6.5 7.6 8.2 0.0 74 8790.00 6 0 1 1 26 5.4 8.5 7.3 8.9 0.0 73 8630.00 6 0 1 1 24 6.4 10.6 7.1 9.5 0.0 72 8510.00 6 0 l 1 21 7.4 12.8 7.0 10.1 0.0 71 8440.00 6 0 l l 19 8.3 15.2 6.8 10.8 0.0 71 8380.00 6 0 1 1 17 9.2 17.7 6.7 11.4 0.0 71 8350.00 6 0 l l 15 10.1 20.3 6.6 12.1 0.0 70 8320.00 6 0 1 1 12 11.0 23.2 6.5 12.7 0.0 70 8320.00 6 0 1 1 10 11.7 25.6 6.5 13.2 0.0 70 8320.00 7 0 1 1 9 12.0 14.7 9.9 13.4 0.0 70 8320.00 7 0 1 1 7 12.0 13.9 10.4 14.0 0.0 70 8320.00 7 0 1 l 5 12.0 13.2 10.9 14.5 0.0 70 8320.00 Page 16 Attachment A Table A-1 7 0 1 1 2 12.0 12.7 11.4 15.3 0.0 70 8320.00 PROPPANT SUMMARY * At End of Pumping Schedule Alaska - Upper Beluga - 6127 - 6276 ft. Lb/Sq-Ft Lost to Embedment ............ 2.000 Distance KfW Prop Concentrationjotal Ib/sq foot) (ft) (md-ft) Prop ID 1.5 10924 1 8.82 3.3 11043 8.89 4.1 11234 9.01 4.9 11283 9.04 5.7 11402 9.12 6.5 11652 9.27 7.3 11726 9.32 8.1 11851 9.40 8.9 12056 9.53 9.7 12035 9.51 10.5 12015 9.50 11.3 11984 9.48 12.1 11972 9.47 12.9 11910 9.43 13.7 11742 9.33 14.5 11604 9.24 15.3 11435 9.14 16.1 11208 9.00 16.9 11045 8.89 17.7 10841 8.77 18.5 10595 8.61 19.3 10401 8.49 20.1 10160 8.34 20.9 9897 8.18 21.7 9667 8.03 22.5 9375 7.85 23.3 9084 7.67 24.1 8849 7.52 24.8 8582 7.36 25.4 8276 7.17 Page 17 Attachment A Table A-1 26.2 7998 6.99 27.0 7634 6.77 27.8 7236 6.52 28.6 6904 6.31 29.4 6515 6.07 30.2 6065 5.79 31.0 5933 5.70 31.8 6466 6.04 32.6 6629 6.14 33.4 6127 5.82 34.2 5422 5.38 35.0 6499 6.06 35.8 7964 6.97 36.6 7257 6.53 37.4 3982 4.49 38.2 1520 2.79 39.0 380 1.37 39.8 114 0.41 Average Conductivity (md-ft) 9368 PROPPANT SUMMARY * At Fracture Closure Alaska - Upper Beluga - 6127 - 6276 ft. Lb/Sq-Ft Lost to Embedment ............ 2.000 Distance KfW Prop Concentration(Total lb/sq foot) (ft) (md-ft) Prop ID 1.5 9836 l 8.13 3.3 9924 8.19 4.1 10143 8.33 4.9 10238 8.39 5.7 10401 8.49 6.5 10919 8.81 7.3 11256 9.02 8.1 10965 8.84 8.9 11022 8.87 9.7 11214 8.99 10.5 11178 8.97 11.3 11171 8.97 Page 18 Attachment A 12.1 11171 8.97 12.9 11157 8.96 13.7 11090 8.92 14.5 10983 8.85 15.3 10869 8.78 16.1 10761 8.71 16.9 10660 8.65 17.7 10540 8.57 18.5 10416 8.50 19.3 10302 8.43 20.1 10163 8.34 20.9 10019 8.25 21.7 9893 8.17 22.5 9731 8.07 23.3 9562 7.96 24.1 9424 7.88 24.8 9270 7.78 25.4 9101 7.68 26.2 8936 7.57 27.0 8744 7.45 27.8 8676 7.41 28.6 8638 7.39 29.4 8132 7.07 30.2 8241 7.14 31.0 8578 7.35 31.8 8647 7.39 32.6 8795 7.49 33.4 8247 7.14 34.2 7934 6.95 35.0 8747 7.46 35.8 9640 8.01 36.6 7680 6.79 37.4 4089 4.55 38.2 1547 2.80 39.0 387 1.38 39.8 116 0.41 Average Conductivity (md-ft) Page 19 Table A-1 9565 Attachment P - "',U A -2A Lower Sterl Frac Pack Design Modeling 050 FRACTURING, LLC. e To: Mr. Jack Burman Exploitation Technologies Houston, Texas 77069 ig 5395-5486' MD July 18, 2016 07042016 Re: Kitchen Lights Unit A -2A - "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand Preliminary Frac Pack Design Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand was evaluated for a frac pack stimulation treatment in order to get a moderately conductive fracture to enhance production from this estimated 600 and reservoir. Reservoir properties for this well are an estimated reservoir pressure of 2,088 psi, an average porosity of 30%, an estimated permeability of 600 md, and an estimated BHT of 96°F. The result indicates a Folds -Of -Increase (FOI) of approximately 1.22 for a 30 ft. propped frac pack half- length with a conductivity of 6 - 8 lbs./sq.ft. Optimal Half -Length and Conductivity: Using the above reservoir properties, propped frac pack half -lengths (0 to 100 ft.) and conductivities (4 to 8 lbs./sq.ft.) were evaluated using a flowing BHP of 1,888 psi to determine the design propped frac pack half-length and conductivity. As can be seen in Figure 1, the optimum propped frac pack half-length is about 30 ft. with a conductivity of 6 - 8 lbs./sq.ft. With this, a FOI of 1.22 could be seen. Thus, a fracture half-length of 30 ft. length was chosen to ensure good production and was used as initial design goals. Figure 1 - Predicted FOI vs Propped Frac Pack Half -Lengths Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand rracmre 112 Length (ft) Stress Profile: A closure pressure of 2,751 psi (0.59 psi/ft.) was used and was based a reservoir pressure of 2,088 psi and a Poisson's Ratio of 0.25. The modulus in the pay sand was estimated to be 0.20 - 0.25 x 106 psi and in the bounding shale was 0.30 x 106 psi and was based on the frac packs around the same depths. Leak -Off Profile: The leak -off coefficients that were used are estimated to be 0.0075 - 0.010 ft./sq.rt. minute (this gives a fluid efficiency of 31% for the mini -frac) in the pay sand and in the adjacent layers estimated to be 0.001 ft./sq.rt. minute and was based on the frac packs around the same depths and perms. Proppant Selection: With this being an gas zone having a reservoir temperature of 96°F with a possible fines migration problem and a closure pressure estimated to be 2,088 psi, 30/50 mesh Carbo -Lite is recommended. Fracturing Fluid Selection: Since the bottomhole temperature is around 96°F, a 20# Borate Gel is recommended. Gel crosslink times should be halfway down the workstring (1.0 minute with a 3-1/2" drill pipe) and break times should be around 60 minutes to 50 cp at 170 sec'. Preliminary Frac Pack Treatment Design: The preliminary design is shown in Table 1. The proppant schedule starts out with a 0., ppg stage and goes up to a maximum concentration of 12.0 ppg. The design injection rate is 18 bpm through the entire job and reduced for the annular pack (based on the results of the mini -frac rate may be increased for the frac pack). The resultant treatment calls for 14,000 gals. of gel and 75,500 lbs. of 30/50 mesh Carbo -Lite. The predicted point of the TSO is at the beginning of the 3.0 ppg stage going into the fracture. Prior to this point, the model predicted net BHTP (BHTP - closure P) is 115 psi with a corresponding average fracture width of 0.34 inches. Throughout the remainder of the treatment, the predicted net pressure increased to 472 psi (Figure 2) and was coupled with an average width increase of 1.58 inches. The resultant frac pack dimensions are a propped half-length of 46 ft., a maximum height at the wellbore of 103 ft., and an average conductivity of 11,974 and -ft (avg. in-situ conc. = 9.28 lbs./sq.ft.). These are shown in Figures 3 - 6 with the model 1/0 included in Attachment A Table A-1. Table 1 - Preliminary Frac Pack Design Schedule Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand 174 14 0 Floes Bac K Rate (BP&J) 4re:2':=, 54 75 5___ 23 0 ('C onstaul PPG Steps Scneoule e-- FIUld Ramp C Slurry Ramp Design - Patl Page 3 Proppant Type Carbo EconoProp. 250 F Lo g Term 33-50 Carbo EconoProp. 250 F. LO g Term 30-50 Carbo EconoProp, 250 F Lo Term 30-50 Carbo EconoProp. 250 E Lo g Term 30-50 Carbo EconoProp, 250 F Lo g Term 30-50 Carbo EconoProp,. 250 F Lo g Term 30-50 Carbo EconoProp. 250 F. Lo g Term 30-50 (*- Blesseo--- ------ Slurry Fluio Proppant Corr, r'irs, stage volume A7 Volume 'M (PPG) Ratei'!u' Proppant Pump Time Cum -Gal -Gal Stan Erb (BPM) Fracticr.) (M-Lb9i p Time 2 2.000 2.000 0.00 0.00 16 L 0.0000 0 0 minl (MM) Flu10 Type 1.022 1.000 0.50 050 18.0 0.0000 0.5 2.8 2.6 20# Borale 3 1.045 1.000 700 1.00 18.0 0 ODDO 10 14 4 0 20k Borate 4 1.089 1.000 2.00 200 18.0 0.0000 2 r 2 G 1,4 5 4 20X Borate 5 1.134 1 000 3.00 3.00 18 0 0.0000 1 4 6.8 20p Borate 7 8.006 6000 3.D0 12.00 18.0 0.0000 450 1.5 8.3 20N Borale 7 3.071 2.000 12.00 12 DD i 6.0 D.0000 10.6 18.9 20Y Borate 24.0 4,1 230 2Cgi Borate 174 14 0 Floes Bac K Rate (BP&J) 4re:2':=, 54 75 5___ 23 0 ('C onstaul PPG Steps Scneoule e-- FIUld Ramp C Slurry Ramp Design - Patl Page 3 Proppant Type Carbo EconoProp. 250 F Lo g Term 33-50 Carbo EconoProp. 250 F. LO g Term 30-50 Carbo EconoProp, 250 F Lo Term 30-50 Carbo EconoProp. 250 E Lo g Term 30-50 Carbo EconoProp, 250 F Lo g Term 30-50 Carbo EconoProp,. 250 F Lo g Term 30-50 Carbo EconoProp. 250 F. Lo g Term 30-50 O N Figure 2 - Preliminary Frac Pack Design - Nolte -Smith Plot Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand Time (min) Figure 3 - Preliminary Frac Pack Design - Frac Pack Penetration Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand MD ft 5400 5450 5500 Alaska - Lower Sterling - 5395 •5486 ft Fracture Penetration (ft) Page 4 c n C d m t N Figure 4 - Preliminary Frac Pack Design - Width Profile Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand Alaska -Lower Sterling .5395 .5486 ft MD ft 5380 e C C C C C T e c c C � v c E a a w Y 0 0 0 0 0 0 v 0 0 0 N 5400 5420 5440 5460 5480 5500 Figure 5 - Preliminary Frac Pack Design - Conductivity Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand rracture Penetration (ft) Page 5 C cc N Figure 6 - Preliminary Frac Pack Design - In -Situ Concentration Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand Fracture Penetration (ft) Figure 7 is a plot of predicted surface injection pressures using a 3-1/2" string and Figure 8 is a plot of bottomhole injection pressures based on a closure pressure of 2,751 psi. d Figure 7 - Preliminary Frac Pack Design - Predicted Injection Pressures Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand Tlme (min) Page 6 Figure 8 - Preliminary Frac Pack Design - Predicted Bottomhole Injection Pressures Kitchen Lights Unit A -2A, "Lower Sterling 5,395 ft. - 5,486 ft. MD" Sand lime )min) Recommended Pre -Frac Testing• The following testing program is recommended: (1) A 7,560 gal. 20# Borate Gel mini -frac at 18 bpm to evaluate fluid efficiency, closure pressure, and to calibrate the design model for final treatment design. For the mini -frac fluid only, the breaker needs to be increased to get a break time of 30 minutes at BHT. Increasing the breaker in the mini -frac helps to insure that the gel has broken to when the main frac pack is pumped. (2) A 1,995 gal. slickwater step -rate test to flush the crosslink gel away from the near wellbore region, determine extension pressure, and possibly confirm closure stress at rates of 1, 2, 3, 4, 5, 7.5, 10, & 15 bpm in one -minute step increments. Jack, if you need anything else, please give me a call. Regards, Ron Vandersypen 1 Attachment A Table A-1 STIMPLAN (TM) , NSI, Tulsa,OK - www.nsitech.com Frac Summary *Alaska - Lower Sterling - 5395 - 5486 ft Filename:G... Upper Sterling 4725 - 4803' MD.STP; 18 -Jul -2016 Well ID: Alaska - Lower Sterling - 5395 - 5486 ft Perforated Interval:MD (ft) Top 5395.0 Bottom 5486.0 Formation Temperature (OF) 96 Notes FORMATION LAYER DATA - Multi -Layer Height Growth Depth (ft) Stress (psi) Gradient Modulus Toughness Loss Coef. Spurt Top Bottom Thickness Top Bottom (psi/ft) 4581.8 4624.4 4624.4 4628.1 4628.1 4663.4 4663.4 4672.1 4672.1 4707.5 4707.5 4712.3 4712.3 4731.5 4731.5 4780.7 4780.7 4792.7 4792.7 4826.4 4826.4 4844.4 4844.4 4850.5 4850.5 4867.9 4867.9 4873.2 4873.2 0.00000 FORMATION: 0.00100 TEMPERATURE: PRESSURE: DEPTH: (MMpsi) (psi*sgrt(in)) (ft/sqrt(min)) (gal/100ft^2 42.6 2746.4 2772.0 0.600 0.30 3.7 2722.0 2724.2 0.590 0.25 35.3 2774.2 2795.4 0.600 0.30 8.7 2745.4 2750.5 0.590 0.25 35.5 2800.5 2821.8 0.600 0.30 4.8 2771.8 2774.6 0.590 0.25 19.1 2824.6 2836.1 0.600 0.30 49.2 2736.1 2765.1 0.590 0.20 12.0 2865.1 2872.3 0.600 0.30 33.7 2772.3 2792.2 0.590 0.20 18.0 2892.2 2903.0 0.600 0.30 6.1 2853.0 2856.6 0.590 0.25 17.4 2906.6 2917.0 0.600 0.30 5.3 2867.0 2870.1 0.590 0.25 2920.1 0.600 0.30 0.00000 Perforated Height (ft) 0.00100 Permeability (md) 2800.0 Bottom Hole (OF) 0.00000 Reservoir Pressure (psi) 0.00100 Closure Pressure (psi) 2800.0 Well Depth (ft) Fluid Pressure Gradient (psi/ft) Perforations Top (ft) 0.00000 Bottom (ft) Page 8 2800.0 0.00100 0.00000 2800.0 0.00750 0.00000 2800.0 0.00100 0.00000 2800.0 0.00750 0.00000 2800.0 0.00100 0.00000 2800.0 0.00750 0.00000 2800.0 0.00100 0.00000 2800.0 0.01000 0.00000 2800.0 0.00100 0.00000 2800.0 0.01000 0.00000 2800.0 0.00100 0.00000 2800.0 0.00750 0.00000 2800.0 0.00100 0.00000 2800.0 0.00750 0.00000 2800.0 0.00100 0.00000 87.5 600.000 96 2088.0 2750.7 4731.6 0.442 4731.6 4819.0 Attachment A Table A-1 Initial Top (ft) 4731.6 Bottom (ft) 4819.0 3-D SIMULATOR StimPlan I -D PROGRAM CONTROL Step Size (ft) Automatic Time Step (min) Automatic Calculated Results from 3-D Simulator - StimPlan 1-D Pumping Schedule - Design - Pad Licensed To: NSI Fracturing - Version 7.10 Half Length 'Hydraulic' Length (ft) 46.7 Propped length (ft) 45.7 PRESSURE: Max Net Pressure (psi) 472.0 Surface Pres -End of Pad (psi) 1873.6 Surface Pres -Start of Flush (psi) 1780.0 Surface Pres -End of Job (psi) 2236.3 Maximum Hydraulic Horsepower 1006.4 TIME: Max Exposure to Form. Temp. (min) 1.6 Time to Close 19.9 RATE: Fluid Loss Rate during pad (BPM) 12.97 EFFICIENCY: At end of pumping schedule 0.50 PROPPANT: Average In Situ Conc.(lb/ft^2) 9.28 Average Conductivity (md-ft) 11974.4 Fcd (KfW/k/Xf) 0.44 HEIGHT: Max Fracture Height (ft) 102.8 WIDTH: Avg width at end of pumping (in) 1.58 VOLUMES: Total Fluid Volume (M -Gal) 14.0 Total Proppant Volume (M -Lbs) 75.5 (TM). NSI Technologies, Tulsa, OK Licensed To: NSI Fracturing - Version 7.10 WELL ID: Alaska - Lower Sterling - 5395 - 5486 ft DEPTH: Well Depth (ft) 4731.57 PRESSURE: Reservoir Pressure (psi) 2088.0 Closure Pressure (psi) 2750.7 TEMPERATURE: Bottom Hole Temperature 96.0 Attachment A Table A-1 * * Pumping Schedule Design - Pad S1 Vol Fl Vol Conc (PPG) Rate Fluid Prop Cum Proppant Pump Time (M -Gal) (M -Gal) Start End (BPM) Type Type (M -Lbs) (min) 2.00 2.00 0.0 0.0 18.00 6 10 0.0 2.6 1.02 1.00 0.5 0.5 18.00 6 10 0.5 1.4 1.04 1.00 1.0 1.0 18.00 6 10 1.5 1.4 1.09 1.00 2.0 2.0 18.00 6 10 3.5 1.4 1.13 1.00 3.0 3.0 18.00 6 10 6.5 1.5 8.01 6.00 3.0 12.0 18.00 6 10 51.5 10.6 3.07 2.00 12.0 12.0 18.00 6 10 75.5 4.1 Total Slurry 17.4 Total Fluid 14.0 Total Proppant 75.5 Avg. Conc 5.4 Total Pump Time 23.0 min Pad % Pump Schedule Assumes Prop Conc Increases Linearly With CLEAN FLUID Volume 11.5 Proppant Data Proppant ID No. 10 30-50 Carbo EconoProp, 250 F, Long Term Specific Gravity 2.69 Damage Factor 0.0 = No Damage) 0.70 Proppant Stress 0 2 4 8 16 K1W @ 2 #/sq ft and -ft) 4800 4400 3500 1750 300 Fluid Data Fluid ID No. 6 20# Borate Specific Gravity 1.02 Data @Wellbore (a�FormTmp 0.33 hr 0.66 hr 1.0 hr 1.5 hr vis(cp g 170 1/sec) 251.5 465.7 168.1 125.8 97.4 79.8 non -Newtonian n' 0.58 0.58 0.63 0.67 0.69 0.70 K(lb/sec/ft^2)x1000 44.56 82.50 23.04 14.04 9.81 7.63 Friction Data Q (BPM) P/dL (psi/100ft) 1.0 0.6 7.0 4.3 Pipe Friction Data 13.0 10.5 19.0 18.2 25.0 27.3 Measured Depth (ft) 5395.0 Page 10 Attachment A Table A-1 Time History * NSI STIMPLAN 3-D Fracture Simulation Alaska - Lower Sterling - 5395 - 5486 ft Time Pen Pres Rate Prop S1 Vol Efficiency Loss Hght W -Avg (min) (ft) (psi) (BPM) (PPG) (M -Gal) (BPM) (ft) (in) 0.8 7.3 109 18.00 0.0 0.6 0.59 7.1 88 0.45 1.3 9.3 109 18.00 0.0 1.0 0.60 6.6 88 0.58 1.5 11.3 110 18.00 0.0 1.1 0.58 9.5 89 0.53 1.6 13.3 110 18.00 0.0 1.2 0.56 11.2 89 0.48 1.7 15.3 110 18.00 0.0 1.3 0.54 12.3 89 0.44 1.9 17.3 111 18.00 0.0 1.4 0.51 13.6 89 0.40 2.0 19.3 111 18.00 0.0 1.5 0.49 14.6 89 0.37 2.3 21.3 110 18.00 0.0 1.7 0.46 12.9 90 0.36 2.7 23.7 111 18.00 0.0 2.0 0.44 13.0 90 0.36 2.9 25.7 111 18.00 0.5 2.2 0.43 12.4 90 0.35 3.2 27.7 111 18.00 0.5 2.4 0.41 13.2 90 0.35 3.5 29.7 111 18.00 0.5 2.7 0.40 12.5 90 0.35 3.9 31.7 111 18.00 0.5 2.9 0.39 12.9 91 0.35 4.2 33.7 111 18.00 0.8 3.2 0.38 13.3 91 0.35 4.6 35.7 112 18.00 1.0 3.5 0.37 13.1 91 0.35 5.0 37.7 112 18.00 1.0 3.7 0.36 13.6 91 0.35 5.3 39.7 112 18.00 1.0 4.0 0.35 13.3 91 0.34 5.8 41.7 112 18.00 1.9 4.4 0.34 13.8 92 0.34 6.3 43.7 115 18.00 2.0 4.8 0.34 13.0 96 0.35 7.0 45.7 115 18.00 2.2 5.3 0.33 13.5 101 0.34 8.0 46.7 114 18.00 3.0 6.0 0.32 13.5 103 0.36 Screen Out in Stage 2.0 at Time = 8.0 min at 9.0 46.7 120 18.00 3.2 6.8 0.32 44.7 ft 12.2 103 0.41 10.1 46.7 138 18.00 4.2 7.6 0.33 10.0 103 0.47 11.1 46.7 159 18.00 5.2 8.4 0.35 9.0 103 0.55 12.1 46.7 182 18.00 6.1 9.2 0.36 8.3 103 0.62 Screen Out in Stage 3.0 at Time = 12.1 min at 42.7 It 13.2 46.7 207 18.00 7.0 10.0 0.38 7.8 103 0.71 14.2 46.7 232 18.00 7.9 10.8 0.40 7.3 103 0.79 15.3 46.7 258 18.00 8.8 11.5 0.41 7.0 103 0.88 16.3 46.7 285 18.00 9.6 12.3 0.42 6.6 103 0.97 17.3 46.7 312 18.00 10.4 13.1 0.44 6.4 103 1.06 18.4 46.7 341 18.00 11.2 13.9 0.45 6.1 103 1.15 Page 11 Attachment A Table A-1 Screen Out in Stage 4.0 at Time = 18.4 min at 40.7 ft 19.4 46.7 370 18.00 11.9 14.7 0.46 5.9 103 1.25 20.5 46.7 400 18.00 12.0 15.5 0.47 5.7 103 1.35 21.5 46.7 430 18.00 12.0 16.3 0.48 5.5 103 1.44 23.0 46.7 472 18.00 12.0 17.4 0.50 5.4 103 1.58 26.2 46.7 434 0.00 0.0 17.4 0.46 5.1 103 1.46 29.6 46.7 396 0.00 0.0 17.4 0.42 4.7 103 1.34 33.2 46.7 359 0.00 0.0 17.4 0.38 4.4 103 1.23 35.1 46.7 340 0.00 0.0 17.4 0.36 4.2 103 1.17 36.9 46.7 321 0.00 0.0 17.4 0.34 4.1 103 1.12 38.8 46.7 302 0.00 0.0 17.4 0.33 4.0 103 1.07 40.6 46.7 283 0.00 0.0 17.4 0.31 3.9 103 1.02 42.1 46.7 264 0.00 0.0 17.4 0.30 3.8 103 0.99 42.8 46.7 245 0.00 0.0 17.4 0.29 3.7 103 0.97 GEOMETRY SUMMARY * At End of Pumping Schedule Alaska - Lower Sterling - 5395 - 5486 ft Distance Pressure W -Avg Q Sh-Rate Hght (ft) Bank Prop (ft) (Psi) (in) (BPM) (1/sec) Total Up Down Prop Fraction (PSF) 3 472 2.02 8.9 1 103 7 8 103 0.00 10.25 6 472 2.02 7.5 1 103 7 8 103 0.00 10.52 8 472 2.02 7.0 1 103 7 8 103 0.00 10.77 10 472 2.02 6.5 1 103 7 8 103 0.00 11.00 12 472 2.02 6.0 1 103 7 8 103 0.00 10.98 14 472 2.02 5.5 0 102 7 7 102 0.00 10.95 16 472 2.00 5.0 0 100 6 7 100 0.00 10.78 18 472 1.98 4.5 0 99 5 6 99 0.00 10.60 20 472 1.85 4.0 0 90 1 l 90 0.00 9.92 23 472 1.85 3.6 0 90 1 1 90 0.00 9.88 25 472 1.81 3.0 0 88 0 0 88 0.00 9.66 27 472 1.81 2.6 0 88 0 0 88 0.00 9.60 29 472 1.76 2.2 0 85 -1 -1 85 0.00 9.32 31 472 1.68 1.8 0 81 -3 -3 81 0.00 8.92 33 472 1.60 1.4 0 77 -5 -5 77 0.00 8.48 35 472 1.50 1.1 0 72 -8 -8 72 0.00 7.99 37 472 1.38 0.8 0 67 -10 -10 67 0.00 7.49 39 472 1.25 0.5 0 61 -13 -13 61 0.07 8.80 41 472 1.10 0.3 0 53 -17 -17 53 0.66 10.04 Page 12 Attachment A Table A-1 43 340 0.65 0.1 0 44 -22 -22 44 1.00 6.40 45 181 0.25 0.1 3 31 -28 -28 31 1.00 2.80 46 110 0.18 0.0 8 30 -29 -29 30 0.22 0.36 FLUID SUMMARY * At End of Pumping Schedule Alaska - Lower Sterling - 5395 - 5486 ft Stage Fluid Prop Pos Concentration F] Vol Ex Tim Temp Viscosity Fall No Gone ID ID (ft) Initial Now Design (M -Gal) (min) (pF) (cp) Frac i 1 1 1 47 0.0 0.0 0.0 0.6 1.3 96 6500.00 1 1 1 1 47 0.0 0.0 0.0 1.0 1.0 96 6650.00 l 1 l 1 47 0.0 0.0 0.0 1.1 0.6 96 6640.00 1 1 1 1 47 0.0 0.0 0.0 1.2 0.6 96 6870.00 1 1 1 1 47 0.0 0.0 0.0 1.3 0.5 96 6590.00 1 1 1 1 47 0.0 0.0 0.0 1.4 0.6 96 7400.00 1 l 1 1 47 0.0 0.0 0.0 1.5 0.5 96 7620.00 1 1 l 1 47 0.0 0.0 0.0 1.7 0.6 96 1069 0.00 1 1 1 1 47 0.0 0.0 0.0 2.0 0.8 96 1055 0.00 2 1 1 l 47 0.5 44.8 0.0 2.0 0.6 96 1055 0.00 2 1 1 1 47 0.5 44.8 0.0 2.2 0.3 89 7140.00 2 1 1 1 45 0.5 44.8 0.0 2.4 0.0 86 6690.00 2 1 1 1 46 0.5 44.8 0.0 2.7 0.0 86 1016 0.00 2 1 1 1 46 0.5 44.8 0.0 2.9 0.0 84 1154 0.00 2 1 1 1 45 0.5 44.8 0.0 3.0 0.0 84 1147 0.00 3 1 1 1 43 1.0 44.8 0.0 3.2 0.0 81 1062 0.00 3 1 1 1 43 1.0 44.8 0.0 3.5 0.0 80 1048 0.00 3 1 1 1 44 1.0 44.8 0.0 3.7 0.0 80 1043 0.00 3 1 1 l 44 1.0 44.8 0.0 4.0 0.0 79 1013 0.00 3 1 1 1 43 1.0 44.8 0.0 4.1 0.0 79 1025 0.00 4 1 1 1 42 2.0 44.8 0.0 4.4 0.0 76 9540.00 4 1 1 1 41 2.0 44.8 0.0 4.8 0.0 75 9360.00 4 0 1 1 41 2.0 38.2 1.1 5.1 0.0 75 9260.00 5 1 1 1 40 3.0 44.8 0.0 5.3 0.0 74 9040.00 5 0 1 1 39 3.0 22.8 2.0 5.8 0.0 73 8840.00 5 0 1 1 38 3.0 19.2 2.2 6.0 0.0 73 883 0.00 5 0 1 1 37 3.0 13.7 2.7 6.2 0.0 72 8660.00 6 0 1 1 36 3.3 5.7 6.4 6.6 0.0 72 8640.00 6 0 1 1 34 4.2 7.1 6.7 7.2 0.0 71 8520.00 6 0 1 1 32 5.2 8.9 6.7 7.8 0.0 71 8440.00 Page 13 Attachment A Table A-1 6 0 1 1 30 6.1 10.8 6.7 8.4 0.0 71 8390.00 6 0 1 1 27 7.0 12.7 6.7 9.0 0.0 70 8350.00 6 0 1 1 24 7.9 14.8 6.6 9.6 0.0 70 8320.00 6 0 1 1 22 8.8 16.9 6.6 10.2 0.0 70 8320.00 6 0 1 1 19 9.6 19.1 6.6 10.8 0.0 70 8320.00 6 0 1 1 16 10.4 21.5 6.5 11.4 0.0 70 8320.00 6 0 1 1 14 1 l .2 24.1 6.5 12.1 0.0 70 8320.00 6 0 1 1 12 11.8 25.8 6.5 12.4 0.0 70 8320.00 7 0 1 1 10 12.0 14.5 10.0 12.6 0.0 70 8320.00 7 0 1 1 8 12.0 13.8 10.5 13.2 0.0 70 8320.00 7 0 1 1 6 12.0 13.2 10.9 13.7 0.0 70 832 0.00 7 0 1 1 2 12.0 12.7 11.4 14.4 0.0 70 832 0.00 PROPPANT SUMMARY * At End of Pumping Schedule Alaska - Lower Sterling - 5395 - 5486 ft Lb/Sq-Ft Lost to Embedment ............ 2.000 Distance KfW Prop Concentration(Total lb/sq foot) (ft) (md-ft) Prop ID 1 2.7 13326 10.33 6.3 13656 10.53 8.3 14035 10.77 10.3 14302 10.94 12.3 14341 10.96 14.3 14260 10.91 16.3 14031 10.77 18.3 13558 10.47 20.3 12881 10.05 22.5 12589 9.87 24.7 12312 9.69 26.7 12085 9.55 28.7 11647 9.28 30.7 11042 8.90 32.7 10341 8.46 34.7 9575 7.98 36.7 9511 7.94 38.7 11038 8.90 40.7 10951 8.84 Page 14 Attachment A Table A-1 42.7 6577 6.11 44.7 2285 3.02 46.2 686 1.16 Average Conductivity (md-ft) 11789 PROPPANT SUMMARY * At Fracture Closure Alaska - Lower Sterling - 5395 - 5486 ft Lb/Sq-Ft Lost to Embedment ............ 2.000 Distance KfW Prop Concentration(Total lb/sq foot) (ft) (md-ft) Prop ID 2.7 11951 1 9.46 6.3 12263 9.66 8.3 12710 9.94 10.3 13302 10.31 12.3 13664 10.53 14.3 13414 10.38 16.3 13283 10.29 18.3 13057 10.15 20.3 12985 10.11 22.5 13295 10.30 24.7 12832 10.01 26.7 12679 9.92 28.7 12365 9.72 30.7 12281 9.67 32.7 12538 9.83 34.7 12315 9.69 36.7 12329 9.70 38.7 12865 10.03 40.7 11415 9.13 42.7 6697 6.18 44.7 2316 3.04 46.2 695 1.16 Average Conductivity (md-ft) Page 15 11974 Attachment Q - �U A -2A Upper Sterl Frac Pack Design Modeling 050 FRACTURING, LLC. e To: Mr. Jack Burman Exploitation Technologies Houston, Texas 77069 ig 4725-4803' MD July 14, 2016 07012016 Re: Kitchen Lights Unit A -2A - "Upper Sterling 4,725 ft. - 4,803 ft. MD" Sand Preliminary Frac Pack Design Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft. MD" Sand was evaluated for a frac pack stimulation treatment in order to get a moderately conductive fracture to enhance production from this estimated 600 and reservoir. Reservoir properties for this well are an estimated reservoir pressure of 1,712 psi, an average porosity of 28%, an estimated permeability of 600 md, and an estimated BHT of 90°F. The result indicates a Folds -Of -Increase (FOI) of approximately 1.22 for a 35 ft. propped frac pack half- length with a conductivity of 6 - 8 lbs./sq.ft. Optimal Half -Length and Conductivity: Using the above reservoir properties, propped frac pack half -lengths (0 to 100 ft.) and conductivities (4 to 8 lbs./sq.ft.) were evaluated using a flowing BHP of 1,512 psi to determine the design propped frac pack half-length and conductivity. As can be seen in Figure 1, the optimum propped frac pack half-length is about 35 ft. with a conductivity of 6 - 8 lbs./sq.ft. With this, a FOI of 1.22 could be seen. Thus, a fracture half-length of 35 ft. length was chosen to ensure good production and was used as initial design goals. Figure 1 - Predicted FOI vs Propped Frac Pack Half -Lengths Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft. MW Sand 0 rFdcture itL Length (ft) Stress Profile: A closure pressure of 2,307 psi (0.56 psi/ft.) was used and was based a reservoir pressure of 1,712 psi and a Poisson's Ratio of 0.25. The modulus in the pay sand was estimated to be 0.20 - 0.25 x 106 psi and in the bounding shale was 0.30 x 106 psi and was based on the frac packs around the same depths. Leak -Off Profile: The leak -off coefficients that were used are estimated to be 0.0075 - 0.010 ft./sq.rt. minute (this gives a fluid efficiency of 28% for the mini -frac) in the pay sand and in the adjacent layers estimated to be 0.001 ft./sq.rt. minute and was based on the frac packs around the same depths and perms. Proppant Selection: With this being an gas zone having a reservoir temperature of 90°F with a possible fines migration problem and a closure pressure estimated to be 2,307 psi, 30/50 mesh Carbo -Lite is recommended. Fracturing Fluid Selection: Since the bottomhole temperature is around 90°F, a 20# Borate Gel is recommended. Gel crosslink times should be halfway down the workstring (1.0 minute with a 3-1/2" drill pipe) and break times should be around 60 minutes to 50 cp at 170 sec -1. Page 2 Preliminary Frac Pack Treatment Design The preliminary design is shown in Table 1. The proppant schedule starts out with a 0.5 ppg stage and goes up to a maximum concentration of 12.0 ppg. The design injection rate is 18 bpm through the entire job and reduced for the annular pack (based on the results of the mini -frac rate may be increased for the frac pack). The resultant treatment calls for 15,000 gals. of gel and 75,500 lbs. of 30/50 mesh Carbo -Lite. The predicted point of the TSO is at the beginning of the 3.0 ppg stage going into the fracture. Prior to this point, the model predicted net BHTP (BHTP - closure P) is 111 psi with a corresponding average fracture width of 0.29 inches. Throughout the remainder of the treatment, the predicted net pressure increased to 447 psi (Figure 2) and was coupled with an average width increase of 1.25 inches. The resultant frac pack dimensions are a propped half-length of 58 ft., a maximum height at the wellbore of 104 ft., and an average conductivity of 9,200 and -ft (avg. in-situ conc. = 7.44 lbs./sq.ft.). These are shown in Figures 3 - 6 with the model 1/0 included in Attachment A Table A-1. Table 1 - Preliminary Frac Pack Design Schedule Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft. MW Sand 4Vell2 Na - Lov;Er St_rlln99 _472b n.Mq. u(0- Blessed. - - Slurry Id Proppant Colli Stage Pt VF 'M-GaVolumeil �r"ractior} Proppant Pump Time -Gal Start End End (Pd 7 (h1-Lbs.i Cum Time 1 3000 3.006 OOG 0.00 16.0 0.0000 0.0 mIn (min) Fluid Type 2 1 022 1 DOG 0.50 0.50 18.0 00000 0 5 4.0 4.0 2CVt Borale 3 1.045 7.000 100 1.00 78.0 O.ODQD 1 G 1.4 8.4 2071 Borate 4 1.085 LfiD0 200 2.00 18.0 0.0000 2.0 1.d 0.8 20.7 Borate 5 1 134 1.000 3.00 3.00 18.0 00000 3.0 1.4 8.2 20,'r, Bowie 6 8.006 6.OW 300 12.OG 78 0 0.0000 45.0 t 5 - 9J 20? Borate 7 3.071 2.000 12.00 12.00 78.0 0.0000 24 0 10.6 20 3 20Y Borate 4 1 24.4 20P Borate 784 150 �iT; =^=. 5.0 75.5 24.4 r Constant FFG Steps - SchetluW_---------_ i F Fluid Ramp r Slurry Ramp Design - By Patl .� Flow Bac Y. Rale (Bp,?A ® Page 3 _I Proppant Type Carbo Econ)Prop. 250 F Log Term 30-5G Carbo EconoProp. 250 F Lo Tenn 30-50 Carbo EconoProp 250 F. Lo Tenn 30-50 Carbo EconoProp, 250 F Lo Term 30-50 Carbo EconoProp. 250F Log Tenn 30-50 Carbo EconoProp 250 F Lo ,j Term 30-50 Carbo EconoProp 250 F La g Term 30-50 Figure 2 - Preliminary Frac Pack Design - Nolte -Smith Plot Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft. MD" Sand aLqRka . i I.,..o c.oa,A71. k . �� cv Time (min) Figure 3 - Preliminary Frac Pack Design - Frac Pack Penetration Kitchen Lights Unit A -2A, "Upper Sterling'4,725 ft. - 4,803 ft. MD" Sand Alaska - Upper Sterling - 4725 ft. MD Zo MD ft 4700 4750 4800 Fracture Penetration (ft) t 44 j/ 4J C 1.0 9n r„ �� cv Time (min) Figure 3 - Preliminary Frac Pack Design - Frac Pack Penetration Kitchen Lights Unit A -2A, "Upper Sterling'4,725 ft. - 4,803 ft. MD" Sand Alaska - Upper Sterling - 4725 ft. MD Zo MD ft 4700 4750 4800 Fracture Penetration (ft) Figure 4 - Preliminary Frac Pack Design - Width Profile Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft. MD" Sand Alaska - Upper Sterling - 4725 ft. MD Zo Stress (I)SI) - MD C,. 4ft 700 4780 — r - - — — 4800 m - �o t y 4820 2000 2200 2400 2600 9Rnn 4nnn E °C Figure 5 - Preliminary Frac Pack Design - Conductivity Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft. MD" Sand t-racture Penetration (ft) Figure 6 - Preliminary Frac Pack Design - In -Situ Concentration Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft. MD" Sand rracuare Penetration (ft) Figure 7 is a plot of predicted surface injection pressures using a 3-1/2" string and Figure 8 is a plot of bottomhole injection pressures based on a closure pressure of 2,307 psi. e c b Figure 7 - Preliminary Frac Pack Design - Predicted Injection Pressures Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft. MD" Sand O O O nme (min) Page 6 Figure 8 - Preliminary Frac Pack Design - Predicted Bottomhole Injection Pressures Kitchen Lights Unit A -2A, "Upper Sterling 4,725 ft. - 4,803 ft, MD" Sand Time (min) Recommended Pre -Frac Testing: The following testing program is recommended: (1) A 7,560 gal, 20# Borate Gel mini -frac at 18 bpm to evaluate fluid efficiency, closure pressure, and to calibrate the design model for final treatment design. For the mini -frac fluid only, the breaker needs to be increased to get a break time of 30 minutes at BHT. Increasing the breaker in the mini -frac helps to insure that the gel has broken to when the main frac pack is pumped. (2) A 1,995 gal. slickwater step -rate test to flush the crosslink gel away from the near wellbore region, determine extension pressure, and possibly confirm closure stress at rates of 1, 2, 3, 4, 5, 7.5, 10, & 15 bpm in one -minute step increments. Jack, if you need anything else, please give me a call. Regards, Ron Vandersypen I Attachment A Table A-1 STIMPLAN (TM) , NSI , Tulsa,OK - www.nsitech.com Frac Summary *Alaska - Upper Sterling - 4725 ft. MD Zo Filename:G... Upper Sterling 4725 - 4803' MD.STP; 13 -Jul -2016 Well ID: Alaska - Upper Sterling - 4725 ft. MD Zo Perforated Interval:MD (ft) Top 4725.0 Bottom 4803.0 Formation Temperature (CIF) Notes 90 FORMATION LAYER DATA - Multi -Layer Height Growth Depth (ft) Stress (psi) Gradient Modulus Toughness Loss Coef. Spurt Top Bottom Thickness Top Bottom (psi/ft) (MMpsi) (psi*sgrt(in)) (ft/sgrt(min)) (gal/100ft^2 3923.9 4015.8 91.8 2362.0 2414.4 0.570 0.30 2800.0 0.00100 0.00000 4015.8 4021.4 5.6 2314.4 2317.6 0.560 0.20 2800.0 0.01000 0.00000 4021.4 4054.3 32.9 2418.1 2436.9 0.570 0.30 2800.0 0.00100 0.00000 4054.3 4059.4 5.1 2336.8 2339.6 0.560 0.20 2800.0 0.01000 0.00000 4059.4 4069.2 9.9 2440.0 2445.6 0.570 0.30 2800.0 0.00100 0.00000 4069.2 4073.8 4.5 2346.0 2348.5 0.560 0.20 2800.0 0.01000 0.00000 4073.8 4076.3 2.5 2398.6 2400.0 0.565 0.25 2800.0 0.00100 0.00000 4076.3 4080.5 4.2 2300.0 2302.4 0.560 0.20 2800.0 0.01000 0.00000 4080.5 4085.3 4.8 2402.4 2405.1 0.570 0.30 2800.0 0.00100 0.00000 4085.3 4092.4 7.1 2305.0 2309.0 0.560 0.20 2800.0 0.01000 0.00000 4092.4 4094.0 1.6 2409.0 2409.9 0.570 0.30 2800.0 0.00100 0.00000 4094.0 4122.7 28.7 2309.9 2325.9 0.560 0.20 2800.0 0.01000 0.00000 4122.7 4126.8 4.1 2425.9 2428.3 0.570 0.30 2800.0 0.00100 0.00000 4126.8 4159.9 33.1 2378.3 2397.0 0.565 0.25 2800.0 0.00750 0.00000 4159.9 4186.2 26.3 2447.0 2462.0 0.570 0.30 2800.0 0.00100 0.00000 4186.2 4190.3 4.0 2412.0 2414.3 0.565 0.25 2800.0 0.00750 0.00000 4190.3 4205.1 14.8 2464.3 2472.8 0.570 0.30 2800.0 0.00100 0.00000 4205.1 4210.8 5.7 2422.8 2426.0 0.565 0.25 2800.0 0.00750 0.00000 4210.8 4219.5 8.7 2476.0 2480.9 0.570 0.30 2800.0 0.00100 0.00000 4219.5 4223.5 4.0 2430.9 2433.2 0.565 0.25 2800.0 0.00750 0.00000 4223.5 FORMATION: 2483.2 0.570 0.30 2800.0 0.00100 0.00000 Perforated Height (ft) 75.0 Permeability (md) 600.000 TEMPERATURE: Bottom Hole (OF) 90 Page 8 Attachment A PRESSURE: Reservoir Pressure (psi) 1712.0 Closure Pressure (psi) 2307.0 DEPTH: Well Depth (ft) 4085.3 Licensed To: NSI Fracturing - Version 7.10 Fluid Pressure Gradient (psi/ft) 0.442 'Hydraulic' Length (ft) Perforations Top (ft) 4085.3 Propped length (ft) Bottom (ft) 4160.3 Max Net Pressure (psi) Initial Top (ft) 4085.3 Surface Pres -End of Pad (psi) Bottom (ft) 4160.3 3-D SIMULATOR StimPlan I -D PROGRAM CONTROL Step Size (ft) Automatic Time Step (min) Automatic (TM). NSI Technologies, Tulsa, OK Licensed To: NSI Fracturing - Version 7.10 WELL ID: Alaska - Upper Sterling - 4725 ft. MD Zo Table A-1 Calculated Results from 3-D Simulator - StimPlan 1-D Pumping Schedule - Design - Pig Pad Licensed To: NSI Fracturing - Version 7.10 Half Length 'Hydraulic' Length (ft) 60.4 Propped length (ft) 58.0 PRESSURE: Max Net Pressure (psi) 447.5 Surface Pres -End of Pad (psi) 1442.7 Surface Pres -Start of Flush (psi) 1315.2 Surface Pres -End of Job (psi) 1768.2 Maximum Hydraulic Horsepower 795.7 TIME: Max Exposure to Form. Temp. (min) 1.1 Time to Close 15.4 RATE: Fluid Loss Rate during pad (BPM) 12.39 EFFICIENCY: At end of pumping schedule 0.45 PROPPANT: Average In Situ Conc.(lb/ft^2) 7.44 Average Conductivity (md-ft) 9200.0 Fed (Kf W/k/Xf) 0.26 HEIGHT: Max Fracture Height (ft) 103.5 WIDTH: Avg width at end of pumping (in) 1.25 VOLUMES: Total Fluid Volume (M -Gal) 15.0 Total Proppant Volume (M -Lbs) 75.5 (TM). NSI Technologies, Tulsa, OK Licensed To: NSI Fracturing - Version 7.10 WELL ID: Alaska - Upper Sterling - 4725 ft. MD Zo Table A-1 Attachment A Table A-1 DEPTH: Well Depth (ft) 4085.29 PRESSURE: Reservoir Pressure (psi) 1712.0 Closure Pressure (psi) 2307.0 TEMPERATURE: Bottom Hole Temperature ) 90.0 * * Pumping Schedule * * Design S1 Vol Fl Vol Cone (PPG) Rate Fluid Prop Cum Proppant Pump Time (M -Gal) (M -Gal) Start End (BPM) Type Type (M -Lbs) (min) 3.00 3.00 0.0 0.0 18.00 6 10 0.0 4.0 1.02 1.00 0.5 0.5 18.00 6 10 0.5 1.4 1.04 1.00 1.0 1.0 18.00 6 10 1.5 1.4 1.09 1.00 2.0 2.0 18.00 6 10 3.5 14 1.13 1.00 3.0 3.0 18.00 6 10 6.5 1.5 8.01 6.00 3.0 12.0 18.00 6 10 51.5 10.6 3.07 2.00 12.0 12.0 18.00 6 10 75.5 4.1 Total Slurry 18.4 Total Fluid 15.0 Total Proppant 75.5 Avg. Cone 5.0 Total Pump Time 24.3 min Pad % 16.3 Pump Schedule Assumes Prop Cone Increases Linearly With CLEAN FLUID Volume Proppant Data Proppant ID No. 10 30-50 Carbo EconoProp, 250 F, Long Term Specific Gravity 2.69 Damage Factor (1.0 = No Damage) 0.70 Proppant Stress 0 2 4 8 16 KfW @ 2 #/sq ft and -ft) 4800 4400 3500 1750 300 Fluid Data Fluid ID No. 6 20# Borate Friction Data Pipe Friction Data Q (BPM) P/dL (psi/100ft) Page 10 Specific Gravity 1.02 Data @Wellbore @FormTmp 0.33 hr 0.66 hr 1.0 hr 1.5 hr vis(cp @ 170 1/sec) 251.5 465.7 168.1 125.8 97.4 79.8 non -Newtonian n' 0.58 0.58 0.63 0.67 0.69 0.70 K(lb/sec/ft^2)x 1000 44.56 82.50 23.04 14.04 9.81 7.63 Friction Data Pipe Friction Data Q (BPM) P/dL (psi/100ft) Page 10 Attachment A Table A-1 Page I1 1.0 0.6 7.0 4.3 13.0 10.5 19.0 18.2 25.0 27.3 Measured Depth (ft) 4725.0 Time History * NSI STIMPLAN 3-D Fracture Simulation Alaska - Upper Sterling - 4725 ft. MD Zo Time Pen Pres Rate Prop S1 Vol Efficiency Loss Hght W -Avg (min) (ft) (psi) (BPM) (PPG) (M -Gal) (BPM) (ft) (in) 0.6 8.7 118 18.00 0.0 0,5 0.56 7.6 75 0.34 1.0 11.1 118 18.00 0.0 0.8 0.58 7.1 76 0.43 1.2 13.5 120 18.00 0.0 0.9 0.55 9.8 76 0.40 1.3 15.9 121 18.00 0.0 1.0 0.53 11.6 77 0.36 1.4 18.3 121 18.00 0.0 1,1 0.51 12.8 77 0.33 1.6 20.7 122 18.00 0.0 1.2 0.48 14.4 77 0.30 1.7 23.1 122 18.00 0.0 1.3 0.46 14.6 77 0.28 1.9 25.5 122 18.00 0.0 1.4 0.43 13.5 78 0.27 2.2 27.9 122 18.00 0.0 1.7 0.41 13.2 78 0.27 2.4 30.3 122 18.00 0.0 1.8 0.39 12.8 78 0.27 2.7 32.7 123 18.00 0.0 2.1 0.38 13.4 78 0.27 3.0 35.1 123 18.00 0.0 2.3 0.37 13.0 79 0.27 3.3 37.5 123 18.00 0.0 2.5 0.36 13.6 79 0.27 3.7 39.9 126 18.00 0.0 2.8 0.35 12.9 87 0.27 4.0 41.2 114 18.00 0.0 3.0 0.34 12.4 89 0.25 4.8 43.6 123 18.00 0.5 3.6 0.33 13.2 96 0.26 5.5 46.0 120 18.00 0.6 4.2 0.32 13.1 101 0.26 6.3 48.4 118 18.00 1.0 4.8 0.31 13.6 103 0.27 7.0 50.8 116 18.00 1.5 5.3 0.30 13.6 103 0.28 7.5 53.2 114 18.00 2.0 5.7 0.30 14.0 103 0.28 8.0 55.6 112 18.00 2.0 6.0 0.29 14.4 103 0.28 8.5 58.0 111 18.00 2.7 6.4 0.29 14.5 103 0.29 9.2 60.4 112 18.00 3.0 7.0 0.28 13.9 103 0.29 Screen Out in Stage 2.0 at Time = 9.2 min 10.4 60.4 120 18.00 3.2 at 7.8 0.28 12.6 56.8 ft 103 0.34 11.5 60.4 138 18.00 4.2 8.7 0.30 10.5 103 0.39 12.6 60.4 159 18.00 5.3 9.5 0.31 9.5 103 0.45 Page I1 Attachment A Table A-1 13.7 60.4 182 18.00 6.3 10.4 0.33 8.8 103 0.52 Screen Out in Stage 3.0 at Time = 13.7 min at 54.4 ft 14.8 60.4 206 18.00 7.3 11.2 0.34 8.2 103 0.59 16.0 60.4 231 18.00 8.2 12.1 0.36 7.8 103 0.66 17.1 60.4 258 18.00 9.1 12.9 0.37 7.4 103 0.73 Screen Out in Stage 4.0 at Time = 17.1 min at 52.0 ft 18.2 60.4 286 18.00 10.0 13.8 0.39 7.1 103 0.81 19.3 60.4 315 18.00 10.9 14.6 0.40 6.8 103 0.89 20.4 60.4 344 18.00 11.7 15.5 0.41 6.5 103 0.97 21.6 60.4 374 18.00 12.0 16.3 0.43 6.3 103 1.05 22.7 60.4 404 18.00 12.0 17.1 0.44 6.1 103 1.13 24.3 60.4 447 18.00 12.0 18.4 0.45 5.9 103 1.25 27.1 60.4 412 0.00 0.0 18.4 0.42 5.6 103 1.16 29.9 60.4 376 0.00 0.0 18.4 0.38 5.3 103 1.07 32.9 60.4 340 0.00 0.0 18.4 0.35 5.0 103 0.98 34.5 60.4 322 0.00 0.0 18.4 0.33 4.8 103 0.94 36.0 60.4 304 0.00 0.0 18.4 0.32 4.6 103 0.89 37.5 60.4 286 0.00 0.0 18.4 0.30 4.5 103 0.86 38.8 60.4 268 0.00 0.0 18.4 0.29 4.4 103 0.83 39.7 60.4 251 0.00 0.0 18.4 0.28 4.4 103 0.81 GEOMETRY SUMMARY * At End of Pumping Schedule Alaska - Upper Sterling - 4725 ft. MD Zo Distance Pressure W -Avg Q Sh-Rate Hght (ft) Bank Prop (ft) (psi) (in) (BPM) (1/sec) Total Up Down Prop Fraction (PSF) 3 447 1.59 8.9 1 103 18 10 103 0.00 8.09 7 447 1.58 7.6 1 102 18 9 102 0.00 8.28 10 447 1.58 7.1 1 102 18 9 102 0.00 8.43 12 447 1.57 6.6 1 101 17 9 101 0.00 8.51 15 447 1.56 6.2 1 100 17 8 100 0.00 8.69 17 447 1.55 5.7 1 99 16 8 99 0.00 8.60 19 447 1.50 5.2 1 93 13 5 93 0.00 8.31 22 447 1.49 4.8 1 93 13 5 93 0.00 8.23 24 447 1.44 4.4 1 88 9 4 88 0.00 7.93 27 447 1.43 4.0 1 88 9 4 88 0.00 7.90 29 447 1.33 3.6 1 79 3 1 79 0.00 7.40 31 447 1.33 3.3 1 79 3 1 79 0.00 7.41 34 447 1.32 2.9 1 79 3 1 79 0.00 7.42 Page 12 Attachment A Table A-1 36 447 1.32 2.6 1 78 3 0 78 0.00 7.43 39 447 1.32 2.2 1 78 3 0 78 0.00 7.51 41 447 1.30 1.9 l 77 2 0 77 0.00 7.43 42 447 1.30 1.7 0 77 2 0 77 0.00 7.51 45 447 1.27 1.3 0 75 0 0 75 0.00 7.44 47 447 1.22 1.0 0 72 -2 -2 72 0.00 7.30 50 447 1.12 0.7 0 66 -4 -4 66 0.06 7.64 52 447 1.00 0.4 0 59 -8 -8 59 0.90 9.44 54 256 0.47 0.2 l 49 -13 -13 49 1.00 4.50 57 178 0.25 0.1 4 36 -19 -19 36 1.00 3.13 59 101 0.10 0.1 61 23 -26 -26 23 0.58 0.54 FLUID SUMMARY * At End of Pumping Schedule Alaska - Upper Sterling - 4725 ft. MD Zo Stage Fluid Prop Pos Concentration Fl Vol Ex Tim Temp Viscosity Fall No Gone ID ID (ft) Initial Now Design (M -Gal) (min) (EIF) (cp) Frac 1 1 1 1 60 0.0 0.0 0.0 0.5 0.9 90 5190.00 1 1 1 1 60 0.0 0.0 0.0 0.8 0.8 90 3610.00 1 1 1 1 60 0.0 0.0 0.0 0.9 0.5 90 3600.00 1 1 1 1 60 0.0 0.0 0.0 1.0 0.6 90 6770.00 1 1 1 1 60 0.0 0.0 0.0 1.1 0.4 90 6460.00 1 1 l 1 60 0.0 0.0 0.0 1.2 0.5 90 6310.00 1 1 1 1 60 0.0 0.0 0.0 1.3 0.3 90 6060.00 1 1 l 1 60 0.0 0.0 0.0 1.4 0.3 90 6180.00 l 1 l 1 60 0.0 0.0 0.0 1.7 0.3 90 5650.00 1 1 1 1 60 0.0 0.0 0.0 1.8 0.3 90 5430.00 ] 1 1 1 60 0.0 0.0 0.0 2.1 0.3 90 4830.00 1 1 1 1 60 0.0 0.0 0.0 2.3 0.0 90 4430.00 1 1 1 1 60 0.0 0.0 0.0 2.5 0.0 90 4520.00 1 1 1 1 60 0.0 0.0 0.0 2.8 0.0 90 4700.00 1 1 1 1 60 0.0 0.0 0.0 3.0 0.0 90 4700.00 2 1 1 1 60 0.5 44.8 0.0 3.0 0.0 90 4700.00 2 1 1 1 60 0.5 44.8 0.0 3.4 0.0 85 3600.00 2 1 1 1 58 0.5 44.8 0.0 3.6 0.0 82 5380.00 2 1 1 l 58 0.5 44.8 0.0 4.0 0.0 81 8100.00 2 1 1 1 58 0.5 44.8 0.0 4.0 0.0 81 981 0.00 3 1 1 1 58 1.0 44.8 0.0 4.2 0.0 81 9820.00 3 l 1 1 57 1.0 44.8 0.0 4.6 0.0 78 1064 0.00 Page 13 Attachment A Table A-1 3 1 1 l 56 1.0 44.8 0.0 4.8 0.0 78 1042 0.00 3 1 1 1 55 1.0 44.8 0.0 5.1 0.0 77 1036 0.00 4 1 1 1 53 2.0 44.8 0.0 5.3 0.0 76 9950.00 4 1 1 1 53 2.0 44.8 0.0 5.7 0.0 75 9740.00 4 1 1 l 53 2.0 44.8 0.0 6.0 0.0 75 9600.00 4 1 1 1 53 2.0 44.8 0.0 6.2 0.0 75 9520.00 5 1 1 1 52 3.0 44.8 0.0 6.4 0.0 75 9520.00 5 0 1 1 51 3.0 28.1 1.8 6.9 0.0 73 9130.00 5 0 l 1 49 3.0 16.9 2.4 7.2 0.0 73 9020.00 6 0 1 l 48 3.4 6.5 5.6 7.7 0.0 72 8860.00 6 0 1 1 46 4.2 8.2 5.9 8.3 0.0 72 8750.00 6 0 1 1 43 5.3 10.3 6.0 9.0 0.0 71 8620.00 6 0 1 1 39 6.3 12.5 6.1 9.7 0.0 71 8510.00 6 0 1 1 36 7.3 14.6 6.2 10.3 0.0 71 8440.00 6 0 1 1 31 8.2 16.7 6.3 11.0 0.0 70 8390.00 6 0 1 1 27 9.1 18.9 6.3 11.6 0.0 70 8360.00 6 0 l l 23 10.0 21.3 6.4 12.3 0.0 70 8330.00 6 0 1 1 19 10.9 24.2 6.3 13.0 0.0 70 8320.00 6 0 1 1 16 11.7 26.6 6.3 13.5 0.0 70 8320.00 7 0 1 1 14 12.0 15.2 9.6 13.6 0.0 70 8320.00 7 0 l 1 12 12.0 14.2 10.2 14.2 0.0 70 8320.00 7 0 1 1 8 12.0 13.5 10.8 14.8 0.0 70 8320.00 7 0 1 1 3 12.0 12.8 11.3 15.6 0.0 70 8320.00 PROPPANT SUMMARY * At End of Pumping Schedule Alaska - Upper Sterling - 4725 ft. MD Zo Lb/Sq-Ft Lost to Embedment Distance KfW Prop Concentration(Total ............ 2.000 lb/sq foot) (ft) (md-ft) Prop ID 3.1 9869 1 8.15 7.5 10088 8.28 9.9 10300 8.41 12.3 10489 8.53 14.7 10642 8.63 17.1 10492 8.53 19.5 10190 8.35 21.9 9930 8.18 Attachment A Table A-1 24.3 9612 7.99 26.7 9304 7.79 29.1 8829 7.50 31.5 8722 7.43 33.9 8710 7.42 36.3 8749 7.45 38.7 8788 7.47 40.5 8769 7.46 42.4 8801 7.48 44.8 8694 7.41 47.2 8694 7.41 49.6 9692 8.04 52.0 9401 7.85 54.4 4808 4.99 56.8 2106 2.95 59.2 632 1.26 7.71 Average Conductivity (md-ft) 9031 PROPPANT SUMMARY * At Fracture Closure Alaska - Upper Sterling - 4725 ft. MD Zo Lb/Sq-Ft Lost to Embedment ............ 2.000 Distance KfW Prop Concentration (Total lb/sq foot) (ft) (md-ft) Prop ID 3.1 8655 1 7.38 7.5 8889 7.53 9.9 9088 7.65 12.3 9379 7.84 14.7 9574 7.96 17.1 9623 7.99 19.5 9539 7.93 21.9 9689 8.03 24.3 9809 8.10 26.7 9383 7.84 29.1 9176 7.71 31.5 9537 7.93 33.9 9720 8.05 36.3 9471 7.89 Attachment A 38.7 9502 7.91 40.5 9681 8.02 42.4 9920 8.17 44.8 10158 8.32 47.2 11133 8.93 49.6 12408 9.72 52.0 10548 8.56 54.4 5098 5.17 56.8 2180 2.99 59.2 654 128 Average Conductivity (md-ft) Page 16 Table A-1 9200 Attachment R - Frac Pack Volume Summary - KLU A-2A Mini Zone Frac Step Rate Test Volume Fracpack Total Proposed Volume (gal) Volume (gal) Fluid Proppant al (gal) (lbs) Beluga 6679-6701' MD 2,520 1,365 6,500 10,385 30,300 Upper Beluga 7,560 6127-6276' MD 1,995 15,000 24,555 75,500 Lower Sterling 5395-5486' MD 7560 1,995 14,000 23,555 75,500 Upper Sterling 4725-4803' MD 7,560 1,995 15,000 24,555 75,500 TOTAL 83,050 256,800 Appendix Y - Predicted Maximum Pressure During Frac Pack Nominal % of Nominal Predicted Predicted Shear Shear above Proposed Maximum Maximum for Predicted Zone Treatment Injection with 1000 Packer Maximum Rate (bpm) Pressure psi Over Setting Injection Pressure (psi) Pressure Ball with 1000 psi Over Beluga si Pressure 6679- 6701' MD 6.0 1,700 2,700 4,200 156% Upper Beluga 6127- 18.0 2,280 3,280 4,200 128% 6276' MD Lower Sterling 5395- 18'0 2,220 3,220 4,200 130% 5486' MD Upper Sterling 4725- 18.0 1,800 2,800 4,200 150% 4803' MD Appendix j - Proposed Fracturing and Conflning Zone Details MD TVD True Proposed Proposed Fracturing Confining Thickness Vertical Fracturing Fracturing Zone and Zone and of Proposed Thickness of Zone (MD) Zone (TVD) Description Description Fracturing Proposed Zone (ft) Fracturing Zone ft 6679- 5950-5972' Beluga Beluga 6701' MD TVD Sandstone Interbedded 22 22 Shale Upper Upper 6127- 5430-5571' Beluga Beluga 6276' MD TVD Sandstone Interbedded 149 141 Shale 5395- 4732-4819' Lower Lower Sterling 5486' MD TVD Sterling Interbedded 91 87 Sandstone Shale 4725- 4085-4160' Upper Upper Sterling 4803' MD TVD Sterling Sandstone Interbedded 78 75 Shale Appendix K - Predicted Formation Pressures and Fracture Geometry Estimated Reservoir FracturingEstimateT Confinin timated Estimated Zone Pressure Zone Zoneydraulic Propped Fracturing pressure Fracturin rac Half Frac Half(psi) (psi) Pressure (psi) Length (ft) Length (ft) Beluga 6679- 2,796 3,588 psi 3,688 psi Above 32.6 6701' MD 3,717 psi Below Upper Beluga 2,693 3,356 3,527 psi Above 6127- 3,616 psi Below 40.2F398.6 6276' MD Lower Sterling 5395- 2,088 2,751 2,924 psi Above 46.7 45.7 2,992 psi Below 5486' MD Upper Sterling 4725- 1,712 2,307 2,502 psi Above 60.4 58.0 2,562 psi Below 4803' MD Attachment S Schlumberger Pre -jt --.j Disclosure Report SchImbYppep Client: Furie Well: Kitchen Lights Unit #A-2 Basin/Field: KLU Undefined Gas Pool State: Alaska County/Parish: North Slope Borough Case: 36.0 Gal Disclosure Type: Pre -Job Well Completed: 8/8/2016 Date Prepared: 6/30/2016 4:51 PM Report fl): RPT -43271 YF120ST:WF120 95,480 Gal F103 J218 motion Surfactant 1 Gal / 1000 Gal 96.0 Gal J318 Breaker 4 Lb / 1000 Gal 385.0 Lb J532 Breaker Aid 0.4 Ga l/SO0 Gal 36.0 Gal J891 Crosslinker 2.3 Gal / 1000 Gal 219.0 Gal M275 Guar Slurry 4.5 Gal / 1000 Gal 432.0 Gal G 5524-3050 Bactericide Pro in 0.5 Lb / 1000 Gal 48.0 A ent varied concentrations 302,000Lb Lb of water and additives. Wafer is .0 The total volume listed in the tables above represents the sum supplied by chert •.•_—..,w..o., 1 o --ea document is performed based on the composition of the id -ti ed products to the extent that such was produced. Any new updates will not be recompositional information was known to GRC-Chemicals as of the date of the document reflected in this document. © Schlumberger 2016. Used by Furie by permission. Page: 1 / 1 Appendix T - Predicted Maximum Pressure During Frac Pack Nominal % of Nominal Predicted Predicted Shear Shear above Proposed Maximum Maximum for Predicted Zone Treatment Injection with 1000 Packer Maximum Rate (bpm) Pressure psi Over Setting Injection Pressure (psi)' Pressure2 Ball with 1000 psi Over Beluga si Pressure 6679- 6.0 1,700 2,700 4,200 156% 6701' MD Upper Beluga 6127- 18.0 2 280 3,280 4,200 128% 6276' MD Lower Sterling 5395- 18'0 2,220 3,220 4,200 130% 5486' MD Upper Sterling 4725- 18.0 1,800 2,800 4,200 150% 4803' MD ' Refer to Attachments N, 0, P and Q Figure 7 2 After screenout, surface pressure is allowed to increase an additional 1000 psi to create a packed annulus and gravel reserve. - ;4-UIz:.'4j - 141214� 1.01'r List of Operators within 1/z mile radius of the Furie Operating Alaska, LLC KLU #A2A: 1. Furie Operating Alaska, LLC List of Land owners within 1/2 mile radius of Furie Operating Alaska, LLC KLU #A2A. 1. Alaska Department of Natural Resources List of lease owners within 1/2 mile radius of the Furie Operating Alaska, LLC KLU #A2A: 1. Cornucopia Oil and Gas 2. Taylor Minerals 3. Lawrence Berry 4. Danny S. Davis S. Furie Operating Alaska, LLC 6. Corsair Oil and Gas, LLC List of Operators within 1/2 mile radius of the Furi perating Alaska, LLC KLU #A2A: 1. Furie Operating Alaska, LLC List of Land owners within 1/2 mile ra Furie Operating Alaska, LLC KLU #A2A. 1. Alaska Department of Natural sources List of lease owners within Y2 rQ6 #A2A: 1. Cornucopia Oil and 2. Taylor Miner I Lawrence Berr 4. Danny S. Davi S. Furie Oper ing Alaska, LLC I adius of the Furie Operating Alaska, LLC KLU a STRUCTURAL CROSS-SECTION M -M' Sterling & Beluga - Hung from SS -4000' Attachment C - KLU A -2A Freshwater Aquifers in Vicinity Rw vs. Rwa The Sterling sands encountered between 2500'-3350' are estimated to have TDS less than 2000 ppm. The plots to the left illustrate that the resistivity of the connate water (Rw or Rwa) in these sands range generally between 1.2 and 3.2 ohmm at around 75 degF. A value of 1.4 ohmm for connate water translates into about 1600 ppm Sodium Chlorides (NaCl) which is generally 90% or more of the TDS in formation waters. The higher connate water resistivities translate into lower TDS. The Rw calculation was derived from the standard calculation from the SP log (= -K log (Rmf/Rw)) which is compared and agrees with the Rwa calculation using porosity squared times the deep resistivity measurement. The NaCl concentrations were determined by entering Schlumberger's Gen -9 chart, shown below, with these connate water resistivity values. Resistivity of NaCl Solutions G'n 9 C—'*' epp.o`—%d by R,. R,'n" • B.TIy(r�. B.MrF a Re • R, IR, • 21.5)J(T,. 21.5)rc 10 0.0 0.0 6 ,o — b *b ab 4 L 4b a '4 b r� 4b b th a �. %b 'Qa eb kb bo %b xao b. b th bm boo ro�� C f0 20 30 Me w 801 20D 250 900 M "D 01. 1p,00p M BO 90,00 f20 ,b 180,80200 T-"MhorFm C) Table listing all wells within one-half mile radius of KLU A -2A FURIE OPERATING ALASKA KLU #1 FURIE OPERATING ALASKA KLU UC &L 'P'41 FURIE OPERATING ALASKA KLU #3 Shell SRS #1 For KLU A2A Formation Top Location: Prpec er� Plugged and Suspended ESP�� Producer Plugged and Abandoned Producer Per Producing Plugged and Abandoned Sterling 3595' MD X — 295,534.34 _ Y — 2,537,270. Beluga 5720' M D X — 295,989.99 Y — 2,537,722.09 From all the well petrophysical data that Furie Operating Alaska has acquired on the Kitchen Light Unit, TDS (total dissolved solids) of the connate waters exceeds 10,000 ppm at a depth of about 8500-9000' TVD. Subject well KLU A -2A drilled to 8,160' MD/7,301' TVD, and did not reach those depths. Thus, all connate waters present in the KLU A -2A wellbore are expected to have a TDS of less than 10,000 ppm. All aquifers encountered in KLU A -2A do not currently serve as a source of drinking water, and below — 4500' MD/3871' TVD cannot now and will not in the future serve as a source of drinking water because these are hydrocarbon -producing reservoirs. NOTICE OF APPLICATION FOR FRACTURE STIMULATION SUNDRY Kitchen Lights Unit #A-2 Gas Well Furie Operating Alaska, LLC has applied for Fracture Stimulation Sundry Application, pursuant to the Alaska Oil and Gas Conservation Commission regulations. The well is located in Section 24, Township 10 North, Range 11 West, of the Seward Meridian, within the Corsair Block of the Kitchen Lights Unit ("KLU"). The KLU #A-2 well has been drilled from the Julius R. The nearest well currently capable of production from the same reservoir(s) is: Kitchen Lights Unit #3 ("KLU #3") Bottom hole located approximately 4,196 feet northeasterly from KLU #3 Top of perforations located approximately 3,005 feet northeasterly from KLU #3 There are no other wells currently capable of production within two miles of the proposed KLU 4A-2 gas well. However, the KLU #A-1 well is currently planned to be drilled from the Julius R. Platform this year. Cornucopia Oil and Gas Company, LLC is the majority working interest owner of the lease and Furie Operating Alaska, LLC is the Unit Operator of the Kitchen Lights Unit. A complete list of the working interest owners and their interests is attached as Exhibit A. The oil and gas lessor is the State of Alaska, Department of Natural Resources ("DNR"). The address of record for the DNR is: Department of Natural Resources Division of Oil and Gas 550 W. 7th Avenue, Suite 800 Anchorage, AK 99501 Attn: Corri Feige Director There are no other affected owners, landowners, lessees or operators within one-half (1/2) mile of the proposed KLU #A-2 gas well. Dated this 291h day of July, 2016, in Anchorage, Alaska. 1029 W. 3rd Avenue, Suite 500 1 Anchorage, Alaska 1 99501 1 Office: 907.277.3726 1 Fax: 907.277.3796 EXHIBIT A Kitchen Lights Unit Working Interest Ownership Cornucopia Oil and Gas Company, LLC 78.999000% 100 Enterprise Avenue League City, TX 77573 A. L. Berry 7.875000% 5005 Riverway, Suite 440 Houston, TX 77056 Danny S. Davis 6.875000% 5005 Riverway, Suite 440 Houston, TX 77056 Taylor Minerals, LLC 5.250000% 4119 Montrose, Suite 400 Houston, TX 77006 Furie Operating Alaska, LLC 1.000000% 100 Enterprise Avenue League City, TX 77573 Corsair Oil and Gas, LLC 0.001000% 100 Enterprise Avenue League City, TX 77573 1029 W. 3rd Avenue, Suite 500 1 Anchorage, Alaska 1 99501 1 Office: 907.277.3726 1 Fax: 907.277 3796 AFFIDAVIT IN SUPPORT OF THE NOTICE OF APPLICATION FOR FRACTURE STIMULATION SUNDRY Kitchen Lights Unit #A-2 Gas Well I, Bruce Webb, Senior Vice President of Furie Operating Alaska, LLC hereby certifies that the required information contained in the Notice of Application for Fracture Stimulation Sundry, pursuant to the Alaska Oil and Gas Conservation Commission regulations, for the above referenced well, dated July 29, 2016, are true and correct to the best of my knowledge. Further your affiant sayeth not. FURIE OPERATING ALASKA LLC By: (--J-7Z 9-11 Bruce Webb Date Senior Vice President IN THE UNITED STATES OF AMERICA ) ss. STATE OF ALASKA ) This certifies that on the 29th day of July, 2016, before me a notary public in and for the State of Alaska, duly commissioned and sworn, personally appeared Bruce Webb, to me known and known to me to be the person described in, and who executed the foregoing assignment, who then after being duly sworn according to law, acknowledged to me under oath that he executed the same freely and voluntarily for the uses and purposes therein mentioned. Witness my hand and official seal the day and year first above written. Notary Public My Commission Expires: N uv STATE OT' 7LA,' NOTAPI y IOLadies K.! cowr�� M MX]A!p 1029 W. 3rd Avenue, Suite 500 1 Anchorage. Alaska 99501 1 Office: 907.277.3726 1 Fax: 907.277.3796 FURIE Operating Alaska LLC Certified Mail No. 7010 0290 0002 9142 8702 July 29, 2016 Corn Feige, Director State of Alaska Department of Natural Resources Division of Oil and Gas 550 W. 7th Avenue, Suite 800 Anchorage, Alaska 99501 Subject: Kitchen Lights Unit Well KLU # A -2A Fracture Stimulation Sundry Dear Director Feige: Attached please find AOGCC Fracture Stimulation Sundry Applications for the KLU #A-2. A complete copy of the application is available from Furie Operating Alaska, LLC. Should you have any questions, please contact Mr. David McCraine at 337-981-0270. Thank you. i Bruce Webb Sr. Vice President Furie Operating Alaska, LLC 1029 W. 3,d Avenue, Suite 500 Anchorage, Alaska 99501 OFFICE: 907-277-3726 FAX: 907-277-3796 FURZE Operating Alaska LLC Certified Mail No. 7010 0290 0002 9142 8719 July 29, 2016 A. L. Berry 5005 Riverway, Suite 440 Houston, TX 77056 Subject: Kitchen Lights Unit Well KLU # A -2A Fracture Stimulation Sundry Dear Mr. Berry: Attached please find AOGCC Fracture Stimulation Sundry Applications for the KLU #A-2. A complete copy of the application is available from Furie Operating Alaska, LLC. Should you have any questions, please contact Mr. David McCraine at 337-981-0270. Thank you. i Bruce Webb Sr. Vice President Furie Operating Alaska, LLC 1029 W. 3.d Avenue, Suite 500 Anchorage, Alaska 99501 OFFICE: 907-277-3726 FAX: 907-277-3796 FURZE Operating Alaska LLC Certified Mail No. 7010 0290 0002 9142 8726 July 29, 2016 Danny S. Davis 5005 Riverway, Suite 440 Houston, TX 77056 Subject: Kitchen Lights Unit Well KLU # A -2A Fracture Stimulation Sundry Dear Mr. Davis: Attached please find AOGCC Fracture Stimulation Sundry Applications for the KLU #A-2. A complete copy of the application is available from Furie Operating Alaska, LLC. Should you have any questions, please contact Mr. David McCraine at 337-981-0270. Thank you. i Bruce Webb Sr. Vice President Furie Operating Alaska, LLC 1029 W. 3rd Avenue, Suite 500 Anchorage, Alaska 99501 OFFICE: 907-277-3726 i FAX: 907-277-3796 FURIE Operating Alaska LLC Certified Mail No. 7010 0290 0002 9142 8733 July 29, 2016 Robert G. Taylor, II Taylor Minerals, LLC 5005 Riverway, Suite 440 Houston, TX 77056 Subject: Kitchen Lights Unit Well KLU # A -2A Fracture Stimulation Sundry Dear Mr. Taylor: Attached please find AOGCC Fracture Stimulation Sundry Applications for the KLU #A-2. A complete copy of the application is available from Furie Operating Alaska, LLC. Should you have any questions, please contact Mr. David McCraine at 337-981-0270. Thank you. Bruce Webb Sr. Vice President Furie Operating Alaska, LLC 1029 W. 3,d Avenue, Suite 500 1 Anchorage, Alaska 99501 OFFICE: 907-277-3726 1 FAX: 907-277-3796 FURIE Operating Alaska LLC Certified Mail No. 7010 0290 0002 9142 8740 July 29, 2016 David Elder Cornucopia Oil and Gas, LLC Corsair Oil and Gas, LLC Furie Operating Alaska, LLC 100 Enterprise Avenue League City, TX 77573 Subject: Kitchen Lights Unit Well KLU # A -2A Fracture Stimulation Sundry Dear Mr. Elder: Attached please find AOGCC Fracture Stimulation Sundry Applications for the KLU #A-2. A complete copy of the application is available from Furie Operating Alaska, LLC. Should you have any questions, please contact Mr. David McCraine at 337-981-0270. Thank you. Bruce Webb Sr. Vice President Furie Operating Alaska, LLC 1029 W. 3ro Avenue, Suite 500 1 Anchorage, Alaska 99501 OFFICE: 907-277-3726 1 FAX: 907-277-3796 ru r3 r` ru (Domestic Mail Only; For delivery information V711Cof No Insurance Coverage Provided) -- -- — visit our website at wwwusps.com A L U1 S E 1 Er Jai tn r11-1 ru 0 04rWW Fee so. OL) C3 C3 X=99 —R= 6n I 0. 3) C3 Reshicled Dellvely Fee (Endorsement RAIWed Ir rU C3 ToW Postage & Fees $ 6 CertiTed Fee $0.00 Er n -i C3 ,q SOA NWWMC- L 0 r— orPOBbirNa Restricted Do Fee (Endorsement =ired) AIZ- 9Here 1101 2016 rU (Domestic Mail Only'; No Insurance Coverage Provided. CO ..,For delivery int rTation visit our websiteatwwwxsps.corn� • ru HUUPTVNr,-T 71OV! t j-� F x 11 lq S r Fgt.- 14 Fee . arili '113 (E $L1. I I r" SAW Q 0509 Ir Q 04 75, ru CertiTed Fee $0.00 Er n -i C3 0 Return Receipt Fee (Endorsement Required) $0.80 $0.00 $6.66 r? 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W; ----------- C3 —7 ', r_ [ or PO Box No. ZWO, (Domestic Mail C For delivery inform ru Certified Fee E3 =Rl=D C3 (E Restricted DeberyFee M ( Emlorsement RKfull 13— $1.'... ru C3 T.W Pomp & Few SOW TO IAL USE_ 0509 40 -AK $0.00 C1 ostmark 7 tp -V 2 X16 rA 9 2016 1� A� �0�1 * 46, -7-1051,::;, C3 rq C3 -9F-W-AR—JW- -------- �ogr G, TPtsYc.or� a2 r� or PO Boa Nrz ve Tj -77D9,o 20 AAC 25.283 Hydraulic Fracturing Application — Checklist Well Name No. KLU A -2A (PTD No. 216-086; Sundry No. 316-387) Paragraph Sub -Paragraph Section Compl— ete AOGCC Page 1 July 29, 2016 Dated 7/29/16. On 7/29/16, operator sent Notice of (a) Application for (a)(1) Affidavit Operations (Notice) to all owners, landowners, surface Sundry Approval owners, and operators within one-half mile radius of PKB proposed well trajectory. (a)(2) Plat (a)(2)(A) Well location Provided as Attachment A PKB Legal description of well, (surface, target and bottomhole locations) provided in application and email dated 7/28/16 PKB (a)(2)(B) Each water well within % mile None per DNR water Estate Map (7/29/2016) PKB (a)(2)(C) Identify all well types within % Four wells within % mile radius of KLU A -2A well trajectory. mile Wells identified by name, well type and well status. PKB (a)(3) Freshwater aquifers: geological name Quaternary, Sterling Formation and Beluga Formation PKB From all well petrophysical data the Furie has acquired on (a)(3) Freshwater aquifers: measured and the Kitchen Lights Unit, TDS (total dissolved solids) of the true vertical depth connate waters exceeds 10,000 ppm at a depth of about PKB 8,500-9,000' TVD. NA: KLU A -2A is located approximately 11 miles offshore the Kenai Peninsula, within the Cook Inlet. Shallowest zone within the Sterling Formation to be fracture (a)(4) Baseline water sampling plan stimulated is at a depth of 4,725' MD (4,085' TVD). All PKB aquifers encountered in KLU A -2A, at this location, do not currently serve as a source of drinking water and will not likely serves as a source of drinking water in the future. (a)(5) Casing and cementing information USIT/CBL run, est TOC 4300 ft MD CDW (a)(6) Casing and cementing operation assessment Surface casing shoe set at 2,265' MD. 9 5/8" casing shoe CDW (a)(6)(A) Casing cemented below lowermost freshwater aquifer and set at 8,122' MD. Total depth of well is 8,160' MD (7,301' PKB conforms to 20 AA 25.030 TVD). (a)(6)( B) Each hydrocarbon zone is CDW AOGCC Page 1 July 29, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist Well Name No. KLU A -2A (PTD No. 216-086; Sundry No. 316-387) Paragraph Sub -Paragraph Section Complete? AOGCC Page 2 July 29, 2016 isolated (a)(7) Pressure test: information and pressure -test plans for casing and tubing Test surface iron and frac head 6800 to 7000 psi, dp popoff CDW installed in well to 6500 psi, annulus pop off to 3000 psi. (a)(8) Pressure ratings and schematics: wellbore, wellhead, BOPE, treating head 10 K psi BOP, 15 K head CDW (a)(9)(A) Fracturing and confining zones: Fracturing zones will be sands/siltstones within the Sterling lith ologic description for each zone and Beluga formations. Confining intervals are interbedded shales and coal beds PKB (a)(9)(B) Geological name of each zone within the Sterling and Beluga formations. Furie plans to complete four intervals with frac packs: Beluga: 6,679-6,701'MD/5,950-5,972' TVD and 6,127- (a)(9)(C) and (a)(9)(D) Measured and true 6,276' MD/5,430-5,471' TVD. vertical depths Sterling: 5,395-5,486' MD/4,732-4,819' TVD and 4,735- PKB 4,803' MD/4,085-4,160' TVD. Beluga 6679-6701' MD: 3,588 psi. (a)(9)(E) Fracture pressure for each zone Beluga 6,127-6,276' MD: 3,356 psi. PKB Sterling 5,395-5,486' MD: 2,751 psi. Sterling 4,735-4,803' MD: 2,307 psi (a)(10) Location, orientation, report on mechanical condition of each well CDW (a)(11) Sufficient information to determine wells will not interfere with containment CDW within % mile (a)(11) Faults and fractures, Location, orientation Maximum anticipated frac half-length is 60.4 feet. Local faults are +2,500 feet away from KLU A -2A and not in (a)(11) Faults and fractures, Sufficient danger of contact by short frac pack fractures. See PKB information to determine no interference Attachments A and B for maps. AOGCC Page 2 July 29, 2016 Paragraph 20 AAC 25.283 Hydraulic Fracturing Application — Checklist Well Name No. KLU A -2A (PTD No. 216-086; Sundry No. 316-387) Sub -Paragraph Section Complete? AOGCC Page 3 July 29, 2016 with containment within % mile (a)(12) Proposed program for fracturing operation 83K gal, 256,800 Ib proppant CDW CDW (a)(12)(A) Estimated volume (a)(12)(8) Additives: names, purposes, CDW concentrations provided (a)(12)(C) Chemical name and CAS number CDW of each provided - Schlumberger (a)(12)(D) Inert substances, weight or CDW volume of each CDW (a)(12)(E) Maximum treating pressure with supporting info to determine 2280 psi upper beluga 6127-6276 ft MD zone, allowing appropriateness for program (a)(12)(F) Fractures — height, length, MD 1000 psi additional = 3280 psi. CDW and TVD to top, description of fracturing model (a)(13) Proposed program for post- CDW fracturing well cleanup and fluid recovery provided (b)Testing of casing or intermediate Tested >110% of max anticipated pressure CDW casing (c) Fracturing string (c)(1) Packer >100' MD below TQC of production or intermediate casing TOC 4300 ft MD, gravel pack packer 4593 ft MD identified. - CDW (c)(2) Tested >110% of max anticipated pressure differential CDW (d) Pressure relief Line pressure <= test pressure, remotely valve controlled shut-in device Line test of 7000 psi. popoffs set at 6500 psi CDW (e) Confinement Frac fluids confined to approved formations CDW AOGCC Page 3 July 29, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist Well Name No. KLU A -2A (PTD No. 216-086; Sundry No. 316-387) Paragraph Sub -Paragraph Section Complete? (f) Surface casing pressures Monitored with gauge and pressure relief IA device monitored, popoff set < 3500 psi - - 500 psi criteria CDW (g) Annulus pressure monitoring & notification (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (i) Reporting (j) Post frac water sampling plan (k) Confidential information Clearly marked and specific facts supporting nondisclosure (I) Variances Modifications of deadlines, requests for requested variances or waivers AOGCC Page 4 July 29, 2016 Bettis, Patricia K (DOA) From: Danny S Davis <dsdavis77@gmail.com> Sent: Friday, July 29, 2016 12:42 PM To: Bruce Webb Cc: Bettis, Patricia K (DOA); David McCraine; Schwartz, Guy L (DOA); Feige, Corri A (DNR); Lawrence Berry; Robert Taylor; David Elder Subject: Re: KILL) A -2A (PTD 216-086): Fracture Stimulation Sundry Application What zones are being fraced and with how much sand in each. Please send us working intrest owners a copy of the mud log and e logs run on this well. Also who owns and are the title holders to Corsair oil and gas. Danny Sent from my iPhone On Jul 29, 2016, at 3:06 PM, Bruce Webb <b.webb@furiealaska.com> wrote: All, Please see attached. Originals are in the mail Regards, Bruce Webb Sr. mice President <03CD87EF-6E47-49F4-BF74-229234A7587C[163].png> 1029 West 3rd Avenue, Suite 500 Anchorage, Alaska 99501 Office: 907.277.3726 Fax: 907.277.3796 Cell: 907.331-7399 Email: h.webhftfuriealaska.com <AOGCC Fracture Stimulation Sundry info.pdfl Bettis, Patricia K (DOA) From: David McCraine <d.mccraine@furiealaska.com> Sent: Friday, July 29, 2016 10:21 AM To: Bettis, Patricia K (DOA) Cc: Schwartz, Guy L (DOA) Subject: Re: KLU A -2A (PTD 216-086): Fracture Stimulation Sundry Application Attachments: List of Land owners within 122 mile of KLU A2A Rev.docx Attached is the corrected list of lease owners within 1/2 mile of KLU A2A. Corsair Oil and Gas,LLC was left off the list. Sorry about the confusion. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Patricia Bettis <patricia.bettis@alaska.gov> Date: Thursday, July 28, 2016 at 8:04 PM To: Dave McCraine <d.mccraine@furiealasl<a.com> Subject: RE: KLU A -2A (PTD 216-086): Fracture Stimulation Sundry Application David, Please provide the depth, both MD and TVD, in the KLU A -2A in which the Total Dissolved Solids exceeds 10,000 mg/I. That is the information required by 10 AAC 25.283(a)(3). This information is needed to complete the application. Thank you, Patricia From: David McCraine [mailto:d.mccraine@furiealaska.com] Sent: Thursday, July 28, 2016 2:38 PM To: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz@alaska.gov> Cc: Bruce Webb <b.webb@furiealaska.com> Subject: Re: KLU A -2A (PTD 216-086): Fracture Stimulation Sundry Application Attached are the following for the KLU A2A: 1. List of owners, landowners, surface owners, and operators in a 1/2 mile radius of the Furie Operating Alasak, LLC KLU #A2A. 2. A table all wells within a 1/2 mile radius, their type, and current status. 3. A table with the legal description of the Beluga and the Stering. 4. A page explaining the calculations and values for determing the base of the freshwater with a structural cross-section. 1 Bruce Webb is notifying the landowners and getting the notarized affidavit Thanks you. Contact me if any additional data is needed. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Patricia Bettis <patricia.bettis@alaska.gov> Date: Wednesday, July 27, 2016 at 4:48 PM To: Dave McCraine <d.mccraine@furiealaska.com> Subject: KLU A -2A (PTD 216-086): Fracture Stimulation Sundry Application Good afternoon David, The application to hydraulically fracture KLU A -2A lacks the following information or documents: 1. A notarized affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the wellbore trajectory have been provided a notice of operations. This affidavit and a copy of the notice must be submitted to the AOGCC. The notification must state that upon request, a complete copy of the application is available from the operator, and will include the operator contact information. Please note that Furie Operating Alaska LLC is the operator for the Kitchen Lights Unit. Furie is not the working interest owner(s). Within the fracture Stimulate sundry application, it is stated, "An affidavit has been submitted with the drilling application". The Affidavit submitted for the permit to drill application only pertained to a request for an exception to the statewide spacing requirements under 20 AAC 25.055. 2. List of all owners, landowners, surface owners, and operators within a one-half mile radius of the KLU A -2A. 3. A table listing all wells within one-half mile radius of KLU A -2A with the name, well type (Producer, injector) and its status (producer, injector, plugged and abandoned, shut-in, suspended). 4. Legal descriptions of top Sterling Formation and top Beluga Formation. Only the legal description for surface location and bottom hole location was provided. 5. Provide Total Dissolved Solids calculation for determining base of fresh water aquifer in the KLU A -2A well and all wells within one-half mile radius of KLU A -2A. 20 AAC 25.990(27) defines fresh water as, "has a total dissolved solids concentration of less than 10,000 mg/l, and occurs in a stratum not exempted under 20 AAC 25.440". Please provide the calculation(s) and values used for this determination, so that the information can be verified. Depth, both MD and TVD, to the bottom of all freshwater aquifers must be provided to the AOGCC for all wells within one-half mile radius of the KLU A -2A. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue 2 Anchorage, AK 99501 Tel: (907) 793-1238 CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AC)GCC), 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 Patricia Bettis at (907) 793-1238 or patricia.bettis�a.gov. Schwartz, Guy L (DOA) From: Schwartz, Guy L (DOA) Sent: Friday, July 29, 2016 8:31 AM To: 'David McCraine' Cc: Bettis, Patricia K (DOA) Subject: RE: KLA A2A PTD- 16-086; Sundry to frac David, You have verbal approval to set sump packer after displacing wellbore fluid. Additional wellwork is pending approval of the Hydraulic Fracture sundry . Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: David McCraine fmailto:d.mccraine(s�furiealaska.com] Sent: Friday, July 29, 2016 7:12 AM To: Schwartz, Guy L (DOA) Cc: Bettis, Patricia K (DOA) Subject: Re: KLA A2A PTD- 16-086; Sundry to frac Guy, we discussed going through setting the sump packer. I would like to get verbal extended through setting the sump , which packer which the step after displaing and filtering. Thaks. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Guy Schwartz <guy.schwartz@alaska.gov> Date: Thursday, July 28, 2016 at 7:45 PM To: Dave McCraine <d.mccraine@furiealaska.com> Cc: Patricia Bettis <patricia.bettis@alaska.gov> Subject: RE: KLA A2A PTD -16-086; Sundry to frac David, Based on the USIT/CBL log we just received you have Verbal Approval to proceed with RIH with drillpipe and swapping fluid after the BOPE test. As we discussed further rig operations will require formal approval of the Hydraulic Frac stimulation sundry. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office 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 Guy Schwartz at (907-793-1226 ) or (Guy. schwartzAalaska.gov). From: David McCraine fmailto:d.mccraine(&furiealaska.com] Sent: Thursday, July 28, 2016 2:46 PM To: Schwartz, Guy L (DOA) Subject: KLA A2A PTD- 16-086; Sundry to frac Furie has submitted the USIT cement log and the cement is above the proposed completion interval. Furie plans to revise the upper Sterling perfs to 4735' - 4809'MD, instead of 4725' - 4803'. Furie requests verbal to proceed with going in the hole with drill pipe and begin displacement to completion fluid after testing BOP's. Thanks you for your help. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell 2 Bettis, Patricia K (DOA) From: David McCraine <d.mccraine@furiealaska.com> Sent: Friday, July 29, 2016 8:28 AM To: Bettis, Patricia K (DOA) Cc: Schwartz, Guy L (DOA) Subject: Re: KLU A -2A (PTD 216-086): Fracture Stimulation Sundry Application Attachments: Att C FW Aquifers from AOGCC permit - Adjacent Water Sands-Rev29July16.pdf Attached is the revised aappendix C to include the depth where the total dissolved solids exceed 10,000 ppm,and the KLU A -2A MD and TVD in reference to the TDS depth. The sands deeper than 4500' MD/ 3871' TVD are less than 10,000 ppm TDS, but are hydrocarbon bearing, and not usable fresh water located offshore in the Cook Inet. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Patricia Bettis <patricia.bettis@alaska.ov> Date: Thursday, July 28, 2016 at 8:04 PM To: Dave McCraine <d.mccraine@furiealaska.corrm> Subject: RE: KLU A -2A (PTD 216-086): Fracture Stimulation Sundry Application David, Please provide the depth, both MD and TVD, in the KLU A -2A in which the Total Dissolved Solids exceeds 10,000 mg/l. That is the information required by 10 AAC 25.283(a)(3). This information is needed to complete the application. Thank you, Patricia From: David McCraine[mailto:d.mccraine()furiealaska.com] Sent: Thursday, July 28, 2016 2:38 PM To: Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov>; Schwartz, Guy L (DOA) <guy.schwartz2ala5ka.gov> Cc: Bruce Webb <b.webb@furiealaska.com> Subject: Re: KLU A -2A (PTD 216-086): Fracture Stimulation Sundry Application Attached are the following for the KLU A2A: 1. List of owners, landowners, surface owners, and operators in a 1/2 mile radius of the Furie Operating Alasak, LLC KLU #A2A. 2. A table all wells within a 1/2 mile radius, their type, and current status. 3. A table with the legal description of the Beluga and the Stering. 4. A page explaining the calculations and values for determing the base of the freshwater with a structural cross-section. Bruce Webb is notifying the landuvvners and getting the notarized affidavit. Thanks you. Contact me if any additional data is needed. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Patricia Bettis <patricia.bettis@alaska.gov> Date: Wednesday, July 27, 2016 at 4:48 PM To: Dave McCraine <d.mccraine@furiealaska.com> Subject: KLU A -2A (PTD 216-086): Fracture Stimulation Sundry Application Good afternoon David, The application to hydraulically fracture KLU A -2A lacks the following information or documents: 1. A notarized affidavit stating that all owners, landowners, surface owners, and operators within a one-half mile radius of the wellbore trajectory have been provided a notice of operations. This affidavit and a copy of the notice must be submitted to the AOGCC. The notification must state that upon request, a complete copy of the application is available from the operator, and will include the operator contact information. Please note that Furie Operating Alaska LLC is the operator for the Kitchen Lights Unit. Furie is not the working interest owner(s). Within the fracture Stimulate sundry application, it is stated, "An affidavit has been submitted with the drilling application". The Affidavit submitted for the permit to drill application only pertained to a request for an exception to the statewide spacing requirements under 20 AAC 25.055. 2. List of all owners, landowners, surface owners, and operators within a one-half mile radius of the KLU A -2A. 3. A table listing all wells within one-half mile radius of KLU A -2A with the name, well type (Producer, injector) and its status (producer, injector, plugged and abandoned, shut-in, suspended). 4. Legal descriptions of top Sterling Formation and top Beluga Formation. Only the legal description for surface location and bottom hole location was provided. 5. Provide Total Dissolved Solids calculation for determining base of fresh water aquifer in the KLU A -2A well and all wells within one-half mile radius of KLU A -2A. 20 AAC 25.990(27) defines fresh water as, "has a total dissolved solids concentration of less than 10,000 mg/I, and occurs in a stratum not exempted under 20 AAC 25.440". Please provide the calculation(s) and values used for this determination, so that the information can be verified. Depth, both MD and TVD, to the bottom of all freshwater aquifers must be provided to the AOGCC for all wells within one-half mile radius of the KLU A -2A. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 N Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.Lov. Bettis, Patricia K (DOA) From: Schwartz, Guy L (DOA) Sent: Tuesday, July 26, 2016 10:17 AM To: Jack Burman Cc: Bettis, Patricia K (DOA) Subject: RE: Alternative Compleiton Summary for Furie KLU A -2A That was the big one. Should be 4085 -4160 TVD Also, the upper Beluga 6127-6276' MD seemed to cover some extra non pay... but that may be part of your gravel pack coverage plan. Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301-4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e mail message, including any attachments, contains information from file Alaska Oil and Gas Conservation Commission (AOGC(:), 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 Guy Schwartz at (907-793-1226 ) or (Guy.schwartz@alaska.gov). From: Jack Burman [mailto:jack@exploitech.com] Sent: Tuesday, July 26, 2016 9:14 AM To: Schwartz, Guy L (DOA) Subject: Re: Alternative Compleiton Summary for Furie KLU A -2A Proposed Completion Intervals: Beluga: 6,679-6,701' MD/5,950-5,971' TVD 6,127-6,276' MD/5,430-5,571' TVD Sterling: 5,395-5,486' MD/4,732-4,819' TVD 4,725-4,803' MD/4,985-4,160' TVD Apparent bust in TVD of second Beluga Interval. Does this clear up? 1 Jack Burman 713-703-6246 Cell 281-444-9220 Office ()nJul 2b,20lb"u1 12:01 9M, Schwartz, Guy l.(]()A) vmrdC: Can you look at the perf depths and resend .... I think there are some typo's . Guy Schwartz Sr. Petroleum Engineer AOGCC 907-301--4533 cell 907-793-1226 office CONFIDENTIALITY NOTICE: This e-mail message, including any attachments, contains information from the Alaska Oil and Gas Conservation Commission (AOGCC)'State o|Alaska and bfor the sole use ofthe intended recipient(s). |tmay 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 /ccipien|o|/hiso'moU.p|eosedu|e/eii'wi|hoo1Uotsovingorfonoordingi|'ond.sothat|he AOGCCisaware o[the mistake insending it|o you, con/nc1Guy Schwartz nt(907'793-l226)vr From: Jack Burman Sent: Wednesday, July 28, 2016 11:11 AM To: Schwartz, Guy L(DOA) Subject: Alternative [omp|eiton Summary for Furie KLUA'2A Is this more what you were looking for? Jack Burman 713-703-6246 Cell 281-444-9220 Office 2 THE STATE of .z LASKA GOVERNOR BILL WALKER Bruce Webb Sr. Vice President Furie Operating Alaska, LLC. 4906 Ambassador Caffery Pkwy, Suite 800 Lafayette, LA 70508 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.00gcc.alaska.gov Re: Kitchen Lights Unit, Kitchen Lights Undefined Gas Pool, KLU A-2 A Furie Operating Alaska, LLC. Permit to Drill Number: 216-086 Surface Location: 895.93' FWL, 342.48' FSL, Sec. 24, T1ON, R11 W Bottomhole Location: 2348.76' FSL, 2328.36' FEL, Sec. 24, T1ON, R11 W Dear Mr. Webb: Enclosed is the approved application for permit to drill the above referenced development well. Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Conditions of Approval: 1. 10,000 psi 13-5/8 inch BOPE to be tested to 3500 psi minimum. (5M annular to 2500 psi minimum) 2. BOPE equipment will be on 7 day testing cycle (i.e. not to exceed 7 days). 3. Gas Detection required, including 1-12S, per 20 AAC 25.066. 4. Daily Drilling report to be submitted to AOGCC by email. 5. BOP Casing Rams to be tested as per following: • 9-5/8 inch rams to 2500 psi 6. Casing tests as follows: • 9-5/8 inch casing test pressure = 3500 psi (44% of burst) 7. CBL required over 9-5/8 inch casing to determine TOC and cement quality. 8. Sundry approval required for completion operations including running tubing, perforations or hydraulic fracture stimulations. This permit to drill does not exempt you from obtaining additional permits or an approval required by law from other governmental agencies and does not authorize conducting drilling operations until all other required permits and approvals have been issued. In addition, the AOGCC reserves the right to withdraw the permit in the event it was erroneously issued. PTD: 216-086 Page 2 of 2 Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the AOGCC 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 an AOGCC order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, P��'�4, CathyrFoerster Chair DATED this g day of July, 2016. STATE OF ALASKA -kSKA OIL AND GAS CONSERVATION COMMIS.,..' N PERMIT TO DRILL ?n AAr 9r, nn5 EGEIVED JUL 0 7 2015 1a. Type of Work:1b. Proposed Well Class: Exploratory - Gas Service - WAG Service - Disp 1c. Specify if well is proposed for: Drill Lateral Stratigraphic Test Development - Oil Service - Winj Single Zone Coalbed Gas Gas Hydrates RedrillP'Reentry Exploratory -Oil Development -Gas I Service - Supply Multiple Zone Geothermal Shale Gas 2. Operator Name: 5. Bond: Blanket. Single Well LJ 11. Well Name and Number: Furie Operating Alaska LLC + Bond No. 402-081A a Kitchen Lights Unit # A-2 A ' 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 4906 Ambassador Caffery Pkwy Suite #800, Lafayette, LA 70508 MD: 8149' TVD: 7400' KLU Undefined Natural t Gas Pool 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 895.93 FWL & 342.48 FSL of T10N:R11 W, Sec24 ADL 389197 Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1754.85 FSL & 2299.13 FEL of T10N:R11 W: Sec 24 N/A 7/10/16 Total Depth: 9. Acres in Property: 14. Distance to Nearest Property: 2348.76 FSL & 2328.36 FEL of T10N : R11 W : Sec 24 2560 3+ miles (non Furie) 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 107 15. Distance to Nearest Well Open Surface: x- 294331.49 y- 2,536,125.62 Zone- 4 GL Elevation above MSL (ft): to Same Pool: 3,005 16. Deviated wells: Kickoff depth:IS;kq feet 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 51 degrees Downhole: 3,694 • Surface: 2,954 18. Casing Program: ISpecifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing I Weight Grade Coupling Length MD TVD I MD TVD (including stage data) 12.25" 9 5/8" 153.5 ppf L-80 BTC 9789 0 01 9789 7231 Lead 621 cuff 13.5 ppg Tail 1475 cu.ft. 15.6ppg 19. PRESENT WELL CONDITION SUMMARY (To be completed for Redrill and Re -Entry Operations) Total Depth MD (ft): Total Depth TVD (ft): Plugs (measured): Effect. Depth MD (ft): Effect. Depth TVD (ft): Junk (measured): Casing Length Size Cement Volume MD TVD Conductor/Structural 381' 20" x.812" wall 381' 380' Surface 2265' 13 3/8" 72 ppf N-80 BTC 2862 cu ft. 2265' 1995' Intermediate Production Liner Perforation Depth MD (ft): Perforation Depth TVD (ft): 20. Attachments: Property Plat BOP SketcH Drilling Program Time v. Depth Plot Shallow Hazard Analysi Diverter Sketc Seabed Report Drilling Fluid Program 20 AAC 25.050 requirement 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact David McCraine Printed Name ��`YC >/ Title Email D.mccraine furiealaska.com V `�' � �' y,�- �1K aj J Signature r �(�' Phone U7 -77-377-( -, Date 7/6/16 Commission Use Only Permit to Drill Number: - Do API Number: _ Permit Approval See cover letter for other 50- 3 SS - do Date: requirements. Conditions of approval : If box is checked, well may not be Other: 7SM F_Sk p ,� ` �� J LTJ used to explore for, test, or produce coalbed m hane, Samples req'd: Yes No gas hydrates, or gas contained in shales: Mud log req'd: Y N17 HzS measures: Yes No Directional svy req'd: Y N SEC , yt-a� l �'v wm FO2 Spacing exception req'd: Yes No t Inclination -only svy req'd: Y N +' �PF'2c.�M. t X� I�04 <Z ca G Post initial injection MIT req'd: Y N l� l- ;Za3 APPROVED BY Approved by:a4 i, COMMISSIONER THE COMMISSION Date: 8 �Kh mala -119,1a& ORIGINAL Submit Form and Form 10-401 (Revised 11/2015) This permit is valid for 24 months from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate RECEIVED e�FURIE JUL 0 7 2016 Operating Alaska LLC AOGCC July 6, 2016 Alaska Oil & Gas Conservation Commission 333 W. 7th Ave., Ste. 100 Anchorage, Alaska 99501 Re: Well: Kitchen Lights Unit 4A-2 Redrill TO WHOM IT MAY CONCERN: Furie Operating Alaska, LLC (FOA) hereby requests a Permit to Drill, the KLU # A -2A, a redrill or sidetrack from the KLU A2, an offshore development well within its Kitchen Lights Unit located in the Cook Inlet of Alaska.. FOA would like to drill the well to 8149' MD/ 7400' TVD, and is submitting a new form 10-401 Application for Permit to Drill with the required documents. Attached please find the following information required by 20 AA 25. 00, in duplicate, , for your review. If you have any questions or require further information please contact Furie Drilling Engineer, David McCraine, at (337) 981-0270 or d.mccraine@furiealaska.com. Sincerely, David McCraine Drilling Engineer 4906 AMBASSADOR CAFFERY PKWY SUITE N 800. LAFAYETTE, LA 70508 1 OFFICE: 337.981.0270 -. FURIE Operating Alaska LLC Permit to Drill Kitchen Lights Unit Well # A -2A Table of Contents Description Permit To Drill Well Prognosis Surface Plat Wellbore Diagram Directional Plan Proximity Plat and Statement Drilling Procedure Depth vs Days Plot Geo- Mechanical Plot Sesmic X -Section Formation Top Mud Program Casing Design Factors Kick Tolerance Worksheet Well Control Equipment 13 5/8" 10M BOP Diagram 13 5/8" 10M choke Manifold Mud Pit Capacity Chart Wellhead Diagram F U R I E Op—ftq Alaska LLC Well Prognosis For KLU # A -2A Kitchen Lights unit # A -2A is a developmental sidetrack well off of the Julius R monopod in the Cook Inlet. The objectives are the upper and lower Sterling encountered in the KLU #3. KLU # A -2A is a directional well drilled with the jackup Randolph Yost. Upon reaching TD of 8149'M/7400' TVD, Furie plans to run 9 5/8" 53.5 ppf L-80 BTC casing and cement it in place, and run a CBL prior to nippling down and setting a dry hole tree. A sundry will then be submitted for the completion. Surface Location: X-294,331.49 & Y- 2,536,125.62 Bottom Hole Location: X-296,421.23 & Y- 2,538,094.65 Total Depth 8149'MD / 7400' TVD a) Formation Depths: Sterling - 3639' MD/ 2879' TVD — potential gas zones Beluga — 5758' MD/ 5082' TVD — potential gas zones Property Lease: ADL389197 b) Maximum Anticipated Surface Pressure: MASP = Bottom hole Pressure — Gas gradient 2954 psi = (9.6*.052*7400tvd)- (./psi/ft* 7400') c) Potential Drilling Hazards: Review of KLU # 1 & sidetrack revealed coal sloughing in the 12 '/4' hole causing stuck pipe incidents at 10.248', 10570', 10,625'. Back reaming, washing and reaming helped to successfully clean the hole. Additional mud weight was used to stabilize the wellbore and run 9 7/8" casing. KLU # A 2 just drilled to 5210' TVD without seeing any hazards. KLU # 3 - The drive pipe was washed out with a 26" bit and KLU # 3 was spudded on 4/26/13 drilled to 1950' with a 9.1ppg mud. No mud losses were observed. No gas was encountered. The casing crew was rigged up and 13 3/8" 72 ppf N-80 BTC casing was run to 1903'. The casing was cemented with 37 bbls of cement return and the plugs bumped. The annulus was washed out to 289' using grout strings. A FIT was taken to 12.5 ppg EMW. The mud was displaced with a new LSND 9.3 ppg mud. The KLU # 3 was drilled to 10,293' with no drilling issues FU RI E Operatl,g Alaska LLC Review of the most recent experience drilling of the 12-1/4" hole for the KLU2 & 2a found that lost circulation was experienced at 3179' with a loss rate of 120 bph but was cured with two 30ppb LCM pills. While on KLU41, coal sloughing caused stuck pipe incidents at 10,248', 10,570' & 10,625'. Back reaming, washing and reaming, successfully cleaned the hole. Additional mud weight was used to stabilize hole prior to running 9-7/8" casing. KLU # 4 - KLU4 while driving the 30" X 1.5" X 56 to 318' pipe hit refusal at 257' with 197 blows / ft. A pilot hole was drilled to 317' and which allowed driving to continue to 318'. While drilling the 12-1/4n pilot hole, losses as high as 40 bph between 1080' and 1650' were encountered but 30 bbl pills with 15#/bbl fiber were effective in controlling the loss. The pilot hole was opened to 26" with losses from 491'-728',1260-1340' and 1605"-1845" 30 bbl pills 20#/bbl med fiber 15 #/bbl caco3 were effective in controlling the losses. At 2396' the 20" casing shoe was set. After drillout a LOT of- 14.3 ppg EMW was achieved. With a KOP at 2700' an Inclination to 24 degrees was achieved and the well was directionally drilled to 9200' TO. At 6282' a loss of 105 bbls. occurred which required a 20 bbl _pull 16 #/bbl to cure. The well had to be backreamed 6165-3616' prior to drilling to 7818. Drilling ahead required backreaming each stand. The bit trip from 7818' required backreaming out and wash back into the hole. The second bit trip from 7818 was made on the elevators as well as the rip from 9200 TD. E line logging was attempted but became stuck and had to strip over to recover. Pipe convey logs were run without incident. A 13-5/8" casing string was ran and cemented. The mechanical DV didn't open during the second phase of cement job as the dart didn't reach tool due to 24 -degree angle. A down squeeze of the 20" X 13-5/8" annulus was required. None of the offsets encountered 1-12S. The KLU# A-2 is drilling the same fault block as the KLU #3 and the gas analysis shows that no H2S is present d) Drilling Fluid Summary Production Hole — 12 'V" hole from 2300'MD/ 1985'TVD—8149'MD/ 7400'TVD 10.0 - 10.1 ppg glycol/ KCL/ amine inhibited mud e) Survey Program: 0-�' FURIE Operating Alaska LLC The well will be surveyed at interval not exceeding 100' apart as required by 20 ✓ ACC 25.050. f) Logging Program: Triple combo LWD : 2300' — 8149'MD g) Mud logging: Furie will mud log from 2400' — 8149' MD in accordance with 20 AAC 25.071 . h) Planned Casing program for KLU # A-2: Casing 9 5/8" Depth 8149'MD/ 7400' TVD Hole Size 12 '/4" Weight ( f) 53.5 Grade L-80 Connection BTC - RS * Plain end weight. i) Cementing Summary: 9 5/8" 53.5 ppf set at 9789' MD/ 7231' TVD w/ TO Lead Volume t3• F?w 500' x.3236 Cu ft /ft = 162 cu ft 1174'x .3132 cu ft/ ft x .25% excess = 459 cu ft Total Lead volume - 621 cu. Ft. 11 Tail Volume K - (, PI'5r 4710' x .3132 cu ft/ ft x .25% excess = 1843 cu ft 80' x .3973 Cu ft/ ft x 0% excess = 31.78 cu ft Total Tail volume — 1875 cubic ft. -- j) j) Well Control Equipment: 13 5/8" 5M annular and 13 5/8" l OM three ram BOP 11 V; Soo %r3s'c µ� + %mss �� ►�c�, UzS 2i0 AAC TZ ,06L I FURIE Furie Operating Alaska, LLC BAKER Lxetlan: CooklNet.Al Un tO6shwel Slat. KLl1MA-2 Candor(19.1 B) Field: IOtchen Lights Unk .- KLl/eA-2 _'C do (Sl"Tr= Fein Fude Mona dPledarm 8 HUMES 0 �a 1350 1 B00 G t 2250 a d m 2700 d m F`_ 3150 45 Plot reference weJlinilh a KLUaA-2 Condor SideTrack) _ True wdicat depth. are rafarencsd to Fude Plaeorm I RT Grid System: NAD27 /TM Alaska SP, Zane 4 (5004), US feel Mea sured depths are referenced to Fu re PleBorm(AT North Reference:_Tu north Furls Plelform (RT) la Mean Sea Leval: 104 fast scale' True ddlenee Mean Sea Level to Mud I'ne (AI Slot: KLU4A.2 Condor (S(ot 6)1. 981ee1 Depthe are in feet Coordmlea em in feet referenced to $lol Created e . ueicard on 3INwI2016 cca.t xen•oma 0 T' Easting (ft) 1000 1250 1500 1 5400 r _. _____. _• _._-_ _..�__� 1 I 1 F 1 1 L F 1 F C 450 900 1350 1800 2250 2700 3150 Vertical Section (ft) x.r,l d •edon A,imulh 45.13° with rafaranra 0 OD N DOD 1750 1500 1250 OOD 0 Well Profile Data Desi n Comment MD M1 Inc ' Az I TVD ft Local N Local E fl DLS 1f00fl VS ft Tie On 104.00 0.000 45.404 104.00 0.00 0.00 0.00 0.00 End of Ta ent 300.00 0.000 45.404 300.00 0.00 0.00 0.00 0.00 End of B9dd J 1906.06 48.182 45.404 1723.35 446.83 453.19 3.00 836.42 Tie 0n to KLUIIA•2 End of Dr 2500.00 2545.00 48.182 46.632 45.404 _... __. 45.404 2119.37 2149.77 75761 780.91 _ 788.36 792.01 0.00 3.00 1078.05 111223 End of Tan ont 2565.00 46.632 45.404 2163.45 791.16 602.40 0.00 1126.82 End of 3D Are 3467.23 19.191 43.015 2929.35 1145.00 1152.10 3100 1624.31 T.2gent 4668.64 19.191 431015 /1161.00 1433.76 142132 0.00 2018.96 End of 3D Arc (� 4658.24 14.292 47.639 /22fi.3] 1488.21 1456.07 2067.76 End of Ten enl J 5992.62 14.292 1 47.839 5325.64 1 1656.17 1663.65 _ _3,00 0.00 2347.48 cca.t xen•oma 0 T' Easting (ft) 1000 1250 1500 1 5400 r _. _____. _• _._-_ _..�__� 1 I 1 F 1 1 L F 1 F C 450 900 1350 1800 2250 2700 3150 Vertical Section (ft) x.r,l d •edon A,imulh 45.13° with rafaranra 0 OD N DOD 1750 1500 1250 OOD 0 KLU Caldor "2 5T ccMmatic— 7Mryg 15 14 13 18 Kitchen Lights Unit #A2A Proposed Bottom Hole iP NAD27 Alaska Zone 4 Feet C7 1 X : 296,421.23 I Y 2,538,094.65 Lai: 60°56'31.8930"N NW 1/4 NE 114 Lon : 151°08'41.4193W I NAO83 O KLU-A2 BH Lai: 60'56'29.8837"N I Lon : 151 °0849.4a82"W I - - !328.36' 22 23 — — — -- — 1 9 -- - - KLU-AM 8H �I Top of Production N45°49'2299.13' 45.31"E N48"42'12.62'E NAD27 Alaska Zone 4 Feat 1989.99'- - 2871.25 I X: 295,758.84 Surface to Surface to y: 2,537,512.24 Top of Production '�. ro Bob= Hole I Lai: 60.56'26.0443"N SW 114 - r -ISE 1 /4 Lon : 151'OB'54.8198'VJ i I ! w NAD83 v I a n Let:60°5824.0351"N 8 995.9 9' Lon: 151'09102-6865'W _ _ KLL1-3 '- KLU-A2 r Kitchen Lights Unit #A2A ® KLU-1 Well Surface NAD27 Alaska Zone 4 Feet v X: 294,331.49 Y; 2,536,125.62 Let: 60°58'12.1442N Lon: 151'0923.0125"W NAD83 Let: 60'56'10.135WN Lon: 161'0931.0796"W 27 26 25 30 � � r D - Z o KLU-2 11111110 11*1 34 35 36 � � 31 1 HEREBY CERTIFY THAT THE ABOVE PROPOSED WELL SURFACEFACELOCATION IS CORRECT. NOTES 1. COORDINATES TRANSFORMED USING �,� F U R I E NADCON (ALASKA). Operatlng Alaska LLC 2. THIS DRAWING IS NOT FOR NAVIGATION, PROPOSED LOCATION ONLY WELLS IN THE SHOWN. ATE INITY OF THE SURVEYED WELL ARE 3. AKCS271927SALASKA COORDINATE KITCHEN LIGHTS UNIT #A2A SYSTEM OF . OF1927 4. SECTION 24, TOWNSHIP 10N RANGE 11 W, ADL #389197 SEWARD SE SE 1/4 OF SECTION 24, TOWNSHIP 1ON, RANGE 11W TATEWMERIDIAN OOKI INLET. STATE WATERS OF COOK INLET. 5. SECTION UNE OFFSETS COMPUTED FROM SEWARD MERIDIAN, ALASKA PROTRACTED SECTION CORNER VALUES. �Ro 6. SURFACE AND BOTTOM HOLE INFORMATION PROVIDED BY CLIENT AND DOES NOT FUGRO CHANCE INC. REPRESENT A FUGRO CHANCE FIELD SURVEY. 200 Dulles Dnve Laraye6e, Louisiana 70500 (337) 237-1300 DIGITALCOPY GoodeticDatum: NAD27SCALE ° 200° Ori final hat si ned 7/7/2016 9 P g Pro)ection: AKCS2770ne4 1:24000 �i Grid Units: US SURVEY FEET FEET Job No.: 1600443 Dale: 7(7/2016 Drwn. BCN Of. - -- MARK KEITH BUHRKE RPLS #12656 ;Chad: - - - 1 1 STATE OF ALASKA DWG File: H:12016116004431GIS\...1Cooklnlet Se024-T10N-R11... --l— ",P" R.I—— P R-1,,wp. 1w (A-� r w,wp TI t. w,. s.. t—m I RAlidolph VM1 (ACI� F�j MW L 0 SM jKLU.A I C- EL MMI mmta_f� WKIL"m mmtzm� 10 -1 lo ENAUUMEREI.= N f, 21.91 28.07 4358 275P.32 2662.32 1086.53 1104.6D 296454.57 1 25371 ,44 •5822.6ae'N 151.0 .65 -1 -0.74 1536.3 41.05 9. 48 342.1 3521.91 2509 4268 --4-1-9-2950.38 2858. 2751,74 1 .17 1135.10 295485. 04.53 50.6622 1 1'09V0.0 M 3 -1 7.89 -287 1 53. 9.62 46.47 3606.08 22.13 1128.88 1167. 513.13 2537233.. N 757.08'59. 3.00 -17.86 ,287 -1.12 .OS 7 64.1 4179 9.76 4. 35 382.81 40.36 2922.00 116. 181.65 28.5533. 2537258.04 60'5623.463 161' 9,095.4 3.00 0.00 - ---T-42- .02 1819. 54.60 41.24 S 4826 Endo 30 Arc 19.64-40.38 3043.81 2938.91 1755.56 778.9 295538.72 2537 .03 80'5623.S23°N 151' 9. 000 o.00 0. 0.00 7556. 61. 41.25 87 46, 25 3]].1. 40.35 1 8.08 3031.08 1781. 1208.88 285558.93 72 .25 60'5823.T76N t SW 0.00 .00 0.00 0.00 41.30 9. 48,14 3821.91 3921.91 1964. 40.38 3 2.27 12 27 1206.78 1228. 551.11 53310 24 MrN 151'58'58. a .00 0.00 1722.15 .1 55. 1.5 1006 4-6-9- 4 4538 332046 321. 1232.39 1 .39 285653.35 25 60"5824279'N 151 '67.7 4 000 0, 0.00 0,00 681 50.20 41.41 101 4 1.9 19.64 40.36 3420.81 3313. 1272.15 29 .56 2537360.91 60°58 1N 751.08'57.263 0.0 O.DO 0.00 178908 5072 4. 10.28 .83 4583 41211» 19.4 40.38 -407W--9.00 3514,82 340. 1283,61 1 .91 295847.78 2837 .13 50'5624.783N 161'08'56823"W.0.00 0,00 0.00 782. 41.53 1 1.91 19.89 ---19-9;'-40.38 350200 309. 1315.68 29 .99 2537411.35 60' 8'N '51'08'56.3824 O.0 .00 0.00 .28 57.78 10.47 4 .14 45.64 1321.8'1 3703.18 3596. 1334.83 18 29589220 26374 0°58'25.288-» 151'28' 1' 000 0. 0.00 0.00 .DO 1889.47 68. ,6D 4167 44 9.81 40.36 3 388037 .4/ 1 1 2957 31461.80 60'5626. ON 0655.501'4 ,0 0.00 0. 93 SB.BB 15.70 13,17 21.91 15.69 3881. 1388A5 1380,9 38.62 2537487. 0 151.08'65. 0.00 0.00 1958.39 9.45 41.63 10.82 46.30 4871, 9.84 dO.36 3986. 9878.]0 1.88 1102.74 285758_ 512.24 60.6626.04 15 4.820'W 0.00 0.00 0. 1 986 60.01 41.87 _77-94 17 .t 19.64 d0.38 9067.00 3960,00 19 3,76 1---42=2 .OD 2537531.00 60'56 282'N 151'OB54239 180.68 0. 0.00 2018.73 6 7 97.99 77.5 31 4 . 1 19.2 90.77 40703 3972.93 1 7. .49 295781.03 2537 A2 50.5626.286' 151° .179'W 300 1604 -2.83 2.98 202 3 . 60.58 I6.R4 en[ 18 1595 44.31 4775.11 4068. 459.85 1445.15 295 2.09 25375596 .519N 151.08'63.76 ' 157.12 - 3, 209.87 61.11 42. 1.07 45.23 1-5 4904. 14.2 4822 . 2 »4].42 7474.91 7 1 285 1 .O7 2 7 AS G'S6'26.66T 1 1.0 .444'4 3.00 0.00 .80 .2.73 4.75 2076. 81.50 42.09 42.1 11.19 45- 4927.9 14.21 ---14'0-48.22 48. 4271.84 4164,64 14 --14§T.-1r-/ 1464. 95821.1 2537577.35 '58'28. WN 151.08.5.76 D.00 0.00 2079.95 4220 45.23 End Arc J 5021.91 9 ,58 4281.58 37 295838.80 2537 60'5626. 57" 157'0 DOM 0.00 .00 0.00 0. --210-4W-8202 17.32 45. 4 5 1.91 1921 822 4465.52 -49U-4-6- 43 1510.53 1600.67 26M8.49 25-3-7693F-BO' 7.016» 751.0852. 0.00 .00 0.00 0.00 2129.00 42.28 1 45.28 5717.91 1 1 45.22 4455.46 1626. 779-98- 295977.06 2 5.39 60.6827.1 15 '522674 0.00 0.09 8245 6291 4238 11.56 45. 1.91 14.21 I8. 4559.40 4552.40 54325 197.28 2 .87 297641,4 60° N 151 0851.8 D.DO 0.00 D.00 .53 7. .48 42.58 11.88 4535 5921.81 74 1 I8. . 4 4898.34 1559. 1 5.58 285811.28 2537857,46 60'5827.601 15 51.5254 .00 0.00 D. 0.00 2.58 83.87 B 11.80 11.4 4539 521.91 6621.7 48. 489.28 .28 1575.86 1673. 2. 253767. °5627.862'N 161'58 1.1b5W 0.00 0. 0. 000 2227.1 42.78 12 .42 A6 21 4822 960. 4643.22 16 92.20 285951. 689,52 60°5627.82 1 .784W 0.00 0. O.DO 000 2 64.73 42.9D 219 46,49 721.81 14.21 48. 5%7.1 .1 7608.68 1810. 295970.03 77 V5827.984•N 151.08 ,414 0.00 0.00 0.00 2276.1 65. 43.0' 12 33 45.52 5821,91 48.22 144. 5037.70 1 .03 1828.81 2859 37721.9 60'562 .116» 51.OB'SD.093W 0, 0. 0.00 2305.68 6566 13.13 1247 45.55 21.97 14. 5247.% ,04 154119 1647.11 07.21 253773.1 60 28.306'» 1 4 D.Oa 0.00 0.DO ,00 O.o 2325. 3 4325 80122 .27 48.72 6328. 227.64 .17RO2.03 5 .01 2537752.10 60-56 ,46 151°08'49.3384 O.W 0.00 0. 0 2417.36 . 66.68 --43-W--1274 1 1 S.SB 1.91 14.27 4-80T-5337.96 .98 1657.75 BO 2537 9. 6 '28.967'» 161'08'49. O7W .00 0.00 0. O,OD 2349. et 45, ent J 6121.91 48.22 34. 5327,82 1 .172 .99 2537768.88 60.56 B' 1 1'06'48837 0 O.OD 0.00 0.00 2374.25 67.08 93.37 43. B I5. 2 221.91 14.21 591.86 .88 1890A7 062.88 2977 1 0' 28.7N-N 1 8. 1 000 0.00 0,00 2 4363 1281 16. 65 832L97 14. 48.22 28. 5 21.80 1 3 286081.6 2 8 1. 4 60.5628.9 1 08'48.190W 0.00 0.00 3.30 .59 88.05 8 .OB 15.68 .97 74.21 .2 5725.74 561 1 3.184 2 OD 18 297817.77 80' 9.111"N 16108'47.8 W 5.00 O.DD 00 0.00 2447.83 8 . 93.80 13.21 1 6 797 1 1 4822 228 571586 t 2D8118. 833.60 60.5628.2 17ffW 000 0 0.00 5.0024 69.02 9 15.73 19 1421 1 '882 2.62 t 905 298 .39 29789983 80' 9434"N 151'08'47.0 9W 0.00 000 0.00 000 2496.88 09. 4418 13.7 4676 1421 48.22 5909.58 17722by 286756.97 7 .86 80.5629596» 1 1.08 OBW 000 D 000 21.40 70.00 44.32 13.8 ,727.91 4582 4 .22 11 .50 6006.50 1788. 1 4.5 253788'.89 629. 'N 151°084633 0. 000 0. 2545.93 1 1 4822 6210.44 A4 1821.87 286183.11 7897. 80.5628.9 T'N 1 B' D.W 0.00 .W 0.00 0. 5 .47 44.62 1 14.21 .848921.97 1.91 '4.21 1622 .3 6 82 821. 1646.47 2 11.70 297913.88 ° 0.07 751°08'45.5884 0.00 0.00 0.00 0. 25%.96 71. 1439 45.87 7121.81 1 1 48.22 6904.32 82 . 2 1837.68 1 .T7 298230.28 2 9.9 50'6830.23ff'N 161 5. DAO 0. 0.00 2610.5D 44.93 1 4. 5.92 722. .' 98.12 650. 83%.26 1854!N S.OB 2962 .BB 97%6,02 60.66'3.9 N 1 1.OB'94.BSSW 0.00 0.00 4.03 .00 72-51 14.75 45.96 321.91 14.21 4 . 8588.20 91.20 1670.40 1903. 67.47 2537 '5630.561•» 1 .48 0.00 0.00 0. .00 0.00 2668. 1 .� 45.25 74. 7421. 98.22 8 8.14 1921.69 288286. 26 7B. 80'56'30. 767 .114W 0.00 0.2M.08. 0.00 0.00 73.52 4 ---Irl 3 .D7 1.91 14.21 48. 8792.08 .OB --6782 1903.11 1939. _ 04.65 2537%411 6 ,683'» 751.OB'437 .00 0.00 000 2717.60 45.58 75.32 46. 76 1. 1 4. 98.22 6 .02 1978.47 .30 296323.24 .i4 5D•5671.094N 761' .3734 O.OD 0.00 .D0 0.50 0.00 27 7 .04 7455 45. .@ 1.91 14.21 48 5985.96 6 .B6 193587 --992-- 1876.60 1.83 253802018 1.20 151'08'43. 0. 0.00 0.00 2786.65 .51 4404 7821.81 19.21 48.71 708. 975.90 1 .81 286360.42 253804221 675631.366'71 51' '9 .B32W 000 000 0.00 91,1 .07 75.59 45.92 46.10 1571 4007 7921. 1421 2 7178.84 7D72:4&5:5:4=i201321 1 2538D58.24 0'563. 2TN 151'0642261 --o-m--Goa D.DD 2815.70 48.28 15. 6.1 46.09 1.81 74. 98.22 7 . 6 188.78 203. 286397.60 3807. 60'58'31, BR9 47. 90W 0.00 000 0.00 .1t 883 6.11 81 .91 14.21 9871 7373.72 7 2007.28 2048.82 18.18 2536090. 80° '31.845'» 151'08'41,6 'W 0.00 0.00 000 2864.76 7.16 46,46 1 46.13 8149.02 4. 4822 74 .00 29300 2005.69 2054.79 296421.23 380 60'56'31.883"» '08' 79'4 0.00 000 .00 0.00 0.00 48.64 16.59 1 2871.40 77.30 1 46.68 1 16- 1 46.76 Ende an en Peg. 2 of 2 l Furie Operating Alaska, LLC C FURIF Location: Cook reld MchenlLi9hask „(OAshore) Slot KLU#A-2 Condw (Slot B) Well: KI. 2 Cond:'- da7rack •�•• FU Foci Y. Furs Marto tl Plath�rm Wellbore: KLt:2 Candor SitleTreck HUGHES Plat reference wWalh is KLU#P,2 Condor (SideTrack) Ved6 True vertical depths are referenced to Randolph Yost (Actual Elev) (RT) Measured depths are referenced to Randolph Yost (Actual Elev) (RT) Randolph Yost (Actual Elev) (RT) to Mean Sea Level: 107 feet Mean Sea Level to Mud fine (At Slot: KLU#A-2 Condor (Slot 8)): 118 feet Coordinates are In feet referenced to Slot Grid System: NAD27 / TM Alaska SP, Zone 4 (5004), US feet = Wellpath was transformed from a different geodetic datum _ North Reference: True north Scale: True distance Depths are in feet Created by: ulricard on 201607-06 Database: WA ANC Deft Traveling Cylinder: Map North —WO. M Meentl Dq h m — Y/ — range a — , ' . n ro i uuuu n UR/E Clearance Report 1.Fag e'l.� FKLU#A-2 Condor (SideTrack) Ver16 BAKER Operating Alaska LLC Closest Approach Page 1 of 40 NuruEs Operator Furie Operating Alaska, LLC Slot KLU#A-2 Condor (Slot B) Cook Inlet, Alaska (Offshore) E Well KLU#A-2 Condor SideTrack Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furle Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2621.91 MD IWELLPATH LOCATION Minimum Curvature Randolph Yost Actuel Elev) (RT) to Mean Sea Level 007.00ft orizontal Reference Pt Local coordinates Grid coordinates Geographic coordinates North[ft] East[ft] Easting[US ft] Northing[ US ft] Latitude Longitude Slot Location -7.06 1.11 294331.49 2536125.62 60°56'12.144"N 151'09'23.013"W Facility Reference Pt 294330.50 2536132.70 60°56'12.214"N 151'09'23.035"W Field Reference Pt 295510.04 2636602.47 60°56'06213"N 151°08'58.941"W 1WELLPATH DATUM alculation method Minimum Curvature Randolph Yost Actuel Elev) (RT) to Mean Sea Level 007.00ft orizontal Reference Pt Slot Randolph Yost (Actuel Elev RT to Mean Sea Level 107.00ft ertical Reference Pt [Field Randolph Yost (Actuel Elev) (RT) Randolph Yost (Actuel Elev) (RT) to Mud Line at Slot 225.00ft (KLU#A-2 Condor (Slot B)) D Reference Pt Randolph Yost (Actuel Elev) (RT) .000ft Vertical Reference Mean Sea Level iq OOOft OSITIONAL UNCERTAINTY CALCULATION SETTINGS I se on ence Limitev se u ce osl ion Uncertaintyme u e i Angle 3.88° eclination 6.48° East of TNlonzontal a Field Strength 5543 nT lot Surface Uncertain 1 SD orizontal .000ft 10.000ft ertical .000ft acili Surface Uncertain 1SD ertical iq OOOft ositional Uncertainty values in the WELLPATH DATA table are the projection of the ellipsoid of uncertaintv onto the vertical and horizontal planes 8d Clearance Report IZAr6 e,,:,�,v FURZE KLU#A-2 Condor (SideTrack) Ver16 BAKER Alaska LLC Closest Approach Page 2 of 40 HUGHES IREFERENCEWELLPATH IDENTIFICATION Operator Furie Operating Alaska, LLC ISM KLU#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) lWell LU#A-2 Condor SideTrack Field Kitchen Lights Unit lWallbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condoy�_awp at 2521.91 MD ANTI -COLLISION RULE Rule Name Furie Stop Drilling (offset is HSE risk) Rule Based On Ratio Plane of Rule Closest Approach Threshold Value 1.00 Include Casing & Hole Size yes Apply Cone of Safety no HOLE & CASING SECTIONS - Ref Wellbore: KLU#A-2 Condor (SideTrack) Ref Wellpath: KLU#A-2 Condor (SideTrack) Ver16 String/Diameter Start MD I End MD I Interval Start TVD End TVD Start NIS Steri E/W End HIS End ENV [ft] rft] UU 4 rm [ft] rftl [ft] lit] 12.251n Open Hole 1 2521.91 8149.02 5627.11 2160.48 7400.00 711.71 738.05 2005.69 2054.79 SURVEY PROGRAM - Ref Wellbore: KLU#A-2 Condor (SideTrack) Ref Wellpath: KLU#A-2 Condor (SideTrack) Ver1B Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore Iftl ft 225.00 600.00 Gyrodata standard - Single -shot KLU#A-2 Condor 600.00 2228.27 BHI NaviTrak (SAG, Axial) KLU#A-2 Condor 2228.27 2521.91 OnTrak (SAG, MagCorr) KLU#A-2 Condor 2521.91 8259.40 BHI OnTrak(Standard) KLU#A-2 Condor (SideTrack) 8a �• Clearance Report NSA pil. FURIE KLU#A-2 Condor (SideTrack) Ver16 BAKER Operating Afnska LLC Closest Approach Page 3 of 40 HUG IIs CALCULATION RANGE & CUTOFF From: 107.00ft MD To: 8149.02ft MD C -C Cutoff: (none) OFFSET WELL CLEARANCE SUMMARY (10 offset Weflpaths selected) Ratios are calculated in Closest Approach plane C -C Clearance Distance , ACR Separation Ratio Ref Min C -C Diverging Ref MD Mln Min Ratio ACR Offset Offset Offset Onset Offset MD Clear Dist from MD Min Ratio Ratio Dvrg fro Status Facili Slot Well Well Well lh ft ftl Ifti Iftlft Furs Monopod Platform IG -2 Condor KLU#A-2 KLU#A-2 KLU#A-2 Condor_awp 2521.91 0.00 2521.91 2522.0' .-832 6307. FAIL: (Slot B) Condor Condor Shell -Standard Richfield SRS State #1 SRS State #1 SRS State #1 SRS State #1 Drift Indicator <0-16375'1 6264.46 1094.20 6264.46 8149.0 3.91 8149.02 PASS Siete State #1 Kitchen Lights Unit #1 KLU#1 KLU#1 KLU #1 Rd #1 OnTrak MWD<5082 - 15298'> 2521.91 1386.28 2521.91 2521.91 10.7 3607.0 PASS Kitchen Lights Unit #1 KLU#1 KLU#1 KLU#1 Schlumberger MWD <0 - BB05'> 2521.91 1386.28 2521.91 2521.91 10.7 3607.0 PASS Kifcheh.�' Ms11nH12 KLLk#2. JKLLW2A JKLQ#2A OhT7ak=MV/D:<2Q70:710750'> 7019:3.0 3878;77 7039:30 700700 19;7 7007.. 'PASS; S Cook Inlet SI 3 SCI St 3 SCI St 3 SCI St 3 AWB SCI St 3 AWP 2521.91 10907.95 2521.91 8149.02 41.0 8149.02 PASS Fure Monopod Platform KLIl#3 (Slot A) KLII#3 KLU #3 NaviTrak MWD<388-1893'>OnTrak 2521.91 1024.09 2521.91 8149.02 43.8, 8149.02 PASS MWD<1925-10393'> Kitchen Lights Unit #2 01- JKLLJ#2 JKLU #2 lOnTrak MWD<494 - 9106'1 2521.91 8855.23 2521.91 2521.911 71.9 8149.02 PASS Kitchen Lights Unt#4 JKLI.194 JKLIJ#4 KLU#4 lOnTrak MWD<450-9200'1 6149.02 17394. B2 8149.02 8149.0 134.1 6149.02 PASS Kitchen.. igfits Unit KLIJ#5 - KLU#5 4(*5 l0.U#-5 2521591 31003:94 2521.91 1 8149.04180.811 8149.04 PASS: 85 Clearance Report EPA FURIE KLU#A-2 Condor (SideTrack) Ver16 BAKER Alaska LLC Closest Approach Page 4 of 40 HUGHES ELLIPATH IDENTIFICATION Operator Furie Operating Alaska, LLC Islot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) JWell KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform Sidetrack from KLU#A-2 Condor_awp at 2b21.91 MD LEARANCE DATA - Offset Wellbore: KLU#A-2 Condor Offset Wellpath: KLU#A-2 Condor awp acilit : Furle Monopod Platform Slot: KLU#A-2 Condor Slot 8 Well: KLU#A-2 Condor Threshold Valuem1.00 ■ inte olated/extra oleted station Ref MD Ift] Ref ND Iff] Ref North Ift] Ref East Ift] Offset MD Ift] Offset ND Ift] Offset North Ift] Offset East Ift] Horiz Bearing C -C Clear Dist ACR MASD Sep Ratio ACR Status 2521.91 2160.461 711.71 738.051 2521.911 4 .0 1.0 2522.03 2160.5 711. 738.11 2522.0 2160.5 711.7 738.11 0.00---0.0 1.0 -83.2 UFALL 2566.91 2188.9 735.3 763.57 2566.91 2188.6 735.5 763.8 52.4 0.5 2.2 -0.4 ¢ FAPLf; 2586.91 2201.8 745.81 774.8 2566.9 2201.11 746.1 775.2 53.06 D.9 2.41 -0.0 „._-.FAIL'" , 2621..91 2224;581 763. 794,2 2621.8 2223!0 764�6fl FAIL 2721.91 2292.181 814.281 48.0 2721.771 2286.0 817.5EI 851 8EI 49.0 7.9 4.6 1.91 PASS 2821.91 2363.521 862.481 898.9 2821.5 2350.3 870.061 907.231 47.65 17.3 7.081 2.6G PASS 2921.91 J 2438.421 908.371 946,691 2920.461 2414.5 922.271 961.41 46.79 31.3 9.101 3.7 PASS 3021.91 2516.671 951.84 991.251 3018.461 2478.01 974.231 1015.121 46.8 50.6 10.81 5.o7 PASS 3121.91 259U51 992.74 1032.,47,1 8115,04 2540.1. 1025.431 1 D68.44 47.7 75:5 12.4 6,54 PASS 3221.911 2682.351 1031.031 1070.261 3210.9CI 2601.9 1076.671 1120.8EI 47.9 105.4 13.9 8.0 PASS 3321.91 2769.3 1066.5 1104.5 3305.1 2662.9 1127.5 1171.5 47.6 139.7 15.3 9.8 PASS 3421.91 2858.741 1099.171 1135.101 3397,161 2722.5 1177.2CI 1221.091 47,781 179.0 16.7 11.31 PASS 3521.91 2960.361 1128.84 1161.97 3489.251 2782.6 1226.9 1270.01 47.771 222.2 18.0 12.9 PASS 3606.08 ` 3029.001 1151,501 1181,65 3562.621 2830.61 1266 04 13.0aXA 47.401 2621 19.11 14.4 PASS 3521.91 3043.911 1155.561 1185.09 3576.14 2839AG 1274.051 1315.791 47.811 270.01 19.2 14.74 PASS 3721.91 3138.091 1181.171 1206.86 3661.921 2895.3E 1320.561 1361.3311 47.9 319.6 20.21 16.61 PASS 3821.91 3232.271 1206.781 1228.62 3746.921 2950.5C 1366.451 1406,931 48.1 369.71 21.1 18.31 PASS 3921.91 3326.461 1232.391 1250.39 3842.221 3012.8 1418.14 1457.2 48.0 419.131 22.21 19.66 PASS 4021.91 3420.M 1258;0 1272.45 3032.34 3079.6 1487.3 1505:2 47:8 07<23 ;3 0.97 4121.91 3514.821 1283.611 1293.91 4019.4 3130.6 1514.6 1547.71 47.6 515.1 24.31 22.0 PA 4221.91 3609.0 1309.2 1315.68 4105.4 3187.7 1561.4 1591.8 47.5 563.3 25.3 23.1 PASS 4321.91 3703.1 1334.8 1337.44 4131.3 3244.8 1608.3 1635.9 47.5 611.7 26.3 24.1 PASS 4421.91 3797.3 1360. 1359.21 4277.3 3301.4 1655.0 1680.6 47.5 660.3 27.31 25.0 PASS 4521:91 3891.5 1388}0E144b. 436,3.0 3357.8 1701. -1725': 47.5 709:1 28.3 25.8 PASS 4621.91 3985.7 1411.6 4448.1 3413.7 1747.5 1769.9 47.5 758.1 29.3 26.7 PASS 4708.19 4067.0 1433.7 4520.9 3461.4 1786.9 1808.4 47.61 800.71 302 27.3 PASS 4721.91 4079.9 1437.2 4532.2 3468.8 1793.0 1814.4 47.6 807.5 30.3 27.4 PA 4821.91 4175.11 1459.8 4612.9 3521.3 1838.5 1857.5 47.5 659.8 31.3 28.31 PASS 4904.15 4254.4 1474.91 1460:81 46 6.2 35623 1870. 1881.8 47.4 90fi,2 32.1 29. A 5 8d FllR/E Clearance Report KLU#A-2 Condor (SideTrack) Ver16 Closest Approach Page 5 of 40 WEFA2 BAKER HUGHES O erator Fu Operating Alaska, LLC Slot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (Side"Track Facility Furie Monopod Platform Sidetrack from KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA - Offset Wellbore: KLU#A-2 Condor Offset Wellpath: KLU#A-2 Condor_awp acllit : Furie Monopod Platform Slot. KLU#A-2 Condor Slot 6 Well: KLU#A.2 Condor Threshold Value=1.00 t • Interpolated/extrapolated station Ref MD Iftt Ref TVD I [0] Rel North tft] Ref East I Irft Offset MD I [itl Offset TVD I IN Offset North [N] Offset East IN Horiz Bearing C -C Clear Dist ACR MASD n Sep I Ratio ACR Status 4271.641 1477.8 1464,OEI 4689.64 3570-94 18 1898.8 916. 2. 9.2 5021.91 4368,5f 1494,1 1482.34 4765.1 3619.4 1918.81 1939.8 47.1 975.0 33.1 30.2 PASS 5121.91 4465.5 1510.5 1500.6 4844.6 3670.2 1961.7 1983.3 46.9 1033.9 34.0 31.2 PASS 5221.91 4562. 1526.8 1518.9 4930.9 3725.4 2008.9 2029.9 46.6 1092.7 35.0 32.0 PASS 5321.91 4659 4( 1543.2 1537.2 5033.6 3792.0 2665_ 2084A 3 150B 2 32:6 PASS 5421.91 4756. 1559.6 1555.5 5129.9 3855.9 2118.0 2133.3 45.9 1206.81 37.3 33.1 PASS 5521.91 4853 2 1575.9 1573.8 5223.8 3918. 2169.3 2180.9 45.6 1262. 38.4 33.6 PASS 5621.91 4950.2 1592.3 1592.2 5321.81 3984 6 2222.2 2229.8 45.3 1317.3 39.6 34.1 PASS 5721.91 5047.1 1608.6 1610.5 5403.9 4040.7 2266.761 2270.4 45.04 1371.6 40.5E 34.661 PASS 5821.91 5144.1 CI 1625.0 1628.81 6487.D11 4097.0, 2311. 861 2311.5 44.8 1426.2 41.51 35.1 PASS 5921.9 11 5241.04 1641.3 1647.11 5591.74 4168.5 2369-21 236Z 14 44.44 1460.2 42.7!135.4 PASS 6012.28 5328. 1656.1 1663.6 5684.9 4233.1 2420.7 2405.3 44.1 1527.9 43.8 35.6 PASS 6021.91 5337.9 1657.7 1665.4 5694.0 4239.51 2425.7 2409.4 44.0 1533.0 43.9 35.6 PASS 6121.91 5434.9 1674.11 1683.7 5782.6 4301.3 2474.6 2449.9 43.7 1585.2 45.0 36.0 PASS 6221.91 5531.84 1.690.4 '1702.0 5880.4 4369,7 2528. 2494.7 43.41 1637 46.1 36. PASS 6321.91 5628.8 1706.8 1720.3 6064.4 4502.8 2629.31 2571.8 42.71 1686.4 48.1 35.7 PASS 6421.91 5725.7 1723.1 1738.6 6158.2 4572.6 2679.8 2608.81 42.2 1732.61 49.3 35.8 PASS 6521.91 5822.6 1739.5 1756.9 6236.9 4631.1 2722.2 2640.0 41. 1779.1 50.3 36.0 PASS 6621.91 5919.6 1755.9 1775.2 6319.9 4692.5 2767.1 2673.2 41.61 1826.1 51.3 36.2 PASS 6721.9 6016. 1772.2 1793.5 63 9. 4751.3 2610. 2705.5 41:3 1875.411 52.4 6821.91 6113.5 1788.61 1811.8 6477.5 4808.5 2852.3 2737.21 41.0 1921.1 53.3 36.6 6921.91 6210. 1804.9 1830.1 6554.0 4864.5 2894. 2768.6 40.7 1969. 54.3 36.8 PASS 7021.91 6307.3 1621.3 1848.4 6629.9 4919.7 2935.4 2800.2 40.51 2018.1 55.3 37.1 PASS 7121.91 6404.3 1837.6 1866.7 6704.4 4973. 2976. 2631.7 40.2 2067.3 56.3 37.3 PASS 7221:91 6501. 1854. 1885, o 6775.7 5024.9 3015.0. 2862.31 40.0 2117.2 572 37: PASS 7321.91 6598.2 1870.4 1903.3 6845.81 5074.9 3053.6 2892.6 39.9 2167.7 58.1 37.9 PASS 7421.91 5695.1 1886.7 1921.6 6914.3 5123.5 3091.5 2922.6 39.7 2218.8 59.1 38.1 PASS 7521.91 6792.0 1903.11 1939.9 6984.4 5172.8 3130.5 2953.7 39.5 2270.7 60.0 38.4 PASS 7621.91 6889.0 1919.4 1958.3 7038.0 5210. 3160. 2977.6 39.4 2323.0 60.6 38.9 PASS 7721 81 6985. 1935.8 1976.6 7038A 5210. 3180. 2977.$ 39.2 2377.8_ 60.7 39.7 ASS . 8a 2 oF� Clearance Report KLU#A-2 Condor (SideTrack) Ver16 Closest Approach Page 6 of 40 SUN BAKER HMOs IDENTIFICATION Operator lFurle operating Alaska, LLC Islot KLU#A-2 Condor Slot B Area jCook Inlet, Alaska (Offshore) Well LU#A-2 Condor SideTrack Field lKitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility IFurie Monopod Pfaff or ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD CLEARANCE DATA - Offset Wellbore: KLU#A-2 Condor Offset Wellpath: KLU#A-2 Condor_awp Start MD String/Diameter Start MD End MD Facility: Furle Monapod Platform Slott KLU#A.2 Condor JSIot B Well: KLU#A-2 Condor Threshold Valuecl.00 t a Interpolatedlextrapolated station Ref MD Iftj Res ND I tit] Rei North I Ift] Ref East [ft] Offset MD Ift] Offset TVD [it) Offset North Eft] Offset East IN) Hor12 Bearing CL Clear Dist ACR MASD Sep Ratio ACR Status 7821.91 7082.901 1952.191 Is 03brOCI 3 0. 2977.601 .1 a 2265.00 40.6E PASS 7921.91 7179. 1968.5 2013.21 7038.0 5210.3 3160. 2977.6 38.9 2495.8 60.9 41.6 PASS 8021.91 7276.7 1984.9 2031.5 7038.0 5210.3 3160, 2977.6 38.8 2558.7 60.9 42.6 PASS 8121.91 7373.7 2001.2 2049.8 7038.0 5210.3 3160. 2977.6 38.6 2623.8 60.9 43.7 PASS 8149.02 7400. 2005.6 2054:7 7038.0 5210 3160. 2977.601 38.1621 2641 .871 60,971 44:0 PASS POSITIONAL UNCERTAINTY - Offset Wellbore: KLU#A-2 Condor Offset Wellpath: KLU#A-2 Condor_awp Slot Surface Uncertainty @1SD lHorizontal 10.000ft lVertical 0.000ft Facility Surface Uncertainty @1SD lHorizontal 120.000ft[Vertical 13.000ft HOLE & CASING SECTIONS - Offset Wellbore. KLU#A-2 Condor Offset Wellpath: KLU#A-2 Condor_awp Start MD String/Diameter Start MD End MD Interval Start ND End TVD Start NIS Start EIW End NIS End E/W Condor tt ft ft ft ft 't] BHI OTK+SAG+MagCorr 12-1/4"<2327-6971> ft ft 20in rive Pipe 0.00 81.00 351.00 0.00 380.25 0.00 U-00 409 1.22 13.375in Casing 0.00 2265.00 2265.00 0.00 1994.62 0.00 0.00 176.22 181.19 12.25in Open Hole 2265.00 7038.00 4773.00 1994.62 5210.34 176.22 181.19 963.28 907.57 ELLPATH COMPOSITION -Offset Wellbore: KLU#A-2 Condor Offset Wellpath: KLU#A-2 Condor_awp Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore k k yr wa standard Single - shot ing eo yr ata Condor 600.00 2228.27 BHI NwATrak (SAG, Axial) BHI NaviTK MWD+SAG 12-1/4" <664-2228> KLU#A-2 Condor 2228.27 6971.03 OnTrak (SAG, MagCorr) BHI OTK+SAG+MagCorr 12-1/4"<2327-6971> KLU#A-2 Condor 6971.03 7038.00 BHI Unknown Toot (Standard) Projection to Bit @7038 KLU#A-2 Condor 8R Clearance Report WN Fag FURIE KLU#A-2 Condor (SideTrack) Ver16 Opeioting Afuskn LLC Closest Approach BAKM Page 7 of 40 HuGMs OFFSET WELLPATH REFERENCE - offset Wellbore: KLU#A-2 Condor Offset Wellpath: KLU#A-2 Condor_awp MD Reference: Randolph Yost (Actuel Elev) (RT) Offset TVD 8 local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) Ellipse Start MD P521.91ft 8a Operator Furle Operating Alaska, LLC Islot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) 1well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit jWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD OFFSET WELLPATH REFERENCE - offset Wellbore: KLU#A-2 Condor Offset Wellpath: KLU#A-2 Condor_awp MD Reference: Randolph Yost (Actuel Elev) (RT) Offset TVD 8 local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) Ellipse Start MD P521.91ft 8a Clearance Report Fea6 FUR/E KLU#A-2 Condor (SideTrack) Ver16 BAKED Operating Alaska LLC Closest Approach Page S of 40 HUGHES WELLPATH IDENTIFICATION— Operator Furie Operating Alaska, LLC Slot KM -2 Condor Slot 13 Area Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furle Monopod Platform Sidetrack from[KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA • Offset Wellbore: SRS State #1 Offset Wellpath: SRS State #1 Drift Indicator <0-16375'> Facility: Shell -Standard Richfield State State #1 Slot: SRS State #1 Well: SRS State #1 Threshold Value -1.00 T = Interpolatedlextrapolated station Ref MD IN Ref TVD Ift] Ref North Ift] Ref East Ift] Offset MD Ift] Offset TVD [ft] Offset North [ft] Offset East Ift] Horiz C -C Bearing Clear Dist ACR MASD Sep Ratio ACR Status 2160,481 879.261 2436.34. 13 1 2566.91j2292.1 88.9 735.3 763.5 2112.9 2188.9 879.2 2436.3 85.0 1678.9 140.4 12.0 PASS 2586.9101.8 745.81 774.8 2125.8 2201.8 879.2 2436.3 85.41 1666.9 140. 11.91 PASS 2621.9124.5 763.9 794.2 2148.5 2224.5 879.2 2436.3 85.9 1646.1 141.5 11.7 PASS 2721.91 814.2 648:0 2216.1 2292.1 879.2 2436.3 87. 1589;6 143.6 1 :1 2821.9163.5 862.4 698.9 2287.5 2363.5 879.2 2436.3 89.3 1537.5 145.8 10.6 PAS2921.9138.4 908.3 946.6 2362.4 2438.4 879.2 2436.3 91.1 1489.9 148.2 10.11 PASS 3021.91 2516.6 951. 991.2 2440.6 2516.6 879.2 2436.3 92.8 1446.9 150.8 9.6 PASS 3121.91 2598.0 992.7 1032.4 2522.0 2598.0 879.2 2436.3 94.6 1408.4 153.4 9.2 PASS 3221.91 2682.3 1031. 1070.2 2606:3 82.3 879.2 2436;3 96 1374.5 156.1 6.8 ASS 3321.91 2769.3 1066.5 1104.5 2693.3 2769.3 879.2 2436.3 98.0 1344.9 158.9 8.51 PASS 3421.91 2858.7 1099.1 1135.1 2782.7 2858.7 879.2 2436.3 99.5 1319.7 161.71 8.2 PA S 3521.91 2950.3 1128. 1161.9 2874.3 2950.3 879, 2436.3 101.0 1298.6 164.3 7. PASS 3606.08 3029.0 1151.5 1181.6 2953.0 3029.0 879. 2436.3 102.2 1283:9 166.6 7.7 PASS 3621.91 3043.9 1155, 1385.0 2967.91 3043:81 879:2 2438:3 1024' 128'1.4 167.0. 77 PASS 3721.91 3138.0 1181.1 1206.8 3062.0 3138.0 879. 2436.3 103.8 1268. 169.7 7.4 PASS .91 3232.2 1206.7 1228.6 3156.2 3232.2 879. 2436.3 105.1 1251.3 172.5 7.2 PASS .91 3326.4 1232.3 1250.3 3250.4 3326.4 879.. 2436.3 106.5 1237.4 175.6 7.0 PASS 91 3420.6 1258.0 1272.1 3344.6 3420.6 879.2 2436.3 108.0 1224.2 178.7 6. PASS 91:3514.8 1283.61 1 93:81 34 8' 3514.6 B7 38: 109:4 1211.9 181.9 6l5 91 3609.0 1309.2 1315.6 3533.0 3609.0 879.2 2436.3 110.9 200. 185.0 6.51 PASS 91 3703.1 1334.8 1337.4 3627.1 3703.1 879.2 2436.3 112.5 1159.6 188.2 6. PA.91 M4621�lal 3797.3 1360. 1359.21 3721.3 3797.3 879.2 2436.3 114.0 1179.7 191.4 6.1 PASS .91 3891.5 1386.0 1380.9 3815.5 3891.5 879.2 2436.3 115.6 1170.7 194.6 6.0 PASS 91 3985:7 1491: 1402.7 3909.7 3985.7 878.2 2436:3 11T.2 1162.8 197.9 5.8 PA19 4067.0 1433.7 1421.5 3991.0 4067.0 879.2 2436.3 118.6 1156.4 200.7 57 PASS .91 4079.9 1437.2 1424.4 4003.9 4079.9 679.2 2436.3 118.8 1155.5 201.2 5.7 PASS 91 4175.11 1459.8 1445.1 4099.11 4175.11 879.2 2436.3 120.3 1148.7 204.45.6ASS15 4254.4 1474.91 1460.81 4178.4 4254.4 879.2 2436.3 121.41 1143.0 207.0 5.5 PASS.91 4271. 1477.8 1404. 4195,6 4271. 879.2 2438:3 121.621 1141.781 207.61 5,521 PASS 8a �• Clearance Report WE.. KLU#A-2 Condor (SideTrack) Ver16 FUR/E BAKER Operating Alaska U C Closest Approac h Page 9 of 40 HUGHES IDENTIFICATION O erator Furie Operating Alaska, LLC Siot KI -2 Condor Slot B Area Cook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack Field Kitchen Li hts Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA - Offset Wellbore: SRS State 81 Offset Wellpath: SRS State #1 Drift Indicator <0-16375'> acil : Shelf -Standard Richfield State State #1 Slot: SRS State #1 Well: SRS State #1 Threshold Value=1.00 t a Interpolate d/extra olated station Ref MD In] Ref TVD I Eft] Ref Narth [ft] Ref East [n] Offset MD Ift] Offset TVD IN Onset North Eft] Offset East pt] Horiz Bearing Clear C -C Dist ACR MASD Sep Ratio ACR Status 4368.581 1494.1 1482,371 4292.5EI 4368.61 879.261 2436.3 122.8CI 1135.0 210.751 5121.91 4465.5211 1510.5 1500.671 4389.51 4465.5 879.2 2436.3 124.0 1128.7 213.8 5.2 PASS 5221.911 4562.461 1526.8 1518.91 4486.4 4562.4 879.261 2436.3 125.21 1122. 216.961 5.14 PASS 5321.91 45b9ACI 1543.2 1537.2131 4583.4 46594l 879.2 2436.3 126.4 11 1T71 220.0 5.0 PASS 5421.91 4756.3,4 1559.6 1555,51 4680.34 4756.3 879.2EI 2436.3 127 BEI 1112.9 223.151 5.00I PASS 552191 4853.2 1575.9 1573.8 4777.2 4853.2f 879. 2436.371 128.9 1108.7 226.2 4.911 PASS 5621.91 4950.221 1592.3 1592,2CI 4874.2A 4950.2 879.261 2436.371 130.191 1105.0 229.2E 4.831 PASS 5721.91 5D47.161 1608.6 1610.5Q 4971.14 5047.1 879.261 2436.371 131.4 1101.8 232.3 4.761 PASS 5821.91 5144.101 1625.0 1628.811 5068.1CI 5144.1 879.2 2436,371 13271 1099.2 235,3E 4.6EI PASS 5921.91. 5241.04 1641.3 1647.111 5165.D4 5241.0 879. 2436.371 134.01 1097 1-, 238. 4,611 PASS 6012.28 5328.61 1656.1 1663.64 5252.64 5328. B79 2E 243631 135.14 10957 241.2 4.5 PASS 6021.911 5337981 1657.7 1665.44 5261.91 53379EI 879.2f 2436.34 135.24 1095. 241.54.4.51 PASS 6121.91 5434,921 1674.11 1683.7 5358.9 5434.94 879.2E 2436.3 136.5 1094.6 244.6 4.4 PASS 6221.91 5531.6 1690.4 1702.0 5455.8 5531.8 879.2 2436.3 137.6 1094.2 247.7 4.4 PASS 8264.46 .5573.1 1697.4 - 1709.8 5496:61 55 .6 879.2E 2436. 138,5 1094.2 249.11 4.4 PASS 5321.91 5628.8 1706.6 1720.3 5552.8 5628.8 879.2 2436.3 139.1 1094. 250.6 4.3 PASS 6421.91 5725.7 1723.1 1738. 5649.7 5725.7 879.2 2436.3 140.4 1095.01 253.9 4.3 PASS 6521.91 5822.6 1739.5 1756. 5746.6 5822.5 879.2 2436371 141.7 1096. 256.9 4.2 PASS 6621.91 5919.6 1755.9 1775.2 5843.6 5919.6 879.2 2436.3 142.9 1097.9 259.9 4.2 PASS 6721-91 6016. 1772.2 1793.5 .5940. 6. 879. 2436.3 144.2 1100. 262.9 4.1 6821.91 6113.5 1786.61 1811. 6037.5 6113.5 879.2 2436.3 145.5 1103.1 265.871 4.161 PASS 6921.91 6210.441 1804.9 1830.161 6134. 6210.4 879.261 2436.3 146.7121 1106.54 268,951 4.1 PASS 7021.91 6307.381 1821.3 1848.471 6231.31 6307.31 879.261 2436.3 148.04 11 10.4E 272,011 4.091 PASS 7121.91 6404.321 1837.6 1866.7 6328.3 6404.3 879.2 2436.3 1492 1114.91 275.051 4.061 PASS 7221.91 651)1.21 1854, 1885.0 6425-261 6501.2 879.261 2436.3 15a5il 1119. 278.01 4.04 PSS 7321.91 6598.2 1870.4 1903.3 6522.2 6598.2 879.2 2436.3 1517 1125.3 281.0 4.01 PASS 7421.91 6695.1 1886.7 1921.6 6619.1 6695.1 879.2 2436.3 152.9 1131.3 284.0 3.9 PASS 7521.91 6792.0 1903.11 1939.9 6716.0 6792.0 879.2 2436.3 154.1 1137.8 287.0 3.9 PASS 7621.91 6889.0 1919.4 1958.3 6813.0 6689.0 879.2 2436.3 155.3 1144.81 289.9 3.9 PASS 7721.81 6985.961 1935.81 1976.6 6909.94 6985. 879-261 2436.371 156.4 1152.2 292.871 3.9 PASS 8a e�Clearance Report FUR/E KLU#A-2 Condor (SideTrack) Ver16 , ODemtingAloskeLLC Closest Approach BAKER Page 10 of 40 HUGHES CLEARANCE DATA -Offset Wellbore: SRS State #1 Offset Wellpath: SRS State #1 Drift Indicator <0-16375'> OperatorOperating Alaska, LLC Slot KLU#A-2 Condor Slot B Cook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack MFurie Kitchen Li hts Unit Wellbore KLU#A-2 Condor (SideTrack) Monopod Platform ISidetrack from KLU#A-2 Condor avvp at 2521.91 MD CLEARANCE DATA -Offset Wellbore: SRS State #1 Offset Wellpath: SRS State #1 Drift Indicator <0-16375'> String/Diameter Facility: Shell -Standard Richfield State State #1 Slot: SRS State #1 Well: SRS State #1 Threshold Value -1.00 t - Interpolated/extrapolated station Ref MD [ft] Ref TVD I [it) Ref North IN Ref East [R) Offset MD Offset TVD [ft] [ft] Offset North [ft] Offset East [ft] Horiz Bearing Clear ri C -C Dist lftftl ACR MASD Fin Sep Ratio ACR Status NEW 7082,901 1952.1 1994.9 7006.901 9 89.2 46. 157.6 1160.2 5. 3, 1485.16 7921.91 7179.8 1968.5 2013.21 7103.8 7179.8 879.2 2436.3 158.7 1168.5 298.6 3.9 PASS 8021.91 7276.7 1984.9 2031.5 7200.7 7276.7 879.2 2436.3 159.8 1177.4 301.4 3.91 PASS 8121.91 7373.7 2001.2 2049.8 7297.7 7373.1 879.2 2436.3 160.9 1188.7 304.2 3.91 PAS 8149.02 7400:0 2005:6 2054:7 7324.Ofll 7400.0 87 261 2436;3 161291 1189.311 105.01 3.91 PASS I POSITIONAL UNCERTAINTY - Offset Wellbore: SRS State #1 Offset Wellpath: SRS State #1 Drift Indicator <0-16375'> Slot Surface Uncertainty 01 SO lHorizontal 12.000ft Vertical 7.000ft Facility Surface Uncertainty @1SD Horizontal 120.000ft Vertical 13.000ft HOLE & CASING SECTIONS - Offset Wellbore: SRS state #1 Offset Wellpath: SRS State #1 Drift Indicator <0-16375'> String/Diameter Start MD I End MD Interval Start TVD End TVD Start WS StartE/W End N/S End EMI [ft] rftl I M1 rftl Ift] rft] rftl Iftl [ft] i167onductor 100.00 337.00 237.00 169.00 406.00 536.15 1485.16 536.15 1485.16 10.75in Casing Surface 337.00 2818.00 2461.00 406.00 2887.00 536.15 1485.16 536.15 1485.16 7in Casing Production 2816.00 13441.00 10623.00 2887.00 13510.00 536.16 1485.16 536.15 1485.16 WELLPATH COMPOSITION -Offset Wellbore. SRS State #1 Offset Wellpath: SRS State #1 Drift Indicator <0-16375'> Start MD I End MD Positional Uncertainty Model Log Name/Comment Wellbore ft ft urittincli or - Inclination Only(Actual Survey) tate #1 Survey #1 <0-16375> jKb t5tate 8a Clearance Report MGas e� FURIE KLU#A-2 Condor (SideTrack) Ver16 BAKER Opeiating Alosko Lt C Closest Approach Page 11 of 40 HUGMS CATION Operator Furle Operating Alaska, LLC Islot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD OFFSET WELLPATH REFERENCE - Offset Wellbore: SRS State 91 Offset Wellpath: SRS State #1 Drift Indicator <0-16375'a MD Reference: Cuss II (RT) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) Ellipse Start MD 1218.00ft 85 FUR/E KLClearance Report .K�■ U#A-2 Condor (SideTrack) Ver16 BAKER OpmNagAloskatV Closest Approach Page 12 of 40 H S r erator Furie Operating Alaska, LLC Slot KLU#A-2 Condor Slot B rea Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facili Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2621.91 MD CLEARANCE DATA - Offset Wellbore: KLU #1 Rd #1 Offset Wellpath: OnTrak MWD<5082 - 1529w> Facility: Kitchen Lights Unit #1 Slot: KLU#1 Well: KLU#1 Threshold Value=1.00 t - Interporated/extra orated station Ref MD [it]inl Ref PID I Ref North I [it]I1U Ref East Offset MD (ft] Offsel ND Ift) Offset North In] Offset East IN Roriz Bearing C -C Clear Dist ACR MAED n Sep Ratio ACR Status 2521 r 91 216GA81 711.7 738.051 2155,861 2160. 51 -600.11 161.1 1386.281 10.7Z 2566.91 2168A91 735.3 763.5 2184.71 2189.1 -600.2 1186.01 162.4 1400.8 130.4 10.8 PASS 2586.91 2201.8 745.8 774.8 2197.7 2202.1 -600.2 1185. 163.0 1407.4 190.5 10. PASS 2621.91 2224.5 763.9 794.2 2220.7 2225.11 -600.2 1185.8 163.9 1419.2 130.7 10.9 PASS 2721,91 2292.1 814.2 848,0 2287. 2292, -600. 1185.3 166.5 1454.2 131.3 11.1. PASS 2821.91 2363.5 862.4 898.9 2358.9 2363.3 -600.4 1184.8" 168.9 1490.6 131.8 11.3 PASS 2921.91 2438.4 008.3 946.6 2434.7 2439.1 -600. 1184.3 171.0 1527.51 132.3 11.6 PASS 3021.91 2516.6 951.8 991.2 2510.7 2515.1 -600.6 1183.7 172.9 1564.3 132.7 11.8 PASS 3121.91 2598.0 992.7 1032.4 2592.9 2597.3 -600.7 1163.21 174.6 1600.6 133.1 12.11 PASS 3221.91 2662:3 1031 1070.2 2677 2681.91 -600 1182.5 176. 1635.7 133.4 12. PASS 3321.91 2769.3 1066.5 1104.5 2763.6 2768.0 -600.9 1181.8 177.3 1659.2 133.7 12.5 PASS 3421.91 2858.7 1099.1 1135.1 2852.8 2857.2 -601.0 1181.1 178.4 1700.8 134.0 12. A 3521.91 2950.3 1128.8 1161.9 2943.8 2948.2 -601.1 1180.3 179.3 1730.0 134.2 12.9 PASS 3606.08 3029.0 1151.5 1181.6 3021.5 3025.91 -601.2 1179.0 180.0 1752.7 134.3 13.1 PASS 3621:91 3043.91 1155. 1185:0 3036A 3040.7 -6 1.2 1179.5 180.1 1756.8 134.41 13.1 PASS 3721.91 3138.0 1181.1 1206.8 3131.3 3135.7 -601.4" 1178.7 180.91 1782.8 134.5 13.3 PASS 3621.91 3232.2 1206.7 1226.6 3226.4 3230.81 -601.5 1177.6 181.61 1808.S 134.7 13.5 PASS 3921.91 3326.4 1232.3 1250.3 3319.5 3323.8 -601. 1176.9 162.2 1835.4 134.9 13.7 PASS 4021.91 3420. 1258.0 1272.1' 3413.2 3417.5 -601.6 1976.0 182.961 1862.1 135.0 13.8. PASS 4121.91 .3514.821 1263,61 1293.911 3600.4CI 3512. -601-7fi 1175.1 183.611 1809.11 136-261 14.071 PASS 4221.91 3509.0cl 1309.24 1315.681 3601,561 3605.8 -601,801 1174.1 184.241 1916.2 135.4 141 SS 4321.91 3703.191 1334.821 1337.441 3594.7181 3699.11 -601.94 1173.2 184.8.1 1943.7 135.5 14.4 PASS 4421.91 3797.3 1360.4 1359.29 3768.5 3792.8 -602.0, 1172.3 185.4 1971.3 135.76 14.6 PASS 4521.91 3891.5 1386.0 1380.9 3882.21 3886.5 -602.1 1171.4 186.0 1999.2 135.9 14.8 PASS 4621.91 3985.7 1411. 1402.7 3978.1 3982.4 -6021 1170.5 186.5 2027.2 136 1 15.01 PASS 4708,19 4067.0 1433.7 1421.5 4060.1 4064.4 -602.2 1169.6 187.0 2051.5 136.2 15.1 PASS 4721.91 4079.9 1437.2 1424.4 4072.9 4077.2 -602.2 1169.5 187.1 2055.3 136.2 15,1 PASS 4821.91 4175.11 1459.8 1445.1 4170.3 4174.6 -602.2 1168.4 187.6 2080.5 136.4 15.3 PASS 4904.15 4254.4 1474.91 1460.81 4252.5 4256.8 -602.0 1167.5 188.0 2097.5 136.61 15.4 PASS 4921911,4271_ 1477 6 1A64.0 4269.9 4274.2 602.0 1767 3 188.1 2100.9 136. 15.4 AS gA eFURIE Clearance Report Few Fag KLU#A-2 Condor (SideTrack) Ver16 BAKER OperotingAloskottC Closest Approach Page 13 of 40 HUGHES ]REFERENCE WELLPATH IDENTIFICATION Operator Furie Operating Alaska, LLC Islot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska Offshore Well jKLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetfack from KLU#A-2 Condor_awp at 2521.91 MD LEARANCE DATA - Offset Wellbore: KLU #1 Rd #1 Offset Welipath: OnTrak MWD<5082 - 15298'> scilit . Kitchen Lights Unit #1 Slot: KLU#1 Well: KLU#1 Threshold Value=1.00 t= Interpolatedlextrapolated station Ref MD [ft] Ref ND [ft] Ref North IN Ret East [ft] Offset MD [ft] Offset TVp [it] Offset North IN Offset East [it] Horiz Bearing Ill C -C Clear Dist ft ACR MASD ff Sep Ratio ACR Status 4 .2 11 6.3 188.5 2119.6 136.9 1 .61 5121.91 4465.5 1510.5 1500.6 4464. 4468.9 -601.4 1165.4 189.0 2138.3 136.94 15.7 PASS 5221.91 4562. 1526.8 1518.9 4563.1 4567.4 -601.11 1164.6 189.4 2157.31 137.0 15.8 PASS 5321.91 4659.4 1543.2 1537.2 4661.3 4665.6 -600.7(.1163.8 189.8 2176.2 137.2 15.9 PASS 5421.91 42561. _ 1559:6 1555,591_ . 475?.2 4761,4 X00:2 1 162.8 190.31 2195:2 137 18.0 PA S 5521.91 4853.2 1575.9 1573.8 4853.3 4657.5 599.8 1161.7 190.7 2214.51 137.6 16.21 PASS 5621.91 4950.2 1592.3 1592.2 4957.61 4961.8 -599.2 1160.6 191.1 2233.71 137.6 16.3 PASS 5721.91 5047.1 1608.6 1610.5 5031.21 5035.4 -599.0 1159.8 191.5 2253.2 137.78 16.4 PASS 5821.91 5144.1 1625.0 1628.81 5099.31 5103.5 -599.6 1159.0 191.9 2274.11 137.91 16.5 PASS 5921,91: 5241.. 1641:3 1647.1'1 5162.4 5166:8 607;0 1158.'1 192'.3 229613 138:01 16: .PAS 6012.28 5328.6 1656.1 1663.6 5227. 5231.71 -603.3 1157.1 192.8 2317.6 138.1 16.8 PASS 6021.91 5337.9 1657.7 1665.4 5234. 5238.9 -603.5 1157.11 192.6 2319.9 138.1 16.9 PASS 6121.91 5434.9 1674.11 1663.7 5336.4 5342.5 -608.3 1157.1 192.9 2344.2 138.38 17.0 PASS 6221.91 5531.8 1690.4 1702.0 5463. 5467.6 -613.3 1160.5 193.2 2367.5 138.7 17.1 PASS 6321':81: 5628:8 1706!8 17203 5588. 0, 559 1., -: ,61':3 1165:2 193:.4 2388.8 139,14 17,2 PASS 6421.91 5725.7 1723.1 1738.6 5716.3 5720.0 -619.4 1169.6 193.6 2410.7 139.5 17.3 PASS 6521.91 5822.6 1739.5 1756.9 5806.9 5810.5 -620.1 1171.7 193.9 2431.2 139.77 i7.5 PASS 6621.91 5919.6 1755.9 1775.2 5924.5 5928.1 -620.9 1173.5 194.21 2451.8 140.0 17.61 PASS 6721.91 6016.5 1772.2 1793.5 6022.2 6025.6 620.8 1174.7 194.5 2471.8 140.3 17.7 PASS 682 ;91 'B 1788A 1811, . 61211 5126'. ' =620. 1176'! 6921.91 6210.4 1804.9 1830.1 6218.3 6221.9 -620.6 1177.2 195.0 2511.9 140.9 17.9 PASS 7021.91 6307.3 1821.3 1848.4 6320.0 6323.6 -620.3 1178.4 195.3 2532.01 14'.2 18.0 PASS 7121.91 6404.3 1837.6 1866.7 6422.4 6426.0 -619.9 1179.6 195.6 2551.9 141.54 18.1 PASS 7221.91 6501.2 1854.0 1685.0 6523.9 6527.5 -619.2 1180.6 195.9 2571.7 141.8 18.2 PASS 732.1:91" 6598`2 1870:4 1903,381 662Z 171 6625,7 -6.18A 1181;7: 196:1, 25914 142.1 18:: `PASS 7421.91 6695.1 1886.7 1921.6 6718.41 6721.9 -617.6 1182.71 196.4 2611.31 142.48 18.4 PASS 7521.91 6792.0 1903.11 1939.9 6619.0 6822. -616.7 1163.5 196.71 2631.1 142.81 18.5 PASS 7621.91 6889.0 1919.4 1958.3 6916.9 8920. -615.7 1184.2 196.9 2650.9 143.1 18.6 PASS 7721.91 6985.9 1935.8 1976.6 7012.3 7015.8 -14.7 1184.7 197.2 2670.8 143.4 18.7 PASS 7821.91 7082.9 1952.1 1994:91, ' 7.111 7114,81 -613: 1185.3 197.511 2690. 143.8 18:8 PAS 8a Clearance Report rrra FUR/E KLU#A-2 Condor (SideTrack) Ver16 BAKER Operating Alaska LLC Closest Approach Page 14 of 40 HUGHES LEARANCE DATA- Offset Wellbore: KLU #1 Rd #1 Offset Wellpath: OnTrak MWD<5D82 - 15211 Operator Furie Operating Alaska, LLC Slot LUN -2 Condor Slot B Area Cook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack Field lKitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility lFurie Monopod Platform ISidetrack from KLU#A-2 Condor _avvp at 2621.91 MD LEARANCE DATA- Offset Wellbore: KLU #1 Rd #1 Offset Wellpath: OnTrak MWD<5D82 - 15211 String/Diameter acilil : Kitchen Lights Unit 01 Slot: KLU#1 Well: KLU01 Threshold Value=1.001 t = Interpolatedfoxtropolated station End TVD Start Nis Start ENV I End N/S Ret MD IN Ref ND IN Ref North Ret East [ft] Ift] Offset MD Ift] Offset TVD Ift] Offset North Ift] Offset East Ift] Horiz Bearing ri C -C Clear Dist III ACR MASD III Sep Ratio ACR Status 10.30 7179.8q 1968.54 2013.2 -82.00 71 .5 �1 118. 117.Z 710. 20in Conductor 1 . 1815.30 8021.91 7276.7 1984.9 2031.5 7307.8 7311.3 X11.6 1186.5 198.0 2730.7 144.51 19.01 -82.00 6121.91 7373.7 2001.2 2049.8 7403.7 7407.2 -610.5 1187.0 198.2 2750.7 144.88 19.1 PAS8149.02 dS 725.09 7400.0 2005.6 2054.7 7429.5 7433.1 610.2 118721 1983 27562 14496 191 PAS POSITIONAL UNCERTAINTY - Offset wellbore: KLU #1 Rd #1 Offset Wellpath: OnTrak MWD<5082 -15298'> Slot Surface Uncertainty @1SD Horizontal 12.000 ertical 1.000ft Facility Surface Uncertainty @1SD lHorizontal 120.000ft vertical 13.000ft HOLE & CASING SECTIONS -Offset Wellbore: KLU #1 Rd #1 Offset Wellpath: OnTrak MWD<5082 - 15298'> String/Diameter Start MD End MD Interval Start TVD End TVD Start Nis Start ENV I End N/S End ENV [ft] Ift] [ff] [ft] Ift]_ _ _Lft1 If ! Iftlft 30in Drive Pipe 10.30 338.30 358.00 -82.00 276.00 -367.12 725.09 -367.01 724.8£ 20in Conductor 10.30 1815.30 1805.00 -82.00 1722.99 -367.12 725.09 -366.35 724.6; 13.375in Casing Surface 10.30 4917.30 4907.00 -82.00 4824.86 -367.12 725.09 -366.29 716.4E 9.875in Casing Intermediate 0.00 13383.00 13383.00 -92.30 13289.19 -367.12 725.09 -371.26 721.91 81 FUR/E KLClearance Report r U#A-2 Condor (SideTrack) Ver16 BAKEROperating AlaskO LIC Closest Approach Page 15 of 40 HUGHES REFERENCE WELLPATH IDENTIFICATION ,Operator Furle Operating Alaska, LLC Slot KLU#A-2 Condor Slot B) Area lCook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack Field jKitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility IFurie Monopod Platform Sidetrack from KLU#A-2 Condor awp at 2521.91 MD ELLPATH COMPOSITION - Offset Wellbore: KLU #1 Rd #1 Offset Wellpath: OnTrak MWD<5082 - 15298'> Start MD End MD Positional Uncertainty Model Log NamelComment Wellbore ft ft Nev. an ar c Um erger - < > 4968.23 9880.00 OnTrak (MagCorr) OnTrak MWD< 5082 - 9880'> KLU #1 Rd #1 9880.00 10538,00 BHI OnTrak (Standard) OnTrak MWD< 9975 - 10538'> KLU #1 Rd #1 10538.00 13315.00 OnTrak (MagCorr) OnTrak MWD<l0633-13315'> KLU #1Rd #1 13315.00 15298.00 OnTrak (MagCorr) OnTrak MWD<13432 - 152985 KLU #1 Rd #1 OFFSET WELLPATH REFERENCE - Offset Wellbore: KLU #1 Rd #1 Offset Wellpath: OnTrak MWD<5082 - 1529" MD Reference: Spartan 151-2012 (RT) Offset TVD 8 local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report Ellipse Start MD 1203.00ft 8d FUR/E KLClearance Report iFla U#A-2 Condor SideTrack Ver16 BAKER Operating Alaska ttc Closest Approach Page 16 of 40 HUGHn IDENTIFICATION—— Operating Alaska, LLC Slot KLU#A-2 Condor Slot 13 Cook InletAlaska (Offshore Well KLU#A-2 Condor SideTrack LFurie Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Furie Monopod Platform Sidetrack from KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA -Offset Wellbore: KLU#1 offset Wellpath: Schlumberger MWD <0 - 8805'> Facility- Kitchen Lights Unit #1 Slot: KLU#1 Well: KLU#1 Threshold Value=1.00 t = l"terpolatedlextra olated station Ref MD IN Ref TJD I rft] Ref North I [ft] Ref East I [ft] Offset MD I [ft] Offset TVD I [ft] Offset North I [ft] Offset East [ft] Horiz Bearing C -C Clear Dist ACR MASD ft Sep Ratio ACR Status 2521 91 -2160.4EI 711.711 738.051 55.. 2160.2 -600.151 1186,161 161.1411386.2 130.81 1 1 . 2566.91 2188.9 735.381 763.571 2184.71 2189.1 -600.2CI 1186.011 162.451 1400.801 130.461 10.821 PASS 2586.91 2201.8 745.811 774.8CI 2197.7 2202.1 -600.2 1185-94 163.021 1407.4 130.581 10.861 PASS 2621.911 2224.5 763.921 794.291 2220.7 2225.11 -600.251 1185.801 163.991 1419.2 130.791 10,931 PASS 2721.91 2292.1 814.2EI 848: 2287. 2292. -6mzq 1185:3f 166.591 131.3$1 11.1 PASS 2821.91 2363.5 862.481 898.921 2358.9 2363.3 -600,471 1184.8j, 168.941 1490.6 131.871 11.391 PASS 2921.91 2438.421 908.371 945.691 2434.71 2439.1 -6GO.541 1184.3 171.051 1527.51 132.331 11.631 PASS 3021.91 25M67l 951.84 991.2 2510.7t.2515.1 -600,631 1183.7 172.931 1564.3 132.751 11.871 PASS 3121.911 2598.051 992.761 1032.471 2592.921 2597.3 -600.7 1183.21 174.6 1600. 133.1 12.11 PASS 3221:91. 26823 1031.0 1070;2 2677, 2681.91 -6o0 1182: 17630 1635.7 1.33.4 1234 -PASS 3321.91 2769.3 1066.5 1104.5 2763.6 2768.0 -600.9 1181.8 177.3 1669.2 133.7 12.5 PASS 3421.91 2858.7 1099.1 1135.1 2852.8 2857.2 -601.0 1181.1 178.4 1700.8 134.0 12.7 PASS 3521.91 2950.3 1128.8 1161.9 2943.8 2948.2 -601.1 1180.3 179.3 1730.0 134.2 12.9 PASS 3606.08 3029.0 1151.5 1181.6 3021.5 3025.91 -601.2 1179.6 180.0 1752.7 134.3 13.1 PASS 3821:91 3043:81 1155: 1185.0 3036:4 $040.7 -601. 1179,5 180.1 1756: 134:4 13;1 i�ASS 3721.91 3138.0 1181.1 1206.8 3131.3 3135.7 601.4 1178.7 180.91 1782.8 134.5 13.3 PASS 3821.91 3232.2 1206.7 1228.6 3226.4 3230.81 601.5 1177.8 181.61 1808.8 134.7 13.5 PASS 3921.91 3326.4 1232.3 1250.3 3319, 3323.8 601.5 1176.9 182.2 1835.4 134.9 13.7 PASS 4021.91 3420.6 1258.0 1272.1 3413.2 3417.5 601.6 1176.0 182.9 1862.1 135.0 13.8 PASS 412.1".91 14: 1283:0' 1293. 3508: 35127 60Y: 117-514 183:69' 1889.11 ' 1: :2 14:0 A 4221.91 3609.0 1309. 1315.6 3601.5 3605.8 X01.8 1174.1 184.2 1916.2 135.4 14.2 PASS 4321.91 3703.1 1334.8 1337.4 3694.7 3699.11 -601.9 1173.2 184.8 1943.7 135.5 14.4 PASS 4421.91 3797.3 1360.4 1359.21 3788.5 3792.8 -602.0 1172.3 185.4 1971.3 135.7 14.6 PASS 4521.91 3891.5 1386.0 1380.9 3882.21 3886.5 -602.1 1171.4 186.0 1999.2 135.9 14.8 PASS 4821,81 3985.7.. 1411:8 1402.7 3978.1 3982.4 -602.2 1170:5 186, 2027.2 1`36.1 15.01 PASS 4708.19 4067.0 1433.7 1421.5 4060.1 4064.4 -602.2 1169.6 187.0 2051. 136.2 15.1 PASS 4721.91 4079.9 1437.2 1424.4 4072. 4077.2 -602.2 1169.5 187.1 2055.3 136.2 15.1 PASS 4821.91 4175.11 1459.8 1445.1 4170.3 4174.6 602.2 1166. 187.6 2080.5 136.4 15.3 4904.15 4254.4 1474.91 1460.81 4252. 4256.8 602.0 1167.5 188. 2097.5 136.81 15.4 PASS 4921.91 4271.6 1477,8 1464-0EI 4269.22 4274.291 -602.04 1167. 16a,121 21010.901 PASS Sa Clearance Report FURIE KLU#A-2 Condor (SideTrack) Ver16 �•• Operating AloskaLtC Closest Approach BAKER Page 17 of 40 HUGHES IDENTIFICATION Offset Wellpath: Schlumberger MWD <0 - 8805'> O erator Furie Operating Alaska, LLC Slot KLU#A-2 Condor Slot 8 ea Cook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack Field Kitchen Li hts Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor Wp at 2521.91 MD LEARANCE DATA - Offset Wellbore: KLU#1 Offset Wellpath: Schlumberger MWD <0 - 8805'> aclll : Kitchen Lights Unit 01 Slot: KLU#1 Well: KLU#1 Threshold Value=1.00 t = Int*rpolatedlextranotated station Ref MD Iftl Ref ND I Iftl Ref North Iftl Ref East IN Offset MD I [flu Offset TVD I Iftj Offset North [ft] Offset East [ft] Hot Bearing C -C Clear Dist I'M ACR MASD Iftl Sep Ratio ACR Status 4368.581 1494.14 1482.3 il 4 .2 1166.3 188.5 2119.6 136.7-941 15.611 PA 5121.91 4465.5 1510.5 1500.6 4464.64'4468.9 -601.4 1165. 189.0 2138.3 136.941 15.731 PASS 5221.91 4562,41 1526.8j1610.5 .9 4563.1 4567.4 -601.11 1164.6 189.4 2157.31 137.0 15.8 PASS 5321.91 4659.4 1543.2.2 4661.3 4665.6 -600.7 1163.6 189.8 2176.2 137.2 15.9 PASS 5421.91 4756.3 1559.615 4757. 4761.4 -600.271' 1162. 1.90:31 2395:2 137. 16:0 'PASS 5521.91 4853.2 1575.9.8 4853.3 4857.5 -599.8 1161.7 190.7 2214.51 137.6 16.21 PASS 5621.91 4950.2 1592.3.2 4957.61 4961.8 -599.2 1160. 191.1 2233.71 137.7 16.3 PASS 5721.91 5047.1 1608. 5055. 5059.5 -598.51 1159.5 191.5 2252.8 137.8 16.4 PASS 5821.91 5144.1 1625.0.81 5161.0 5165.3 -597.4 1158.31 191.9 2271. 138.0 16.5 PASS 592! 91 -+5241. 1641:3 184711' S258c 5282.2 -596: 7157,1 192:3 2290.7 1382 16.6 PASS ' 6012.28 5328. 1656.1 1663.6 5349.1 5353.3 -595.1 1156.1 192.7 2307.9 138.4 16.7 PASS 6021.91 5337.9 1657.7 1665.4 5357.9 5362.2 -595.0 1156. 192.7 2309.7 138.4 16.8 PASS 6121.91 5434.9 1674.11 1683.7 5450.7 5454.9 -593.8 1154.9 193.1 2328.8 138.5 16.9 PASS 6221.91 5531.5 1690.4 1702.0 5549.1 5553.3 -592.7 1153.8 193.5 2348.1 138.7 17.0 PASS 0321.91; _ 5628:8 . 17.06:e -17x20.3 5&? A, 5650: :591,4 1.152.6 r 193'8 236 -:4 ` 138 17-1-61: PASS 6421.91 5725.7 1723.1 1738.6 5746.0 5750.1 -590.2 1151.3 194.2 2386.91 139.1 17.2 PASS 6521.91 5822.6 1739.' 1756.9 5850.4 5854.5 -588.5 1150.1 194.61 2406.1 139.31 17.3 PASS 6621.91 5919.6 1755.9 1775.2 5944.31 5948.4 -587.0 1148.8 194.9 2425.3 139.5 17.51 PASS 6721.91 6016.5 1772.2 1793.5 6039.6 6043.7 585.5 1147.5 195.3 2444.6 139.6 17.6 PASS 6821.81 8113. 1'7, .51 181d': 142;., 8 47.01 583':8. 1945.9 195; 2 .'-:31' .9!39!8. 1.7-7,41 6921.91 6210.4 1804.9 1830.1 6242.2 6246.2 -581.9 1144.6 196.0 2483.6 140.0 17.8 PASS 7021.91 6307.3 1821.3 1 848.4 6340.21 6344.2 -580.0 1143.2 196.3 2503.0 140.2 17.9 ASS 7121.91 6404.3 1837.6 1866.7 6438. 6441.9 -578.1 1141.8 196.7 2522.51 140.4 18.0 PASS 7221.91 6501.2 1854.0 1885.0 6536. 6540.51 -576.1 1140.41 197.0 2542.0 140.6 18.1 PASS 7321 :91: 8598 2 1870.4 1903.3 6638.8 6642:8 1573: 11$8:761 197:3 2561..4 140.9 18.301, PASS 7421.91 6695.1 1886.7 1921.6 6734.2 6738.11 -571. 1137.1 197.7 2580.9 141.11 18.4 PASS 7521.91 6792.0 1903.11 1939.9 6829.4 6833.2 -569.51 1135.5 198.0 2600.51 141.3 18.5 PASS 7621.91 6889.0 1919.4 1958.3 6928.8 6930.6 -567.3 1134.0 198.3 2620.2 141.4 18.6 PA S 7721.91 6985.9 1935.8 1976.6 7021.3 7025.1 -565.4 1132.7 198.6 2640.0 141.6 18.7 PASS 7821:91 7082.9 1952.1 1994.91 7122.821 7126. -563:2 W51-34 1.98.951 2659.94 141.891 18.84 PASS 86 2 i FUR/E Operating Alaska Clearance Report KLU#A-2 Condor (SideTrack) Ver16 Closest Approach Page 18 of 40 WEFA2 BAKER HUGHES REFERENCE WELLPATH IDENTIFICATION— Offset Wellpath: Schlumberger MWD <0 - 8805'> O erator lFurie Operating Alaska, LLC Slot _ LU#A-2 Condor jSlot B Area lCook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor _awp at 2521.91 MD LEARANCE DATA - Offset Wellbore: KLU#1 Offset Wellpath: Schlumberger MWD <0 - 8805'> tringlDiameter Start MD I acllit : Kitchen Li hts Unit #1 Slot: KLU#1 Well: KLU#1 Threshold Value=1.00 - into olated/extra olated station End TVD I Start NIS I Start E/W Ref MD [ft] Ref ND [R] Ret North Ref East [ft] [ft] Offset MD [ft] Offset ND IN Offset North [ft] Offset East [ft] Horiz Bearing C -C Clear Dist ACR MASD Sep Ralio ACR Status Oin Drive Pipe I 10.30 1 356.00 .3 - 1.1 11 725.09 6 14 .11 1 . 10.30 8021.91 7276.7 1984.9 2031.5 7318.31 7321.9 558.9 1128.6 199.5 2699.6 72.3519.0 4917.30 PASS 8121.91 7373.7 2001.2 2049.8 7420.0 7423.6 -556.51 1127.2 199.8 2719.5 142.5 19.2 PASS 8149.02 7400.0 2005.6 2054.7 7446.7 7450.3 -555.8 1126.9 199.91 2724.8 142.6 19.2 PASS iOSITIONAL UNCERTAINTY - Offset Wellbore: KLU#1 Offset Wellpath: Schlumberger MWD <0 - 8805'> ;lot Surface Uncertainty @1SD lHorizontal J2.000ft lVertical 11.000ft acility Surface Uncertainty @1SD lHorizontal P0.000ft lVertical 13.000ft IOLE & CASING SECTIONS - Offset Wellbore: KLU#1 Offset Wellpath: Schlumberger MWD <0 - 8805'> tringlDiameter Start MD I End MD I Interval Start ND I End TVD I Start NIS I Start E/W End N/S Erd EIW Ito Iftl Iftl Ift1 rftr rftl iftl I rftt I U Oin Drive Pipe I 10.30 368.30 356.00 -82.00 276.00 -367.12 725.09 -367.01 724.E Din Conductor 10.30 1815.30 1805.00 -82.00 1722.99 -367.12 725.09 -366.35 724.E 3.375in Casing Surface 10.30 4917.30 49D7.00 -82.00 4824.86 -367.12 725.09 -366.29 716.4 VELLPATH COMPOSITION -Offset Wellbore: KLU#1 Offset Wellpath: Schlumberger MWD <0 - 88051> Start MD I End MD ft ft Positional Uncertainty Model Log Name/Comment Wellbore eV. n ard) Schlumberger MVVD < - 8605> KLUfl- 8a Clearance Report Wins FURZE KLU#A-2 Condor (SideTrack) Ver16 BAKER Operating Alosko LLC Closest Approach Page 19 of 40 HUGHES OFFSET WELLPATH REFERENCE - Offset wellbore: KLU#1 Offset Wellpath: Schlumberger MWD <0 - 8805' MD Reference: Spartan 151-2012 (RT) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) Ellipse Start MD 1203.00ft 8a Operator Furie O rating Alaska, LLC Islot JKLIJ#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) lWell KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD OFFSET WELLPATH REFERENCE - Offset wellbore: KLU#1 Offset Wellpath: Schlumberger MWD <0 - 8805' MD Reference: Spartan 151-2012 (RT) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) Ellipse Start MD 1203.00ft 8a FU / Clearance Report rias e.,d yR/E KLU#A-2 Condor (SideTrack) Ver16 OpetRAKERatingAlaSko CLC Closest Approach Page 20 of 40 HUGHES CLEARANCE DATA -Offset Wellbore: KLU #2A Offset Wellpath: OnTrak MWDt2070.10750'> Operator Furie Operating Alaska, LLC Islot LU#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) lWell KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furle Monopod Platform ISidetrack from KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA -Offset Wellbore: KLU #2A Offset Wellpath: OnTrak MWDt2070.10750'> Facility: Kitchen Lights Unit #2 Slot: KLU#2 Well: KLU#2A Threshold Value=1.00 t = Interpolatedlextrapolated station Ref MD Ift] Ref TVD I Ift] Ref North Ift] Ref East Ift] Offset MD Ift] Offset TVD Ift] Offset North Ift] Offset East I Ift] Hertz Bearing C -C Clear Dist ACR MASD Sep Ratio ACR Status 1 .9 -2205.271.3 39.721 .91 2186.9 735.3 763.5 10221.4 6673. 2182.91 476.0 185.6 5526.9 140.9 39.4 PASS .91 2201.8 745.81 774.8 10235.61 6880.5 -2172.9 483.5 185.7 5522.1 141.2 39.3 PASS 2224.5 763.9 794.2 10261.9 6892.9 -2154.4 497. 185.81 5513.5 141.7 39.1 PASS .91 2292.1 B14. $4$.0 10356:'1 6937,8 -20$7.7 5473 185:9 5485:81 143.0 38:61 PA S.91 E2621.91i 2363.5 8624 698.9 10409.2 6963.1 -2050.51 574.8 186.3 5454.0 144.51 38.0 PASS .91 2438.4 908.3 946.6 10545.1 7028.5 -1955.0 645.9 186. 5418.3 146.1 37.3 PASS .91 2516.6 951. 991.2 10739.7 7118,61 -1816.7 749.1 185.0 5376.0 147.8 36.61 PASS .91 2598.0 992.7 1032.4 10750.0 7123.2 -1809.4 754.6 185.6 5329.8 149.4 35.91 PASS .91 2882. 1031 1070:2 10750.0. 7123. -1809;4 754:8 186, 5281.1 151,01 35: PASS 3321.91 2769.3 1066.5 1104.5 10750.0 7123.2 -1809.4 754.6 186.9 5229.7 152.6 34.4 PASS 3421.91 2858.7 1099.1 1135.1 10750.0 7123.2 -1809.4 754.8 187.4 5176.0 154.2 33.7 P 3521.91 2950.3 1128. 1161.9 10750.0 7123.2 -1609.4 754.60.187.8 5119.8 155.91 33.0 PASS 3606.08 3029.001 1151. 1181.651 10750.00 7123.2 -1809.4 754.6 188.21 5070.7 157.31 32. PASS 3621:91- 3043.91 1155. 1185.0 10750 -OC 712312 -1809:4 754[ 188-2 ,: 5061.9 157.7 32.3A PASS 3721.91 3138.0 1181.1 1206.8 10750.0 7123.2 -1809.4 754.6 188.6 5003.0 159.21 31.6 PASS 3821.91 3232.2 1206.7 1228.6 10750.0 7123.2 -1809.4 754.6 188.9 4945.9 160.8. 30.9 PASS 3921.91 3326.4 1232.3 1250.3 10750.0 7123.2 -1809.4 754.6 189.2 4890.2 162.5 30.2 PASS 4021.91 3420. 1258.0 1272.1 10750.0 7123.2 -1809.4 754.6 189.5 4835.9.. 164.2 29.6 PASS 7---4-17T,791 14: 1283,6' 293.9 10 50.0 7123.2 -18N,46154: 8 783 2 165:8 PA 4221.91 3609.0 1309.2 1315.6 10750.0 7123.2 -1809.4 754.6 190.2 4731.9 167.5 28.41 PAS 4321.91 3703.1 1334.8 1337.4 10750.0 7123.2 -1809.4 754.6 190.5 4682.2 169. 27.8 PASS 4421.91 3797.3 1360.4 1359.21 10750.0 7123.2 -1809.4 754.6 190.8 4634.1 170.8 27.2 PASS 4521.91 3891.5 1386.0 1380.9 10750.0 7123.2 -1809.4 754.6 191.0 4587.7 172.5 26.7 PASS 4621.91 3465.74 1411: 1402.7 10756.001 7123.2 -1809.4 754.0 191. 4543.1 174.1 26.2 PASS 4708.19 4067.0 1433.7 1421.5 10750.0 7123.2 -1809.4 754.6 191.6 4506.01 175.5 25.81 PASS 4721.91 4079.9 1437.2 1424.4 10750.0 7123.2 -1809. 754.6 191.6 4500.1 175.7 25.7 PASS 4821.91 4175.11 1459.8 1445.1 10750.0 7123.2 -1909.41754.6 191.9 4456.11 177.3 25.2 A22 4904.15 4254.4 1474.91 1460.81 10750.0 7123.2 1809.4 754.6 192.1 4417.7 178.6 24.8 PASS 4921,91 4271. 1477.8 1464. 10750.0 7123:2 -1809. 754.8 192.1 4-409.241 17,5.911 24.7al PASS 8a Clearance Report riita e� f UR/E KLU#A-2 Condor (SideTrack) Ver16 BAKER Operating Alaska tr Closest Approach Page 21 of 40 HUGHES CLEARANCE DATA - Offset wellbore: KLU #2A Offset Wellpath: OnTrak MWD<2070-10750'> REFERENCE WELLPATH IDENTIFICATION Operator Furle O erating Alaska, LLC Slot KLU#A-2 Condor (Slot B Area Cook Inlet, Alaska (Offshore) lWell KLU#A-2 Condor SideTrack Field Kitchen Lights Unit jWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD CLEARANCE DATA - Offset wellbore: KLU #2A Offset Wellpath: OnTrak MWD<2070-10750'> acill : Kitchen Lights Unit #2 Slot: KLU#2 Well: KLU#2A Threshold Value=1.00 = Ints olate d/extra olated station Ref MD [ft] Ref ND [ft] Ref NorthRef [ft] East [ft] Offset MD [ft] Offset ND [h] Offset North [ft] Offset East [ft] Horiz Bearing C -C Clear Dist ACR MASD ft Sep Ratio ACR Status 11 .2 -1809.4 754.6 1 180.3 24,321 PASS 5121.91 44655 1510.51 1500.6 10750.0 7123.2 -1809.46 754.6 192.6 4317.7 181 .82 23,881 PASS 5221911 4562.4 152684 1518.9E 10750.0 7123.2 -1809.4 754.6 192.9C 4274.7 183.2 23.4 PASS 5321.91 4659.4 1543.21 1 537.2k 10750.0 7123.2 ----1809A6 754.6C 193.14 423M7 184.6 23.0 PASS 5421.9111 4756.3, 1559.6CI 1555.5E 10750.0 7123. -1801).461 754.6C.193.3 4194.5 185.9 22.681 PASS 5521.91 4853.21 1575.91 1573.84 10750.0 7123.2 -1809.461 754.601 193.601 4157.5 187.2 22.3 PASS 5621.91 4950.2 1592.321 1592.201 10750.0 7123.2 -1809.4 754,601 193.831 4122.61 188.4 21.9 PASS 5721.91 5047.1 1608.6 1610.5 10750.0 7123.2 -1809.4 754.6 194.0 4089.61 189.5 21.6 PASS 5821.91 5144.1 1625.0" 1628.81 10750.0 7123.2 -1809.4 754.6 194.2_ 405921 190.6 21.4 PASS 8921..91 5241. 1641.3 16471 10750.6( 7123. -1809.4 754.6 194. 4030.8 191.71 21.1 PASS 6012.28 5328.LAI 1656.1 1663.6 10750.0 7123.2 -18094 754.6 1947. 4007.21 192.5 20.91 PASS 6021.91 5337.9 1657.7 1665.4 10750.0 7123.2 -1809.4 754.6 194.7 4004.8 192.6 20.8 PASS 6121.91 5434.9 1674.11 1683.7 10750.0 7123.2 -1809.4 754.6 194.9 3981.0 193.5 20.6 PASS 6221.91 5.531.8 1690.4 1702.0 10750.0 7123.2 -1809.4 754.6 195.1 3959.7 194.31 20.4 PASS 6321.91 _ 5628.8 1706:8 1720.3 10750.0 7123.2 -1809.4 754.6 195. 3940.8 195. 20:31 PASS 6421.91 5725.7 1723.1 1738.6 10750.0 7123.2 -1809.4 754,6 195.5 3924.41 195.6 20.1 PASS 6521.91 5822.6 1739.5 1756,9 10750.0 7123.2 -1809.4 754.6 195.7 3910.4 196.1 20.0 PASS 6621.91 5919.6 1755.9 1775.2 10750.0 7123.2_ 1809.4 754.6 195.9 3899.01 196.5 19.9 PASS 6721.911 6016.5 1772.2.. 1793.5 10750.0 7123.2 -1809.4 754.6 196.1 3890.11 1968(.19.8 PASS 6821.91 8113.5 1788 -IBA 181181 10750.001 7 -1809,461 754.6 - 196.3fl 3683.7 198.91 19.811 PASS 6921.911 6210,44 1804.971 1830.11 10750.0 7123.2 -1809.461 754.6 196.5A 3879.971 197.0 19.791 PASS 7007.00 6292921 1818.81 1845.7 10750.0 7123.2 -1809.461 754.6 196.741 3878,781 197.09 19.7EI PASS 7019.30 6304.81 1820.9CI 1847.9 10750001 7123.2 -1809.4 196.761 3878.771 197 DE 19.7 PASS 7021,91 6307.3 1821.3 1848.4 10750A 7123.2 -1809 .46 .754,601 754.6 196.7 3878.7 197.0.. 19.7 PASS 7121.81 6404.3 1837.6 1866.7 10750.001 7123.2 -1809;4 754.601 196.94 3880,141 196.9 19.8CI PASS 7221.91 6501.2 1854. 1885.01 10750.0 7123.__l2 -1809.46 754.601 197.151 3884.091 196.6 19.8 PASS 7321.91 6598.2 1870.4 1903.3 10750.0 7123.2 -1809.4 754.6 197. 3890.6 196.3 19.91 PASS 7429.91 6695.1 1886.7 1921.6 10750.0 7123.2 -1809.4 754.6 197.5 3899.6 195.91 20.0 PASS 7521.91 6792.0 1903.11 1939.9 10750.0 7123.2 1809.4 754.6 197.71 3911.2 195.3 20.1 PASS 7621.91 6889.03 1919.471 1958.3q 10750.0 7123.2 -1809.4 754,601 197.54 3925.3 194-14 2D.2 PAS 8a Clearance Report FURIE KLU#A-2 Condor (SideTrack) Ver16 BAKER Owtotin9 Alaska LLC Closest Approach Page 22 of 40 HUGHES IDENTIFICATION]REFERENCE WELLPATH Oerator Furie O eratin Alaska, LLC Slot KLU#A-2 Condor Slot 8 rea Cook Inlet, Alaska (Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISIdetrack from KLU#A-2 Condor_awp at 2521.91 MD CLEARANCE DATA - Offset Wellbore: KLU #2A Offset Wellpath: OnTrak MWD<2070-10750'> Start MD ftj End MD Poslticnal Uncertainty Model Log Name/Comment Facility: Kitchen Li hts Unit #2 Slot: KLU#2 Well: KLU#2A Threshold Value=1.00 t = Interpolatedlextra olated station KLU #2 1832.01) 1974.00 OnTrak (MagCorr) Ref MD [tY] Ref TVD I [ft] Ret North I [ft] Ref East [41 Offset MD [ft] Offset TVD [it] Offset North [ft] OM7� z g Ill cC Clear Dist Htl ACR MASD Fri) I Sep Rado ACR Status 1. 1 9. 8.0 3041.9! ? .4 7821.91 7082.9 1952.1 1994.91 10750.0 7123.2 -1809.4 8.2 3961.0 193.2 20.61 PASS 7921.91 7179.8 1968.5 2013.21 10750.0 7123.2 -1809.4 8.4 3982. 192.31 20.87 PASS 8021.91 7276.7 1984.9 2031.5 10750.0 7123.2 1809.4 .6 4006.4 191. 21.0 PASS 6121:91 737$:. 21101.2 2049:8 10750.0 7123, 180$.4 ; 41)32.6 190: 21.3 PAS 6?49.02 7400.0 2005.6 2054.7 10750.001 7123.2 _jRnQ,4FJ 751 rot IQR R4 4040.101 190.01 21.3 PASS POSITIONAL UNCERTAINTY - Offset Wellbore: KLU #2A Offset Wellpath: OnTrak MWD42070-10750'> Slot Surface Uncertainty 181) lHorizontal 12.000ft Vertical 11.000ft Facility Surface Uncertainty OISD Horizontal 120.000ft[Vertical 13.000ft ELLPATH COMPOSITION -Offset Wellbere: KLU #2A Offset Wellpath: OnTrak MWD<2070-10750'> Start MD ftj End MD Poslticnal Uncertainty Model Log Name/Comment Wellbore 0.001 1832.00 OnTrak (MagCorr) OnTrak MVVD<494 - 1832'> KLU #2 1832.01) 1974.00 OnTrak (MagCorr) OnTrak MIND<1974 - 90305 KLU #2 1974.00 10750.00 OnTrak (MagCorr) OnTrak MVVD<2070 - 107505 KLU #2A OFFSET VVELLPATH REFERENCE - Offset Wellbore: KLU #2A Offset Wellpath: OnTrak MWD<2070-10750'> MD Reference: Spartan 151 (2012) (RTE) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) Ellipse Start MD 1212.00ft 89 I Clearance Report rig FURIE KLU#A-2 Condor (SideTrack) Verl6 BAKER Operating Ataska UC Closest Approach Page 23 of 40 HUG ES IDENTIFICATION_____ Operator Furle Operating Alaska, LLC Slot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack Facility Furie Monopod Platform Sidetrack from KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA - Offset Welibare: SCI St 3 AWB Offset Wellpath: SCI St 3 AWP Facility; S Cook Inlet St 3 Slot: SCI St 3 Well: SCI St 3 Threshold Value=1.00 ta interpolate lextraolated station Ret MD [ft] Ref TVD [ft] Ref North [ft] Ref East [ft] Onset MD IN Offset TVD [ft] Offset North [ft] Offset East [ft] Horiz Bearing C -C Clear Dist ACR MASD ft Sep Ratio ACR Status --"TTTr 2160.481 71ft 1. 1 .4 4 .41 -2025.3 1 4.6 109 2566.91 2188,991 735,38 763.571 219T991 2188.9 -9840.41 -2025.3 194.7 10937.3 146.0 75.5E PASS 2586.91 2201.81 745.81 774.8 2210.8 2201.8 -9840.41 -2025.3 194.8 10950.2 146.3 75AS PASS 2621.911 2224.581 763.92 794,291 2233.581 2224.5 -9840.41 -2025.3 194.84 10972.7 147.01 75.32 PASS 2721:91 2292.181 814.28 8413.081 2301.181 2292.1 -9840.41 -2025.3 195b0911 11035.3 148.871 747S PASS 2821.91 2363.54 862.48 898.921 2372.521 2363.5 -9840.41 -2025.3 195.21 11095.1 150.8 74.21 PAS 2921.91 2438.4 908.37 946.6 2447.4 2438.4 -9840.41 -2025.3 195.4 11152.0 152, 73.6 PASS 3021.91 2516.6 951 991.2 2525.6 2516.6 -9840.41 -2025.3 195.6 11205.91 154.5 73.0 PASS 3121.91 2598.0 992.7 1032.4 2607.0 2598.0 -9840.41 -2025.3 195.7 11256.4 156.5 72.3 PASS 3221:9f 2682.9 1031,0 1070. 2691.3 2682.3 -9840.41 -2025.3 195.5 11303.5 158.7 71.6 PASS 3321.91 2769.3 1066.5 1104.5 2778.3 2769.3 -9840.41 -2025.3 196.01 11347.1 161.0 70.9 PASS 3421.91 2858.7 1099.1 1135.1 2867.7 2858.7 -9840.41 -2025.3 196.11 11386.9 163.7 70.0 PA S 3521.91 2950.3 1128.8 1161.9 2959.3 2950.3 -9840 41 -2025.3 196.2 11422.9 166.5 69.0 PASS 3606.08 3029.0 1151.5 1181.6 3038.0 3029.0 -9840.41 -2025.3 196.2 11450.1 168.9 68.1 PASS 3621.91 304391 1155. 1185.0. 3052.91 3043.9 -9840:41 -2025.3 196.2 11455.0 169, 68.0 PASS 3721.91 3138.0 1181.1 1206.8 3147.0 3138.0 -9840.41 -2025.3 196. 11485.7 172.3 67. PASS 3821.91 3232.2 1206.7 1228.6 3241.2 3232.2- -9840.41 -2025.3 195.41 11516.4 175.3 66.0 PASS 3921.91 3326.4 1232.3 1250.3 3335.4 3326.4 -9840.41 -2025.3 1964 11547.1 178.2 65.1 PASS 4021.91 3420.6 1258.00 1272.1 3429.64 3420.6 -984041 -2025.3 196.5 11577.91 181.0 64.31 PASS 4121.91 3514.8 1283.61 129391 3523: 3514,821 9840.4 2025:3 196,4511 11608-671 183: 83.4 A 4221.91 3609.0 1309.2 1315.6 3618.0 3609.0 -9840.41 -2025.3 196.6 11639.4 186.6 62.71 PASS 4321.91 3703.1 1334.8 1337.4 3712.1 3703.1 9840.41 2025.3 196.7 11670.2 189.3 61.9 PASS 4421.91 3797.3 1360.44 1359.21 3806.3 3797.3 -9840.41 -2025.3 196.81 11701.0 192.0 61.2 PASS 4521.91 3891.5 1386.0 1380.9 3900.5 3891.5 -9840.41 -2025.3 196.8 11731.8 194.7 60.5 PASS 4621:91. 3985.7 1414. .1402.74.3994.7 3985.7 -9840.41 -2025.3 196. 11762.6 197.5 - 59.8 PASS 4708.19 4067.0 1433.7 1421.5 4076.0 4067.0 -9840.41 -2025.3 1970. 11789.3 199.7 59.3 PASS 4721.91 4079.9 1437.2 1424.4 4088.9 4079.9 -9840.41 -2025.3 197.01 117934 200.0 59.2 PASS 4321.91 4175.11 1459.85 1445.1 4184.11 4175.11 -9840.41 -2025 3 197.0 11821.1 202.6 59.6 PASS 4904.15 4254.4 1474.91 1460.81 4263.4 4254.4 -9840.41 -2025.3 197.1 11840.1 204.7 58.1 PASS 4921.91 4271. 14TI.8 1464. 4280: 4271.6 -9840.41 -2025.3 197.1 11 W.90, 205.11 55.04 PASS 85 Clearance Report FURIEKLU#A-2 Condor (SideTrack) Ver16 BAKEROperating Atasko CLC Closest Approach Page 24 of 40 HUGHES REFERENCE WELLPATH IDENTIFICATION Wellbore: SCI St Operator Furie Operating Alaska, LLC Islot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor SideTrack Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD CLEARANCE DATA -Offset Wellbore: SCI St 3 AWB Offset Welipath: SCI St 3 AWP Facility*. S Cook Inlet St 3 Slot: SCI St 3 Well: SCI St 3 Threshold Value=1.00 t = Inter olatedlextra olated station Ref MD Iff] Ref ND I Ift] Ret North Ift] Ref East I Ift] unset MD Ift] Offset TVD Ift] Offset North Ift] Offset East Ift] Horiz Bearing C -C Clear Dist N ACR MASD Sep Ratio ACR Status 1. .5 840.41 11 4.9 207.71 .41 5121.91 4465.5 1510.5 1500.6 4474.5 4465.5 -9840.41 -2025.3 197.2 11885.9 210.3 56.8 PASS 5221.91 4562.4 1526.8 1518.9 4571.4 4562.4 -9840.41 -2025.3 197.3 11907.0 212. 56.1 PASS 5321.91 4659.4 1543.2 1537.2 4668.4 4659.4 -9840.41 -2025.3 197.3 11928.11 215.7 55.5 PASS 5421.91. 4756: 1559.& 1555.5 4765: 4756_ -9840.41 -2025.3 19. 11849.1 218, 54.9 PASS 5521.91 4853.2 1575, 1573.8 4862.2 4853.2 -9840.41 -2025.3 197.5 11970.2 221.2 54.3 PASS 5621.91 4950.2 1592.3 1592.2 4959.2' 4950.2 -9840.41 -2025.3 197. 11991.4 223.9 53.81 PASS 5721.91 5047.1 1608.6 1610.5 5056.1 5047.1 -9840.41 -2025.3 197.6 12012.5' 226.7 53.2 PASS 5821.91 5144.1 1625.0 1628.81 5153.1 5144.1 -9640.41 -2025.3 197.6 12033.6 229.9 52.5 PASS 5921.91 5241. 1641.3 1847,11 5250. 5241. -9840.41 -2025.3 197.7 12054.8 233.2 51.9 PASS 6012.28 5328.6 1656.1 1663.6 5337. 5328 -9840.41 -2025.3 197.7 12073.9 236.1 51.3 PASS 6021.91 5337.9 1657.7 1665.4 5346.9 5337.9 -9840.41 -2025.3 197.8 12075.9 236.4 51.3 ASS 6121.91 5434.9 1674.11 1683.7 5443.9 5434.9 -9840.41 -2025.3 197. 12097.1 239.7 50.6 PASS 6221.91 5531.8 1690.4 1702.0 5540.8 5531.8 -984071 2025.3 197.91 12118.3 242.9 50.1 PASS 632191 5628.8 1706.8 1720:3 $637. 5628.8 -9840AI -2025.3 197.9 12139, 246.2 49.5 PA 6421.91 5725.7 1723.1 1738. 5734.7 5725.7 -9840.41 -2025.3 198. 12160.7 249.4 48.9 PASS 6521.91 5822.6 1739.54 1756.9 5831.6 5822.5 -9840.41 -2025.3 198.0 12181.9 252.71 48.41 PASS 6621.91 5919.6 1755.9 1775.2 5928.6 5919.6 9840.41 2025.3 198.1 12203.2 255.9 47.8 PASS 6721.91 6016.5 1772.2 1793.5 6025. 8016.5 -9840.41 -2025.3 198.2 12224.4 2592 47.3 PASS 6821.91 61 3. 1788.81 1811. 612 d5 6113.5 -9840.41 - T -3 15M 198. 1 2 :7. 26 . 6921.91 6210.4 1804.9 1830.1 6219. 6210. -9840.41 -2025.3 198.3 12267.01 265.7 46.3 P S 7021.91 6307.3 1821.3 1 W 6316.3 6307.3 -9840.41 -2025.3 198.3 12288.3 269.0 45.8 PASS 7121.91 6404.3 1837.68 1866.7 6413.3 6404.3 -9840.41 -2025.3 198.4 12309.6 272.3 45.3 PASS 7221.91 6501.2 1854.04 1865.0 6510.2 6501.2 -9840.41 -2025.3 196.4 12330.91 275.6 44.91 PASS 7321.91 6598.2 1870.4 1903.3 6807.2 6598.2 -9840.41 -2025.3 198.5 12352.2 278.91 44.4 PASS 7421.91 6695.1 1886.76 1921.6 6704.1 6695.1 -9840.41 -2025.3 198.6 12373.54262.2 44.01 PASS 7521.91 6792.0 1903.11 1939.9 6801. 6792.0 -9840.41 -2025.3 198.6 12394.9 285.4 43.5 PASS 7621.91 6689.0 1919.47 1958.3 6898.0 8689.0 -9840.41 -2025.3 198.71 12416.2 288.7. 43.1 PASS 7721.91 6985.9 1935.83 1976.6 6994.9 6985.9 -9840.41 -2025.3^ 188.7 12437.6 292.0 42.7 PASS 7821.91 7082.8 1952.1 1994.91 7091.9 7082.9 -9840.41 -2025.3 196.8 12459. 2fl5.3 42.3 PASS 85 �. Clearance Report Few Fag FURZEKLU#A-2 Condor (SideTrack) Ver16 BAKEROperoliny Alosko LLC Closest Approach Page 25 of 40 HUGHES O er8tor Furie Operating Alaska, LLC Slot KLU#A-2 Condor Slot 8 Area Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen LI hts Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA -offset Wellbore: SCI St 3 AWB Offset Wellpath: SCI St 3 AWP String/Diameter Start MD Facility: S Cook Inlet St 3 Slot: SCI St 3 Well: SCI St 3 Threshold Value=11.00 t = interpolate lextraolatad station End TVD Start NtS Start E/W Ref MD [H) Ref ND [ft] Ref North Ref East [ft] [H] Offset KID [ft] Offset ND IH] Offset North IN Offset East IN Horiz Bearing C -C Clear Dist ACR MASD Sep Ratio ACR Status 20in Conductor 7179.841 1 2257.00 1 .8 -9840.41 -202. 198. 80. 8. 41.93 PA 8021.91 7276.7 1984.9 2031.5 7285.7 7276.7 -9840.41 2025.3 198. 12501.8 302.01 41. PASS 8121.91 7373.7 ZOD1.26 2049.8 7382.7 7373.7 -9640.41 -2025.3 198.9 12523.2 305.4 41.1 PASS 8149.02 7400.0 2005.6 2054.7 7409. 7400.0 -984D.41 -2025.3 199.01 12529.0 306.51 41.0 PASS HOLE & CASING SECTIONS - Offset wellbore: SCI St 3 AWB Offset Wellpath: SCI St 3 AWP String/Diameter Start MD End MD I Interrt val startTVD End TVD Start NtS Start E/W End N/S End E/W ft I ft ft ft 20in Conductor 238.00 2495.00 2257.00 360.00 2617.00 -5998.61 -1235.15 -5998.61 -1235.1 13.375in Casing Surface 360.00 9031.00 8671.00 482.00 9153.00 -5998.61 -1235.15 -5998.61 -1235.1 9.625in Casing Intermediate 2595.00 13500.00 10905.00 2717.00 13622.00 -5998.61 -1235.15 -5998.61 -1235.1 7in Casing Intermediate 13343.00 14320.00 977.00 13465.00 14442.00 -5998.61 -1235.15 -5998.61 -1235.1 Sir. Liner 14000.00 16000.00 2000.00 14122.00 16122.00 -5998.61 -1235.15 -5998.61 -1235.1 WELLPATH COMPOSITION - Offset Wellbore: SCI St 3 AWB Offset Wellpath: SCI St 3 AWP Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore rft] ft 238.001 16000.00 untt indicator - Inclination Only (ActualSurvey) t 3 Survey fromSLB(350-16000') GI St 33 A�I 8d e;Clearance Report NSAa FURZE KLU#A-2 Condor (SideTrack) Ver16 BAKER Operating atoska LLC Closest Approach Page 26 of 40 HUMES REFERENCE WELLPATH IDENTIFICATION Operator Furie Operating Alaska, LLC Islot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD OFFSET WELLPATH REFERENCE - Offset Wellbore: SCI St 3 AWB Offset Welipath: SCI St 3 AWP MD Reference: Rig on SCI St 3 (RT) Offset TVD & focal coordinates use Reference Wellpath settings (See WEI IPATH DATUM on page i of this report) Ellipse Start MD 1356.00ft 85 el.v�'FURIE Clearance Report �� KLU#A-2 Condor (SideTrack) Ver16 BAKER LLC Closest Approach Page 27 of 40 HUGHES r O erator Furie Operating Alaska, LLC Slat KLU#A-2 Condor Slot B rea Cook Inlet, Alaska (Offshore) LIV211 KLU#A-2 Condor SideTrack Field Kitchen Lights Unit VVellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD CLEARANCE DATA -Offset Wellbore: KLU #3 Offset Wetlpath: Navi7rak MWD<388.1893>0nTrak MWD<1925-10393'> Facility: Furle onopod Platform Slot: KLU#3 Slot A Well: KLU#3 Threshold Val e=1.00 t= inter olatedlextra olated station Ref MD [kj Ref ND [k] Ref North 1111 Ref East [ft] Offset MD IN Offset ND IN Offset North [k] Offset East [ft] Hcriz Bearing C -C Clear Dist ACR MASO ft Sep Ratio ACR Status 1 149.1 1 -12.461 227.131 1024.09 2566.91 21889 735.3 763.5 2174.71 2177.61 15.2 -13.0 227.1 1059.21 21.5 50.9 PASS 2586.91 2201,8 745.81 774.8 2187.7 2190.61 15. -13.3 227.1 1074.6 21.5 51.6 PASS 2621.91 2224.5 763.9 794.2 2210.7 2213.6 15. -13.8 227.2 1101.51 21.6 52.8 PASS 2721.91 2292181 814.2 .0 2279.3 22821 16.1 -15.3 2272, 1175.81 21.7 55. A S 2821.91 2363.5 862.4 898.9 2352.11 2.354.9 17.0 -16.8 227.2 1246.41 22.11 58.4 PASS 2921.91 2438.4 908.3 946.6 2433.0 2435.9 17.5 -17.8 227.2 1312.9 22.5 60.4 PASS 3021.91 2516.6 951.8 991.2 2512.5 2515.4 17.8 -18.2 227.2 1375.3 22.9 62.0 PASS 3121.91 2598.0 992.7 1032.4 2599.1 2601. 17. -18.2 227.1 1433.3 23.5 63.11 PASS 3221.91 2682.3 1031.0 1079.2 2667 5 2690. 17.7 - -17.5 227.0 -1486. - 24.1 63.7 PASS 3321.91 2769.3 1066.5 1104.5 2775.7 2778.61 17.5 -16.6 226.9 1535.3 24.71 64.1 PASS 3421.91 2858.7 1099.1 1135.1 2864.91 2867.74 17. -15.7 226.7 1579.51 25. 64.3 PASS 3521.91 2950.3 1128.8 1161.9 2958.3 2959.17 17.C5 -14.7 226.6 1618.9 26.01 64.1 PASS 3606.08 3029.0 1151.5 1181,6 3035.11 3037.9 16.8 -13.9 226,5 1648.3 26.5 63.9 PASS 362L91 3043.91 1155. 1185. 30.50-0 3052 1$7 -13.8 226.4 '1653, 26671 63: PASS 3721.91 3138091 1161.1 1206.8 3144.1 3146.97 16.5 -12.9 226.3 1686.4 27.2 63.6 PASS 3821.91 3232.2 1206.7 1228.6 3238.4 3241.2 16.3 -12.0 226.1 1719.4 27.6 63.6 PASS 3921.91 3326.4 1232.3 1250.3 3332.3 3335.1., 162 -11.2 226.0 1752.3 28.4 63.4 PASS 4021.91 3420. 1258.0 1272.1 3425.8 3428.6 16.1 10.5 225.9 1785.3 29.0 63.1 PASS 4121.91 3 14.8 1283.6 1293.91 3519.3 3522,1 15.1 -9.9 225. 1816.4 29:7 62.8 A 4221.91 3609.0 1309.2 1315.6 3613.0 3615.8 16.11 -9.4 225.7 1851.5 30.4 62.4 PASS 4321.91t.3703.1 1334.8 1337.4 3707.1 3739. 16.0 -8.9 225.6 1884.6 31.1 62.0 PASS 4421.91 3797.3 1360.4 135921 3801.8 3804.6 16.11 -8.4 225.4 1917.7 31. 61.5 PASS 4521.91 3891.5 1386.0 1380.9 3896.4 3899.2 16.1 -8.0 225.4 1950.8 32.7 61.1 PASS 4621-91 3085.7 1411-6 1402.7 3990:2 3993.01 16. -7.61 225.31 1984.0 33.51 60.6 PASS 4708.19 4067.0 1433.7 1421.5 4071.3 4074.14 16. -7.3 225.2 2012.61 34.21 60.2 PASS 4721.91 4079.9 1437,2 1424.4 4084.41 4087.21 16.3 -7. 225.2 2017.11 34.3 60.1 PASS 4821.91 4175.11 1459.8 1445.1 4179.7 4182 58 16.5 6.9 225.1 2047.3 35.1 59.5 PASS 4904.15 4254.4 1474.91 1460.81 4259.4 4262.2 16.7 -6.7 225.1 2068.8 35.9' 58.8 PASS 4821.91 4271. 1477.8 1464. 42771 4279. 16.61 6.6 2251 2073. 36.11 58.7 PAS 8a FUR/E KLClearance Report Far Fla U#A-2 Condor (SideTrack) Ver16 BAKER Operating Alosko CCC Closest Approach Page 28 of 40 HUGHES E DATA -Offset Wellbore: KLU #3 Offset Wellpath. NaviTrak MWD<388-1893'>OnTrak MWD<1925-10393'> Furie Operating Alaska, LLC Slot KL #A-2 Condor Slot 13 For Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Furie Monopod Plafform Sidetrack from KLUM-2 Condor awp at 2621.91 MD E DATA -Offset Wellbore: KLU #3 Offset Wellpath. NaviTrak MWD<388-1893'>OnTrak MWD<1925-10393'> Mono od Platform SicL• KLU#3 SlotA Well: KLUS3 Threshold Value=1.00 = Inter olatedlextre olated statioRer M.Mlity:Furte ND [ft] Ref North [ft] Ref East [fq Offset MD [ft] Onset ND [ft] Offset North Offset East IN [ft] Horiz Bearing C -C Clear Dist AGR MASD ft14S4.1-i Sep Ratio ACR Status 1482.371 43763, 49. 1 .11 6.3 2 . 2 4465.5 1510.5 1500.6 4472.7 4475.5 17. -5.9 225.2 2121.1 37.8 57.31 PASS 5221.91 4562.4 1526.8 1518.9 4569.4 4572.2 17.7 -5.7 225.3 2145.2 38.6 56.6 PASS 5321.91 4659.4 1543.2 1537.2 4667.4 4670.21 18.2 5.4 225.3 2169.3 39.5 55.9 PASS 5421.91- 4758: 1559:6 1555.5 4765:2 4768:0 18.7 -5.2 225.3 2195. 40.4 55. A S 5521.91 4853.2 1575.9 1573.8 4862.1 4864.91 19.1 -4.9 225.4 2217. 41.31 54.7 PASS 5621.91 4950.2 1592.3 1592.2 4959.3 4962.11 19.6 -4.7 225. 2241.3 422 54.1 PASS 5721.91 SD47.1 1608.6 1610.5 5061.3 5064.1 20.2 4.4 225.4 2265.2 43.1 53. PASS 5821.91 5144.1 1625.0 1628.81 5160.4 5163.2 20.9 4.0 225.51 2289.01 44.11 52.8 PASS 5924.61 641. 1641.3 1647.11 5257.8 5260.5 2171 -3.6 228:5 2,312:71 45.0 52.2 PASS 6012.28 5328.6 1656.1 1663.6 5346.2 5349.0 22.51 -3.3 225.5 2334.1 45.9 51.7 PASS 6021.91 5337.9 1657.7 1665.4 5355.7 5358.4 22.5 -3.3 225.5 2336.4 45.9 51.6 PASS 6121.91 5434.9 1674.11 1683.7 5458.2 5461.0 23.6 -2.8 225.6 2359.9 46.9 51.0 PASS 6221.91 5531.8 1690.4 1702.0 5558.8 5561.5 24.8 -2A 225.6 2383. 47.9 50.51 PASS 6321.91 5628.8 1706.8 1720.3 5657021 59. 25.9 -1.7 225.6 2406,8 48 49.9 PASS 6421.91 5725.7 1723.1 1738.6 5752.6 5755.4 26.1 -0.2 225.7 2429.9 49.9 49.48.PASS 6521.91 5622.6 1739.5 1756.9 5850.7 5853.4 25.71 1.8 225.6 2453.2 50.8 48.9 PASS 662'1.91 5919.6 1755.9 1775.2 5944.0 5946.71 25.3 3.9 225.6 2476. 51.8 48.5 PASS 6721.91 6016.5 1772.2 1793.5 6017.8 6020.5 24.5 5.3 225.6 2500.4 52.6 48.2 PASS 21.91 1 .5 ?88.6 811: 6114:9 61 23. 6: 5.8 2524. 53. 4. A 6921.91 6210. 1804.9 1830.1 6210.2 6212. 21.5 8.61 225.61 2549.2 54.5 47.41 PASS 7021.91 6307.3 1821.3 1848.4 6311.0 6313.6 20.0 10.2 225.5 2573.61 55.5 46.9 PASS 7121.91 6404.3 1837.6 1866.7 6412.8 6415.4 18.7 12.1 225.5 2597.7 56.61 46.5 PASS 7221.91 6501.2 1854.0 1885.0 6507.9 6510.4 17.51 13. 225. 2621.9 57.5 46.1 PASS 7321.91 6598.2 1870.4 1903.3 6597. 6600.3 16.0 15.6 225.51 2646.1 58.5 45.8 A S 7421.91 6695.1 1886.7 1921.6 6670.0 6672.5 14.7 16.5 225.5 2671.0 59.3 45.6 PASS 7521.91 8792.0 1903.11 1939.9 6741.1 6743.5 13.5 16.41 225.51 2696.8 60.0 45.4 PASS 7621.91 6889.0 1919.4 1958.3 6822.1 6824.8 12.2 15.2 225.5 2723.4 60.9 45.2 A S 7721.91 6985.9 1935.6 1976.6 6915.4 6917.9 10.6 13.5 225.5 2750.3 61.A 45.0 PASS 7821.91 7082:9 1952.1 1994.911 7012.4 7014.Ewl 9.1 El 1 1.6q 225.59 2777.25162.pq 44.711 PASS 8a 2 e� FOpefUR/EAfoskc LLC Clearance Report KLU#A-2 Condor (SideTrack) Ver16 Closest Approach Page 29 of 40 .� FA. BAKER Hue E ]REFERENCE WELLPATH IDENTIFICATION Operating Alaska, LLC Slot KLU#A-2 Condor Slot B Cook inlet Alaska (Offshore) Well KLU#A-2 Condor SideTrack rFurie Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Furie Monopod Platform Sidetrack from KLU#A-2 Condor ,awp at 2521.91 MD ARANCE DATA - Offset Wellbore: KLU #3 Offset Wellpath: NaviTrak MWD<388.1893'>0nTrak MWD<1925-10393'> tring/Diameter StarttAD t : Furie Mono od Platform Slot: KLU#3 Slot A Well: KLU#3 Threshold Value=1.00 = Inter olatedlextra elated station End TVD Start NIS efMD P8121.91t RefTVD [R] RetNorth RefEast [ft] [H] OffsetMD Offset TVD OHsel North Otfset East [ft] [ft] [ft] [k] Horiz Bearing C -C Clear Dist ACR MASD ft7179.84 Sep Ratio ACR Status Iftl Iftl 1968.541 2013.21( 7109.321 7,771 9.7 22 .6 804.1 3.8 44.48021.91 104.00 449.00 7276.7 1964.9 2031.5 7203.3 7205.7 6.2 7.8 225. 2831.1 64.844.1 20DZ00 PASS 104.00 7373.7 2001.2 2. 8 7299.61 7301.9 4.6 6.0 225.6 2858.0 65.8 43.91 PASS 8149.02 _74OOmOCI 2005.691 2054791 7325.3 7327. 4.24 5,571 225,68 2865.3 66.1 43.84PASS TOLE & CASING SECTIONS - Offset Wellbore: KLU #3 Offset Wellpath: NaviTrak MWD<388-1893'>0nTrak MWD<1925-10393'> tring/Diameter StarttAD End MD End Interval Start TVD End TVD Start NIS Start E/V11 End NIS End ENy Iftl [it] Iftl rftl Iftl Iftl rftl MI Din Conductor 104.00 449.00 345.00 104.00 449.00 4.31 -0.68 4.78 T. 3.375in Casing Surface 104.00 20DZ00 1903.00 104.00 2006.95 4.31 -0.68 6.39 -3.2 in Casing 104.00 10497.00 10393.00 104.00 N/A 4.31 -0.68 N/A N! fELLPATH COMPOSITION -Offset Wellbore: KLU #3 Offset Wellpath: NaviTrak MWD<388-1893'>OnTrak MWD<1925-10393'> Start MD End MD Positional Uncertainty Model Log Name/Comment Wellbore Iftl ft NaviTrak (Stn ar New I rak MVVU<386> 1950.00 10393.00 BHI On?rak (Standard) OnTrak MWD -1925 - 10393', KLU #3 8a Clearance Report riFla FURIEKLU#A-2 Condor (SideTrack) Ver16 BAKEROperatingAlosko LLC Closest Approach Page 30 of 40 HUGHES IREFERENCE WELLPATH IDENTIFICATION O erator Furie Operating Alaska, LLC Islot LU#A-2 Condor Slot B rea Cook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SldeTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor awD at 2521.91 MD OFFSET WELLPATH REFERENCE - Offset Wellbore: KLU 93 Offset Welipath: NavlTrak MWD<388-1893'aOnTrak MWD<1925-10393'a MD Reference: Spartan151 on KLU#3 (RT) Offset TVD 8 local coordinates use Reference Wellpeth settings See WELLPATH DATUM on page f of this report) Ellipse Start MD 1222.00ft 8a Clearance Report Few Fag FUR/E KLU#A-2 Condor (SideTrack) Ver16 BAKEROperating Alasko LLC Closest Approach Page 31 of 40 HUGHES CLEARANCE DATA - Offset Wellbore: KLU #2 Offset Wellpath: OnTrak MWD<494 - 9106'> IDENTIFICATION Operator Furle O rating Alaska, LLC Islot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor,awp at 2521.91 MD CLEARANCE DATA - Offset Wellbore: KLU #2 Offset Wellpath: OnTrak MWD<494 - 9106'> Facility; Kitchen Lights Unit #2 Slot KLU#2 Well: KLU#2 Threshold Value=1.00 t = Inte olated/extra olated station Ref MD IRj Ref ND ift] RefNorth ift] Ref East IN Offset MD ift] Offset TVD iftl Offset North ift] Onset East Ift] Horiz Bearing CL Clear Dist ACR MASD Sep Ratio ACR Status o 1 1. - 146. -3342.88 .4 .2 124. i 71.9 2586.91 2188.9 735.3 763.5 2268.1 2281.4 -7146.2 -3342.81 207.5 8887.71 124.2 72.1 PASS 2586.91 2201.8 745.81 774.6 2281.6 2294.8 -7146.1 -3342.7 207.5 6902.01 124.2 72.2 PASS 2621.91 2224.5 763.9 794.2 2305.3 2318.6 -7145.8 -3342.71 207.61 8926.8 124.2 72.4 PASS 2721.91 2292.1 814.2 848,0 2574.31 2987 714:1 5342:5 207.7 8995. 124. 72;$ A S_ 2821.91 2363.5 662.4 898.9 2443.5 2456.7 -7144.4 -3342.3 207.91 9061.3 124.6 73.3 PASS 2921.91 2438,421 908.3 946,6E 2517.621 2530.8 -7143.6 -3342A91 208.041 9123.51 124.81 73.691 PASS 3021.91 2516.6 951.6 991,2E 2589.4 2602. -7142.9 -3342.0 208.1 918Z01 125.01 74,051 PASS 3121.91 2598.051 992.7 1032.4 2670.121 2683.3 -7142.1 -3341. 208.2 9236.8 125.21 74 371 PASS 3221.91 2682.3A 1031' iD70.2 2n9,7 . . .277. 7141.2. -3341:8 208.3 9287. 1Y .4 746 PASS 3321.91 2769.3 1066.5 1104.5 2645.2 2858.5 -7140.3 -3341.7 208.4 9334. 125.6 74.9 PASS 3421.91 2858.7 1099.1 1135.1 2935.7 2948.9 -7139.4 -3341.6 208.5 9376.7 125. 75.11 PASS 3521.91 2950. 1^28.8 1161.9 3030.6 3043.8 -7138.4 -3341.5 208.5 9414.8 126.0 75.2 PASS 3606.08 3029. 1151.5 1181.6 3123. 3136.8 -7137.3 -3341.4 208.6 9443.2 126.2 75.41 PASS 3621.94 $043.91 1155, 1185.0 3142 3155.6 -7137121 ,. =3341 4 2 6 T 75'. PASS 3721.91 3138.0 1181.1 1206.8 3246.1 3259.3 -7135.6 -3341.3 208.6 9480.0 126.4 75.5 PASS 3821.91 3232.2 1206.7 1228.6 3345.2 3358.4 -7134.1 -3341.4 208.7 9511.7 126.6 75.7 PASS 3921.91 3326.4 1232.3 1250.3 3407.2 3420.3 7133.31 3341.3 206.7 9543.4 1200".7 75.8 PASS 4021.91 3420.64 1258.0 1272.1 3442.3 3455.5 -7133.0 -3341.3 208.8 9575.7 126. 76. PASS 4121':91. - 14: -1283.67 1293.9 77:3- 3490.561 1;33: 1. 208: 127 i. 1 76.2PAM 4221.91 3609.0 1309.2 1315.6 3570.2 3583.3 -7133.3 -3341.3 208.8 9641. 127.31 76. PASS 4321.91 3703.1 1334.8 1337.4 3675.2 3688.4 -7133. -3341.2 208.9 9674.9 127. 76. ASS 4421.91 3797.37 1360. 1359.21 3764.01 3777.1 -7134.0 -3340.6 208.9 9708.0 127.7 76.5 PASS 4521.91 3891.5 1386.0 1380.9 3859.61 3872.7 -7134.4 -3340.4 208.9 9741. 128.01 76.7 PASS 4621.91 3985.7 1411. 1402�I' 3958: 396951 -7.134.8 -3340,0 209.D 9774. 128.2. 76.81 PASS 4708.19 4067 0 1433.7 1421.5 4050.3 4063.5 -7135.1 -3339.7 209.0 9802.8 128.5 76.8 PASS 4721.91 4079.93 1437.2 1424.4 4062.9 4076.1 -7135.2 -3339.6 209.0 9807.3 128. 76.9 PASS 4821.91 4175.11 1459.8 1445.1 4156.6 4169.6 -7135.4 -3339.2 209.1 9837.1 128.8 PASS 4904.15 4254.4 1474.91 1460.81 4237.5 4250.7 -7135.7 -3338.8 209.1 9858.01 129.0 J769 PASS 4921.91 4271. 1477.8 1464.,9 4256.31 4269.4 -7135.81 -3336.7 2091 9862.1 129.1 PASS 85 60� FURIE Clearance Report KLU#A-2 Condor (SideTrack) Ver16 Closest Approach Page 32 of 40 rias BAKER HUGHES Operator Furie Operating Alaska, LLC Slot LU#A-2 Condor Slot B Area Cook Inlet Alaska (Offshore) Well KLU#A-2 Condor SldeTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD LEARANCE DATA -Offset Wellbore: KLU #2 Offset Welipath: OnTrak MWDc494 - 9106'> sell : Kitchen Lights Unit 02 Slot: KLU#2 Well: KLU#2 Threshold Value=1.00 t - Interpolatedlextrapolated station Ref MD Ift] Ref ND I Iff] Ref North I [ft] Ret East Itt] Offset MD Ift] Offset ND [ft] Offset North Iflt] Offset East [R] Horiz Bearing C -C Clear Dist ACR MASD Sep Ratio ACR Status 1 8.2 .1 1 .9 5121.91 4465.5 1510.5 1500.6 4449.2 4462.4 -7136.3 -3337.81 209.2 9908.5 129.7 76.9 PASS 5221.91 4562. 1526.8 1518.9 4549.8 4562.8 -7136.61 -3337.3 209.2 9931.7 130.0 76.9 PASS 5321.91 4859. 1543.2 1537.2 4646.61 4659.7 -7136,8313337.01 209.3 9955.0 130.3 76.9 PASS 1.91 4750.341 1558,8 1555. 47f)6,8131 4 . 0.:. -7137.071 -3336:9 209: 9978.2 1 :7 $ PASS 5521.91 4853. 1575.9 1573.8 4868.5 4881.6 -7137.0 -3335.91 209.4 10001.21 131.0 76.8 PASS 5621.91 4950. 1592.3 1592.2 4980.9 4994.11 -7137.01 -3335.2 209.4 10024.11 131.4 76.8 PASS 5721.91 5047.1 1608.6 1610.5 5072.51 5085.6 -7136.9 -3334.6 209.4 10046.8 131.8 76.8 PASS 5821.91 5144.1 1625.0 1628.81 5166.31 5179.4 -7136.8 -3333.9 209.53 10069.8 132.1 76.7 PASS 0921.9 7. 76413 1647 525ZQ 52(15. 71 -3333.a .: 1 3 i 78.7 ASS 6012.28 5328. 1655.1 1663.6 5342.8 5356.01 -7137. -3332.6 209.61 10113.6 132.8 76.7 PASS 6021.91 5337.9 1657.7 1665.4 5352.81 5365. -7137.11 -3332.5 209.61 10115. 132.91 76.6 PASS 6121.91 5434.9 1674.11 1683.7 5469.4 5482.57 -7137.2 -3331.3 209.6 10138.7 133. 76.6 PASS 6221.91 5531. 1690.4 1702.0 5565.7 5578.9 -7137.3 -3330.2 209.6 10161.5 133.7 76.5 PASS 6321.9:1 56213, 17 r8 1720. 588 .7 78.97 .7147: -3329:. ' 209.7 '10184. 130.3 M .i 6421.91 5725.7 1723.1 1738. 5754.01 5767.1 -7137.7 -3327.8 209.7 10207. 134.5 76.4 PASS 6521.91 5822.8 1739. 1756.9 5827.7 5840.81 -7137.9 -3327.0 209,8 10230.2 134. 78.3 PASS 6621.91 5919.6 1755.9 1775.2 5948.0 5961.1 -7138.3 -3325.7 209.P10253.2 135.4 76.2 PASS 6721.91 6016. 1772.2 1793.5 6053.5 6068. -7138.5 -3324.3 209.876.0 135.8 76.1 PASS 6821.91 t : 1768.,& 18 1.8 64496921.91 6210. 1804.9 1830.1 6223.6 6236.7 -7139.0 -3322.0 209.921.91 136.7 76.0 PA 7021.91 6307. 1821.3 184B.4 6319.7 6332.8 -7139.5 -3320.7 209.944.9 137.21 75.9 PASS 7121.91 6404.3 1837.6 1866.7 6413.8 6426.9 -7140.0 -3319.4 210.0168.1 137.6 75.8 PASS 7221.91 65012 1854.0 1885.0 6544.2 6557.3 -7140.5 -3317.4 210.0 10390.9 136.2 75.7 PASS 7321: 11 6598. 1870:4. 1190.4 86$0: "T3.2 -7.140: , 316.6 210,0 10413.7 138. 76A, PASS 7421.91 6695.1 1886.7 1921.6 6763.71 6776.7 -7140.9 -3313.8 210.11 10436.3 139.2 75.4 PASS 7521.91 6792.0 1903.11 1839.9 6862.6 6875. -7141.0 -3312.0 210.1 10458.8 139.81 75.3 PASS 7621.91 6889.0 1919.4 1958.3 8977.3 6990.2 -7141. -3309.7 210.1 10481.3 140.3 75.21 PASS 7721.91 6885. 1935.8 1976.6 7067.2 7080.2 7141.3 3307.7 210.21 10503.7 140.8 75.1 PASS 7821.91 OB : 1952.1 1994:9 7108. 7121.7 -714j- . -3306.9a 21 10528. 14 .: 0 PASS 8a // RIr / Clearance Report WMA Fag FVKLU#A-2 Condor (SideTrack) Ver16 BAKER � Opeiatfng Alosko LCC Closest Approach Page 33 of 40 HUGHES rRiFERENCE WELLPATH IDENTIFICATION Operator Furte Operating Alaska, LLC Slot KLU#A-2 Condor Slot B rea lCook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility IFurie Monopod Platform ISidetrack from KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA -Offset Wellbore: KLU #2 Offset Wellpath: OnTrak MWD<494 - 9106'> Facility: Kltchon Lights Unit #2 Slot: KLU#2 Well: KLU#2 Threshold Value -i.00 t = Interpolated/extrapolated station Ref MD Ift] Ref TVD [ft] Ref North I Ref East I Ift] [ft] Offset MD [it] Offset TVD Ift) Offset North I Ift] Offset East Ift] Horiz Bearing C -C Clear Dist ACR MASD Sep Ratio ACR Status 1968.5Q 2013.211 1 .0 -7141.771 -33 .4 .2 1 141. .01 8021.91 7276.7 1984.9 2031.5 7187.0 7200.0 7142.1 3306.1 210.3 10573.5 142.01 74.9 PASS 8121.91 7373.7 2001.2 2049.8 7223.9 7236. 7142.5 3306.1 210.3 1 D597.8 142.3 74.9 PASS 8149.02 7400. 2005.6 2054.7 7233.8 7246.8 7142.7 3306.1 210.3 10604.5 142.48174.9 PA S POSITIONAL UNCERTAINTY - Offset Wellbore: KLU #2 Offset Wellpath: OnTrak MWD -C494 . 9106'> Slot Surface Uncertainty @1 SD orizontal 12.000ft[Vertical 11.000ft Facility Surface Uncertainty @1 SD torizontal 120.000ft[Vertical P.300ft WELLPATH COMPOSITION -Offset Wellbore: KLU #2 Offset Wellpath: OnTrak MWD<494 - 9106'> Start MD I End MD Positional Uncertainty Model Log Name/Comment Wellbore fftl ffti O.OD 1832.00 OnTrak(MagCorr) OnTrak MWDr 494 - 1832'> KLU #2 1832.00 9106.00 OnTrak (MagCorr) OnTrak MWD<l974 - 903U> KLU #2 OFFSET WELLPATH REFERENCE • Offset Wellbore: KLU #2 Offset Wellpath: OnTrak MWD<494 - 9106'> MD Reference: Spartan 151 (2012) (RTE) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 1 of this report) Ellipse Start MD 212.01)ft 8a eFURIE Clearance Report KLU#A-2 Condor Sidetrack Ver16 opeieangnro5tc icc Closest Approach Page 34 of 40 FEFie jArea )Cook Inlet, Alaska (Offshore) lWell IKLU#Al2 Condor SideTrack at 2521.91 MD CLEARANCE DATA -Offset Wellbore: KLU#4 Offset Wellpath: OnTrak MWD<450-9200'> Facility-. Kitchen Lights Unit 04 Slot: KLU#4 Well: KLU#4 Threshold Value -1.0 0 = Interpolatedlextropolated station Ret MD [ft] Ref TVD [ft] Ref North [ft] Ref East I [ft] Offset MO I IN Offset ND I if Offset North [fl] Offset East I [ft] Horiz Bearing C -C Clear Dist ACR I MASD Sep I Ratio ACR Status 1.13072.11 14663.861 48A1 18620.231 123.611 152.281 2566.91 2188.9 735.3 763.5 2255.8 2256.8 13072.01 14663.8 48.41 18585.3 123.6 151.9 PASS 2586.91 2201.8 745,81 774.8 2272.51 2273.4 13071.94 14663.81 48.41 18569.9 123.6 151.8 PASS 2621.91 2224.5 763.9 794.2 2301.9 2302.9 13071.8 14663.7 48.41 18543.2 123.7 151. PASS 2721.91 2292.1 814.2 848.0 24527 2453.71 13Q7A.B 14663.1 48;9 18469.11 123. 150:8 PASS 2821.91 2363.5 862.4 898.9 2468.3 2469.3 13070.8 14663.4 48.4 18398.5 123.5 150.1 PASS 2921.91 2438.4 908.3 946.6 2484.8 2485.8 13070.8 14662.9 48.4 18332.0 123. 149. PASS 3021.91 2516.6 951.8 991.2 2502.1 2503.1 13070.8 14662.9 48.4 18269.8 123.7 148.9 PASS 3121.91 2598.0 992.7 1032.4 2520.2 2521.2 13070.9 14662.9 46.4 18212.0 123.8 148.3 PASS 3221.91 2682. 1031:0 1070. 25317 253.6 13071. 14662. 48:4 18158:8 123.9 1 7,8 PASS 3321.91 2769.3 1066.5 1104.5 2538.1 2539.1 13071.1 14662.9 48.4 18110.6 124.01 147.3 PASS 3421.91 2858.74 1099.1 1135.1 2544.9 2545.8 13071.2 14662.9 48.4 18067.4 124.1 146.8 PASS 3521.91 2950.3 1128.6 1161.9 2551.7 2552.7 13071.4 14663.0 48.51 18029.4 124.2 146.3 PASS 3606.08 3029.0 1151.5 1181.6 2557.7 2558.67 13071.5 14663.0 48.5 18001.61 124.3 146.0 PASS 3621.91 3043.91 9155, 1185:0 2558_5 659.7 13071.6 14663.0 48.5 17996.7 124.3 146,01 PASS 3721.91 3138.0 1181.1 1206.8 2565.9 2566.91 13071.84 14663.1 48.5 17966.2 124.4 145.6 PASS 3821.91 3232.2 1206.7 1228.6 2573.1 2574.0 13072.1 14663.2 48.5 17936.2 124.4 145." PASS 3921.91 3326.4 1232.3 1250.3 2560.2 2581.22 13072.4 14663.31 48.5 17906.6 124.5 145.0 PASS 4021.91 3420. 1258.0 1272.1 2567.4 2588.4 13072.81 14663.4 48.5 17877.5 124.6 144.6 PASS 41 1.91 3 1 .8 283.61 1293.9' 2594;- 2595.61 13073:1 14869:5 48: 9 144. 8 4221.91 3609.0 1309.2 1315.6 2601.9 2602.8 13073.6 14663.6 48.61 7820.8 124. 143.9 PASS_ 4321.91 3703.191 1334.8 1337.441 2609,201 2610.07 13074.14 14663.801 48.6 17793,211 124.91 143.64 PASS 4421.91 3797.371 1360.4 1359.211 2616A81 2617.33 13074.67 14663.961 48.6 17766.0 125.0 143.301 PASS 4521.91 3891,551 1386.0 1380.971 2623.781 2624.61 1307524 14664.1 48.6 17739.3 125.1 114Z94 PASS 4621-911 3985,741 1411.61 1402.74 2630.721 26315 13075.8 14664.301 48.6 177131 125,2 142.61 PASS 4708.19 4067.001 1433,71 1421.5 2636.471 2637.25 13076.3 14664.4 48,6 17690.9 T 125.3 142.321 PASS 4721.91 4079.9 1437.2 1424.4 2637.3 2638.161 13076.4 14864.4 48.6 17687.4 125.3 142.2 PASS 4821.91 4175.11 1459.8 1445.1 2644.11 2,61 11 13077.06 14654.6 46.6 17665.1 125.5 141.9 PASS 4904.15 4254.4 1474.91 1460.81 2649.7 13077.6 14664.8 48.6 17650.51 125.64 14,74 PASS 492.1.91t 4271M 1477 8 1464Z4 2650.911 2651.611 13077.7 14664-B61 48.691 17647 7EJ 125.681 141661 PASS 8a r C�/ / Clearance Report war us. ry r RIE KLU#A-2 Condor (SideTrack) Ver16KER OperatingAloskoUC Closest Approach Page 35 of 40 HUGHES CLEARANCE DATA - Offset Wellbore: KLU#4 Offset Wellpath: OnTrak MWDc450-9200'> Operator lFurie Operating Alaska, LLC Islot RLURA-2 Condor Siot B Area lCook Inlet, Alaska (Offshore) Well JKLU#A-2 Condor SideTrack Field) lKitchen Lights Unit lWellbore KLU#A-2 Condor SideTrack Facility lFurie Monopod Platform ISidetrack from KLU#A-2 Condor_awp at 2521.91 MD CLEARANCE DATA - Offset Wellbore: KLU#4 Offset Wellpath: OnTrak MWDc450-9200'> Facility: Kitchen Lights Unit 94 Slot: KLU#4 Well: KLU#4 Threshold Valuee1.00 s interpolate dlextra olated statlon Ref MD [ft] Ref ND I [ft] Ref North [rt] Ref East [ft] Offset MD IN Offset TVD [it] Offset North IN Offset East [ft] Ho Bearing I'll Clear Dist Fftl ACR MASD ft Sep i Ratio i ACR Status 5021.91 4 13078.4 146 12 . 1 5121.91 4465.5 1510.5 1500.8 2664.5 2665.1 13079.2 14665.2 48.6 17617.7 125.61 141.1 PASS 5221.911 4662.461 1526.81 1518.9E 2671.44 2671.96 13080.07 14665.5 48F61 17603.4 125.9 140.94 PASS 5321.91 4659.401 1541251 1537.2E 267824 2678.75 13080.93 14665.7 48691 17589.7 126.01 140.70 PASS 5421.91 4758.341 i559.6Cj 1555.51 2685ACl 26a5.54 15081,83 14688:0 48.6 17576.51 . 126.21 140.47 S 5521.91 4853.281 1575.961 1573.8E 2691.9 2692.3 13082m77 14666.31 48.6 17563.6 126,31 140.2 PASS 5621.91 4950.2 1592.3 1592.2 2698.8 2699.11 13083.7 14666.5 48.6 17551.6 126.4 140.01 PASS 5721.91 5047.1 1608.6 1610.5 2705.6 2705.8 13084.77 14666.8 48.6 17539.9 126.5 139.7 PASS 5821.91 5144.1 1625.0 1628.81 2717.2 2717.3 13086.57 14667.3 48,6 17528.8 126.6 139.5 PASS 5821.91 241: 1641.9 16471 4 2733:1. 27.33.. 13089:1 14668.1 48,6 17518. 126.8 139;31 P 6012.28 5328.6 1656.1 1663.6 2747.6 2747.2 13091.5 14668,81 48.6 17508.9 126.9 139.0 PASS 5021.91 5337.9 1657.7 1665.4 2749.1 2748.7 13091.7 14668.8. 48,6 17508.0 126.9 139. PASS 6121.91 5434.9 1674.11 1683.7 2765.0 2764.4 13094.4 14669.6 48.6 17498.3 27.0 138.8 PASS 6221.91 5531.8 1690.4 1702.0 2781.0 2780.1 13097.2 14670.5 46.6 17489.0 127.2 138.61 PASS 6321:99 28. 1706. 1720:3 2797.0 2795. 13111,0.'1 54671.8 48,0 17480:. 12739 _ 138. , PASS 6421.91 5725.7 1723.1 1738.6 2815.5 2814.0 13103.5 14672.3 48.6 17472.0 127.5 138.1 PASS 3521.91 5822.6 1739.5 1756.9 2836.1 2834,1 13107.4 14673.5 48.6 17464.2 127.7 137.9 PASS 6621.91 5919.6 1755.9 1775.2 2856.6 2854.2 13111.51 14674.71 48. 17456.8 127.8 137.6 PASS 6721.91 6016.5 1772.2 1793.5 2877.2 2874.4 13115.6 14675.9 48. 17449.9 128.01 137.47.PASS 8821.91 8 13:6 '1788.6 1811. 2899.114 ,2895 18 1 14677.2 48.8 1 443:q 1281 137 . 6921.91 ' 6210.4 1804.9 1830.1 2933.4 2929.21 13127.2 14679.3 48.6 17437.4 128.3 136.9 PASS 7021.91 6307.315 1821.34 1848.4 2967.751 2962.7C 1 3134.601 14681.5 48.6 17431.7 126. 136.7 ASS 7121.91 6404.3 1837.6 1866.7 3016.1 3011.7 13145.5 14684.6. 48.5 17426.4 128.7 136.4 PASS 7221.91 6501.2 1854.0 1885.0 3089.3 3081.1 13160.9 14669.8 48.5 17421.2 129.0 136.1 PASS 7321.91 6598,2 1870. 1903.3 $106. 3098.2 13164. 14690.8 4$, 174184 129.1 135.9 PAS 7421.91 6695.1 1886,7 1921.6 3124.5 3115. 13168.8 14692.() 48 5 17412.1 129.3 135.7 PASS 7521.91 6792.0 1903.11 1939.9 3142.1 3132.4 13172.9 14693.2 46.5 17408.2 129.5 135.51 PASS 7621.91 6889.0 1919.4 1958.3 3159,71 3149. 13177.1 14694.51 48.5 17404.9 129.71 135.3 PASS 7721.91 8985.9 1935.6 1976.6 3177.2 3166.4 13181.4 14695.7 48.5 17401.9 129.9 735.0 PASS 7821,91 7082.9 1952.1 1994:91 3196.2 31 13188. 146971 48.51 17'499 513 190.0 134: PASS 8a 2 I Clearance Report w., e,,.-,-�'FURIE KLU#A-2 Condor (SideTrack) Ver16 BAKEROparatingAlmkOLEC Closest Approach Page 36 of 40 HUGMS CLEARANCE DATA - Offset Wellbore: KLU#4 Offset Wellpath: OnTrak MWD<45O.9200'> itring/Diameter Start MD I Facility: 10tchen Lights Unit #4 Slot: KLU#4 Well: KLU#4 Threshold Value=1.00 t = Interpolated/extrapolated station Start NIS Start EMEnd FUS Ref MD Ref TVD I Ref North Ref East I Offset MD I [it] Offset TVD I [it] Offset North [ft] Offset East Eft] Horiz Bearing C -C Clear Dist ACR MASD Sep Ratio ACR Status 7179." 1968.5 2013.211 3215.391 3203.211 13190.971 146130.2841 -106.00 294.00 7980.88 134.651 PA r 8021,91 7276.7 1984.9 2031.5 3234.5 3221.61 13195.9 14700.0 48.4 17396.0 130.4 134.4 PASS 8121.91 7373.7 2001.2 2049.8 3253.5 3239.96 13200.9 14701.5 48.4 17395.D 130.6 134.2 PASS 8149.02 7400.0 2005.6 2054.7 3258.7 3244.9 13202.3 14701.9 48.4 17394.6 130.7 134.1 PASS IOSITIONAL UNCERTAINTY - Offset Wellbore: KLU#4 Offset Wellpath: OnTrak MWD<450-9200'> ilot Surface Uncertainty @ISD lHorizontal 12.000ft ertical 11.000ft 'acility Surface Uncertainty @1SD lHoOzontal 120.000ft ertical P.000ft TOLE & CASING SECTIONS - Offset wellbore: KLU#4 Offset Wellpath: OnTrak MWD<450-9200'> itring/Diameter Start MD I End MD I Interval Start TVD End TVD Start NIS Start EMEnd FUS End EIW fft] Iftl ift] [it] [H] Iftl rftl Iftl Ift] 0in Conductor 0.00 400.00 400.00 -106.00 294.00 7980.88 8935.85 7980.53 6935.9 !Oin Conductor 0.00 2400.00 2400.00 -106.00 2293.96 7980.88 8935.85 7977.38 8934.8 3.625in Casing 0.00 9200.00 9200.00 -106.00 8567.51 7980.88 8935.85 8721.81 9152.6 VELLPATH COMPOSITION - Offset Wellbore: KLU#4 Offset Wellpath: OnTrak MWD<450.9200'> Start MC I End MD Positional Uncertainty Model Log Name/Comment Wellbore ft ft OnTrak (Standard) n ra < > 2374.00 9200.00 BHI OnTrak (Standard) OnTrak MWD<2428 - 92005 KLU#4 8d FURlE Clearance Report AL KLU#A-Z Condor (SideTrack) Ver16 Operating Alaska UC Closest Approach BAIM Page 37 of 40 HUGHES O erator IFurie Operating Alaska, LLC islot KLU#A-2 Condor Slot B Area ICo6k Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field jKitchenijghts Unit JVVellbore KLU#A-2 Condor (SideTrack) Facility IFurie Monopod Platform Sidetrack from KLU#A-2 Condor_awp at 2521.91 MD OFFSET WELLPATH REFERENCE - Offset Wellbore: KLU#4 Offset Wellpath: OnTrak MWD<450.9200'> MD Reference: Rig on KLU#4 (RT) Offset TVD & local coordinates use Reference Weflpath settings (See WELLPATH DATUM on page 1 of this report) Ellipse Slart MD 1192.00ft Ri �• Clearance Report rKA`'. FURJE KLU#A-2 Condor (SideTrack) Ver16 BAKER Alnsko LLC Closest Approach Page 38 of 40 HUGHES REFERENCE WELLPATH IDENTIFICATION Operator Furie Operating Alaska, LLC Slot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform Sidetrack from KLU#A-2 Condor_awp at 2521.91 MD LEARANCE DATA - Offset Wellbore: KLU#5 Offset Wellpath: KLU#5 acilit : Kitchen Lights Unit #5 Slot: KLU#5 Well: KLU#5 Threshold Value=1.00 t = Inter olatedlextra olated station Ref MI) [ft] Ref ND [it] Ret North [ft] Ref East [ft] Offset MD [ft] Offset ND Offset No [it] [ft] Offset East [ft] Horiz gearing rci C -C Clear Diet Fit? ACR MASD ml Sep Ratio ACR Status f�ib.L)tq 2148.481 2160.481 984 1 1 . 4 .3 .461 2566.91 2186.9E 735.3 763-571 2176.991 2188. -29849.3 -7313.6 194.79 31633.311 149.1 213.511 PASS 2586.91 2201.8 745.81 774.801 2189.851 2201.8 -29849.3 -7313.6 194.81 31646.2 149.51 213.1 PASS 2621.91 2224.5 763.9 794.2 2212.5 2224.5 29849.3 7313.6 194.8 31668.7 150.0 212.4 PASS 2721.91 2292.1 8142 648.0 2280.1 2292.1 -29849. -7313:6 194.91 31731. '151. 210.3 PA S 2821.91 2363.5 862.4 898.9 2351.5 2363.5 -29849.3 -7313.6 194.9 31790.9 153.7 208.1 PASS 2921.91 2438.4 908.3 946.6 2426.4 2438.4 -29849.3 -7313.6 195.0 31847.6 155.6 205.91 PASS 3021.91 2516.6 951.8 991.2 2504.6 2516.6 -29849.3 -7313.6 195.0 31901.1 157.6 203.6 PASS 3121.91 2598.0 992.7 1032.4 2586.0 2598.0 -29849.3 -7313.8 195.14 31951.41 159.6 201.4 PASS 3221.91; 2682.3 1031.0 107D.24 2870.3 2682:3 29849. . -7313.6 1961 31998, 181.7 199.11 PSS 3321.91 2769.3 1066.5 1104.5 2757.3 2769.3 -29849.3 -7313.6 195.23 32041.4 163.9 196.7 PASS 3421.91 2858.74 1099.1 1135.101 2782.5 2794.5 -29849.3 -7313.61 195.2 32081.0 164.6 196.001 PASS 3521.91 2950.3EI I 128.8E 1161.971 2792.9 2604.1 -29649.4 -7313.5 195.3 32117.1 165.11 195.7 PASS 3606.08 3029.0 1151.5c 1181.6 2800.4 2812.4 -29849.4 -7313.4 195.3 32144.5 165.41 195.531 PASS 3621.91 t 3043.91 11 55,5E 1185.01 2801. 2813.90 29649.491 -731. 195.8 32149.51 165.4 195. PASS 3721.91 3138.0 1181.1 1206.8 2975.4 2987.4 -29851.0 -7311.7 195.3 32180.5 165.7 195.321 PASS 3821.91 3232.271 1206.7 1228.621 3114.0 3126.0 -29851.7 -7311.3 195.3 32211.4 168.0 195.2 PASS 3921.91 3326.4 1232.3 1250.3 3246.11 3258.0 -29852.1 -7311.11 195,40. 32242.1 156.31 195. PASS 4021.91t 3420.64 1258.0 1272.151 3421.981 3433. -29852.5 -7310.81 195A21 32272.71 166.61 194.81 PASS 41' 1.91 3514.8 1283.61 1293.91 348 .8 3474. -29$52:5 -7310. 19 .4 3 30 .2 166.8 194.7 4221.£1 3609.Oq 1309.2 1315.6 3503.2 3515.2 -29852.6 -7310.71 195.47 32333.9 167.1 194.6 PAS 4321.91t 3703.1 q 1334.8 1337.441 3679,191 3691.1 -29852.91 -7310.5E 195.5C 32364.5 167.5 194.4 PASS 4421.91 3797.371 1360.4 1359.21 3819.5 3831.5 -29852.8 -7310.4 195.5 32394.9 167.6 194.1 PASS 4521.91 3891.5 1386.0 1380.971 3892A01 3904.0 -29852. -731,0.3 195.5 32425A 168.1 194.0(.PASS 4621 91 398574 1411 1402.7 3034.461 3946. -29852.8 -7310.3 195.5 32455: 1 .4 193.8 PASS 4708.19 4067.01 1433.7 1421.5 3970.9 3982. -29852.9 -7310.2 195.5E 32482.4 168.7 191661 PASS 4721.911 4079.9 1437.2 1424.4 3976.7 3988. -29852.9 -7310.24 195.60 32486.6 166.7E.193.6 PASS 4821.91 4175.11 1459.8 1445.1 4149. 4161.6 -29853.2 -7309.9 195.6 32514.0 159.1 193.3 PASS 4904.15 4254.4 1474.91 1460.81 4217.0 4229.0 29853.3 -7309.8 195. 32532.81 169.4 193.11 PASS 4921.91 4271.6 1477.8 1464,061 4230.8q 4242.8 -29853.3 -7M.74 195.64, 32536.52 169.54 193.Oq PASS 85 Clearance Report FMFla FUR/E KLU#A-2 Condor (SideTrack) Ver16 BAKER Operating Afar&o LCC Closest Approach Page 39 of 40 HUGHES CLEARANCE DATA - Offset wellbore: KLU#5 Offset Wellpath: KLU#5 [Operator Furie Operating Alaska, LLC Islot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska (Offshore) 1W.11 KLU#A-2 Condor SideTrack Field Kitchen Lights Unit lWellbom KLU#A-2 Condor (SideTrack' Facility Furie Monopod Platform ISidetrack from KLU#A-2 Condor awp at 2521.91 MD CLEARANCE DATA - Offset wellbore: KLU#5 Offset Wellpath: KLU#5 aclllt : Kitchen Lights Unit #5 Slot: KLU#5 Well: KLU#5 Threshold Value=1.00 t = Inter olatedlextra olated station Ref MD [ft] -=1.91 Ref ND I [ft] Ref North [it] Ref East [ft) Offset MD [ft] Offset TVD [k] Offset North IN Offset East [ft] Horiz Beating C -C Clear Dist Iftl ACR MASD ft Sep Ratio ACR Status 436B.581 1 -29853.5 -7309581 19&671 32557.31 16 2. 5121.91 4465.5 15105 1500,671 4419.01 4430.9 -29853.8 -7309.151 195.691 32578.2 170,251 192.51 PASS 5221.91 J 4562.4 1526.8 1518.981 4554.28 4566,2 -29853.9 -730B.84 195.711 32598.91 170.64 192.19 PASS 5321,91t 4659.41 1543.2 1537-281 4600.95 4612.9 -29854.01 -7308,84 195.741 32619.6 170.91 191.93 PASS 5421.91 4756.34 11559.61 1555.51 4719.801 4731 7 -2985421 -7308.91 195.7 3264D,5 171.3 191.61 PASS 5521.91 4853.2 1575.9 1573.8 4774.81 4786.7 -29854.2 -7309.0 195.7 32661.4 171.7 191.3 PASS 5621.91 4950.2 1592.3 1592.2 4821.7 4833.7 -29854.3 -73091 195.81 32682.4 172.0 191.0 PASS 5721.91 5047.1 1608.6 1610.5 4970.1 4982.1 -29854.4 -7309.91 195.8 32703.2 172.5 190.6 PASS 5821.91 5144.1 1625.0d1738.64 5109.6 5121.61 -29854.5 -7310.5 195.8 32724.2 172.9 190.3 PASS 5821.91 524E 16413 5202.9 5214.8 -29854. -7311.1` 195, 32745.0 173. 189. PASS 6012.28 5328.6 1656.1 5324.7 5336.6 -29854.21 -7311.81 195.9 32763.7 173.7 189.6 PASS 6021.91 5337.8 1657.7 5329.5 5341.5 -29B54.21 -7311.8 195.9 32765.7 173-81 189.6 PASS 6121.91 5434.9 1674.11 5379.8 5391.7 -29854.1 -7312.1 195,9 32786.5 174.2 189.31 PASS 6221.91t.5531.8 1690.4 5447.7 5459.6 -29854.1 -7312.4 195.9 32807491 174.61 188.9 PASS 6321,91 56213,8(1 1706;8 5547.9 5559. -29854.8 -7312.. 195.9 32928.4 176. 188: PASS 6421.91 5725.7 1723.1 5632.9 5644.9 -29854.4 -7313.0 196.0 32849.4 175.5 188, PASS 6521.91 5622.6 1739.5 1756. 57644 5776. -29854.7 -7313.0 196.0 32870.4 175.9 187.8 PASS 6621.91 5919.6 1755.9 1775.2 5864.4 5876. -29854.9 -7312.8 196.04 32891.3 176.4 187.4 PASS 6721.91 6016.5 1772.2 1793.5 5896.9 5908.9 -29855.0 -7312.8 196.0E 32912.3 176.8 187.1 PASS 6821.91 6113. 17W.T31 1819.` 5929.4 5941: -20855:. -7312.7 196. 32933.54 177.2 186. A 6921.91 6210. 1804.9 1830.1 6015.7 6027.7 -29855.7 -7312.7 196.11 32954.91 177.7 186.4 PASS 7021.91 tj 6307.3 1821.331 1848.47 6134.49 6146.4 -29856.3 -7312.8 196.13 32976.191 178.281 186.0 PASS 7121.91tj 6404.3 1837.681 1866.77 6249.781 6261.7 -29856.7 -7313.21 196.15 178.8 185611 PASS 7221.91 6501.21 1854.0 1885.0 6360,4 6372.3 -29857.0 -7313.9 196.1 33618.6 179.3 105.1 PASS 7321.91 6598.2 1870.401 1903.3 6477H 2 -29857.3 -7314.2 196.2 33039.7 179.8 164.7 PASS 7421.91 6695.1 1886.7 1921.6 65417 -29857.5 -7314.4 196.2 33060.9 180.3 164.3 PASS 752191 6792.0 ?903.11 1939.9 65927 -29857.7 -7314.5 196.2 33082.2 180.8 184.01 PASS 689.0 1919.4 1958.3 67789 -29858.4 -7314.81 196.27 33103.4 181. 183.4 PASS7721.91 6985.9 1935.8 1976.6 7100? -29857.91 -7316.2 196.2 33124.2 182.2 182.7 PASS 7821.91 7082. 1952.1 1994.91 71565 -29857.5 -7316.8q 196.3 33144 781 182 74 182.3A4PASS 8d FUR/EClearance Report CAFA■ KLU#A-2 Condor (SideTrack) Verl6 BAKER OperotingAfosko LLC Closest Approach Page 40 of 40 HUGHES ]REFERENCE WELLPATH IDENTIFICATION O erator Furic Operating Alaska, LLC Slot KLU#A-2 Condor Slot B Area Cook Inlet, Alaska Offshore Well KLU#A-2 Condor SideTrack Field Kitchen Lights Unit Wellbore KLU#A-2 Condor (SideTrack) Facility Furie Monopod Platform Sidetrack from KLU#A-2 Condor awp at 2521.91 MD LEARANCE DATA - Offset Wellbore: KLU#5 Offset Wellpath: KLU#5 acilit : IOtchen Lights Unit #5 Slot. KLU#5 Well: KLU#5 Threshold Value=1.00 a Interpolated/extrapolated station Ref MD Ref TVD Ref North IN Ift] Ift] Ref Fast [ft] Offset MD [ft] Offset TVD IN Offset North I:t] Offset East [ft] Horiz Bearing I'll C -C Clear Dist fill ACR MASD fftl Sep Ratio ACR Status 1 -29855.661 18. 196.34 6 . 183. 1 1. 7 It 8021.91 7276.7 1984.9 2031.5 7496.5 7508.5 -29654.9 7318.5 196.3 33185.1 184.0 181.3 PASS 8121.91 7373.7 2001.2 2049.8 7542.11 7554, -29854.6 7318.7 196.3 33205.4 184.5 180.9 PASS 8149.02 7400.0 2005.6 2054.7 7556.8 7568.8 29854.5 7318.81 196.3 33210.9 184.6 180.81 A POSITIONAL UNCERTAINTY - Offset Wellbore: KLU#5 Offset Wellpath: KLU#5 Slot Surface Uncertainty @1SD Horizontal .000ft Vertical 11.000ft Facility Surface Uncertainty @1SD Horizontal 120.000ft[vertical 13.000ft WELLPATH COMPOSITION - Offset Wellbore: KLU#5 Offset Wellpath: KLU#5 Start MD I End MD Positional Uncertainty Model Log Name/Comment Wellbore 2715.00 DnA Indicator - Inclination Only (ActualSurvey) KLU#5 <0-2775 inc only 2775.00 11827.00 BHI OnTrak (Standard) KLLI#5<2805-11827 OnTrak> KLU#5 OFFSET WELLPATH REFERENCE - Offset Wellbore: KLU#5 Offset Wellpath: KLU#5 MD Reference: Rig on KLU#5 (RT) Offset TVD & local coordinates use Reference Wellpath settings (See WELLPATH DATUM on page 9 of this report) Eliiose Start MD 11179.00ft 8a j�� FURIE Operating Alaska LLC DIRECTIONAL PROXIMITY A directional plat showing the well within 200' of the KLU A -2A, the KLU # 3 is included in the directional proximity section. The KLU # 3 is owned by Furie Operating Alaska, LLC, making Furie Operating Alaska, LLC the only affected applicant to wells in proximity. KLU # A2A1.70 ;1 AtiGC'� 4F, feu- V;LW Tm Redrill 1. MU KO assembly consisting of PDC bit, mud motor, MWD and triple combo LWD. 2. TIH and tag cement plug.?'. C►aS.AeE &_N 15 -IE-Si-CD -z 3ScC) Psi 3. Kick-off of plug at 2400'. '""vV-'%to -VVW PAC.—. -1 caAyS 4. Drill to 8149' MD/ 7400' TVD dropping angle to 14*. BHL X- 296,421. and Y- 2,538,094. S. POOH. Condition to run 9 5/8" casing or for logging run. 15. POOH and L/D BHA, LWD. 16. If additional MDT is wanted, rig up electric line unit. NOTE: Be prepared make a wiper with 12 '/a" hole opener, after logging. 9 -'Wig %i CAC_,"(- TUr�-..XM -M 2SCO PC - 17. Change rams to 9 5/8" casing rams. Test bonnet seals to 1000 psi. 18. Set test plug in wellhead. 19. RU casing running tools. 20. Run 9 5/8" 53.5 # L-80 BTC -RS casing as follows: a. 9 5/8" 53.5# L-80 BTC - RS float shoe b. 80' of 9 5/8" 53.5 ppf L-80 BTC - RS casing c. 9 5/8" 53.5# L-80 BTC float collar d. 5900' of 9 5/8" 53.5# L-80 BTC - RS casing. e. Cameron 9 5/8" mandrel casing hanger with running tool. f. 13 3/8" 68 ppf K-55HC BTC Landing joint Note: 9 5/8" float shoe is baker -locked to pin end of joint # Land coupling is Baker -locked on joint # 1. Baker lock joint # 1 coupling and joint # 2 pin. Joint # 2 coupling is baker -locked to joint and float collar is Baker locked in coupling. Do not Baker lock joint # 3 to float collar. Make up torque values should be carefully noted on the fust 6 -8 joints while making up casing to the base of the triangle. Use this established torque value on the remainder of the casing. If coupling face is between minus 1 thread turn (.2") and the base of the triangle, the make-up is satisfactory. Centralize first joint at 10' from shoe with stop ring. Centralize next 8 joints and then every other joint to 2265'. 21. Land casing in MBS system. 242 Rig up and circulate bottoms up with 25% wash-out factor or 391.5bbls minimum. Circulate until background gas is the same or below drilling levels. Stage pumps up to 6.5 - 7 bbls /minute. Watch for losses and reduce rate if losing volume. 23. Rig up and cement per cement program below: Spacer- 80 bbls Mud push II @ 11.5 ppg Lead 363 sacks Class G +.05 gal/sac,, k Antifoam + 0.5agl/sack Extender (wYIELD: WEIGHT: 13.5 mw- 1.71 Cu. Ft / sk Water: 8.146 gps: - Seawater Mix Fluid: 9.256 gps Tail 1575 sacks Class G + .2 gal/sack Antifoam + 0.12 gal/sack Dispersant + 0.3 gal/sack Fluid Loss + .06 gal/sack Alerator WEIGHT: 15.6 ppg 61 YIELD: 1.19 Cu. Ft / sk Water: 4.951 gps: Seawater Mix Fluid: 5.631 gps 24. Displace cement with f 570 BBLS Sea Water to top of float collar. Bump plug with 1000 psi over pump pressure. Use top and bottom plugs. Do not over displace cement by more than 3 bbls. Capacity of 9 5/8" shoe track is 5.6 bbls. 25. Bleed off pump pressure and make sure floats are holding. 26. ND cement head. 27. Back off running tool with 16 right hand rotations and lay running tool and landing joint down. ,,28. Install pack-off. 2 nn 29. PU 8 ''/z" bit. TIH to PBTD. M time cement in place. T2 Int 30. RU shoot nipple and Schlumberger wireline. �l -�1�," (✓ksi�(, 31. RIH and run CBL over. Make sure 24 hours have elapsed from cement in -M 3)SCO rSi JC4AVT- place until running CBL. msr.32. POH and rig down wireline.-* 33. ND BOP. NU dry hole tree. 34. Completion to be performed before rig leaves platform. AOGCC sundry is required before completing KLU # A-2 ,A C F U R I E KLU A2A Operating Alaska LLC DVD 0 _ i 1000 I 2000 i 2 H a W 0 3000 4000 ORE 6000 7000 8000 1 -- - - -- -- f i 9000 - -T- T r ir—rr—r—r r i rr r i 0 1 2 3 4 5 6 7 8 910 DAYS �KLU A2A DVD r KLU 1 #1 KLU A6 R edtail A6 SB8 A3 i16TBt1 1416k 2 f 2139k- 0 1796.0 1796.0 3443.0 un n YOU CAN DESIGN KOP FOR BEST RESULTS - KLU A2 REDACTED M. Guhl 1/12/2017 KLU A2 \ KLU A2 / CONDOR BHL r iV KLU A2 s "PLAN B" BHL ,y. r FURIE Operating Alaska LLC KLU A2A FORMATION DEPTHS: Geological Data from KLU # 3 Formathom Formation Tops ( TVD RT) MD RT Potential Sterling 2879' 3639' Gas Beluga 5082' 5758' Gas Property Lease: ADL 389197: Furie Operating Alaska has 100% ownership. FURIE Opera., Alaska LLC KLU # A 2A Mud MD Mud Weight Viscocity Plastic Viscosity Yield pH Fluid loss Point Caustic 0.2 ppb (9pH) Barazan D plus 1.0 ppb 2300- 10.0 8149 1 40-53 6-15 13-24 8.5-9.5 <12.0- HTHP System Formulation for 2350'- 8149': 2% KCL/BDF-499/ GEM GP. PRODUCT Water CONCENTRATION 0.905 bbl KCL 7 ppb Caustic 0.2 ppb (9pH) Barazan D plus 1.0 ppb Dextrid 1-2 ppb Pac L 1ppb BDF 499 4 ppb GEM GP 1.0 % bv volume Baracarb 5/25150 10 ppb 3.3 ppb of each Baritol Plus As needed Soltex As needed Baroid 41 As needed for 10.0 ppg Aldacide -G 0.1 ppb The KLU A -2A mud and cuttings will be discharged in accordance ADEC pemits for expF Zt wells. Furie will not ask for annular injection at a later date. I LV4�W� j0000--0-) FURIE Operating Alaska LLC CASING DESIGN FACTORS - KLUA2A NOTE: 13 3/8" is already in place on sidetrack. Csg Collap Burst Burst Tensile Tensile SF SF SF se Connection Connection Collapse Burst Tension 13 2670 5380 5380 1661M 1693000 2.75 4.50 10.0 3/8" 9 5/8" 6620 7930 7930 1244M 1329000 2.39 2.68 2.85 13 3/8" 72ppf N-80 BTC set at 2300'MD/ 1985' TVD Collapse based on mud weight at casing point. 9.4 ppg x .052 x 1985 = 970.3 psi; DF = collapse rating/ collapse pressure = 2670/970.3 = 2.75 Calculated Burst is based on Frac Gradient at 13 3/8" shoe - gas gradient (13.5 ppg x.05 2 x 1985') - (.1psi/ft x 1985') _ 1195 psi - 199 psi = 1210 psi; Drilling MASP DF = Burst/MASP = 5380/1195 = 4.50 Tension Strength Calculation 72 ppf x 2300' = 165,600# DF = pipe body yield/ calculated tensile DF = 1661000/ 165600 = 10.0 Casing Test Pressure - 2700 psi. ✓ i-5--tm (o/Zplw 50% of 5380 = 2690 ((MW - PP backup)x .052 x TVD depth)) +test pressure = (9.4 -9.0) x .052 x1900 + 2700 = 2740 psi 9 5/8" 53.5 ppf L-80 BTC - RS at 8149' MD/ 7400' TVD Collapse based on mud weight at casing point. 10.0 ppg x .052 x 7400' = 3848 psi; DF = collapse rating/ collapse pressure = 6620/3848= 1.72 Calculated Burst is based on pore pressure - gas gradient (9.6 ppg x.05 2 x 7400') - (.1psi/ft x 7400') _ 3694 psi - 740 psi = 2954 psi; Production MASP DF = Burst/MASP = 7930/2954 = 2.68 DF Calculated Tension in air 53.5ppf x 8149' = 435,971.5# DF = pipe body yield/ calculated tensile = 1244000/435,971.5 = 2.85 joos�)FURIE Operating Alaska LLC KICK TOLERANCE CALCULATION Possible Formation Pressure - 10.1 ppg (.5 ppg over anticipated) Planned TD mud weight -10.1 ppg Surface Casing Shoe - 2265' MD/ 1995' TVD LOT @ Surface Casing shoe - 13.5 ppg EMW ►/ lA ac-+ 612,d%, Hole Depth - 8149' MD/ 7400' TVD Bit Size - 12 1/4" Bha Length -151' Average OD of BHA - 8" Drill Pipe OD - 5" Influx Gradient =.I psi/ft Kick Intensity =.5 ppg - MASCIP - Maximum Allowable shut-in casing Pressure (Shoe LOT/ Frac - MW) x.052 x TVD of shoe (13.5 ppg-10.1ppg) x.052 x 1985'= 351 psi Height influx: ( MASICP-((Kick Intensityx.052x tvd of well) ))/ (Current MW x .052) -Gas Gradient (( 351-(.5 x .052x 7400))/ ((10.1 x.052) -.1 psi/ft)= 374' Influx volume: Annular capacity between the hole and pipe BHA annular capacity - ((12.25"x12.25") - (8x8)) /1029.4 =.0836 bbl/ ft - Drill Pipe annular capacity: ((12.25"x12.25") - (5x5)) /1029.4 = .0836 bbl/ ft - Influx volume: Influx Volume at shoe = Height / Pipe Cap. - 374'x.1215 bbl/ft = 45 bbl LOT @ shoe = 13.5 ppg x.052 x 1995'= 1400 psi Formation pressure @ TD = 10.1 ppg x.052 x 7400' TVD = 3886 psi Using Boyle's Law - P1V1= P2V2: to get bottom hole conditions. 45 bbls x 1400 psi= 3786psiV2 V2 = 16.2 bbls The smaller is the max kick before breaking down the shoe - 16.2 bbls. Proposed length of inner barrel to Flowline i 25.00 ` i - ft Stick in ' I RKB Bottom section Bellnipple ------------------------------- B/NIPPLE LENGTH i 12. i TOP of ANNULAR Flange ; ANNULA , Shaffer 13.5/8x5K top studded BX160 4" Bottom flange 13.5/8x5K BX 160 i i 13 518" BX159 10m by 13 518" BX160SEn DSA _A i - _ A Cameron Type U 13.518 x 10K 2718"x6' � VBR --------- -------► , Bind Sheer i i Rams --- t] i Kill lige--'"� Choke Line ` Cameron Type U 13.5/8x10K i ISR Shear Rams cw booster 3 Cameron Type U 13.5/8 x 10K 2718"x6" VBR �--�-- _._..�....._...... Flanoes13.3/8x10KBX169 --- i Bf from standpipe overboard #16 Rflp* #14 VOLUME TANK RIG RANDOLPH YOST SANDTRAP 1 : 50 BBLS DEGASSER PIT: 70 BBLS DSR: 35 BBLS DST: 35 BBLS CLEAN PIT: 38 BBLS 0.9 BBLSIINCH 0.45 BBLS/INCH 0.45 BBLS/INCH 0,48BBLS/INCH 0.35 BBLSICM 0.175 BBLS/CM 0.175 BBLSICM 0.18 BBLSICM 3 BBLSIINCH 1.2 BBLS/CM 'ANK 2: 335 BBLS 2.8 BBLSIINCH 1.1 BBLSICM 1.2 BBLSIINCH 0.5 BBLSICM LUG PIT: 45 BBLS 375 BBLSIINCH 15 BBLSICM ANK 3: 335 BBLS 2.8 BBLSIINCH 1.1 BBLS/CM C% FURIE Operating Alaska LLC :366 BBLS 3 BBLSIINCH 1.2 BBLSICM 45.56" Note: Dimensional information reflected on this drawin are estimated measurements only. 4-1/16" 5,000# 4-1/16" 5,0 04 11.38" 86.22" 4-1/16" 5,000# 4-1/16" 5,000#x— Baker C" " O 3-1/8" 5,000# Adapter Spool 51.16" 4-1/16" 5,000# 4-1/16" 5,000# 11" 13-5/8" 5,000# 2-1/16" 5,000# 22.38" 13-5/8" 5,000# 2-1/16" 5,000# 23.50 " e 6.19" 20" 13-3/8 " 9-5/8 " 4-1/2" Furie Operatin 2 Sta e MBS System 4tCAMERON w/4-1/16" 5K Completion KLU 1A & 2A "ate: Jeanette oie 6-28-16k p # SO# 3388399 Well: KLU A -2A —D ataput Name: FURIE <=put Mud Weight (ppg) 10.10 <_= Data Input Weak point or LOT - Measured depth (ft) 1,995' <-- Data Input Weak point or LOT True vertical depth (ft) 2,265' <-- Data Input Weak point or LOT - Hole angle (deg) 48.00 <-- Data Input Weak point or LOT - Hole size (in) 16.000" <-- Data Input Weak point pressure or LOT - EMW (ppg) 13.50 <-- Data Input Zone of interest - Measured depth (ft) 9,800' <-- Data Input Zone of interest - True vertical depth (ft) 7,400' <-- Data Input Zone of interest - Hole angle (deg) 14.00 <-- Data Input Zone of interest - Hole size (in) 12.250" <-- Data Input Zone of interest - Pore pressure EMW (ppg) 10.60 <_- Data Input Gas gradient (psi/ft) 0.10 <-= Data Input Bottom hole assembly OD (in) 8.0" <-- Data Input Bottom hole assembly length (ft) 151' <-- Data Input Drill pipe OD (in) 5.000" <-- Data Input BHA annular vol. @ zone of interest (bbl/ft) 0.0836 DP annular vol. @ zone of interest (bbl/ft) 0.1215 DP annular vol. @ weak point (bbl/ft) 0.2244 Additional safety margin (psi) 1 0.00 <-- Data Input Weak point pressure (psi): Plo 1,590 psi Weak point pressure - Safety margin: Pmax Pmax EMW 1,590 psi 13.50 ppg Max anticipated formation pressure (psi): Pf 4,079 psi Weak Pt to Zone of Interest distance (TVD ft): OH {TVD) 5,135' Weak Pt to Zone of interest distance (MD ft): OH {MD) 7,805' Maximum influx height at the bit (TVD ft): H (TVD) 489' Maximum influx height at the bit (MD ft): H (MD) 504' Calc. volume of (H) around BHA: Calc. volume of (H) around drill pipe: Calc. volume that H equals @ initial shut in: V1bha V1 dp V1 12.6 bbl 42.9 bbl 55.5 bbl Calc. vol. that H equals @ weak point (MD ft): VW p 164.1 bbl Calc. volume of Vwp @ initial shut in: V2 64.0 bbl Kick Tolerance: V1 55.5 bbl NOTE: M Quick 7/7/2016 e -o*' FURIE Casing Pressure / Formation Leakoff Test Report Operating Alaska LLC TYPE IN YELLOW ARES ONLY Well Data Calculations Date: 28 -Jun -16 Well: KLU # A-2 Casing: 13 3/8" Select Leakoff Pressure=> 1450 psi Completed by: James Pritchard / Dale Munger Rig: Randolph Yost Test Mud Wt.: 9.2 ppg Shoe Frac Grad: 113.54 ppg Title: Co. Reps. Casing Test Shoe Depth (TVD): 1995 ft Leak Off Test Shut In Pressure Volume bbls(psi) Pressure Volume bbls(psi) Pressure Time minutes(psi) Pressure 0.00 0 0.00 0 0 400 0.50 264 0.25 202 1 370 1.00 650 0.50 237 2 356 1.50 1050 0.75 350 3 333 2.00 1529 1.00 450 4 323 2.50 1945 2.50 5 1 310 3.00 2403 3.00 3.50 2800 3.50 INPUT REQUIRED INPUT REQUIRED Casing Test Data FIT TMid- Bled back .5 bbls Final Vol Final Press Final Vol 3.50 2800 1.00 Bettis, Patricia K (DOA) From: David McCraine <d.mccraine@furiealaska.com> Sent: Thursday, July 07, 2016 12:05 PM To: Bettis, Patricia K (DOA) Cc: Quick, Michael J (DOA) Subject: Re: KLU A -2A Permit to Drill Application (PTD 216-086) Attachments: KLU#A2A Mud.docx My mistake. We will dispose of the mud and cuttings in accordance with the ADEC permit for development wells.. Furie is required to have zero discharge. Attached is the corrected mud statement. Thanks. Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Patricia Bettis <patricia.bettis@alaska.gov> Date: Thursday, July 7, 2016 at 2:53 PM To: Dave McCraine <d.mccraine@furiealaska.com> Cc: Michael Quick <michael.guick@alaska.gov> Subject: KLU A -2A Permit to Drill Application (PTD 216-086) Good afternoon David, In the application, Furie states that the KLU A -2A mud and cuttings will be discharged in accordance with ADEC permits for exploratory wells. Please provide a general discussion of how the operator plans to dispose of drilling mud and cuttings as KLU A -2A is a development well. 20 AAC 25.005(c)(14). Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7th Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 1 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 Patricia Bettis at (907) 793-1238 or patricia.bettis(@alaska.gov. Bettis, Patricia K (DOA) From: David McCraine <d.mccraine@furiealaska.com> Sent: Thursday, July 07, 2016 11:03 AM To: Bettis, Patricia K (DOA) Subject: Re: KLU A -2A: Permit to Drill Application (PTD 216-086) Attachments: KLU#A-2_Condor_S lot B_Ver#16 Sidetrack WellPath Georpt.xlsx Attached is the well path. Anything else needed, let me know. Thanks Dave McCraine Furie Operating Alaska -Lafayette Drilling Engineer 337-981-0270 Office 337-501-6854 Cell From: Patricia Bettis <patricia.bettis@alasl<a.gov> Date: Thursday, July 7, 2016 at 1:47 PM To: Dave McCraine <d.mccraine furiealaska.com> Subject: KLU A -2A: Permit to Drill Application (PTD 216-086) Good morning David, Please send the Planned Wellpath Geographic Report for the proposed KLU A -2A in an excel spread sheet. As submitted, the information is too small to read. Thank you, Patricia Patricia Bettis Senior Petroleum Geologist Alaska Oil and Gas Conservation Commission 333 West 7t" Avenue Anchorage, AK 99501 Tel: (907) 793-1238 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 Patricia Bettis at (907) 793-1238 or patricia.bettis@alaska.gov. TRANSMITTAL LETTER CHECKLIST WELL NAME: 1{ k(.k A PTD: 911 _ Co /Development _ Service _ Exploratory Stratigraphic Test _ Non -Conventional FIELD: x 1+ i POOL: 9 1 Check Box for Appropriate Letter / Paragraphs to be Includedi Transmittal Letter CHECK OPTIONS TEXT FOR APPROVAL LETTER MULTI The permit is for a new wellbore segment of existing well Permit LATERAL No. , API No. 50- - - - (If last two digits Production should continue to be reported as a function of the original in API number are API number stated above. between 60-69) In accordance with 20 AAC 25.005(f), all records, data and logs acquired for the pilot hole must be clearly differentiated in both well Pilot Hole name ( PH) and API number (50- - - -� from records, data and logs acquired for well (name onpermit). The permit is approved subject to full compliance with 20 AAC 25.055. Approval to produce/inject is contingent upon issuance of a conservation Spacing Exception order approving a spacing exception. (Company Name) Operator assumes the liability of any protest to the spacing exception that may occur. All dry ditch sample sets submitted to the AOGCC must be in no greater Dry Ditch Sample than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Please note the following special condition of this permit: production or production testing of coal bed methane is not allowed for Non -Conventional (name of well) until after (Company Name) has designed and Well implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the AOGCC to obtain advance approval of such water well testing program. Regulation 20 AAC 25.071(a) authorizes the AOGCC to specify types of well logs to be run. In addition to the well logging program proposed by (Company Name) in the attached application, the following well logs are also required for this well: Well Logging Requirements Per Statute AS 31.05.030(d)(2)(B) and Regulation 20 AAC 25.071, composite curves for well logs run must be submitted to the AOGCC within 90 days after completion, suspension or abandonment of this well. Revised 2/2015 WELL PERMIT CHECKLIST Field & Pool KITCHEN LIGHTS, UNDEFINED GAS - 470500 _ Well Name: _KLU A -2A Program DEV Well bore seg ❑ PTD#:2160860 Company FURIE OPERATING ALASKA LLC Initial Class/Type DEV/PEND GeoArea 820 Unit 11120 On/Off Shore Off _ Annular Disposal ❑ Administration 17 Nonconven_ gas conforms to AS31,05.030(y1.A),(y2.A-D) - - - - - - - - - - - - - - NA_ - - - _ _ _ - - - - - - _ - - - - _ _ _ Appr Date PKB 7/7/2016 Engineering Appr Date MJQ 7/8/2016 Geology Appr Date PKB 7/7/2016 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 139 fee attached - - - - - - - - - -Permit- ------------------- ------ -- - --------------- NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - . Lease number appropriate_ - - - - - - - - - _ . - - - Yes - - - - - - ADL 0389197, entire wellbore- - - - - - - - - -- - - - - - - - Unique well name and number - - - - - - - - - - - - - - - - Yes - - - - - - - KLU A -2A - - - - - - - - - - - - - - - - - - - - - - - - - - Well located in_a_defined-pool - - - - - - - - - - - - - - - - No_ - - - - - - - Undefined gas pool - Well located proper distance from drilling unit -boundary ------------ - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - Well located proper distance from other wells_ _ - - - - - - - - - - - - - - . - - - No- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Sufficientacreage_avail_ablein_dril_ling unit - -- - - - --- ---- - - - - - - - - _ _ _ _ _ _ _ _ _ No_ - - - - -- -- - _ - - - - - If_deviated,is_wellboreplat_included--------------------------------- - Yes--- --------------------------- ----------------------------------------- Operator only affected party- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes _ - _ - _ - - Wellbore -will be more than 1,500' from an external property line where ownership or landownership changes._ Operator has_appropriatebond inforce ------- ----------------------- Yes -------------- ------------- ----------- --------- ------------------- -Permit can be issued without conservation order- - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - . - - - - - - _ _ - - - - - - - _ _ - - - - - - - - - - - - - . - -- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Permitcanbeissuedwithoutadministrativ_e-approval_________________________ Yes. _-.--______-_________________-_____.__________________________________ Can permit be approved before 15 -day - wait ------------- -- - - - _ - - Yes- - - - - - - - - - -- - -- - - _ _ _ - - - - - . - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - - - - - - Well located within area and -strata authorized by Injection Order # (put 10# in_ corn ments)_(For NA_ All wells -within -1/4 -mile area of review identified (For service well only)- - - - - - - - - - - - - - NA - -- --------------------- - - - - _ - - - - - - .. - - - - - - - -- - - - - - - - - - - - - - - - - - Pre -produced injector; duration of pre production less than 3 months_ (For -service well only) - N_A- - - - - - - - - - - - - - - - - Conductor string- provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - _ - - - - - NA_ - - - - - - - No Conductor_- Waiver granted on original _w_ell A-_2 -- - - - - - - - - - - - - - - - - - - - - - - Surface casing -protects all -known USDWs - - - - - _ - - _ - NA_ _ - _ - - - Casing set on original well A-2- _ _ _ _ _ _ _ _ CMT -vol_ adequate to circulate_on conductor & surl.csg - - - - - - - - - . - - NA_ - - - - - - - Casing set -on original well A-2 - - - - _ - - - - - - _ _ - -- - - - - - - - - - - - - - - - - - CMT vol_ adequate to tie -in -long string to surf csg- - - - - - Yes - - - - - - TOC 509 above surface casing shoe - - - - - - - - - - - - - - - - - _CMT will cover all known -productive horizons- - - - - - - - - - Yes - - ---- - - - -- -- - - - - - - - - -- - - - - - - - - - - Casing designs adequate for C,_T, B &-permafr_ost_ - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Adequate -tankage or reserve pit - - - - - Yes - - - - - - Rig has steel pits_ - - - - - - - - - - - - If_a_re-drill_, has _a10-403 for abandonment been approved- ----- -------- Yes___ Sundry.316-356---------- ____---- _---- _________________ Adequate wellbore separation -proposed _ - - - - - Yes Proximity and Risk analysis_ completed - _ _ If_diverter required, does it meet regulations- - - - - - - - - - . NA_ _ _ _ _ _ _ - wellhead in place- BOP to be used _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ D_ril_ling fluid. program schematic_& equip list adequate_ - - - - - - - Yes Max Formation Pressure is a 9.6-ppg EMW, plan is -fora_ 1.0Appg MW BOPEs,_do they meet regulation ------------------ Yes--- --- ------------ -- ----- BOPE_press rating appropriate; test to_(put psig in comments)_ - - - - - - - - - - Yes - - - - - - - MASP is 2954 psi, BOPE test to 3500 psi - - - - - - - - - - - - Choke -manifold complies w/API_RP-53 (May 84)_ _ _ _ _ Yes - -- - - - - - - - - - - - - - Work will occur without operation shutdown_ - - - - - - . -_ _ Yes - - - - - - - - - - - - - Is presence of H2S gas probable - - - - - - No_ - - - - - - H2S detection_required - - - - - - - - - - - - - - - - - - - - Mechanical_condition of wells within AOR verified (For service well only) - - - - - - - - - - - - - - NA. - _ - - - _ _ _ _ _ _ _ - - .. - _ - - - _ - - - - - _ _ Permit_can be issued w/o hydrogen_ sulfide measures _ _ _ _ _ _ _ No_ _ H2S measures required, - - - - - - - - - - - - - - - - D_ata_presented on potential overpressure zones - - - - - - - - - - - - - - Yes - - - - - Expected r_eservoirpressure is 9.62 ppg EMW; sidetrack will be drilled using 10.0 ppg mud. - - - - - - Seismic_analysis of shallow gas -zones ------ - - - N_A------- I. -- - - - I - - - - - - - - - - -- - -- - - - - - - - - - - - - - Seabedconditionsurvey_(ifoff_-shore) - - - NA- - - - - - - - - - - - - - - - - - - - I - - - - - - - - - - - .. - - -- - - - - - - - - - - - - - - Contact name/phone for weekly -progress reports [exploratory only] - - - - - - - _ - - - - - N_A-------- Development well to be drilled from Julius R monopod----------- - - - - - - - - - - - - - - - - - Geologic Engineering Public Commissioner: Date: COMM 'ssioner: Date Commissioner Date KITCHEN LIGHTS UNIT A-2A Exploration Well Cook Inlet, Alaska ADL # 389197 Tract 9 1521.6’ FNL & 2807.6’ FWL of Section 10, T10N/R11W, Seward Meridian X= 290840.19’, Y= 2529041.92’ FINAL WELL REPORT MUDLOGGING DATA Provided by: Approved by: Tony Cosenza Compiled by: Allen Odegaard Dave Deatherage James Foradas Distribution: 7/26/2016 T.D. Date: 7/13/2016 Kitchen Lights Unit A-2A 1 TABLE OF CONTENTS 1 MUDLOGGING EQUIPMENT & CREW ................................................................................................ 2 1.1 Equipment Summary ...................................................................................................................... 2 1.2 Crew ................................................................................................................................................ 2 2 WELL DETAILS ..................................................................................................................................... 3 2.1 Well Summary ................................................................................................................................ 3 2.2 Hole Data ........................................................................................................................................ 4 2.3 Daily Activity Summary ................................................................................................................... 5 3 KLU A-2A GEOLOGICAL DATA ............................................................................................................ 6 3.1 KLU A-2A Lithostratigraphy ............................................................................................................ 6 3.2 KLU A-2A Mudlog Summary ........................................................................................................... 6 3.2.1 Surface to the top of the Sterling Formation ............................................................................ 6 3.2.2 Top of the Sterling to the Top of the Beluga ............................................................................ 7 3.2.3 Top of the Beluga to TD .......................................................................................................... 8 3.3 Lithology Descriptions ................................................................................................................... 10 3.3.1 Top of Sterling ....................................................................................................................... 15 3.3.2 Top of Beluga ........................................................................................................................ 19 4 DRILLING DATA .................................................................................................................................. 23 4.1 KLU A-2A Connection Gases ....................................................................................................... 23 4.2 KLU A-2A Trip (Wiper) Gases ...................................................................................................... 23 4.3 Flowback/Connection Gas Chart .................................................................................................. 24 4.4 KLU A-2A Sampling Program / Sample Dispatch ......................................................................... 24 4.5 Survey Data .................................................................................................................................. 25 4.6 Bit Record ..................................................................................................................................... 28 4.7 Dilling Fluid Record ....................................................................................................................... 28 4.1 Drilling Progress Chart .................................................................................................................. 29 5 DAILY REPORTS ................................................................................................................................ 30 Enclosures: 2”/100’ Formation Log (MD/TVD) 2”/100’ LWD Combo Log (MD/TVD) 2”/100’ Gas Ratio Log (MD/TVD) 2”/100’ Drilling Dynamics Log (MD/TVD) Final Data CD Kitchen Lights Unit A-2A 2 1 MUDLOGGING EQUIPMENT & CREW 1.1 Equipment Summary Parameter Equipment Type / Position Total Downtime Comments Ditch gas QGM Agitator gas trap Flame ionization total gas & chromatography. 0 Hook Load / Weight on bit RW Transducer 0 Mud Flow In RW Calculation 0 Mud Flow Out RW Flow Paddle 0 Mudlogging unit computer system HP Compaq Pentium 4 (x2, DML & Rigwatch) 0 Data collection system RW K-Box data collection & distribution center 0 Pit Volumes, Pit Gain/Loss RW Vega sonic pit sensors 0 Pump Pressure RW Pressure transducer 0 Pump stroke counters RW Proximity switch 0 Rate of penetration RW Calculation/Draw works encoder 0 Topdrive RPM RW RPM sensor 3 hrs Spud before rigged up Top DriveTorque RW Torque sensor 3 hrs Spud before rigged up 1.2 Crew Unit Type : Arctic Steel Unit Number : ML067 Mudloggers Years *1 Days *2 Mudloggers Years Days Technician Days Allen Odegaard 19 11 Jessie Becerra 6 7 David Deatherage 34 7 James Foradas 8 11 *1 Years experience as Mudlogger *2 Days at wellsite between spud and total depth of well Kitchen Lights Unit A-2A 3 2 WELL DETAILS 2.1 Well Summary Operator FURIE Operating Alaska, LLC Well Name KLU A-2A Field Kitchen Light Unit County Kenai Peninsula Borough State Alaska Company Representative James Pritchard, Isaiah Del Toro Location: Surface Coordinates NAD 27 X = 298,000 Y = 2,540,009 AK Zone #4 60o 56’ 12.144” Latitude, 151o 09’ 23.013” Longitude Water Depth 107’ MLLW Rig Floor Elevation 118’ RKB To MLLW Sea Level Classification Gas API # 50-733-20655-01-00 Permit # 216-055 Contractor Advanced Drilling Solutions Rig Name/Type Randolph Yost / Jackup Triple Topdrive Spud Date 7/9/2016 (Kick-0ff) Total Depth Date 7/13/2016 Total Depth 8160’ MD /7301’ TVD Days Drilling 5 TD Formation Beluga Primary Target Depth 4018 Sand (Sterling) 5535’ MD / 4103’ TVD Secondary Target Depth Beluga MDT 4973A 6960’ MD / 5156’ TVD Completion Status / Date LWD-MWD Services Baker Hughes Inteq Directional Drilling Baker Hughes Inteq Drilling Fluids Service Halliburton | Baroid Wireline Logging Service NONE Cementing Service Schlumberger Rig Instrumentation CANRIG Drilling Technology Ltd - RigWatch Kitchen Lights Unit A-2A 4 2.2 Hole Data Hole Section Maximum Depth TD Formation Mud Weight (ppg) Dev. (oinc) Coring Casing/ Liner Shoe Depth LOT (ppg) MD (ft) TVD (ft) MD (ft) TVD (ft) 12.25” / 17.5” 2,284’ 2,007’ Surface 9.1 48.5 No 13 3/8” 2,265’ 1,994’ 13.5 12.25” 8,160’ 7,301.5’ Beluga 10.3 28.0 No 9 5/8” 8,122’ 7,268’ — Additional Comments KLU A-2 Drilled to 7038’ MD. Decision made to sidetrack well 7-4-2016. 4 cement plugs set. Sidetrack Kick-Off Point at 2278’ MD (Top Kick-Off plug). Kick-Off 13:40hours 7-9-2016 Kitchen Lights Unit A-2A 5 2.3 Daily Activity Summary 7/8/16 RIH to 4892’; Tag cement plug; Pull to 3255’; Circulate; Pump/set cement Kick-Off plug; POOH; Make up, RIH test plug; Test BOPE; Pull. Lay down test plug. 7/9/16 2278’-3076’ (798’) RIH 3 ½” drill pipe from derrick; Lay down 3 ½” drill pipe. Make up Mudmotor, bit, MWD and LWD BHA; Test tools; RIH to 2200’; Slip and cut drill line; Tag cement at 2278’; Drill out cement and formation; Drill to 3076’ 7/10/16 3076’-4448’ (1372’’) Drill 3076’ to 3355’; Circulate; Wipe hole to shoe; Drill 3355’-4448’. 7/11/16 4448’-5867’ (1419’) Drill 4448’-5616’; Circulate/condition gas cut mud; Drill 5616’-5867’. 7/12/16 5867’-7327’ (1460’) Drill 5867’-6156’; Repair pump #1; Drill 6156’-7327’. 7/13/16 7327’-8160’ (833’) Drill 7327’-8160’ TD; Circulate clean; Backream 8160’-7888’; Pull to 7600’; Tight; Backream 7600’-7322’. 7/14/16 Backream 7600’-4331'. 7/15/16 Backream 4331'-2298'; Circulate clean; Pull out of hole; Download LWD; Standback DP and HWDP; Lay down LWD tools; break down bit; Makeup of 12 1/4" Wiper Assembly. 7/16/16 Run in hole with 12 1/4" Wiper assembly; Circ. clean; POOH; Lay down Wiper Assembly; Standback DP and HWDP; Changeout rams; R/U testing assembly and test rams (good test); Rig up to run casing. 7/17/16 Prejob safety meeting to run casing; Run 9 5/8" casing; Landed casing at 8122'; Attempting to circulate. Kitchen Lights Unit A-2A 6 3 KLU A-2A GEOLOGICAL DATA 3.1 KLU A-2A Lithostratigraphy KLU A-2A FORMATION Prognosed (KLU A-2) Geologist Picks MD (ft) TVD (ft) SSTVD (ft) MD (ft) TVD (ft) SSTVD (ft) Sterling 3639’ 2879’ -2761 3599’ 3023’ -2905’ Beluga 6959’ 5054’ -4936 5838’ 5156’ -5038’ TD 9805’ 7203’ -7085’ 8160’ 7301’ -7183’ 3.2 KLU A-2A Mudlog Summary 3.2.1 Surface to the top of the Sterling Formation 291’ to 3,599’ MD (391’ to 3,023’ TVD) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 957 0.7 165.3 65 0 5.7 This Section was comprised mainly of massive unconsolidated sand, conglomeratic sand and occasionally interbedded with tuffaceous claystone. No notable hydrocarbon shows were observed through this interval. The sands were typically medium gray to dark medium gray with occasional blue, brown or olive hues. Dominated by clear, translucent and opaque quartz with dark gray to black lithics abundant as well. Unconsolidated, upper coarse to lower medium to lower fine grained. Grains ranging up to 14mm were not uncommon in the top section of the interval, decreasing in size near the base. Sorting ranged from poorly sorted in the upper hole section to moderate down through to the top of the Sterling. Sub angular to angular to sub rounded and occasionally well rounded. Overall, moderate to poor sphericity with scattered good sphericity. Micas, pyrite, greenstone, carbonaceous material, volcanic ash and siltstone were all present but not abundant. The tuffaceous claystones are typically light to dark medium gray with brown, olive and occasionally reddish hues. Lumpy to mushy consistency with a pulverulent to malleable to earthy fracture. Typically pulverized to nodular to rounded cuttings habit. Waxy to earthy to dull luster and silty to smooth to sometimes gritty texture. Trace interbedded with thin sands. No notable gas peaks. Kitchen Lights Unit A-2A 7 3.2.2 Top of the Sterling to the Top of the Beluga 3,599’ to 5,838’ MD (3,023’ to 5,156’ TVD) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 333.0 0.3 172.9 2421 0.1 185.9 This section was comprised of tuffaceous sandstone, sand, tuffaceous siltstone and tuffaceous claystone with occasional coal beds. The sands and tuffaceous sands were typically medium gray to yellowish gray to off white and ranged from unconsolidated to soft and crumbly to trace firm. Predominantly fine to medium grained but ranged from granule to very fine. Typically sub rounded to angular with occasional well rounded grains and moderate to poor sorting. Typically grain supported with pale white ashy matrix. Dominantly quartz with feldspars and dark lithics common. Other accessory minerals include: Rhyolite, micas, pyrite, carbonaceous sediment/shale and dark mafics. The tuffaceous siltstones and claystone in this section are typically light medium gray to medium gray with pale yellow, brown or blue hues. Occasional dark brown siltstone clasts lacking tuffaceous material. Typically soft to crumbly to firm crumbly and occasionally pulverulent. Smooth to very fine abrasive texture and very to moderately expansive. Occasional carbonaceous banding throughout, occasionally deformed to trace sediment in matrix. Non calcareous. The coals in this section are typically black to very dark brown. Firm, crumbly to dominantly crunchy. Typically have a smooth texture with a sub hackly fracture. Commonly matte to slightly shiny luster to occasionally micro sparkly. Noted Zones of Interest Zone Name Top Depth (MD) Bottom Depth (MD) Top Depth (TVD) MDT3732 4433 4462 3807 MDT3800 4513 4550 3883 MDT3864 4616 4645 3981 MDT4018 4715 4829 4075 MDT4172 4869 4924 4223 MDT4669 5385 5443 4721 MDT4725 5458 5531 4792 Gas Peaks Depth TG C1 C2 C3 iC4 nC4 iC5 nC5 5272 618 107043 5292 771 129735 5398 1650 288160 133 5471 2421 412539 350 5479 2225 383732 420 5540 563 100459 5558 576 100775 5573 606 106001 5629 901 137044 5655 1091 178626 5684 1189 206699 5743 2365 356573 5775 1527 240671 30 5827 587 82627 Kitchen Lights Unit A-2A 8 3.2.3 Top of the Beluga to TD 5,838’ to 8,160’ MD (5,156’ to 7,301’ TVD) Drill Rate (ft/hr) Total Gas (units) Maximum Minimum Average Maximum Minimum Average 209.3 6.5 90.1 2799 14 280.7 This section was comprised of tuffaceous sandstone, sand, tuffaceous siltstone and tuffaceous claystone with occasional coal beds and carbonaceous shale. The sands and tuffaceous sands were typically medium gray to yellowish gray to off white and ranged from unconsolidated to soft and crum bly to trace firm. Predominantly fine to medium grained but ranged from granule to very fine. Typically sub rounded to angular with occasional well rounded grains and moderate to poor sorting. Typically grain supported with pale white ashy matrix. Dominantly quartz with feldspars and dark lithics common. Other accessory minerals include: Rhyolite, micas, pyrite, carbonaceous material/organic debris/carbonaceous shale and dark mafics. There was typically good porosity and permeability. Often interbedded with coals. The tuffaceous siltstones and claystone in this section are typically light medium gray to medium gray with pale yellow, brown or blue hues. Occasional dark brown siltstone clasts lacking tuffaceous material. Typically soft to crumbly to firm crumbly and occasionally pulverulent. Smooth to very fine abrasive texture and very to moderately expansive. Occasional carbonaceous banding throughout, occasionally deformed to trace sediment in matrix. Non calcareous. Often siltstones would grade to very fine grained sandstone/tuffaceous sandstone.. The coals in this section are typically black to very dark brown. Firm, crumbly to dominantly crunchy. Typically have a smooth texture with a sub hackly fracture. Commonly matte to slightly shiny luster to occasionally micro sparkly from trace pyrite. The carbonaceous shales were typically medium to dark brown, brownish black; firm crumbly, occasionally flakey; poor incipient fissility due to common high silt and organic debris content; non- calcareous; variable silt and organics; associated with coal, medium yellow brown siltstone; irregular laminations wavy, semi parallel; occasional silty, ash lentils, discontinuous lenses. Noted Zones of Interest Zone Name Top Depth (MD) Bottom Depth (MD) Top Depth (TVD) MDT5402 6180 6330 5480 MDT5597 6484 6540 5767 MDT5630 6547 6594 5827 MDT5700 6627 6697 6124 MDT5940/5990 6866 6913 6124 MDT6320 7159 7247 6396 MDT6570 7452 7573 6666 MDT6960 7899 7969 7070 Kitchen Lights Unit A-2A 9 Gas Peaks Depth TG C1 C2 C3 iC4 nC4 iC5 nC5 6017 1068 165696 87 6159 1183 179683 6187 2799 175570 589 6264 2646 217679 381 6308 706 58226 34 6383 1060 72317 435 6422 1471 123111 993 6493 640 52538 6523 670 54948 6580 766 62250 6666 2537 235240 1105 6880 2605 240813 427 6909 602 50843 7006 799 67646 7171 645 51152 7187 945 77464 42 7258 624 46894 7282 961 73550 7439 636 50391 7446 706 59895 7480 719 58088 7525 1125 89489 7706 717 107892 36 Kitchen Lights Unit A-2A 10 3.3 Lithology Descriptions Sand (300’ - 400’) = clear to translucent dominant, with slight moderate greenish yellow hues, light dusky yellow hues, light moderate orange pink hues, and very light gray colors; quartz dominant micas, and metalic black lithics; very fine to lower coarse grain size; poorly to fair sorting; angular to subrounded angularity; very low to moderate sphericity; unconsolidated sands; massive to large bedding structure; no hydrocarbon indictors in bulk sample. Sand (400’ - 500’) = medium bluish gray to medium gray to dark gray with dark greenish gray hues; unconsolidated; upper medium to lower coarse to upper coarse with some lower medium and trace fines; poor to very poor sorting at the top of the interval coarsening up down through and becoming slightly more uniform; angular to sub angular becoming sub rounded near the bottom of the interval; sub spherical to spherical to occasional sub prismoidal; trace disaggregated quartz grains near the top ranging up to 4mm in size; overall dominated by quartz and gray to black lithics; minor amounts of biotite, pyrite, clay, carbonaceous shale and tuffaceous material. Sand (505’ - 570’) = clear to translucent dominant with light gray hues, greenish gray hues, and grayish green yellow hues colors; quartz dominant with black lithics, and small amounts of tuffaceous sandstone framework; upper fine to very coarse grain sizes; fair to poorly sorting; very angular to subangular angularity; very low to low sphericity; unconsolidated sand and few consolidate sandstone with firm friable hardness; massive bedding structure; micas accessory minerals; no HCL reaction in bulk sample. Sand (580’ - 655’) = clear to light milky white with light gray hues, light olive green hues, and greenish yellow hues colors; quartz dominant with blacks lithics, micas, reddish to milky yellow tuffaceous materials framework; pebble to coarse grain sizes; very poor to poor sorting; very angular to subrounded angularity; low to moderate sphericity; unconsolidated sands with few firm friable sandstones hardness; massive bedding structure; very weak HCL reaction in bulk sample; no hydrocarbon indictors in sample. Sand (655’ - 720’) = translucent to clear dominant with milky white hues, light greenish gray hues, light grayish hues, and light greenish yellow hues colors; quartz dominant with black lithics framework; lower fine to coarse grain sizes; poor to moderate sorting; angular to subangular angularity; very low to low sphericity; unconsolidated sands; massive bedding structure; very low reaction to HCL in bulk sample; no oil indictors in sample. Sand (740’ - 795’) = translucent to clear dominant with milky white hues, light greenish gray hues, light grayish hues, and light greenish yellow hues colors; quartz dominant with lithics and micas framework; medium to coarse grain sizes; poor to moderate sorting; angular to subrounded angularity; low to moderate sphericity; unconsolidated sands; massive bedding structure; very low reaction to HCL in bulk sample; no oil indictors in sample. Coal/Shale (805’-845’) = black to brownish black in color; tough to stiff tenacity; hackly to splintery fracture; platy to wedgelike with occasional massive cut- ting habit; dull to waxy luster; smooth to slight matte texture; thin bedding structure; very weak HCL reaction in bulk sample; no hydrocarbon indictors in sample. Sand (855’ - 910’) = clear to translucent with light gray hues, light green hues, grayish hues and greenish yellow hue colors; quartz dominant with blacks lithics, micas, tuffaceous materials framework; pebbles to lower medium grain size; poor sorting; very angular subrounded angularity; very low to moderate sphericity; unconsolidated sands; massive bedding structure; no HCL reaction in bulk sample; no hydro- carbon indictors in sample. Sand (955’ - 985’) = clear to light milky white with light gray hues, light olive green hues, and greenish yellow hues colors; quartz dominant with blacks lithics, micas, milky to creamy yellow tuffaceous materials framework; medium to coarse grain sizes; very poor to poor sorting; very angular to sub-round angularity; very low to moderate sphericity; unconsolidated sands; massive bedding structure; micas as accessory minerals; no HCL reaction in bulk sample; no hydrocarbon indictors in sample. Kitchen Lights Unit A-2A 11 Sand (995’ - 1050’) = clear to light gray translucent with occasional light green hues, grayish yellow hues, yellowish green hues, and milky white hues colors; quartz dominant with black lithics framework; fine to small pebbles grain sizes; poorly sorted; angular to subrounded angularity; low sphericity; unconsolidated sands; massive bedding structure; no HCL reaction in bulk sample; no hydrocarbon indictors in bulk sample. Tuffaceous Claystone (1060’ - 1120’) = light medium gray to light gray with pale red to brown hues; lumpy to mushy consistency; pulverulent to malleable; earthy fracture; pulverized cuttings habit; greasy to waxy to earthy luster; silty to gritty texture; slightly hydrophilic; moderate amount of conglomerate sand and coal; grains range up to 14mm; disaggregated and pitted quartz and lithic grains common. Sand (1120’ - 1190’) = light medium gray to light olive gray with dark gray to brown hues; lower coarse to upper medium with occasional lower medium to upper fine grains; moderate sorting throughout to occasional well sorted sections; sub rounded to sub angular; sub spherical to sub prismoidal; dominated by clear to translucent quartz; dark gray to black lithics common; trace pyrite, biotite, carbonaceous shale and tuffaceous claystones; deformed carbonaceous banding in claystones. Sand (1190’ - 1300’) = dark medium gray to medium gray with pale brown and dark olive hues; upper medium to lower coarse with lower medium and upper coarse being semi common; well sorted at the top of the interval degrading to moderate and poorly sorted at the base; sub angular to sub rounded; sub prismoidal to sub spherical; dominated by clear to translucent quartz and dark gray to black lithics; clay and silt content increasing down through; minor amounts of carbonaceous shale, pyrite, muscovite and tuff; 3-5mm pebbles with sizes ranging up to 12mm; clays are moderately hydrophilic; mushy; earthy fracture; pulverized cuttings habit; trace siltstones with deformed carbonaceous banding; trace bit broken and pitted large quartz and dark lithic grains. Sand (1300’ - 1370’) = medium gray to dark medium gray with dark to pale olive and pale brown hues; unconsolidated to trace soft to easily friable clasts; lower coarse to upper medium with lower medium to upper fine and upper coarse being semi common; sub angular to sub rounded; sub prismoidal to sub spherical; dominated by clear to translucent quartz and dark gray to black lithics; minor amounts of carbonaceous shale, coal, pyrite, and biotite; trace pale yellowish conglomerates and volcanic ash. Sand (1380’ - 1440’) = medium gray to dark medium gray with pale olive and brown hues; lower to upper medium with upper fine and lower coarse being common; moderate sorting becoming less uniform down through; sub rounded to sub angular; sub spherical to sub prismoidal; predominantly clear to translucent quartz with dark gray to black lithics common; slight clay increase down through the interval; minor amount of biotite, pyrite and trace conglomerates and siltstones. Sand (1450’ - 1505’) = clear to very light gray with light olive gray hues, pale greenish yellow hues, and very pale orange hues colors; quartz dominant with black lithics framework; upper fine to upper medium grain size; poor to fair sorting; subangular to subrounded angularity; moderate to low sphericity; unconsolidated sands; massive bedding structure; very weak HCL reaction in bulk sample; no hydrocarbon indictors in sample. Tuffaceous Claystone (1515’ -1555’) = medium dark gray to medium gray colors; clotted to lumpy consistency; malleable tenacity; irregular fracture; nodular to rounded cutting habits; dull to earthy luster; colloidal to clayey texture; soft sediment deformation bedding structure; very weak HCL reaction; no hydrocarbon indictors. Tuffaceous Siltstone (1565’ - 1610’) = medium dark gray to medium light gray with olive light gray hues colors; brittle to crumbly tenacity; earthy to slight hackly fracture; tabular to wedgelike cutting habits; frosted to earth luster; silty to matte texture; thin bedding structure; no HCL reaction in bulk sam ple; no hydrocarbon indictors in sample. Kitchen Lights Unit A-2A 12 Sand (1620’ - 1675’) = clear to very light gray with light olive gray hues, light greenish gray hues, and very pale orange hues colors; quartz dominant with black lithics framework; upper fine to lower coarse grain size; poor to fair sorting; angular to subrounded angularity; moderate to very low sphericity; unconsolidated sands; thick bedding structure; very weak HCL reaction in bulk sample; no hydrocarbon indictors in sample. Tuffaceous Claystone (1685’ - 1725’) = medium light gray to medium gray colors; mushy to pasty consistency; malleable to pulverulent tenacity; irregular fracture; nodular cutting habits; earthy to waxy luster; clayey to colloidal texture; soft sediment deformation to thick bedding structure; no HCL reaction in bulk sample; no hydrocarbon indictors. Sand (1735’ - 1785’) = clear to medium light gray with greenish gray hues, and light olive gray hues colors; quartz dominant with black lithic, micas, and volcanics framework; fine to upper medium grain size; fair sorting; angular to subrounded angularity; very low to low sphericity; unconsolidated sands; thick to massive bedding; weak HCL reaction in bulk sample; no hydrocarbon indictors in sample. Tuffaceous Claystone (1815’ - 1870’) = medium dark gray to dark gray with light gray hues colors; clotted to lumpy consistency; adhesive clay properties; malleable tenacity; irregular fracture; nodular to large cutting habits; waxy to earthy luster; clayey to smooth with gritty individual sand grain interbedded within clay balls; thick bedding structure; very weak HCL reaction in bulk sample; no hydrocarbon indictors in sample. Sand (1880’ - 1930’) = clear to light gray translucent with greenish gray hues, light olive gray hues, and dark greenish gray hues colors; quartz dominant with black lithics framework; very fine to lower coarse grain size; very angular to subrounded angularity; low sphericity; unconsolidated sands; thick bedding structure; very weak HCL reaction in bulk sample; no hydrocarbon indictors. Sand (1940’ - 1985’) = clear to very light gray with light olive gray hues, light greenish gray hues, and light green hues colors; quartz dominant with black lithics framework; upper fine to upper coarse grain size; poor sorting very angular to subrounded angularity; moderate to very low sphericity; no HCL reaction in bulk sample; no hydro- carbon indictor in sample. Sand (1995’ - 2040’) = clear to very light gray with light olive gray hues, light greenish gray hues, and light green hues colors; quartz dominant with black lithics framework; very fine to lower coarse grain size; poor to fair sorting; subangular to subrounded; moderate to low sphericity; no HCL reaction in bulk sample; no hydrocarbon indictor in bulk sample. Tuffaceous Siltstone (2050’ - 2090’) = dark gray to medium dark gray colors; brittle to stiff with occasional crumbly tenacity; earthy to hackly fracture; elongated to tabular cutting habits; earthy to frosted luster; silty to matte texture; thin bedding structure; no HCL reaction in sample; no hydrocarbon indictors in bulk sample. Sand (2090’ - 2170’) = dark medium gray to medium gray with pale brown and dark olive hues; upper medium to lower coarse with upper coarse to lower medium and upper fine being common; moderate to well sorted; sub angular to angular to sub rounded; sub spherical to sub prismoidal; predominantly clear to translucent quartz with dark gray to black lithics common; minor amount of clay, tuff, carbonaceous shale, biotite, pyrite and trace siltstones. Trace grains ranging from 2-5mm in the middle of the interval; commonly disaggregated with occasional pitting. Sand (2170’ - 2284’) = dark medium gray with pale brown hues to medium gray with dark olive hues; upper medium to lower coarse with upper coarse to lower medium and upper to lower very fine being common; moderate sorting; sub angular to angular to sub rounded; sub spherical to sub prismoidal; predominantly clear to translucent quartz with dark gray to black lithics common; minor amount of carbonaceous shale, biotite and pyrite; trace amounts of tuffaceous material and clay. Kitchen Lights Unit A-2A 13 Sand (2277’ - 2410’) = medium light gray to medium dark grayish hues overall with common greenish gray, yellowish gray and grayish black lithics; occasional pale reddish purple weathered grains; predominantly angular translucent to transparent quartz/volcanic glass; upper fine to upper coarse with rare sub to well-rounded grayish black lithic pebbles; poor to fairly sorted overall; predominantly very angular to angular, occasional subrounded; very low to moderate sphericity; unconsolidated with rare evidence of hydrophilic clay matrix support; common greenstone and grayish black mafic lithic grains; no oil or gas indicators present. Tuffaceous Claystone (2410’ - 2470’) = dominantly medium, common dark, light gray, olive gray, scattered bluish hues; soft sectile to crumbly; smooth to occasion- ally silty texture; dull luster; scattered organic material, commonly oriented along bedding; faint bedding; minor dark carbonaceous shale, trace coal; occasional very silty grading to tuffaceous siltstone; no oil attributes. Granular Sand (2470’ - 2530’) = dominantly clear, common transparent grays, greens black, scattered orangish, reddish; fine to upper granule, dominantly medium; dominantly subrounded, moderate sphericity; occasional well rounded granules; dominantly quartz; scattered feldspar; scattered to common dark mafics, lithic volcanics, including red to orange rhyolite, minor metamorphic fragments; good apparent porosity and permeability; no evident structure; no oil indicators. Sand (2530’ - 2650’) = dominantly clear, common cloudy, pale transparent green, light gray, opaque medium to dark gray, black, scattered milky, white, reddish orange, trace brown, purple, pink, silver, yellow green; very fine to trace granule, dominantly fine to medium; angular to trace well rounded, dominantly subrounded; scattered to good to common poor, dominantly moderate sphericity; dominantly quartz with scattered to common feldspar; scattered mafics, lithic fragments; lithics dominantly volcanics, scattered to trace metamorphics; minor mica, dominantly silver, trace clear, brown, black; no evident structure; loose, unconsolidated, non- cemented; occasional black to very dark brown carbonaceous material; trace coal; no oil attributes. Sand (2650’ - 2760’) = loose, non-cemented, unconsolidated; dominantly clear, common cloudy, transparent light to medium gray, milky to opaque white, common black, opaque medium to dark gray, scattered transparent to opaque light to trace dark green, reddish, orangish, trace yellow, yellow green, purple, silver, brown, bluish; occasional very fine to scattered very coarse, dominantly medium; angular to trace well rounded, dominantly subrounded; occasional good to common poor, dominantly moderate sphericity; moderately well to well sort; grain support; lacks matrix, minor tuffaceous lithic types interbedded; trace carbonaceous material; dominantly quartz; scattered to common feldspar scattered dark mafics, volcanic lithics, occasional metamorphic fragments; trace mica, biotite, muscovite; good apparent porosity, permeability; no oil attributes. Sand (2760’ - 2850’) = dominantly clear, common cloudy, off white, milky, light to dark gray; scattered black, transparent to opaque green, occasional reddish, minor, brownish, trace bluish, yellow green; trace very fine to trace lower granule, dominantly medium; trace angular, well rounded, dominantly sub- rounded; poor to common good, dominantly moderate sphericity; moderately well to well sorted; loose, unconsolidated, non-cemented; rare tuffaceous matrix; dominantly quartz, common feldspar scattered mafics, lithics; lithics dominantly volcanic including red orange brown rhyolite; trace mica; immature; no oil indicators. Sand (2850’ - 2910’) = dominantly clear quartz, common variable color feldspar; scattered dark lithic fragments, dominantly volcanic, trace metamorphic; trace mica, organic debris; occasional very fine to scattered granules 2880, dominantly medium; occasional angular to common rounded, dominantly subrounded; good to dominantly moderate common poor sphericity; well to moderately well sorted; loose, non-cemented; good apparent porosity and permeability, lacks matrix; no oil attributes. Tuffaceous Claystone (2910’-2970’) = dominantly medium, common light gray, occasional olive gray, scattered bluish hue soft to firm sectile to crumbly; smooth to very fine abrasive texture when grading to siltstone; noncalcareous; minor trace dark brown to black organic debris; non-fissile, non-laminated; minor interbedded carbonaceous shale, siltstone; no hydrocarbon indicators. Kitchen Lights Unit A-2A 14 Sand (2970’ - 3090’) = overall medium gray; individual grains dominantly clear, cloudy, common transparent to occasionally opaque light to dark gray, scattered milky, black, reddish brown, reddish orange, light to trace green; fine to scattered very coarse, dominantly medium; trace well rounded to scattered angular, dominantly sub-round occasional poor to common good dominantly moderate sphericity; moderately to moderately well sorted; dominantly quartz with common feldspar; scattered mafics; scattered to common green meta lithics, common orangish, reddish rhyolite, scattered dark basalt fragments; loose, non-cemented; occasional tuffaceous matrix grading to tuffaceous sandstone; trace to scattered black to dark brown carbonaceous debris, coal, dominantly specs, occasional large flakes; minor evident structure seen in claystone and tuffaceous sands; no oil attributes. Sand (3090’-3210’) = clear, cloudy, common light to dark gray, scattered black, transparent milky to opaque white, light to occasional dark green, trace to scattered orangish, brown, reddish, silver, pale yellowish green; scattered very fine to trace lower granule, dominantly medium with common fine; occasionally angular to common rounded, dominantly subrounded; dominantly moderate sphericity; loose, unconsolidated, non-cemented; good apparent porosity and permeability; minor black organic debris dominantly quartz with common variable color feldspar; scattered dark mafics; occasionally common mica, dominantly biotite, scattered muscovite; common to scattered lithics, dominantly volcanic, trace metamorphic; occasional heavy minerals, pale green apatite; no oil indicators. Sand (3210’ - 3345’) = overall medium gray; individual grains dominantly clear, cloudy, common transparent to occasionally opaque light to dark gray, scattered milky, black, reddish brown, reddish orange, light to trace green; fine to scattered very coarse, dominantly medium; trace well rounded to scattered angular, dominantly subrounded occasional poor to common good dominantly moderate sphericity; moderately to moderately well sorted; dominantly quartz with common feldspar; scattered mafics; scattered to common green meta lithics, common orangish, reddish rhyolite, scattered dark basalt fragments; loose, non-cemented; occasional tuffaceous matrix grading to tuffaceous sandstone; trace to scattered black to dark brown carbonaceous debris, coal, dominantly specs, occasional large pieces; minor evident structure seen in claystone and tuffaceous sands; no oil attributes. Siltstone/tuffaceous claystone (3345’- 3400’) = pale bluish gray to yellowish gray tuffaceous claystone; poor induration; crumbly to pulverulent; irregular fracture; dull to waxy luster; clayey to silty texture; occasional sand in the clasts; semi-hydrophobic; siltstones are brownish gray to olive brown; poor induration; irregular to planar fracture; crumbly; dull to earthy luster. Sand (3400’-3500’) = dominantly clear to cloudy quartz, scattered to common off white, milky to opaque white, trans- parent to opaque light to dark gray feldspar; often vitreous; scattered black mafics, common to scattered reddish brown, orangish lithic rhyolite; trace dark basalt fragments; scattered to occasionally common light to dark green metamorphics; fine to coarse, rare lower granule, dominantly medium grained; occasional angular to scattered well rounded, dominantly subrounded; dominantly moderate to good sphericity; loose, unconsolidated, non-cemented; rare tuffaceous matrix; scattered black black lignitic, bituminous organic material; immature; no oil attributes. Tuffaceous Siltstone/Claystone (3500’- 3550’) = predominantly light gray, occasional scattered bluish hues; very soft, crumbly to occasionally sectile; smooth to minor very fine abrasive texture; dull luster with trace micro-sparkle bentonitic, expansive; non-calcareous; trace to occasionally silty; scattered black organic debris; occasional evident structure, bedding, dominantly irregular discontinuous; no oil indicators. Sand (3550’ - 3660’) = overall peppered medium gray; individual grains dominantly clear, cloudy, transparent to opaque light to dark gray, black; scattered milky, opaque white, transparent light to dark green, orangish, reddish, pink, trace bluish, purple, pale yellow green, yellowish; occasionally vitreous; fine to trace granule, dominantly medium with common coarse grained; trace angular to occasional well rounded, dominantly subrounded, moderately spherical; loose, unconsolidated; minor tuffaceous clay matrix, dominantly good porosity and permeability, lacking matrix; dominantly quartz with common feldspar; scattered lithic fragments, dominantly volcanic, traces metamorphic; occasional dark mafics, mica; no oil attributes. Kitchen Lights Unit A-2A 15 3.3.1 Top of Sterling Sand (3660’ - 3750’) = dominantly, clear, cloudy, common transparent light, gray, green, opaque black, scattered medium to dark green, gray, occasional reddish, orangish, pale yellow green; fine to scattered granular intervals, dominantly medium; occasional angular to scattered well rounded, dominantly subrounded; occasional poor to common good sphericity; moderately well to well sorted; loose, non- cemented; good apparent porosity and permeability; immature; dominantly quartz with common feldspar and lithic fragments including pinkish, orange, reddish rhyolite, dark basalts, green metamorphics; trace to scattered dark mafics; scattered black carbonaceous material, lignitic to bituminous; minor tuffaceous clay matrix; no oil indicators. Sand (3750’ - 3870’) = dominantly clear to cloudy quartz, scattered to common off white, milky to opaque white, trans- parent to opaque light to dark gray feldspar; scattered black mafics, common to scattered reddish brown, orangish lithic rhyolite; trace dark basalt fragments scattered to occasionally common light to dark green metamorphics; fine to common coarse, rare lower granule, dominantly medium; occasional angular to scattered well rounded, dominantly subrounded; dominantly moderate to good sphericity. Loose, unconsolidated, non-cemented; rare tuffaceous matrix; scattered black lignitic, bituminous organic material; immature; no oil attributes. Sand (3870’ - 3960’) = dominantly clear, cloudy, transparent light gray, common medium to dark gray, scattered milky, opaque white, black, light green, reddish, orangish; occasional very fine to scattered upper coarse, dominantly medium; occasional angular, well rounded, dominantly subrounded; dominantly moderate sphericity; loose, non-cemented dominantly quartz; variable feldspar; scattered dark mafics; scattered to common lithics, dominantly volcanic; occasional mica, black organic debris; no evident structure; good porosity permeability, lacks matrix; minor tuffaceous matrix, silt/claystone interbeds stringers; no oil indicators. Granular Sand (3960’ - 4050’) = dominantly clear, cloudy light gray, common variable multicolored greens, grays, black reddish, brown, pink, purple, bluish, orangish associated with increased grain size and lithic fragment content; fine to trace lower pebble, scattered granule, dominantly medium to lower coarse; loose; scattered tuffaceous, kaolinitic sandstone; minor tuffaceous, silt matrix occasionally angular to scattered well rounded, dominantly subangular; good to common poor dominantly moderate sphericity; immature; dominantly quartz, common feldspar, lithic fragments; trace mica; scattered dark mafics; lithic variable, dominantly volcanic, scattered metamorphics, trace granitics; good apparent porosity, permeability; no oil attributes. Tuffaceous Siltstone (4060’ - 4110’) = dominantly medium to light gray, olive gray, scattered bluish hues; soft to firm; slightly crumbly; smooth to dominantly abrasive tex; dull luster; noncalcareous; non-fissile, non-laminated scattered to common black carbonaceous debris along bedding, common random orientation; grades to interbedded with minor carbonaceous shale, yellow brown light brown carbonaceous siltstone; no oil indicators. Coal (4120’ - 4150’) = black to minor very dark brownish black; firm, slightly crunchy; smooth texture with sub-hackly break; matte slightly shiny luster; minor faint laminations; trace inclusion occasional silt, ash; trace disseminated pyrite associated carbonaceous shale, siltstone noncalcareous; no fluorescence or cut. Kitchen Lights Unit A-2A 16 Tuffaceous Sandstone/Siltstone (4150’- 4280’) = medium gray to dark medium gray with dark to moderate brownish hues; soft to easily friable to trace unconsolidated; upper fine to upper medium with lower fine and lower coarse common; moderate to poor sorting; sub angular to sub rounded to occasionally angular; grain supported by an off white tuff; scarce matrix supported clasts; predominantly clear, opaque and translucent quartz grains with minor dark lithics and carbonaceous sediment; the clays are pale yellowish brown to yellowish gray; poor induration; crumbly to pulverulent; irregular to trace semi planar; tabular PDC cut clasts; trace carbonaceous banding; trace very fine to silt sized floating grains; trace moderate to pale brown siltstone with deformed carbonaceous banding; no oil indicators. Sand/Sandstone (4280’-4370’) = overall light gray, scattered dark, off white, white possibly kaolin alteration; individual grains dominantly clear, cloudy, transparent light gray, milky, occasion- al opaque dark gray white, black, trace green, bluish; very fine to trace lower granule, dominantly fine-medium; trace well rounded to angular, dominantly subangular; very well sorted clean to moderately sorted with common ash occasional detrital clay/silt matrix; dominantly quartz with common feldspar trace lithics and mafics; scattered black carbonaceous debris; occasional thin organic lams; no oil attributes. Sandstone (4410’ - 4470’) = light gray, bluish tuffaceous, minor off white, white kaolinitic, common peppered light to medium gray; very fine to trace lower granule, dominantly medium; angular to rounded; poor to good sphericity; moderate sorting; variable matrix content; non-cemented; dominantly quartz with com- mon feldspar; scattered lithics, trace mafics; variable organic content; organics randomly oriented; increased lithics associated with overall increase in grain size; matrix dominantly tuffaceous; common silt; no oil indicators. Tuffaceous Sandstone (4470’ - 4560’) = dominantly light gray, very pale brown, off white, scattered white kaolinitic loose grains, grain to matrix support common grains floating in matrix; soft soluble to firm mushy hydrated; scattered grain packed competent sandstone without matrix; variable silt content; very fine to scattered granular intervals; dominantly fine to medium; angular to trace well rounded, dominantly sub- rounded; good to poor sphericity; variable sorting, poor matrix rich to well sorted matrix free; overall decrease porosity and permeability with increase tuffaceous content; minor evident bed- ding, oriented organic material; scatter ed carbonaceous debris, commonly as small flakes, specs, occasional large chunk to granule size; no oil attributes. Tuffaceous Siltstone (4560’ - 4620’) = overall light gray, variable hues gray to pale brown, off white, minor bluish, very pale green; soft to firm; hydrated mushy to semi-friable; dull luster; fine abrasive texture; noncalcareous; occasionally very sandy grading to tuffaceous sandstone; scattered mod to dominantly light yellow brown siltstone; scattered to common black to dark brown organic debris, random to parallel orientation to weak bedding; no oil indicators. Sandstone (4620’ - 4770’) = overall light gray to off white; soft, soluble loose tuffaceous to firm friable grain packed to soft to firm kaolinitic; individual grains dominantly clear, cloudy, common transparent milky, light gray, scattered medium to dark gray, black, opaque white occasional green, trace bluish, reddish- orange; very fine to trace lower granule dominantly medium; angular to occasional rounded; poor to good dominantly moderate sphericity; variable sorting de- pending on matrix content, tuffaceous, clay, silt to scattered apparent mobile kaolin from feldspar alteration; minor evident bedding; scattered to common black organic debris, occasionally oriented; trace reddish brown slightly orangish phosphatic plant material; variable porosity and permeability de- pending on matrix content; dominantly quartz, common feldspar, trace to occasionally scattered lithics; occasional mafics, mica; no oil attributes. Tuffaceous Siltstone (4770’ - 4840’) = overall light gray, variable hues gray to pale brown, off white, minor bluish, very pale green; soft to firm; hydrated mushy to semi-friable; dull luster; fine abrasive texture; non- calcareous; occasionally very sandy grading to tuffaceous sandstone; scattered moderate to dominantly light yellow brown siltstone; scattered to common black to dark brown organic debris, random to parallel orientation to weak bedding; no oil attributes. Kitchen Lights Unit A-2A 17 Coal (4840’ - 4890’) = black, dark brownish black; firm crumbly, occasionally flakey, scattered slightly moderately hard to slightly tough; matte luster; minor thin discontinuous interbeds, with ash, silt, sand; dominantly occurs as thin stringers; non-calcareous; associated black carbonaceous material, flakes, specs, chunks scattered in other lithic types; no fluorescence or cut. Tuffaceous Sand/Sandstone (4890’ - 5000’) = dark medium gray to medium gray with moderate brown to moderate yellowish brown; disaggregated to soft to trace firm; lower medium to upper fine to moderate lower fine to lower coarse; poor to moderate sorting; sub-angular to angular to sub rounded; sub- spherical; predominantly clear, translucent to opaque quartz with dark lithics and carbonaceous sediment common; trace bit broken quartz, conchoidal fracture; typically matrix to grain supported; trace firm clasts are upper fine, well sorted and grain supported with 5-10% matrix; minor very pale blue to off white tuffaceous claystone; firm crumbly; irregular to semi-planar fracture; waxy to dull luster; clayey to silty texture; loose sand grains often vitreous; no oil attributes. Tuffaceous Claystone (5000’ - 5070’) = light to medium gray, scattered bluish hue, light yellowish-brown when grading to detrital rich silt/claystone; soft mushy to firm crumbly; smooth to very fine abrasive texture grading to silt- stone, tuffaceous silt; minor very fine sand; non-calcareous; very to moderately expansive; trace micro-mica; scattered to common organic debris, carbonaceous material to coal, common randomly oriented; no oil attributes. Sand (5070’ - 5150’) = overall light gray; individual grains dominantly clear, cloudy transparent light gray, milky, common medium to dark gray, opaque white, scattered green, orangish, reddish, black, occasional transparent light yellow green, green, bluish; loose grains occasionally vitreous; trace very fine grains, dominantly fine to medium; angular to trace well rounded, dominantly subrounded; dominantly moderate sphericity; loose, non-cemented, scattered tuffaceous matrix, overall lacks matrix; dominantly quartz, common feldspar, scattered lithics, dominantly volcanic; trace mica; occasional dark mafics; good apparent porosity and permeability; no evident structure; no oil attributes. Coal (5150’ - 5220’) = black, dark brownish black; firm crumbly, occasionally flakey, scattered slightly moderately hard to slightly tough; matte luster; minor thin discontinuous interbeds, with ash, silt, sand; dominantly occurs as thin stringers; non-calcareous; associated black carbonaceous material, specs flakes, and chunks scattered in other lithic types; no fluorescence or cut. Sand (5220’ - 5320’) = overall light gray; individual grains dominantly clear, cloudy transparent light gray, milky, common medium to dark gray, opaque white, scattered green, orangish, reddish, black, occasional transparent light yellow green, green, bluish; loose grains occasionally vitreous; trace very fine grains, dominantly fine to medium; angular to trace well rounded, dominantly subrounded; dominantly moderate sphericity; loose, non-cemented, scattered tuffaceous matrix, overall lacks matrix; dominantly quartz, common feldspar, scattered lithics, dominantly volcanic; trace mica; occasional dark mafics; good apparent porosity and permeability; no evident structure; interbedded with coal seams; no fluorescence or cut. Coal (5320’ - 5380’) = black, trace very dark brownish black; firm, crunchy, flakey, layered; matte to slightly shiny luster; smooth texture with sub-hackly break; noncalcareous; minor interbedded silt/clay/ash stringers; trace disseminated silt; trace to common disseminated pyrite; bedding slightly wavy irregular; associated carbonaceous siltstone, shale; no fluorescence or cut. Granular Sand (5380’ - 5470’) = multicolor, dominantly clear, cloudy, transparent white, milky, common black, scattered to dark gray, occasional opaque white, light to trace dark green, trace reddish brown, purple, bluish; fine to scattered upper granule, dominantly medium to coarse; angular to occasional well rounded, dominantly subangular; com- mon good to poor sphericity; moderate sort; loose, unconsolidated, non-cemented variable ash matrix content; minor bed- ding evident in tuffaceous lithics; good apparent porosity and permeability; dominantly quartz with common to abundant feldspar; scattered lithics, dominantly volcanics; trace mica, dark mafics no oil indicators. Kitchen Lights Unit A-2A 18 Tuffaceous Sandstone (5470’ - 5590’) = overall off white, light gray; soft mushy hydrated to firm semi- friable; very fine to scattered granule, dominantly medium with common coarse to fine; angular to trace well rounded, dominantly sub angular; dominantly moderate sphericity well to moderately sorted depending on matrix content; poor to good apparent porosity and permeability; dominantly quartz with common feldspar; scattered dark mafics; occasional lithic fragments, dominantly volcanic, occasional metamorphic; minor mica; trace to common organic debris; no oil attributes. Sand (5590’ - 5650’) = dominantly cloudy, transparent clear, milky light gray, common transparent pale green, black, opaque medium to dark gray, scattered medium to dark green, orangish, reddish trace purple, bluish; scattered very fine to trace lower pebble, occasional granule, dominantly medium with common coarse; angular to occasional well rounded, dominantly sub-angular; poor to occasional good, dominantly moderate sphericity; dominantly loose, disaggregated, non-cemented; grain support with variable dominantly minor tuffaceous matrix; no evident structures; dominantly quartz with abundant feldspar; variable common to scattered lithics, dominantly volcanic scattered metamorphics; trace to common mafics, trace mica; immature; minor kaolinitic alteration of feldspar; good apparent porosity and permeability; no oil indicators. Sandstone/Sand (5650’ - 5740’) = dominantly clear, cloudy light to dark gray; scattered black; very fine to coarse, dominantly fine to medium; dominantly subangular moderate sphericity; dominantly quartz, common feldspar; non-cemented, loose; variable porosity and permeability depending on tuffaceous matrix content; clean matrix free to 6885’, after high tuffaceous clay matrix content; scattered organic material; scattered coal interbeds; no oil attributes. Tuffaceous Claystone (5740’ - 5800’) = dominantly light to medium gray with occasional bluish, scattered brownish hues; soft, pliant to crumbly; smooth to occasionally abrasive texture grading to tuffaceous siltstone; minor trace very fine sand; noncalcareous; occasional to scattered black streaks, coal to lignitic organic material; rare disseminated pyrite; blush hued moderately expansive other hues slightly expansive; clay serves as high matrix content in sands grading to matrix supported tuffaceous sandstone; no oil indicators. Tuffaceous Siltstone (5800’ - 5890’) = light gray, occasional bluish, scattered brown hues; soft hydrated soluble to firm; dull luster; abrasive texture; noncalcareous; minor sand; commonly grades to tuffaceous claystone; rare evident bedding; occasional oriented organic material; scattered to common black to dark brown carbonaceous debris, coal grading to carbonaceous shale/siltstone; no oil attributes. Kitchen Lights Unit A-2A 19 3.3.2 Top of Beluga Sand (5890’ - 6020’) = dominantly loose, floating to point contact in abundant tuffaceous matrix; dominantly clear, cloudy, common light gray, scattered black, medium to dark gray, milky, transparent white, occasional light to dark green, trace pink, brown, reddish, orange, pale yellow green, bluish; very fine to trace granule, dominantly fine to medium; angular to trace well rounded, dominantly subangular; scattered good, common poor dominantly moderate sphericity; immature; variable ash matrix; variable poor to occasionally good porosity and permeability; scattered to abundant coal, organic debris; dominantly quartz, common feldspar; scattered dark mafics; trace to scattered lithic fragments; lithics dominantly volcanic, trace metamorphic; occasional mica; occasional feldspar alteration to kaolinite, dominantly in situ, minor appears as mobile matrix; no oil indicators. Tuffaceous Sandstone (6020’ - 6090’) = dominantly light gray with pale brown hue; soft mushy, hydrates, soluble to occasionally firm semi friable; very fine to occasional lower granule, dominantly fine to medium; dominantly subangular, moderate to poor sphericity; moderate to poor sorting; grain to common matrix support grading to tuffaceous siltstone; poor apparent porosity and permeability; noncalcareous; minor evident bedding evidenced by oriented organic debris; dominantly quartz; common feldspar; occasional mafics, lithics; common soluble dissolving into mud; no oil attributes. Tuffaceous Siltstone (6090’ - 6150’) = overall light grayish brown, off white, light gray, occasional very pale blue; soft, mushy, sectile, hydrated, soluble; dull luster; abrasive to occasional fine grainy texture when grading to tuffaceous sandstone; occasional black organic material; noncalcareous; occasional scattered micro-mica; no oil indicators. Coal (6150’ - 6200’) = brownish black to matte black; semi-firm to crumbly; hackly to semi planar to occasionally splintery; semi flakey to semi-wedge- like cuttings habit; trace thin inter- beds of silt and ash and carbonaceous shale; fissile across bedding planes; no fluorescence or cut. Tuffaceous Siltstone/Sand (6200’ - 6300’) = overall medium gray to medium light gray to yellowish gray to moderate yellowish brown with trace off white to very pale blue; poor induration; crumbly to occasionally firm crumbly; irregular to occasionally semi-planar or fissile fracture; platy to tabular stacked PDC cuttings; occasionally interbedded with thin layers of carbonaceous shale and sand; silty to clayey to sometimes gritty texture; slight waxy to dull luster; non-calcareous; the sands are unconsolidated to soft and easily friable; lower coarse to upper fine; upper medium common; moderate sorting; sub-spherical; sub-angular to sub-rounded, angular common; predominantly clear to translucent to opaque quartz, occasion- ally vitreous; no oil attributes. Tuffaceous claystone (6300’ - 6360’) = dominantly light to medium gray with occasional bluish, scattered brownish hues; soft, pliant to crumbly; smooth to occasionally abrasive texture grading to tuffaceous siltstone; minor trace very fine sand; non-calcareous; occasional to scattered black streaks, coal to lignitic organic material; occasionally moderately expansive; clay serves as high matrix content in sands grading to matrix supported tuffaceous sandstone; no fluorescence or cut. Tuffaceous Siltstone/Sand (6360’ - 6470’) = overall medium gray to medium light gray to yellowish gray to moderate yellow- brown with trace off white to very pale blue-gray; poor induration; crumbly to occasionally firm crumbly; irregular to occasionally semi-planar or fissile fracture; platy to tabular stacked PDC cuttings; PDC bit buttercurl cuttings observed; occasionally interbedded with thin layers of carbonaceous shale and sand; silty to clayey to sometimes gritty texture; slight waxy to dull luster; non-calcareous; the sands are unconsolidated to soft and easily friable; lower coarse to upper fine; upper medium common; moderate sorting; sub- spherical; sub-angular to subrounded, angular common; predominantly clear to translucent to opaque quartz, occasion- ally vitreous; no fluorescence or cut. Kitchen Lights Unit A-2A 20 Tuffaceous Claystone (6300’ - 6360’) = dominantly light to medium gray with occasional bluish, scattered brownish hues; very soft, pliant to crumbly; smooth to occasionally abrasive texture grading to siltstone; minor trace very fine sand; non-calcareous; occasional to scattered black streaks, coal to lignitic organic material; occasionally moderately expansive; clay serves as high matrix content in sands grading to matrix supported tuffaceous sandstone; no fluorescence or cut. Sand (6360’ - 6650’) = dominantly cloudy, transparent, clear, milky light gray, common transparent pale green, black, opaque medium to dark gray, scattered medium to dark green, orangish, reddish trace bluish hues; scattered very fine to trace lower pebble sized grains, dominantly medium with common coarse; angular to occasional well rounded, dominantly sub-angular; poor to occasionally good, dominantly moderate sphericity; dominantly loose, disaggregated, non-cemented; grain support with variable dominantly minor tuffaceous matrix; no evident structures; dominantly quartz with abundant feldspar; variable common to scattered lithics, dominantly volcanic scattered metamorphics; trace to common mafics, trace mica; good apparent porosity and permeability; no fluorescence or cut. Coal (6650’ - 6700’) = black, occasionally very dark brown; firm, crumbly to dominantly crunchy; smooth texture with sub-hackly break; matte to slightly shiny luster with scattered very fine disseminated micro- pyrite sparkle; occasional thin irregular discontinuous stringers tuffaceous clay/silt/sand; no fluorescence or cut. Tuffaceous Siltstone (6700’ - 6760’) = dominantly light, common medium, scattered bluish, brownish, trace greenish hues; soft, sectile to crumbly; abrasive to smooth texture; matte to dull luster; non- calcareous; minor evident structure, dominantly oriented organic debris along bedding; grades to tuffaceous claystone, sandstone; no fluorescence or cut. Tuffaceous Claystone (6760’ - 6830’) = dominantly light to medium gray with common bluish hue, scattered brownish hues; soft, pliant to crumbly; smooth to occasionally abrasive texture grading to tuffaceous siltstone; minor trace very fine sand; non-calcareous; occasional to scattered black streaks, coal to lignitic organic material; bluish hued moderately expansive, other hues slightly expansive; clay serves as high matrix content in sands grading to matrix supported tuffaceous sandstone; no fluorescence or cut. Sand (6840’ - 6920’) = dominantly clear, cloudy, common milky, opaque white, black, scattered light to dark gray, trace green, reddish; very fine to scattered granule, dominantly medium; common angular to trace well rounded, dominantly subrounded; good to common poor sphericity; non-cemented; loose, unconsolidated; immature; good porosity and permeability; dominantly quartz with common to abundant feldspar; trace mica; scattered dark mafics, decreasing lithics, dominantly volcanic; scattered to common coal, scattered small flakes, specs carbonaceous material; no fluorescence or cut. Tuffaceous Sandstone (6920’ - 6980’) = dominantly light gray, scattered very pale brown, occasionally yellowish gray; soft, hydrated easily soluble, mushy occasionally firm semi friable; very fine to medium, dominantly very fine with moderate silt, high clay content; grains dominantly subrounded, moderate sphericity; occasional grain to dominantly matrix support grading to tuffaceous siltstone; poor apparent porosity and permeability; minor evident bedding; occasional to common black organic debris, coal stringers; no oil attributes. Coal (6980’ - 7040’) = black, minor very dark brownish black; firm crumbly to occasionally slightly moderately hard flakey; matte to slightly shiny luster; common sub-hackly break; smooth texture; variable disseminated micro-pyrite; trace thin discontinuous interbeds; no cut or fluorescence. Tuffaceous Siltstone (7040’ - 7100’) = very light gray, pale yellowish gray, yellow brown, minor bluish hue; occasionally firm to dominantly soft, sectile to mushy; easily soluble, hydrated; variable fine to very fine sand content; grades to tuffaceous claystone, sand- stone; scattered black organic specs, flakes; organics occasionally oriented along crude bedding, common random orientation; non-calcareous; no oil indicators. Kitchen Lights Unit A-2A 21 Carbonaceous Shale (7100’ - 7160’) = medium to dark brown, brownish black; firm crumbly, occasionally flakey; poor incipient fissility due to common high silt and organic debris content; non- calcareous; variable silt and organics; associated with coal, medium yellow brown siltstone; irregular laminations wavy, semi parallel; occasional silty, ash lentils, discontinuous lenses; no oil attributes. Sand (7160’ - 7220’) = dominantly clear, cloudy, common milky, scattered black, lt to dark gray; very fine to occasional coarse, dominantly fine; angular to rounded; good to moderate sphericity; loose dominantly float in tuffaceous, clay, silt matrix; dominantly quartz, common feldspar; trace dark mafics, lithics; occasional to common black carbonaceous debris, specs, flakes dominantly random oriented in tuffaceous lithics types; no oil indicators. Tuffaceous Sandstone (7220’ - 7340’) = very light gray, grayish brown, brown gray, occasional off white, pale yellow gray; soft hydrated, mushy occasionally sectile soluble to occasionally firm semi friable; grain to abundant matrix support grading to tuffaceous siltstone and siltstone; very fine to scattered medium, trace coarse; angular to round- ed, dominantly subangular; scattered poor to good sphericity; dominantly quartz; common feldspar; occasional mafics, mica, lithics; lithics dominantly volcanic; scattered to common black organic material, coal, carbonaceous debris; organics occasionally oriented, dominantly random orientation; non- calcareous; variable porosity and permeability depending on matrix content; occasional white kaolinitic alteration of feldspar; no oil attributes. Siltstone (7350’ - 7410’) = light to medium gray brown, medium yellow brown; soft to firm; crumbly to sectile; slightly to moderately hydrated, soluble; dull luster; abrasive texture; minor faint bedding; non- fissile; noncalcareous scattered very fine sand; variable ash content grading to tuffaceous siltstone; scattered black carbonaceous material; no oil indicators. Tuffaceous Siltstone (7410’ - 7470’) = light gray, pale brown, yellow brown, off white, pale yellow gray, occasional bluish; soft hydrated, mushy to firm; fine abrasive texture; dull luster; scattered very fine sand grading to matrix rich tuffaceous sandstone; non- calcareous; rare evident bedding; common black carbonaceous debris, coal, specs, flakes, chunks; no oil attribute Sandstone (7470’ - 7530’) = overall light gray; very fine to medium, dominantly fine, common silt; dominantly subangular ,moderate sphericity; firm friable grain packed to semi-friable soft with high ash matrix content; occasional white kaolin alteration of feldspar, dominant- ly in situ, some mobile as matrix; non- calcareous; variable porosity, permeability depend on matrix content; quartz and feldspar; scattered dark mafics trace lithics; scattered organic debris; no oil indicators. Tuffaceous Siltstone (7530’ - 7600’) = light gray, pale brown, yellow brown, off white, pale yellow gray, occasional bluish; soft hydrated, mushy to firm; fine abrasive texture; dull luster; scattered very fine sand grading to matrix rich tuffaceous sandstone; non- calcareous; rare evident bedding; common black carbonaceous debris, coal, specs, flakes, chunks; often interbeds with tuffaceous claystone; no oil attributes. Tuffaceous Sandstone (7600’ - 7680’) = overall light gray, often grayish brown, occasionally off white; very fine to medium grained, dominantly fine, common silt; dominantly sub-angular; moderate sphericity; firm friable grain packed to semi-friable soft with high ash matrix content; occasional white kaolinite alteration of feldspar, dominantly in situ, some mobile as matrix; non-calcareous; variable porosity, permeability depending on matrix content; quartz and feldspar; scattered dark mafics; trace lithics; scattered organic debris; no oil attributes. Coal (7680’ - 7720’) = black, minor very dark brownish black; firm crumbly to occasionally slightly moderately hard; flakey; matte to slightly shiny luster; common sub-hackly; smooth texture; variable disseminated micro-pyrite; trace thin discontinuous interbeds; no fluorescence or cut. Kitchen Lights Unit A-2A 22 Tuffaceous Claystone (7720’ - 7800’) = dominantly light to medium gray with common bluish hue, scattered brownish hues; soft, pliant to crumbly; smooth to occasionally abrasive texture grading to tuffaceous siltstone; minor trace very tuffaceous sandstone; non-calcareous; occasional to scattered carbonaceous material; rare to trace disseminated pyrite; blush hued moderately expansive other hues slightly expansive; clay serves as high matrix content in sands; no oil attributes. Tuffaceous Siltstone (7800’ - 7860’) = light gray, pale brown, yellow brown, off white, pale yellow gray, occasional bluish; soft hydrated, mushy to firm; fine abrasive texture; dull luster; scattered very fine sand grading to matrix rich tuffaceous sandstone; non-calcareous; rare evident bedding; common black carbonaceous debris, coal, specs, flakes, chunks; often interbeds with tuffaceous claystone and tuffaceous sandstone; no oil attributes. Tuffaceous Sandstone (7860’ - 7940’) = overall light gray, often grayish brown, occasionally off white; very fine to medium grained, dominantly fine, common silt; dominantly sub-angular; moderate sphericity; firm friable grain packed to semi-friable soft with high ash matrix content; large amount of loose grains due to bit action; non-calcareous; variable porosity and permeability depending on matrix content; quartz and feldspar; scattered dark mafics; trace lithics; scattered organic debris and carbonaceous material; no oil attributes. Coal (7940’ - 7980’) = black, minor very dark brownish black; firm crumbly to occasionally slightly moderately hard; flakey; matte to slightly shiny luster; common sub-hackly; smooth texture; trace thin discontinuous interbeds; no fluorescence or cut. Tuffaceous Siltstone (7880’ - 8040’) = light gray, pale brown, yellow brown, off white, pale yellow gray, occasional bluish hues; soft hydrated, mushy to firm; fine abrasive texture; dull luster; scattered very fine sand grading to matrix rich tuffaceous sandstone; non-calcareous; rare evident bedding; common black carbonaceous debris, coal, specs, flakes, chunks; often interbeds with tuffaceous claystone and tuffaceous sandstone; no oil attributes. Tuffaceous Sandstone (8040’ - 8130’) = overall light gray, often grayish brown, occasionally off white; very fine to medium grained, dominantly fine, common silt; dominantly sub-angular; some scattered grains appear vitreous; moderate sphericity; firm friable grain packed to semi-friable soft with high ash matrix content; non-calcareous; variable porosity and permeability depending on matrix content; quartz and feldspar; scattered dark mafics; trace lithics; scattered to trace organic debris and carbonaceous material; no oil attributes. Kitchen Lights Unit A-2A 23 4 DRILLING DATA 4.1 KLU A-2A Connection Gases 1unit = 0.05% Methane Equivalent = 200ppm Methane Depth (feet) Gas Over Background (units) Depth (feet) Gas Over Background (units) 5520.94 0 6941.24 481 5615.77 980 7036.03 357 5710.09 330 7129.98 411 5804.16 105 7225.11 1632 5899.07 162 7320.61 112 5994.16 151 7415.44 292 6088.93 71 7510.41 842 6183.35 2260 7604.88 276 6278.09 2000 7699.64 47 6372.63 115 7794.91 242 6467.53 0 7889.84 310 6561.82 310 7984.38 295 6656.81 2200 8078.86 35 6751.49 215 8110.00 0 6846.43 402 4.2 KLU A-2A Trip (Wiper) Gases 50 units = 1% Methane Equivalent Depth (feet) Trip Type Trip to (feet) Gas (units) 3355’ W iper 2265’ (Shoe) 0 8160’ TD Trip Out of Hole, 8160’ TD 143 8160’ TD Wiper Out of Hole, 8160’ TD 7* 8160’ TD Casing 8122’ 0** *Note: mud weight at TD was 10.2ppg; weighted up to 10.9ppg before pulling out. **Note: circulated with loss of returns; no gas. Kitchen Lights Unit A-2A 24 4.3 Flowback/Connection Gas Chart 4.4 KLU A-2A Sampling Program / Sample Dispatch Set Type / Purpose Frequency Interval Dispatched to A Washed, screened & dried Reference Samples Set owner: Furie 30’ 2278’-8160’ Attn: Leslie K. Smith 1029 W. 3rd Ave, Suite 500, Anchorage, AK 99501 Office: 907.277.3726 B Washed, screened & dried Reference Samples Set owner: Furie 30’ 2278‘-8160’ Sample frequency was locally altered according to drill rate constraints and zones of interest. Kitchen Lights Unit A-2A 25 4.5 Survey Data KLU A-2A Measured Depth (ft) Inclination (o) Az imuth (o) TVD (ft) Vertical Section (ft) North(+) East(+) Dogleg (o/100ft) South(-) West(-) 107.00 0.00 0.00 107.00 0.00 0.00 0.00 0.00 200.00 0.50 357.67 200.00 0.27 0.41 -0.02 0.54 300.00 3.94 3.50 299.91 3.11 4.27 0.18 3.44 366.17 9.49 28.15 365.61 10.00 11.36 2.89 9.27 418.00 6.67 29.73 416.92 16.97 17.74 6.40 5.46 476.00 5.87 32.30 474.57 23.10 23.17 9.65 1.46 506.00 5.62 32.65 504.42 26.02 25.71 11.27 0.84 600.00 5.41 39.68 597.99 34.91 32.99 16.58 0.75 664.00 6.07 40.93 661.67 41.28 37.87 20.72 1.05 696.00 6.37 43.07 693.48 44.74 40.44 23.04 1.18 727.00 6.59 45.40 724.28 48.24 42.95 25.48 1.11 758.00 7.57 47.49 755.04 52.06 45.58 28.26 3.27 790.00 8.75 47.54 786.72 56.60 48.65 31.61 3.69 822.54 9.86 47.49 818.83 61.86 52.20 35.49 3.41 857.30 11.28 46.80 853.00 68.23 56.54 40.16 4.10 889.56 12.58 46.56 884.56 74.90 61.11 45.01 4.03 916.38 13.67 46.80 910.68 80.99 65.29 49.44 4.07 953.33 14.73 47.95 946.50 90.05 71.43 56.11 2.97 984.99 15.70 48.33 977.05 98.35 76.97 62.30 3.08 1010.11 15.96 48.81 1001.22 105.19 81.51 67.44 1.16 1048.42 16.53 49.12 1038.00 115.89 88.54 75.52 1.50 1079.97 18.02 49.27 1068.13 125.24 94.66 82.61 4.72 1104.45 19.07 49.11 1091.33 133.01 99.75 88.51 4.29 1142.76 19.40 47.94 1127.51 145.62 108.11 97.96 1.32 1173.87 20.04 46.83 1156.79 156.11 115.22 105.69 2.38 1198.78 20.81 45.72 1180.14 164.80 121.23 111.97 3.46 1294.69 24.93 46.66 1268.49 202.07 147.01 138.88 4.31 1389.14 27.26 47.50 1353.30 243.60 175.29 169.31 2.50 1483.89 29.83 47.07 1436.53 288.85 206.00 202.56 2.72 1578.30 35.10 46.30 1516.16 339.50 240.77 239.41 5.60 1672.81 39.53 46.63 1591.30 396.77 280.22 280.94 4.69 1766.17 42.40 46.93 1661.79 457.96 322.13 325.54 3.08 1861.24 48.11 45.93 1728.69 525.45 368.67 374.42 6.05 1956.42 49.29 46.15 1791.51 596.95 418.30 425.89 1.25 2051.95 48.43 46.21 1854.36 668.89 468.11 477.80 0.90 2147.98 49.36 46.68 1917.49 741.25 517.97 530.24 1.04 2228.27 48.51 46.93 1970.23 801.77 559.41 574.37 1.08 2327.49 47.98 47.28 2036.31 875.76 609.79 628.59 0.60 2364.89 47.48 48.33 2061.47 903.42 628.38 649.10 2.47 2396.90 46.97 46.82 2083.21 926.90 644.22 666.44 3.81 2426.54 46.50 45.84 2103.52 948.48 659.13 682.05 2.88 Kitchen Lights Unit A-2A 26 KLU A-2A Measured Depth (ft) Inclination (o) Azimuth (o) TVD (ft) Vertical Section (ft) North(+) East(+) Dogleg (o/100ft) South(-) West(-) 2520.99 45.70 46.40 2169.01 1016.54 706.30 731.10 0.95 2615.08 44.66 46.46 2235.33 1083.27 752.30 779.46 1.11 2710.18 43.13 46.90 2303.86 1149.20 797.54 827.43 1.64 2805.50 42.45 45.10 2373.81 1213.94 842.51 874.01 1.47 2900.06 41.90 43.57 2443.89 1277.41 887.92 918.37 1.23 2995.65 40.48 43.23 2515.83 1340.31 933.65 961.63 1.50 3089.08 38.28 43.76 2588.04 1399.54 976.65 1002.42 2.38 3185.40 36.16 44.39 2664.74 1457.77 1018.51 1042.94 2.24 3279.71 34.18 43.76 2741.83 1512.07 1057.53 1080.73 2.13 3375.89 30.32 42.65 2823.15 1563.33 1094.92 1115.88 4.06 3471.03 27.29 42.98 2906.51 1609.11 1128.54 1147.02 3.19 3566.00 23.38 43.42 2992.33 1649.70 1158.17 1174.83 4.12 3661.23 19.50 42.13 3080.96 1684.46 1183.69 1198.49 4.10 3754.86 19.54 41.58 3169.20 1715.67 1206.99 1219.36 0.20 3849.23 19.55 41.69 3258.14 1747.17 1230.59 1240.34 0.04 3944.84 19.55 41.32 3348.23 1779.07 1254.55 1261.54 0.13 4041.04 19.59 41.15 3438.88 1811.20 1278.78 1282.78 0.07 4133.95 19.91 41.14 3526.32 1842.50 1302.42 1303.44 0.34 4228.38 20.10 40.79 3615.05 1874.69 1326.82 1324.61 0.24 4322.77 20.31 41.69 3703.64 1907.19 1351.33 1346.11 0.40 4416.39 18.69 41.75 3791.88 1938.37 1374.66 1366.90 1.73 4511.83 18.56 41.62 3882.32 1968.77 1397.42 1387.17 0.14 4606.35 18.80 41.69 3971.87 1998.97 1420.04 1407.29 0.26 4701.33 16.14 42.97 4062.46 2027.43 1441.13 1426.47 2.83 4795.44 15.58 43.52 4152.98 2053.13 1459.87 1444.09 0.62 4889.08 15.19 45.01 4243.27 2077.96 1477.66 1461.43 0.59 4984.69 14.99 45.60 4335.58 2102.85 1495.17 1479.12 0.26 5078.61 14.70 48.55 4426.37 2126.90 1511.55 1496.73 0.86 5173.88 15.11 48.97 4518.43 2151.37 1527.71 1515.16 0.45 5268.22 15.39 49.21 4609.45 2176.14 1543.96 1533.91 0.30 5362.94 15.84 49.57 4700.67 2201.58 1560.55 1553.27 0.49 5456.52 15.99 49.71 4790.67 2227.18 1577.17 1572.82 0.17 5551.38 16.46 49.70 4881.75 2253.62 1594.31 1593.04 0.50 5645.81 16.75 49.93 4972.24 2280.54 1611.72 1613.65 0.31 5740.29 17.10 50.13 5062.63 2307.96 1629.39 1634.73 0.38 5833.44 17.61 50.90 5151.54 2335.65 1647.05 1656.18 0.60 5929.88 18.03 50.93 5243.35 2365.04 1665.66 1679.09 0.44 6023.28 18.28 51.14 5332.10 2394.01 1683.96 1701.72 0.28 6118.38 18.60 51.03 5422.32 2423.96 1702.86 1725.12 0.34 6212.73 18.89 50.98 5511.66 2454.15 1721.94 1748.69 0.31 6306.25 19.18 50.70 5600.07 2484.53 1741.20 1772.34 0.33 Kitchen Lights Unit A-2A 27 KLU A-2A Measured Depth (ft) Inclination (o) Azimuth (o) TVD (ft) Vertical Section (ft) North(+) East(+) Dogleg (o/100ft) South(-) West(-) 6402.26 19.55 50.72 5690.65 2516.24 1761.36 1796.98 0.39 6497.08 19.98 50.57 5779.88 2548.19 1781.69 1821.77 0.46 6593.18 20.34 51.15 5870.09 2581.17 1802.60 1847.46 0.43 6687.50 20.60 51.10 5958.46 2614.01 1823.30 1873.14 0.28 6782.80 21.23 50.98 6047.48 2647.88 1844.69 1899.59 0.66 6878.28 21.36 51.29 6136.44 2682.40 1866.45 1926.59 0.18 6971.83 21.88 51.22 6223.41 2716.71 1888.02 1953.47 0.56 7065.73 22.36 51.20 6310.40 2751.90 1910.17 1981.03 0.51 7161.77 22.41 51.58 6399.20 2788.29 1932.99 2009.61 0.16 7256.35 22.74 51.93 6486.53 2824.40 1955.47 2038.13 0.38 7350.54 23.23 51.49 6573.24 2860.98 1978.26 2066.99 0.55 7445.48 23.71 52.47 6660.33 2898.56 2001.55 2096.78 0.65 7540.75 24.37 52.20 6747.33 2937.11 2025.26 2127.51 0.70 7636.27 25.05 52.22 6834.11 2976.78 2049.73 2159.06 0.71 7730.06 25.79 52.40 6918.82 3016.77 2074.34 2190.92 0.79 7824.82 26.41 52.54 7003.91 3058.17 2099.74 2223.98 0.66 7919.46 27.08 52.99 7088.43 3100.43 2125.51 2257.89 0.74 8014.39 27.52 53.62 7172.79 3143.59 2151.52 2292.80 0.55 8093.30 28.00 53.91 7242.61 3179.98 2173.25 2322.45 0.63 PROJECTED TD SURVEY 8160.00 28.00 53.91 7301.51 3210.97 2191.69 2347.75 0.00 Kitchen Lights Unit A-2A 28 4.6 Bit Record Bit Size Make Type / Serial# Jets / TFA In Out Total Footage Bit Hrs Avg ROP (ft/hr) Avg WOB (klbs) RPM PP (psi) Bit Grading NB 3 12.25” BHI PDC DP605X 7040941 7x16 1.3744 2278’ 8160’ 5882’ 64.9 141.6 7.22 60.65 2319 1-1-WT-A-A-1-NO-TD 4.7 Dilling Fluid Record Contractor: Halliburton Date Depth (ft) MW (ppg) VIS PV YP Gels FL FC Sols (%) O/W Ratio Sd (%) pH Cl (mg/l) Ca (mg/l) MBT FLT (oF) KCl Polmer/GEM 7/8/16 2,350 10.05 53 17 18 5/8/10 6.8 1 8.3 0/90.7 0.01 10.9 12,000 840 8.0 7/9/16 2,926 10.0 47 16 16 4/12/15 6.0 1 7.0 0/92.0 0.20 10.8 12,000 1080 6.0 88 7/10/16 4,234 10.0 46 15 20 6/14/17 5.6 1 7.0 0/92.0 0.20 10.5 12,000 840 7.0 98 7/11/16 5,710 10.0 50 18 20 5/11/15 5.8 1 7.5 0/91.5 0.10 10.2 12,000 880 8.5 108 7/12/16 7,213 10.2 55 23 21 5/11/19 5.4 1 10.0 0/89.0 0.10 9.5 12,000 720 12.0 112 7/13/16 8,160 10.3 47 19 18 5/7/12 5.8 1/2 10.1 0/89.0 0.10 10.2 11,000 460 12.5 115 7/14/16 8,160 10.5 63 24 24 6/26/38 6.0 1/2 10.9 0.0/88.2 0.10 10.3 10,500 460 12.5 110 7/15/16 8,160 10.4 89 22 33 12/36/43 7.2 1/3 10.8 0.0/88.2 0.10 9.0 12,000 520 16.0 112 7/16/16 8,160 11.0 82 25 28 10/31/41 7.0 2/3 12.8 0.0/86.3 0.10 9.8 11,000 440 17.5 104 7/17/16 8,160 10.2 55 17 20 5/9/12 5.6 1 9.5 0.0/89.5 0.10 10.9 11,500 160 15.0 Abbreviations MW = Mud Weight Gels = Gel Strength Sd = Sand content ECD = Effective Circulating Density FL = Filtrate/Fluid Loss (ml/30min) Cl = Chlorides VIS = Funnel Viscosity (sec/qt) FC = Filter Cake (1/32inch) Ca = Hardness Calcium PV = Plastic Viscosity Sols = Solids O/W = Oil to Water ratio YP = Yield Point FLT = Flowline Temperature MBT = Methylene Blue Test (ppb equiv) Kitchen Lights Unit A-2A 29 4.1 Drilling Progress Chart 30 5 DAILY REPORTS 31 32 33 34 35 36 37 38