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216-008
Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 11/20/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20251120 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BCU 23 50133206350000 214093 10/14/2025 AK E-LINE PPROF T41129 BR 09-86 50733204480000 193062 10/28/2025 AK E-LINE Perf T41130 BRU 213-26T 50283202040000 225038 10/30/2025 AK E-LINE Perf T41131 END 1-57 50029218730000 188114 11/16/2025 READ PressTempSurvey T41132 END 2-28B 50029218470200 203006 11/15/2025 READ PressTempSurvey T41133 END 2-30B 50029222280200 208187 11/18/2025 READ PressTempSurvey T41134 END 2-52 50029217500000 187092 10/28/2025 HALLIBURTON LDL T41135 KALOTSA 10 50133207320000 224147 11/7/2025 AK E-LINE Perf T41136 MPF-92 50029229240000 198193 11/8/2025 READ CaliperSurvey T41137 MPH-01 50029220610000 190086 11/7/2025 READ CaliperSurvey T41138 MPI-14 50029232140000 204119 11/8/2025 READ CaliperSurvey T41139 MPU H-01 50029220610000 190086 11/4/2025 AK E-LINE Drift/CBL/Caliper/Packer T41138 MPU I-14 50029232140000 204119 11/8/2025 AK E-LINE RigAssist T41139 MPU J-02 50029220710000 190096 11/6/2025 AK E-LINE Caliper/Gyro T41140 NCIU A-07A 50883200270100 225094 11/1/2025 AK E-LINE CBL T41141 NCIU A-07A 50883200270100 225094 11/4/2025 AK E-LINE Perf T41141 ODSN-01A 50703206480100 216008 10/24/2025 HALLIBURTON PACKER T41142 ODSN-25 50703206560000 212030 10/23/2025 HALLIBURTON PACKER T41143 ODSN-26 50703206420000 211121 11/4/2025 HALLIBURTON PERF T41144 PBU 02-10B 50029201630200 200064 10/27/2025 HALLIBURTON RBT T41145 PBU A-24B 50029207430200 225067 10/20/2025 BAKER MRPM T41146 PBU B-05E 50029202760500 225093 10/23/2025 HALLIBURTON RBT T41147 PBU B-05E 50029202760500 225093 10/23/2025 BAKER MRPM T41147 PBU B-20A 50029208420100 212026 10/16/2025 BAKER SPN T41148 PBU F-18B 50029206360200 225099 11/5/2025 HALLIBURTON RBT-COILFLAG T41149 PCU D-10 50283202080000 225082 10/31/2025 AK E-LINE Patch T41150 PCU D-10 50283202080000 225082 10/17/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/22/2025 AK E-LINE Perf T41150 PCU D-10 50283202080000 225082 10/29/2025 AK E-LINE Perf T41150 ODSN-01A 50703206480100 216008 10/24/2025 HALLIBURTON PACKER Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:19 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: PCU D-11 50283202090000 225088 10/16/2025 AK E-LINE CBL T41151 PCU D-11 50283202090000 225088 10/24/2025 AK E-LINE Perf T41151 Please include current contact information if different from above. Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.11.20 13:27:31 -09'00' Nolan Vlahovich Hilcorp Alaska, LLC Geotech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 09/19/2025 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20250919 Well API #PTD #Log Date Log Company Log Type AOGCC E-Set# BRU 212-35T 50283200970000 198161 8/10/2025 AK E-LINE PPROF T40899 BRU 223-34T 50283202060000 225059 8/17/2025 AK E-LINE CBL T40900 BRU 234-27 50283202070000 225065 9/12/2025 AK E-LINE CBL T40901 BRU 242-04 50283201640000 212041 6/9/2025 AK E-LINE Perf T40902 KBU 11-08Z 50133206290000 214044 9/8/2025 AK E-LINE Perf T40903 MPU H-03 50029220630000 190088 9/9/2025 AK E-LINE SetPacker T40904 MPU H-11 50029228020000 197163 2/9/2025 AK E-LINE Caliper T40905 MPU M-62 50029237440000 223006 8/31/2025 AK E-LINE LDL T40906 NCIU A-06 50883200260000 169050 8/25/2025 AK E-LINE TubingCut T40907 NCIU A-21A 50883201990100 225075 8/26/2025 AK E-LINE Perf T40908 ODSK-33 50703205620000 207183 9/10/2025 READ Caliper Survey T40909 ODSN-01a 50703206480100 216008 9/8/2025 READ Caliper Survey T40910 ODSN-06 50703207150000 215098 9/9/2025 READ Jewelry Log T40911 PBU C-34C 50029217850300 225068 8/25/2025 BAKER MRPM T40912 PBU Q-06A 50029203460100 198090 8/21/2025 BAKER SPN T40913 TBU M-25 50733203910000 187086 8/31/2025 AK E-LINE Drift T40914 Please include current contact information if different from above. ODSN-01a 50703206480100 216008 9/8/2025 READ Caliper Survey Gavin Gluyas Digitally signed by Gavin Gluyas Date: 2025.09.22 13:22:50 -08'00' 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: HWO: GL to ESP 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: 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: Junk (MD): 18,811 NA Casing Collapse Conductor NA Surface 3,180psi Intermediate 1 3,090psi Intermediate 2 5,410psi Liner 7,500psi Liner Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): 12. Attachments: Proposal Summary Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch Exploratory Stratigraphic Development Service 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: OIL WINJ WDSPL Suspended 16. Verbal Approval: Date: GAS WAG GSTOR SPLUG AOGCC Representative: GINJ Op Shutdown Abandoned Contact Name: Contact Email: Contact Phone: Authorized Title: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Plug Integrity BOP Test Mechanical Integrity Test Location Clearance Other 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 NA 5" x 7" Baker ZXP LTP and 4-1/2" HES 'XXO' SVLN 11,119' MD / 6,251' TVD and 2,186' MD / 2,048' TVD NA 18,440 11,354 7,432 See Schematic 907-777-8503 ryan.rupert@hilcorp.com Operations Manager October 2, 2025 4-1/2" Perforation Depth MD (ft): See Schematic 6,2404-1/2" 158 16" 11-3/4" 9-5/8" 4,099 7"11,354 4,017 5,830psi 5,750psi 3,238 5,003 6,272 4,099 7,940 158 158 12.6#, C-110 TVD Burst 11,152 8,430psi MD NA 7,240psi Hilcorp Alaska, LLC Length Size Proposed Pools: 6,329 18,440 6,240 1,529 NUIQSUT OIL Same STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 ADL0355036, ADL0389959 216-008 OOOGURUK NUQ ODSN-01A 3800 Centerpoint Dr, Suite 1400 Anchorage, AK 99503 50-703-20648-01-00 OOOGURUK PRESENT WELL CONDITION SUMMARY AOGCC USE ONLY Tubing Grade: Tubing MD (ft):Perforation Depth TVD (ft): Ryan Rupert 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: Form 10-403 Revised 06/2023 Approved application valid for 12 months from date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 1:35 pm, Sep 18, 2025 Digitally signed by Sara Hannegan (2519) DN: cn=Sara Hannegan (2519) Date: 2025.09.18 13:08:27 - 08'00' Sara Hannegan (2519) 325-568 A.Dewhurst 23SEP25MGR22SEP2025 DSR-9/24/25 * BOPE test to 2500 psi. 48 hour notice to AOGCC. 10-404 *&: Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.09.24 15:30:05 -08'00'09/24/25 RBDMS JSB 092625 GL to ESP conversion HWO Well: ODSN-01A Well Name:ODSN-01A API Number:50-703-20648-00-01 Current Status:Non-op GL producer Permit to Drill Number:216-008 First Call Engineer:Ryan Rupert (907) 301-1736 (c) Second Call Engineer:Keith Lopez (907) 903-5432 (c) Regulatory Contact:Darci Horner (907) 777-8406 Max Expected BHP:2164psi at 6350’ TVDss (6.6ppg) Max from offsets Max. Potential Surface Pressure: 1529 psi 0.1psi/ft to surface Brief Well Summary ODSN-01A is a shut in Nuiqusit producer. The well is non-operable due to TxIA communication. The well was redrilled and completed as a multistage frac’d producer in 2016. Standard Nuiqusit completion strategy was to install a 4-1/2” GL completion string post-drill, and execute the frac down that string. Then free-flow the well initially, and switch to GL when needed. Most producers were eventually recompleted with smaller tubing ESP completions for better drawdown. This well was being evaluated for a workover, when TxIA was discovered, and the well was shut-in. It did pass a CMIT-TxIA at the time, so casing integrity is proven. The 3-phase Oooguruk subsea export line is hydraulically bottlenecked, so returning this well to production via ESP instead of GL will also alleviate some of that bottleneck. The goal of this project is to swap the tubing to remediate current TxIA and convert the well to ESP Pertinent wellbore information: - SVLN at 2186’ MD: No WL-SSSV set currently (was pulled for integrity screening) - Deviation o Goes >70 degrees at 10,375’ MD (close to XN-nipple) o Sail angle: 63 degrees from 4600 – 10,200’ MD o Max deviation above top liner = 85 degrees at top liner - Min ID in tubing: 3.725” at XN-nipple at 10,320’ MD - Pertinent History o August-2025 CMIT-TxIA PASSED to 2050psi against a TTP set in XN-nipple at 10,320’ MD MIT-T FAILED @ 2bpm at 730psi o Jan-2022: CT Cleanout #4 (Fluff and Stuff) reached 17,300’ MD o October-2021: CT Cleanout #3 (Fluff and Stuff) reached 18,230' MD o 2018: CT Cleanout #2 (Fluff and Stuff) Reached 16,700’ MD. Had to work pipe around 12,500’ MD o 2016: Sidetrack from N-01 (collapsed casing) New 4-1/2” frac string and new 7” run back to surface (10ppg brine in IA) MIT-IA to 4000psi PASSED Multi-stage ball drop frac performed CT cleanout #1 made it to 18,121’ MD and returned 23bbls frac sand back to surface GL to ESP conversion HWO Well: ODSN-01A HWO Conditions x Traditional well control approach will be implemented x KWF will be a barrier at all times during HWO operations x No snubbing operations will be conducted x TSI Rig #102 will be new to the slope and new to the state. The rig is not fully winterized. x Hilcorp will conduct HWO operations with TSI #102 NO later than 10/31/25 RWO Procedure 1. MIRU TSI Hydraulic Workover rig #102 2. Circulate / kill well: a. Work over fluid will be injection water (8.33ppg or heavier) b. Ensure any wellbore fluids are fully displaced with KWF either via circulation or bullheading c. Tubing + Liner volume to top frac port = 177bbls d. IA volume to XN-nipple = 192bbls 3. Set BPV/TWC, ND tree, NU BOP stack (see attached) a. Notify AOGCC 48 hours in advance for witness b. Test to 250psi Low /2,500psi High / 2,500psi Annular c. BOPE will be used as needed to circulate the well 4. Pull BPV/TWC 5. BOLDS and unseat hanger 6. POOH laying down existing 4-1/2” GL completion from 11,152’ MD 7. Pickup snorkel pipe and workstring for cleanout run (ensure BOPE has been tested for snorkel pipe OD, or smaller) 8. Cleanout casing and liner as deep as practical 9. Pickup and RIH with 3-1/2” x 2-7/8” ESP / GL completion a. Plan to run a shroud and ±400’ of 4-1/2” screens below ESP b. Bottom ESP to be set at ±9,900’ MD c. Equip well with Packer, SSSV, and Packer Vent Valve (PVV) all set below permafrost d. Well to be equipped for backup GL as well 10. Land ESP / GL completion 11. Drop Ball and rod and set packer 12. Set BPV/TWC, ND BOP 13. NU tree and test, pull BPV/TWC 14. RDMO TSI #102 GL to ESP conversion HWO Well: ODSN-01A Post RWO Procedure 1. MIRU SL 2. PT PCE to 250psi low / 2500psi high 3. Pull B&R and catcher sub 4. RDMO Operations 1. Return well to production 2. Within 5 days of stabilized production, test SSV and SSSV per state guidelines (give 48hr witness notification) 3. TIFL to prove integrity of Packer Vent Valve (PVV) a. Can be conducted with well online or offline. Thermally stable is most important b. Ensure IA FL is at 500’ MD or deeper. Depress with GL, if necessary c. Close in IA at surface d. Close PVV e. Shoot IA FL and note SI IAP f. Bleed IAP down at least 200psi below shut-in IAP g. Monitor IA pressures and fluid level every hour for at least 2 hours i. Shut in IAP would be expected to build, but PVV will prevent this ii. Should be no increase in FL beyond thermal expansion / degassing or foaming effects iii. Pass / fail criteria 1. IA fluid level should inflow no more than 500’ MD over the 2 hours, and show a stabilizing trend (decreasing height gain every hour) 2. Shut in IA pressure should increase no more than 100psi over the 2 hours and show a stabilizing trend (decreasing pressure gain every hour) 4. Open PVV, open IA at surface and return well to production Attachments: 1. Current Well Schematic 2. Proposed Well Schematic 3. BOPE schematic (TSI) 4. Fluid Flow Diagram (TSI) 5. Rig stabilization Diagram (TSI) Oooguruk Field Last Completed: 3/13/2016 PTD: 216-008 API #: 50-703-20648-01-00 Casing 16” 16" A 9-5/8" 3 B 4-1/2" Size ID Top Btm TVD 16"N/A Surface 158' 11-3/4"10.772" Surface 3,238' 9-5/8"8.835” 3,923' 5,003' 7"6.276" Surface 6,272' 2 4-1/2”3.958" 11,098' 6,240' 11-3/4" C 4-1/2”3.958" Surface 6,254' 9-5/8"No Top MD TVD Inc ID A 2,186 2,048 37 3.813" B 2,952 2,608 50 3.813" C 5,808 4,028 63 3.813" D 8,632 5,320 63 NA E 10,132 6,013 63 3.813" D F 10,204 6,045 64 3.842" 1 G 10,320 6,093 68 3.725" H 11,098 6,250 85 E J 11,152 6,254 85 3.500" F St. MD (ft) TVD (ft) Inc Type Valve Latch Port G 3 2,833 2,531 48 KBG Dummy BK-4 NA 2 5,689 3,974 63 KBG Dummy BK-4 NA 1 10,013 5,958 63 KBG Dummy BK-4 NA H, I J Resman Int. Vented Carriers (x4) Swell Packers (x13) Ball Actuated Sleeves (x11) 7"Two Ported Pups 81 degrees Inc at bottom 4-½” Liner from 11,098' MD to 18,440' MD with Halliburton Ball Actuated Sleeves & Swell Packers Nuiqsut Sand Original Completion Original Wellbore Spudded Jan 2012 11,152' Date CompleteEvent Mar 2012 7" ES Cementer HES "X" Nipple HES "X" Nipple 40#, L-80, Hyd 521 26#, L-80, Hyd 563 12.6#, C-110, Hyd 521 Rig Event Well History Gas Lift Mandrels 4-1/2" x 1" Date 8/31/2025 3/13/2016 8/16/2025 Baker 5" x 7" ZXP Liner Top Packer w/Flex Loc Hanger, 20' 4-1/4" Seal Bore Receptacle Below Hanger856,251 Intermediate 2 Item Halliburton 'XXO' SVLN ODSN-01A Schematic Nuiqsut Producer TUBING DETAIL CASING DETAIL Cement Details Hole MD 7" 9-1/2” underreamed hole: Pumped 87.6 bbls of 15.8ppg class G cement with full returns. See 2/28/16 XBAT Sonic log 2nd stage: Pumped 57 bbls of 15.8ppg class G cement with full returns through ES Cementer at 8636’ MD. See 2/28/16 XBAT Sonic log 6-1/8" Open Hole, Uncemented Ball Actuated Sleeves and Swell Packers 18,811' Driven in 24" hole 11-3/4"14-1/2" hole, 499 sx 11.34 ppg Permafrost 'L', plus 563 sx Premium 'G' tail, Returns to surface? 11-3/4" underreamed hole: Pumped 42 bbls (197 sx) of 15.8ppg Class G cement with full returns. Volumetric TOC at 6,875’ MD assuming 0% washout.7,943' 4,099' Intermediate 1 Surface Conductor Type Tubing Production Liner CEMENT INFORMATION 11,362' 158' Wt/ Grade/ Conn Btm MD 158' 4,099' 109#, X-65 60#, L-80, BTC 7,940' 11,354' 18,440' 12.6#, C-110, Hyd 521 11,119I Sidetracked & Completed Frac Job JEWELRY DETAIL HES "X" Nipple 4-1/2" Halliburton 'ROC' Gauge Carrier w/ Encapsulated e-line to Surface HES "XN" Nipple w/ PXN plug set, w/ "catcher sub" Top of Tie Back Extension Mar 2016 Mar 2016 Bottom of Solid Mule Shoe/Bullet Seals 70 degree inclination @ 10,393' MD / 6,119' TVD SSSV X X Whipstock window 4,077'- 4,099' MD 7 Stage 1 TOC Estimated@ 9,850' MD ODSN-01 Original Hole Abandoned X Gauge XN "Catcher sub" on PXN plug set ODSN-01A Schematic 9-17-2025 Last edited by: GP 9/17/2025 Oooguruk Field Last Completed: 3/13/2016 PTD: 216-008 API #: 50-703-20648-01-00 Casing 16” 16" A 9-5/8" 3 B C 4-1/2" 2 D Size ID Top Btm TVD 16"N/A Surface 158' E 11-3/4"10.772" Surface 3,238' 9-5/8"8.835” 3,923' 5,003' 11-3/4"7"6.276" Surface 6,272' 4-1/2”3.958" 11,098' 6,240' 3-1/2"2.992" Surface 2,200' 2-7/8" 2.441" 2,375' 2,369' 3-1/2" 2.992" 2,600' 5,652' 2-7/8" 2.441" 9,350' 5,906' 9-5/8" No Top MD TVD Inc ID A 2,200 2,060 37 B 2,375 2,200 39 C 2,450 2,258 40 F D 2,550 2,333 43 1 E 2,600 2,369 44 F 9,250 5,606 62 G G 9,750 5,836 63 H H 9,800 5,859 63 I 9,900 5,906 63 J 9,900 5,906 63 K 11,098 6,250 85 L 11,119 6,251 85 St. MD (ft) TVD (ft) Inc Type Valve Latch Port I 3 2,325 2,160 37 TBD Shear TBD NA J 2 2,500 2,295 41 TBD Dummy TBD NA 1 9,300 5,629 63 TBD OV TBD TBD K, L Resman Int. Vented Carriers (x4) Swell Packers (x13) Ball Actuated Sleeves (x11) 7"Two Ported Pups 75 degrees Inc at bottom 4-½” Liner from 11,098' MD to 18,440' MD with Halliburton Ball Actuated Sleeves & Swell Packers Nuiqsut Sand Original Completion Original Wellbore Spudded Jan 2012 Date CompleteEvent Mar 2012 2-7/8" "XN" Nipple ESP Pump Assembly, Discharge gauge with shroud Top of Tie Back Extension TBD TBD TBD Bottom of ESP Assembly Screens below shroud, 400' long, bottom @ 10300 Date 6-1/8" Open Hole, Uncemented Ball Actuated Sleeves and Swell Packers 18,811' Driven in 24" hole 11-3/4"14-1/2" hole, 499 sx 11.34 ppg Permafrost 'L', plus 563 sx Premium 'G' tail, Returns to surface? 11-3/4" underreamed hole: Pumped 42 bbls (197 sx) of 15.8ppg Class G cement with full returns. Volumetric TOC at 6,875’ MD assuming 0% washout.7,943' 4,099' Type Conductor Surface Intermediate 1 18,440' 11,354' 7,940' ODSN-01A Proposed Schematic Nuiqsut Producer Cement Details Hole MD 7" 9-1/2” underreamed hole: Pumped 87.6 bbls of 15.8ppg class G cement with full returns. See 2/28/16 XBAT Sonic log 2nd stage: Pumped 57 bbls of 15.8ppg class G cement with full returns through ES Cementer at 8636’ MD. See 2/28/16 XBAT Sonic log CEMENT INFORMATION 11,362' 158' Sidetracked & Completed Frac Job 2-7/8" x 3-1/2" XO Item 3-1/2" TRSSV 3-1/2" x 2-7/8" XO 7" x 2-7/8" ESP Packer with Packet Vent Valve 2-7/8" "X" Nipple Mar 2016 Mar 2016 Rig Event Well History Gas Lift Mandrels 4-1/2" x 1" 3-1/2" x 2-7/8" XO CASING DETAIL TUBING DETAIL Baker 5" x 7" ZXP Liner Top Packer w/Flex Loc Hanger, 20' 4-1/4" Seal Bore Receptacle Btm MDWt/ Grade/ Conn 60#, L-80, BTC 109#, X-65 4,099' 158' 40#, L-80, Hyd 521 JEWELRY DETAIL 9,350' 9,900' Production Liner Tubing Intermediate 2 2,375' Tubing 2,600' 26#, L-80, Hyd 563 12.6#, C-110, Hyd 521 Tubing Tubing 6.4#, L-80, W533 9.2#, L-80, EUE 9.2#, L-80, EUE 6.4#, L-80, W533 70 degree inclination @ 10,393' MD / 6,119' TVD 7 Stage 1 TOC Estimated @ 9,850' MD 0000 0 0 X Whipstock window 4,077'-4,099' MD XN SSSV ODSN-01A Proposed Schematic 9-17-2025 darci edits Last edited by: GP 9/17/2025 June 17, 2025TEAM SNUBBINGINTERNATIONALSP-12BOP Stack Drawing54.13"33.8"33.8"24.0"5000 PSI Annular5000 PSI Single Ga e VBR:2 7/8" - 5 1/2"5000 PSI Single Ga eBlinds5000 PSI Flow Cross5000 PSI Riser /D E^/KE^ΘdK> ZE ^ϭΣ&Zd/KE>E'h>ZϬ͘ϬϬ͘ϬϬϬ͘ϬϬϬцϬ͘ϬϯϬϬ͘ϬϭϱϬ͘ϬϬϱццццϭͬϭϲцϬ͘ϬϬϬϬ Ϭ͘ϬϬϭ(1(5*<6(59,&(6,&21ϬΗ'ZKhE> s >ϭϲ͘ϬϬĨƚϭϵϮΗϲϳ͘ϱϭĨƚϴϭϬΗtKZ<&>KKZZϱϰΖ'hz'hz'hz'hz'hz 'hz&'hz''hz,>K<^>K<^ D>DW^ D>DW^EKd ͗Z & ZdKK D^W ^&KZ'hz'/EWK> 'hzZ Yh/Z D Ed^ ^W WK> ^ W>Kz dK^h^dZhdhZ W>d&KZDϯϵΣϱϬΣDy^ d/KEͲEKd ͗E,KZ>K<^Dh^d W> KE^K>/'ZKhEt/d,E,KZ> d^ D /E^K/>͘Z KDD E D/E/DhDE,KZt /',dϭϴ͕ϬϬϬ>EKd ͗>/E >K^^^hD ^dZhdhZ /^&h>>z E>K^ &KZt/E>K/E''hzt/Z ^W ^ yW d >Kd E^/KEϵ͕ϬϬϬ>^ KEϭ͕ϬϬϬ>WZ Ͳd E^/KE͘ϯͬϰ/tZ /W^ϲyϭϵt/Z ZKW 'hzϴϱ&d'hzϴϱ&d'hzϴϱ&d'hzϴϱ&d'hz ϲϱ&d'hz&ϲϱ&d'hz'ϲϱ&d'hz,ϲϱ&d6'a63<,6/$1'+,/&253B*8</,1(6^, dϭK&ϭZ s͗$5&+&' E Z>EKd ^͗ϭ͘h͘E͘K͘>>&/>> dt >^dK ϭͬϰΗKEd/EhKh^͘Ϯ͘h͘E͘K͘>>hddt >^dK ϭͬϰΗKEd/EhKh^͘ϯ͘^ >t >>>dh/E'͘ϰ͘^d/<E&>hyͲKZ t >/E'WZK hZ ^Z /Ed Z,E'> KEE Yh/s> Ed^/^͘ϱ͘KEKd^> Zt/E'͘ϲ͘/&/EKhd^<͘Z/'ηZtE͗, < ͗WWZKs ͗d ͗^, d^/ ͗WZK: d/KE͗^ϬϮdKW> s >^^ D>zDW/Z h^dKD Z͗&/> ͗d/d> ͗d D^Eh/E'^, dd/d> ͗' E Z>^^zd^ϭϬϭt'η͗ϮϬϮϱͲϬϳͲϬϮ>^<^Eh/E'W<'ϮϮϳϯϰΕd, /E&KZDd/KE/E>h /Ed,/^KhD Ed/^WZKWZ/ dZzE^,>>EKd Z WZKh ͕dZE^& ZZ ͕KZ/^>K^ dKKd, Z^͕&KZEzWhZWK^ t,d^K s Z͕t/d,Khdd, tZ/dd Ehd,KZ/d/KEK&/KE E Z'z^ Zs/ ^͘ϱϬϮϯϵ͘ϵ>td͗ • • Guhl, Meredith D (DOA) From: Shannon Koh <Shannon.Koh@caelusenergy.com> Sent: Thursday, May 4, 2017 9:36 AM To: Guhl, Meredith D (DOA) Subject: RE: MDT Log ODSN-01A, PTD 216,008 Hi Meredith, It looks like typo on the Well Completion Report. Can you please file this e-mail trail and update it for us? Let me know if you need anything else! SCANNED N ' 0 8 25I?, Thanks, Shannon Koh I Sr.Site Records Coordinator Caelus Energy Alaska 13700 Centerpoint Dr.,Suite 500,Anchorage,Alaska 99503 Direct 907 343 2128 shannon.koh@caelusenergy.com From: Robert Tirpack Sent: Thursday, May 04, 2017 9:30 AM To: Andy Bond; Shannon Koh Subject: RE: MDT Log ODSN-01A, PTD 216-008 I read the well history and could not find an MDT log being run. That is a typo. Rob Robert Tirpack Drilling Operations Manager Caelus Energy Alaska robert.tirpack@caelusenergy.com 907-343-2121 Direct 907-903-9454 Mobile 907-343-2190 Fax From: Andy Bond Sent: Thursday, May 04, 2017 9:17 AM To: Robert Tirpack; Shannon Koh Subject: FW: MDT Log ODSN-01A, PTD 216-008 We did not run an MDT—might be a typo. From: Mike Morgan Sent:Thursday, May 4, 2017 9:16 AM To:Andy Bond <Andy.Bond@caelusenergy.com> Subject: RE: MDT Log ODSN-01A, PTD 216-008 We did not run an MDT in N-01A. 1 • • I believe it is a typo either referring to the MWD logs or the MPD (managed pressure drilling)—we did a few MPD pore pressure tests while drilling the lateral. From: Andy Bond Sent: Thursday, May 04, 2017 9:03 AM To: Mike Morgan Subject: FW: MDT Log ODSN-01A, PTD 216-008 Did we get an MDT in N-01A? From:Shannon Koh Sent:Thursday, May 4, 2017 9:01 AM To: Robert Tirpack<Robert.Tirpack(c@caelusenergy.com>;Andy Bond <Andy.Bond@caelusenergy.com> Subject: FW: MDT Log ODSN-01A, PTD 216-008 Rob/Andy, I am unable to find any MDT log for ODSN-01A in fileroom or my database. Can you let me know? Thanks, Shannon From: Guhl, Meredith D (DOA) [mailto:meredith.guhl@alaska.gov] Sent: Wednesday, May 03, 2017 9:42 AM To: Shannon Koh Subject: MDT Log ODSN-01A, PTD 216-008 [External Email Source] Hi Shannon, On the 10-407 Well Completion report for ODSN-01A, PTD 216-008,a MDT log was listed as completed. However a MDT log has not yet been received for this well. Can you please research and let me know what the status of the log is please? 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. 2 i 0 Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. 3 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2160080 Well Name/No. OOOGURUK NUQ ODSN-01A Operator CAELUS NATURAL RESOURCES ALA API No. 50-703-20648-01-00 MD 18811 TVD 6329 Completion Date 3/11/2016 Completion Status 1-0I1- Current Status 1 -OIL UIC No REQUIRED INFORMATION " , i) I Mud Log pa �5Vf1 QQ Samples ��`w�-Q J Directional Survey Yes DATA INFORMATION Types Electric or Other Logs Run: Gyro, MWD/LWD, DIR, DDSr, DDS, DDS -DGR, ABG/ABI, EWR, PW (data taken from Logs Portion of Master Well Data Maint) Well Log Information: Log/ Electr Data Digital Dataset Log Log Run Interval OH / Type Med/Frmt Number Name Scale Media No Start Stop CH Received Comments ED C 26903 Digital Data 3/9/2016 Electronic File: ODSN-01A XBAT CEMENT. LOG.cgm ED C 26903 Digital Data 3/9/2016 Electronic File: ODSN-01A XBAT CEMENT• LOG.emf ED C 26903 Digital Data 3/9/2016 Electronic File: PACERS CAELUS ODSN- 01 A_28Feb2016_CLR_PDF. pdf ED C 26903 Digital Data 3/9/2016 Electronic File: FACERS _CAELUS_ODSN-' 01A 28Feb2016 CLR TIF.tif ED C 26903 Digital Data P 3/9/2016 Electronic File: ODSN-01A XBAT CEMENT ° LOG.pdf ED C 26903 Digital Data 3/9/2016 Electronic File: ODSN-01A XBAT CEMENT ° LOG.tif Log C 26903 Log Header Scans 0 0 2160080 OOOGURUK NUQ ODSN-01A LOG HEADERS ED C 26981 Digital Data 3900 18811 3/24/2016 Electronic Data Set, Filename: ODSN- ' 01A_Composite+ADR Quads.las ED C 26981 Digital Data 3900 18811 3/24/2016 Electronic Data Set, Filename: ODSN- 01A_Composite.las ED C 26981 Digital Data 3900 18811 3/24/2016 Electronic Data Set, Filename: ODSN- 01 A_TC_ADR_Logs.las ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC—ADR 2in MD.cgm - ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC—ADR 2in TVD.cgm ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC—ADR 5in MD.cgm ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC_ADR 5in TVD.cgm AOGCC Page I of 5 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2160080 Well Name/No. OOOGURUK NUQ ODSN-01A Operator CAELUS NATURAL RESOURCES ALA API No. 50-703-20648-01-00 MD 18811 TVD 6329 Completion Date 3/11/2016 Completion Status 1-0I1- Current Status 1-0I1- UIC No ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A Definitive Surveys.pdf ' ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A Definitive Surveys.txt ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A Plan vs Actual - EOW.pdf ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A_Composite.dlis ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A_Composite.ver ' ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN- 01A_Comp_Geost_Imag.dlis ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN- _ 01 A_Comp_Geost_Imag.ver ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A_Geosteering.dlis , ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A_Geosteering.ver " ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01 A_TC_ADR_Logs.dlis , ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A_TC_ ADR_Logs.ver ' ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC ADR 2in MD.emf ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC ADR 2in TVD.emf ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC ADR 5in MD.emf , ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC ADR 5in TVD.emf ED C 26981 Digital Data P 3/24/2016 Electronic File: ODSN-01A TC—ADR 2in MD.pdf. ED C 26981 Digital Data 93/24/2016 Electronic File: ODSN-01A TC_ADR 2in TVD.pdf, ED C 26981 Digital Data P 3/24/2016 Electronic File: ODSN-01A TC_ADR 5in MD.pdf, ED C 26981 Digital Data p3/24/2016 Electronic File: ODSN-01A TC—ADR 5in TVD.pdf - ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC ADR 2in MD.tif ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC ADR 2in TVD.tif" ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC ADR 5in MD.tif, , ED C 26981 Digital Data 3/24/2016 Electronic File: ODSN-01A TC ADR 5in TVD.tif ' Log C 26981 Log Header Scans 0 0 2160080 OOOGURUK NUQ ODSN-01A LOG HEADERS Log C 26990 Log Header Scans 0 0 2160080 OOOGURUK NUQ ODSN-01A LOG HEADERS AOGCC Page 2 of 5 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2160080 Well Name/No. OOOGURUK NUQ ODSN-01A Operator CAELUS NATURAL RESOURCES ALA API No. 50-703-20648-01-00 MD 18811 TVD 6329 Completion Date 3/11/2016 Completion Status 1-0I1- Current Status 1-0I1- UIC No ED C 26990 Digital Data 4078 18810 4/1/2016 Electronic Data Set, Filename: ODSN-01A All In One.las ED C 26990 Digital Data 4078 18811 4/1/2016 Electronic Data Set, Filename: ODSN-01A ' Chromatograph.las ED C 26990 Digital Data 11400 18810 4/1/2016 Electronic Data Set, Filename: ODSN-01A Lith Cuttings.las ED C 26990 Digital Data 11400 18789 4/1/2016 Electronic Data Set, Filename: ODSN-01A Lith Interp.las ED C 26990 Digital Data 4078 18811 4/1/2016 Electronic Data Set, Filename: ODSN-01A ' tu�o..las ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A Definitive Surveys.pdf ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A Definitive Surveys.txt ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A FINAL END OF WELL REPORT.pdf ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 21VID DEL.emf ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 21VID FEL.emf' ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 21VID GRL.emf' ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 51VID FEL.emf ED C 26990 Digital Data Q 4/1/2016 Electronic File: ODSN-01A 21VID DEL.pdf• ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 21VID FEL.pdf' ED C 26990 Digital Data p 4/1/2016 Electronic File: ODSN-01A 21VID GRL.pdf - ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 51VID FEL.pdf ' ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 2MD DEL.tif ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 21VID FEL.tif ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 2MD GRL.tif ED C 26990 Digital Data 4/1/2016 Electronic File: ODSN-01A 5MD FEL.tif ED C 27327 Digital Data 6/22/2016 Electronic File: N01AAp1.doc ED C 27327 Digital Data 6/22/2016 Electronic File: N01AAp1.rtf . ED C 27327 Digital Data 6/22/2016 Electronic File: N01AAp2.doc, ED C 27327 Digital Data 6/22/2016 Electronic File: N01AAp2.rtf ED C 27327 Digital Data 6/22/2016 Electronic File: N01AData.xls AOGCC Page 3 of 5 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2160080 Well Name/No. OOOGURUK NUQ ODSN-01A Operator CAELUS NATURAL RESOURCES ALA API No. 50-703-20648-01-00 MD 18811 TVD 6329 Completion Date 3/11/2016 ED C 27327 Digital Data ED C 27327 Digital Data ED C 27327 Digital Data ED C 27327 Digital Data ED C 27327 Digital Data ED C 27327 Digital Data ED C 27327 Digital Data ED C 27327 Digital Data Log C 27327 Log Header Scans ED C 27638 Digital Data ED C 27638 Digital Data Log C 27638 Log Header Scans Well Cores/Samples Information: Name Cuttings INFORMATION RECEIVED Completion Report 0 Production Test Information 6 NA Geologic Markers/Tops 0 COMPLIANCE HISTORY Completion Date: 3/11/2016 Release Date: 1/22/2016 Description Completion Status 1 -OIL Current Status 1 -OIL UIC No 6/22/2016 Electronic File: N01AFig1.pdf 6/22/2016 Electronic File: N01AFig2.pdf- 6/22/2016 Electronic File: N01AFig3.pdf' 6/22/2016 Electronic File: N01AFig4.pdf' 6/22/2016 Electronic File: N01AFig5.pdf' 6/22/2016 Electronic File: N01ARept.doc 6/22/2016 Electronic File: N01ARept.rtf . 6/22/2016 Electronic File: N01ASums.xls ' 0 0 2160080 OOOGURUK NUQ ODSN-01A LOG HEADERS 4/28/2016 Electronic File: Caelus Energy Alaska - ODSN- 01a - Disclosure Report Rev1.xml 4/28/2016 Electronic File: Caelus Energy Alaska - ODSN- ' 01a - Disclosure Report _6831606_03.pdf 0 0 404 CD - PTD Hydraulic Fracture Data Interval / Start Stop 11382 18811 Directional / Inclination Data Mechanical Integrity Test Information Y / 1� Daily Operations Summary l./ Date Comments Sent Received 3/29/2016 Sample Set Number Comments 1578 Mud Logs, Image Files, Digital Data NA Composite Logs, Image, Data Files Cuttings Samples Ul / NA Core Chips Y / Core Photographs Y / Laboratory Analyses Y /& AOGCC Page 4 of 5 Thursday, January 19, 2017 DATA SUBMITTAL COMPLIANCE REPORT 1/19/2017 Permit to Drill 2160080 Well Name/No. OOOGURUK NUQ ODSN-01A Operator CAELUS NATURAL RESOURCES ALA API No. 50-703-20648-01-00 MD 18811 TVD 6329 Completion Date 3/11/2016 Completion Status 1-0I1- Current Status 1-0I1- UIC No Comments: Compliance Reviewed : Date: — _� AOGCC Page 5 of 5 Thursday, January 19, 2017 AUG � 2 2016 0G� C CAIPLUS Energ Alaska 21 6008 26 98 1 LETTER OF TRANSMITTAL DATA LOGGED % / M/201C. ;.1. K. BENDER DATE: August 10, 2016 DESCRIPTION . ftfttn: Shannon Koh GCC Caelus Energy Alaska Makana Bender 3700 Centerpoint Dr., Suite 500 333 W. 7t' Avenue, Suite 100 Anchorage, AK 99503 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑Maps CD -R Other -Logs ❑ Agreement n1=TAn QTY DESCRIPTION ODSN-01A (50-703-20648-0100) 1 CD Digital graphic logs, digital log data, definitive surveys, Geosteering Data 4 Well Logs ABG, DGR/GM, EWR-Phase 4, ADR, ALD, CTN, Invert/Revert Sections (1:240, 1:600) TVD; ROP, ABG, DGR/GM, EWR-Phase 4, ADR, ALD, CTN, Horizontal Presentation (1:240, 1:600) MD ioowiv wim Gvrreciea Neutron Porosity curves Received by:fij.4& "Date: Please sign an return one copy to: Caelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.kohCa)-caelusenergy com RECEIVED 21 60 08 i� CAELUS AaTTER OF TRANSMITTAL Energy Alaska DATA LOGGED iV /ZX201Cr M K.BENDER DATE: June 21, 2016 ❑ Maps O Other - Binder Shannon Koh AOGCC Caelus Energy AlaskaAttn: Makana Bender 3700 Centerpoint Dr., Suite 500 333 W. 7th Avenue, Suite 100 Anchorage, AK 99503 nchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ CD -R ❑ Agreement Other - Binder nFTn11 QTY DESCRIPTION Palynostratigraphy of a short section: 1 binders (CD included) ODSN-01 A(50-703-20648-01 00) 20400 ft. — 21211 ft. Received by: A_ia ,'A Date: Please sign and return one copy to: Caelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon. koh(a)-caelusenergy.com DATA LOGGED STATE OF ALASKA kO/t3/201ro AL :A OIL AND GAS CONSERVATION COMI 31ON M. K. BENDER REPORT OF SUNDRY WELL OPERATIONS RECEIVED APR 2 8 2016 Arv3cc 1. Operations Abandon Ld Plug Perforations Fracture Stimulate ✓ Pull Tubing Li Operations shutdown Performed: Suspend ❑ Perforate ❑ Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Redrill ❑ Brforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other: ❑ 2. Operator 4. Well Class Before Work: 5. Permit to Drill Number: Name: Caelus Natural Resources Alaska, LLC Development ❑✓ Stratigraphic❑ Exploratory ❑ Service ❑ 216.008 6 3. Address: 6. API Number: 3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503 50-703-20648-01-00 7. Property Designation (Lease Number): 8. Well Name and Number: ADL 355036 / ADL 389959 ODSN-01A 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pool(s): N/A Ooo uruk Nui sut Oil 11. Present Well Condition Summary: Total Depth measured 18,811' feet Plugs measured N/A feet true vertical 6,329' feet Junk measured N/A feet Effective Depth measured 18,440' feet Packer measured See attachment, pg. 3 feet true vertical 6,240' feet true vertical See attachment, pg. 3 feet Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A N/A Surface 4,060' 11-3/4" 4,099' 3,238' 5,830 psi 3,180 psi Intermediate 4,017' 9-5/8" 7,940' 5,003' 5,750 psi 3,090 psi Production 11,318' 7" 11,354' 6,272' 7,240 psi 5,410 psi Liner 7,432' 4-1/2" 18,440' 6,240' 11,590 psi 9,200 psi Perforation depth Measured depth see attachment, pg. 2 feet True Vertical depth see attachment, pg. 2 feet Tubing (size, grade, measured and true vertical depth) 4-1/2", 12.6# C-110, Hydril 521 11,152' MD 6,254' TVD Packers and SSSV (type, measured and true vertical depth) See attachment, pg. 3 12. Stimulation or cement squeeze summary: Intervals treated (measured): SEE ATTACHED POST JOB REPORTS FROM VENDOR Treatment descriptions including volumes used and final pressure: 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: 0 0 0 1 0 Subsequent to operation: 2294 823 518 1723 480 14. Attachments (required per 20 AAc 25.070, 25.071, 8 25.283) 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 ❑ Printed and Electronic Fracture Stimulation Data 2 GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: 316-194 Contact Jack Kralick, 343-2185 Email lack.kralick(a)caelusenergy.com Printed Name Jack Kralick Title Wells Superintendent Signature Phone 907-343-2185 Date Form 10-404 Revised 5/2015 / n �J J X16 ,� —�--/� �" ' fi�l /� Submit Original Only RBDMS 0, APR 2 9 2016 Wallace, Chris D (DOA) From: Jack Kralick < Jack. Kral ick@caelusenergy.com> Sent: Tuesday, May 10, 2016 9:23 AM To: Wallace, Chris D (DOA) Cc: Schwartz, Guy L (DOA) Subject: RE: ODSN-01A PTD 2160080 Sundry 316-194 Hydraulic Fracturing Hello Chris, Sorry about the delay — we've had our contractors on holiday after the frac season. The below is a response to your questions: I've asked our disclosure team about the "Unknown" CAS # and this is what they had to say: Regarding the issue with the Unknown CAS number for potassium salt of maleic -acid co -polymer in the post job disclosure report, this is the explanation: The prejob report for this well was revised and generated in December of 2015 based on the most current composition information we had from the supplier back then. Earlier this year, we received word from the supplier that although the product composition had not changed, the CAS numbers needed to be revised to clearly represent the product provided to Schlumberger. Previously, the CAS numbers were listed for ingredients that the supplier uses to make the product but once mixed, they form the polymer salt in the final product. The revised listing now includes potassium salt of maleic acid co -polymer but unfortunately, there is no CAS number available from the supplier for this ingredient yet therefore, the CAS is currently labeled as Unknown. Nonetheless, we have reached out to the supplier requesting an update for this ingredient CAS number. Note that is issue is only tied to one chemical within the disclosure. Let me know if we need to provide more information. Thanks Chris, Jack From: Wallace, Chris D (DOA)[mailto:chris.wallace(&alaska.g_ov] Sent: Wednesday, May 04, 2016 8:46 AM To: Jack Kralick Cc: Schwartz, Guy L (DOA) Subject: ODSN-01A PTD 2160080 Sundry 316-194 Hydraulic Fracturing Jack, AOGCC has received the 10-404 for the recent frac of ODSN-01A. The 10-404 chemical disclosure has an additive potassium salt of maleic acid co -polymer with "CAS Not Assigned". The fracfocus submission lists the CAS # as "UNKNOWN" The sundry application 316-194 lists all additives and their CAS numbers. Did Caelus use an additive that was not disclosed in the frac application or is there additional information you can provide? Thanks and Regards, Chris Wallace Sr. Petroleum Engineer Alaska Oil and Gas Conservation Commission Attachment 2 AOGCC Form 10-404 Sundry Report Box 11- Perforation Locations Well: ODSN-01A To MD Bottom(MD) Length ft To TVD Bottom (TVD) 4-1/2" RapidStage Sleeve #11 11,618 11,621 2.71 6,288 6,289 4-1/2" RapidStage Sleeve #10 12,271 12,274 2.71 6,282 6,282 4-1/2" RapidStage Sleeve #9 12,841 12,844 2.71 6,272 6,272 4-1/2" RapidStage Sleeve #8 13,495 13,498 2.71 6,262 6,262 4-1/2" RapidStage Sleeve #7 14,144 14,147 2.71 6,247 6,247 4-1/2" RapidStage Sleeve #6 14,711 14,714 2.71 6,230 6,230 4-1/2" RapidStage Sleeve #5 15,321 15,324 2.71 6,224 6,224 4-1/2" RapidStage Sleeve #4 15,967 15,970 2.71 6,216 6,216 4-1/2" RapidStage Sleeve #3 16,786 16,789 2.71 6,218 6,218 4-1/2" RapidStage Sleeve #2 17,399 17,402 2.71 6,214 6,214 4-1/2" RapidStage Sleeve #1 18,255 18,258 2.71 6,223 6,223 Pre -Perforated Pup 18,420 18,425 4.69 6,237 6,237 Pre -Perforated Pup 18,424 18,429 4.69 6,238 6,238 PACKERS 5" x 7" Baker ZXP Liner Top Packer 11,119' 6,251' HES Swell Packer #13 11,404' 6,276' HES Swell Packer #12 11,444' 6,280' HES Swell Packer #11 11,891' 6,286' HES Swell Packer #10 12,422' 6,280' HES Swell Packer #9 13,199' 6,266' HES Swell Packer #8 13,850' 6,253' HES Swell Packer #7 14,378' 6,240' HES Swell Packer #6 14,945' 6,229' HES Swell Packer #5 15,631' 6,219' HES Swell Packer #4 16,367' 6,221' HES Swell Packer #3 17,102' 6,216' HES Swell Packer #2 17,672' 6,211' HES Swell Packer #1 18,366' 6,231' A Operations Summary Report -State CE ELUS rncrgya Alaska Well Name: ODSN-01A Contractor: Rig Number: Job Category: FRAC Start Date: 3/12/2016 End Date: Start Depth FooVMeters Dens Last Start Date End Date (ftKB) (ft) Mud (lb/gal) Summary 3/12/2016 3/13/2016 0.0 00:00 3/12/16 - 00:00 3/13/16 * Vetco installed VR plug & secondary 10k gate valve. Vetco pulled TWC utilizing hydraulic lubricator. * Stand by for Nabors 19AC to complete the rig move to ODSN-20i. * Stand by for the SLB coil unit to spot in on ODSN-07i. 3/13/2016 3/14/2016 0.0 00:00 3/13/16 - 00:00 3/14/16 * MIRU HES Slickline w/.125 wire. * Drifted w/3.83" gauge ring to SVLN @ 2,156' slm. * Pulled 4.5" Dummy SSSV from SVLN @ 2,156' slm. * Set 4.5 X catcher sub in X nipple @ 2,924' sim. / * Pulled 1" DCK shear valve from GLM # 3 @ 2,806' slm. * Set 1" Dummy GLV (BK -4) in GLM # 3 @ 2,806' slm. I * LRS MIT -IA to 4000 psi for 30 minutes. Test charted and put in well file. * Vetco removed 7" tree cap flange & installed 4" 1002 10k flange. * MIRU SLB cement unit and 2" hardline. Pressure test lines to 7000 psi. *_SLB MIT -Tubing to 6050 psi. Test passed on first attempt. * RDMO SLB Cement unit & 2" 1502 hardline from wellhead. * Vetco removed 4" 1002 10k flange and installed 7" 5k flange w/otis connection. * Pulled Ball & Rod from RHC plug @10,287' slm. * Pulled RHC -M plug body from 10,292' slm. 3/14/2016 3/15/2016 0.0 00:00-06:00 3/14/16 * Drifted w/3.34" centralizer & sample bailer to 10,830' slm. Tools stopped due to deviation. No sample. * Drift 4.5 Frac Isolation Sleeve(3.12" ID) on surface w/3.009" ball prior to running in the hole. * Set 4.5 Frac Isolation Sleeve(3.12" ID) in the XXO nipple @ 2,146' slm. Establish control line integrity to 5000 psi. * RDMO HES Slickline. Spot unit on staging pad until area is cleared on ODSN-26i. 3/26/2016 3/27/2016 00 00:00 3/26/16 - 00:00 3/27/16 * Complete Frac program for stages 1 - 4. * Rig up SLB lines to Wellhead and pressure test same * Frac stages 1 - 4, max 8 ppa per stage * Cut 8 ppa stage in 3rd frac and exteneded 4-8 ppa stages in 4th frac (� * Total prop pumped: 700,800 lbs 16/20 CarboBondl-ite as per SLB load tickets r r * Total bbls Slurry: 7114 bbis * Freeze Protect past Well Head: 61 bbis (4000' MD) * Max Pressures: 8115 psi WHP, 9067 psi BHP, 3570 psi IA, 3 psi OA 3/27/2016 3/28/2016 0.0 00:00 3/27/16 - 00:00 3/28/16 * Complete frac stages 5-7. * 700,209 lbs 16/20 CBL metered at end of stage. * 2.681" DM ball dropped at 5798 bbls, 21 bpm - Heard it clear the well head. 5983 bbis slow rate to ball seat. 5993 blls away and 2.681" DM ball seats. * Max Pressure: WHP: 7886 psi, BHP: 6815 psi, IA:3608 psi, OA: 14 psi. * 6202 bbls total slurry on job. * Final SIP: WHP 1368 psi, BHP: 3826 psi, IA: 156 psi, OA: 0 psi. 3/28/2016 3/29/2016 0.0 00:00 3/28/16 - 00:00 3/29/16 . Loading and Heating Frac tanks via Nanuq and LRS. * Rig up HES combo unit pulled and re -set Frac Isolation Sleeve. * Tested Frac Isolation Sleeve to 5000 psi. Good test. * RDMO HES Combo equipment. Page 1/3 ReportPrinted: 4/28/2016 1 Operations Summary Report -State Well Name: ODSN-01A CE CAELUS Fncrqy Alaska. Start Depth Foot(Meters Dens Last Start Date End Date (ftKB) (ft) Mud (lb/gal) Summary 3/29/2016 3/30/2016 0.0 00:00 3/29/16 - 00:00 3/30/16 * Nanuq continues with maintenance to Frac pad. * Frac operations begin. * 716370 lbs 16/20 CBL metered at end of stage * 2.925"DM Ball dropped at 5057 bbls 21 bpm. Heard it clear the well head. 5214 bbls slow rateto ball seat * 5231 bbls away and 2.925" DM-XTball seats. * Max Pressure: WH: 7915 psi, BHP: 6074 psi, IA: 3536 psi, OA: 10 psi. * 5441 bbls total slurry on job. * Bled pressure on WH & IA to zero. * Final Shut In Pressures. WH: 1566 psi, BHP: 4018 psi, IA: 3069 psi, OA: 10 psi. * Frac operations concluded. 3/30/2016 3/31/2016 0.0 00:00 3/30/16 - 00:00 3/31/16 * Rig up SLB frac equipment * Function the GE accumulator and valve * Fluid pack all lines and prime the pumps S * Safety meeting * Pump stages 11 and 12 f * Freeze protect the TBG with 40 bbls diesel. Total slurry 3600 bbls * Prop metered per Frac cat 487,000 lbs - Prop per load out sheets 486,400 lbs SIP TBG - 1890 psi - IA 3110 psi - OA 4402 psi 3/31/2016 4/1/2016 0.0 00:00 3/31/16 - 00:00 4/1/16 * Rig down and move SLB frac ground support iron. * Vetco removed frac hydraulic valve & installed 7" otis flange. * MIRU HES Slickline w/.125 wire. * Drifted w/3.84" gauge ring to SVLN @ 2156 slm * Pulled 4.5 Frac Isolation Sleeve from SVLN @ 2156 slm * Drifted w/KJ, 4.5 Brush, 2' weight bar & 3.80" gauge ring to X nipple @ 4/1/2016 4/2/2016 00 00:00 4/1/16 - 00:00 4/2/16 * MIRU LRS Hot Oil to support Slick Line brush & flush operations. * Perform brush & flush operations w/KJ, 4.5 BLB, 2' weight bar, & 3.70" gauge ring to 10,320' slm. * LRS pumped 160 bbls of diesel during brush & flush operations. * Attempt to set 4.5" XX plug body. Unable to get past 48' slm. * Drifted w/KJ, double 4.5" BLB's, & 3.80" gauge ring to XN nipple @ 10,285' slm. Schlumberger FracCAT Treatment Report Well : ODSN-01 a, Stages 1-4 Field :Oooguruk Formation Nuigsut Prepared for 490 Client : Caelus Energy Alaska Client Rep Mike Martin Date Prepared : 03/26/16 Prepared by Surface Shut in Pressure(psi) Name Alexander Martinez Division : Schlumberger Phone :561-389-5006 Pressure (All Zones) Initial Wellhead Pressure (psi) 490 Initial BHP at Gauge (psi) 3,080 Final Surface ISIP (psi) 1,630 Final ]SIP at Gauge (psi) 4,095 Surface Shut in Pressure(psi) 1,450 BH Shut in Pressure (psi) 3,890 Maximum Treating Pressure (psi) Treatment Totals (All Zones As Per Total Slurry Pumped Water+Adds+Proantbbls FracCAT) 8,111 7,114 BH Gauge at 10,204' MD, 6,045' TVD Total YF127ST Past Wellhead (bbls) 5,758 Total WF125 Past Wellhead (bbls) 542 Total Freeze Protect Past Wellhead bb]s 60 Total Proppant Pumped (lbs.) Total .. F103 (gal) 274 700,800 274 Total Proppant in Formation (lbs.) M275 (lbs.) 0 700,800 0 L065 (gal) 541 541 J218 (lbs.) 165 165 J580 (lbs.) 6968 6968 J475 (lbs.) 1540 1540 J922(mgal) 242 242 J134 (lbs.) 0 0 J510(bb1s) 0 1.0 J450 (gal) 96 96 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. schlumbe,poep Summary Client: Caelus Energy Alaska Well: ODSN-1 a Formation: Nuiqsut District: Prudhoe Bay Country: United States On March 26, 2016, Schlumberger finished stages 1-4 for the ODSN-01a well. The treatment consisted of 4 stages with 3 Rapid ball DM ball drops and one DM -XT ball drop. Approximately 700,800 lbs of proppant in 7,114 bbl of slurry was pumped during this treatment. The well was freeze protected using physical straps from the freeze protect transport and it was determined that 60 bbls of freeze protect fluid made it into the well. All stages were pumped as designed and the summary for the totals is noted below. a Materials Actual (Design) Slurry Volume- All Volumes (bbl) 7,114 (7,085) Clean Fluid- All Volumes (bbl) 6,080 (6,347) Proppant, lbs. 700,800 (700,800) Pressure Test — Tr. Pressure IA Pressure BHP Caelus Energy Alaska ODSN-01 a 03-26-2016 50 40 30 fD t7 Cr 20 -' y a 10 0 10:54:53 11:01:33 11:08:13 11:14:53 11:21:33 Time - hh:mm:ss -20 -18 -16 14 -12 'o 10 O 8 6 a 4 2 0 100 M a d 6000 RoOR, 2000 011 Main Treatment 5:56 Tr. Pressure IA Pressure BHP Slurry Rate -- PCM Viscosity Prop Con BH Prop Con T-- 13:14:16 14:12:36 1510:56 Time - hh:mm:ss Caelus Energy Alaska ODSN-01 a 03-26-2016 50 40 30 CD a- 7 20 _< N� n Cr 10 0 16:09:16 3 3 Stage 1: Summary Stage 1 consisted of a PAD, 8 proppant steps (1-8PPA), a ball drop and a flush. Flush at the WH was called at 958 bbls and the 2.236" Rapidball DM ball was dropped at 986 bbls to open Port 1 for Stage 2. The ball seated at 1,246 bbls of total slurry. Total Proppant Pumped (lb) Summary of 72,715 Stage 1 Max pumping Rate (bpm) 40.3 Total Proppant in Formation (lb) 72,715 Average Pumping Rate (bpm) 35.1 Total Slurry Pumped (bbls) 987 Maximum Treating Pressure (psi) 7,969 YF127ST Pumped (bbls) 610 Average Treating Pressure (psi) 6,041 WF127 Pumped (bbls) 300 Average Viscosity of WF 127 (cP) 18.5 Freeze Protect (bbls) 0 Stage 1 10000 8000 .N Q 6000 Vl N N 4000 2000 0 Tr. Pressure IA Pressure BHP Slurry Pnfa PCM Viscosity — Prop Con BH Prop Con Caelus Energy Alaska ODSN-01 a 03-26-2016 50 40 30 fD a a 20 -' N 10 Cr 3 S' 0 12:36:37 12:44:57 12:53:17 13:01:37 13:09:57 Time - hh:mm:ss 20 18 16 14 12 0 �10 0 k0 8 v -6 n �4 2 10 Schlumbugep Stage 1: As Measured Pump Schedule Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country. United States Step # Step Name Stage Average Slurry Rate (bbl/min) Pressures & Maximum Slurry Rate (bbl/min) Rates Average Treating Pressure (psi) As Measured Pump Schedule Break Down 35.4 40.5 Step Step Slurry Slurry Pump 36.7 Fluid Drax op Prop Prop � Name Volume Rate Time Fluid Name Volume Proppant Name 2.0 PPA 40.0 40.1 6167 (bbl) (bbl/min) (min) 3.0 PPA (gal) ConicConicMass (PPA) (lb) 6238 6 4.0 PPA 39.8 39.9 6575 6628 (PPA) 5.0 PPA 39.7 Break 6747 6934 6628 6.0 PPA 39.7 39.9 7109 1 Down 300 35. 9.5 WF127 12600 0 0 10 2 PAD 160 36.', 5 YF127ST 671 CarboLite w/ 5% CSG 16/20 01 0 39.8 3 1.0 PPA 40 39. 1 YF127ST 1617 CarboLite w/ 5% CSG 16/20 1.1 0.2 137 4 2.0 PPA 55 4 1.4 YF127ST 2136 CarboLite w/ 5% CSG 16/20 2 1.6 389 5 3.0 PPA 69.9 39. 1.8 YF127ST 2607 CarboLite w/ 5% CSG 16/20 3 2.4 744 6 4.0 PPA 69. 39.E, 1.8 YF127ST 2510 CarboLite w/ 5% CSG 16/20 4.1 1.9 9648 7 5.0 PPA 69. 39.A 1.8 YF127ST 2419 CarboLite w/ 5% CSG 16/20 5 4.6 1169 8 6.0 PPA 69J 39.A 1.8 YF127ST 2334 CarboLite w/ 5% CSG 16/20 6.11 2.5 1363 9 7.0 PPA 54. 39.7 1.4 YF127ST 177A CarboLite w/ 5% CSG 16/20 71 3 1206 10 8.0 PPA 44. 39.5 1.1 YF127ST 14031 CarboLite w/ 5% CSG 16/20 8.1 2.6 10931 Clear 11 Lines 24 39.3 0.6 YF127ST 946 CarboLite w/ 5% CSG 16/20 8.1 2.1 202 12 1 Spacer 1 29 31.1 0.9 YF127ST 1049 0 0 13 Ball 2.236" "21 01 YF127ST 126 0 0 0 Step # Step Name Stage Average Slurry Rate (bbl/min) Pressures & Maximum Slurry Rate (bbl/min) Rates Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 Break Down 35.4 40.5 6767 8102 1537 2 PAD 36.7 0.4 5074 5831 1267 1.0 PPA 39.5 39.8 5893 6030 5836 2.0 PPA 40.0 40.1 6167 6238 3032 5 3.0 PPA 39.9 40.1 6359 6481 6238 6 4.0 PPA 39.8 39.9 6575 6628 6486 5.0 PPA 39.7 39.8 6747 6934 6628 6.0 PPA 39.7 39.9 7109 7300 948 9 7.0 PPA 39.7 39.7 7474 7648 7305 10 8.0 PPA 39.5 39.7 7783 7909 7653 11 Clear Lines 39.3 39.8 7826 7946 7731 12 Spacer 31.1 40.2 5381 7946 3620 13 Ball 2.236" 21.0 21.0 K124 14267 037 Schlumberger Stage 2: Summary Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Stage 2 consisted of a PAD, 8 proppant steps (1-8PPA), a ball drop and a flush. Flush at the WH was called at 2674 bbls and the 2.307' Rapidball DM ball was dropped at 2700 bbls to open Port 2 for Stage 3. The ball seated at 2946 bbls of total slurry. I Total Proppant Pumped (lb) Summary 189,012 of Stage 2 Max pumping Rate (bpm) 40.2 Total Proppant in Formation (lb) 189,012 Average Pumping Rate (bpm) 37.1 Total Slurry Pumped (bbls) 1,715 Maximum Treating Pressure (psi) 8,111 YF127ST Pumped (bbls) 1,517 Average Treating Pressure (psi) 6,725 WF127 Pumped (bbls) 0 Average Viscosity of WF 127 (cP) 18.5 Freeze Protect (bbls) 0 Q d V) CDU) IL Stage 2 Tr. Pressure IA Pressure BHP Slurry Rata Caelus Energy Alaska ODS N-01 a 03-26-2016 50 40 7a m 30 0 0 13:02:24 13:19:04 13:35:44 13:52:24 14:09:04 Time - hh:mm:ss r20 �18 i �16 14 �12 -10 o 3 6 n �4 �2 0 schlumbepoep Stage 2: As Measured Pump Schedule Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States 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) As Measured Pump Schedule 35.6 37.6 526 7007 Step Step Slurry Slurry Pump 108 Fluid 2984 PMraax op Prop Prop # Name Volume Rate Time Fluid Name Volume Proppant Name 6511 Conc Mass 5 2.0 PPA (bbl) (bbl/min) (min) 6495 (gal) Conc (PPA) (Ib) 6441 6522 3376 4.0 PPA 39.7 39.8 6732 (PPA) i522 8 1 PAD 2 247 35.6 7.1 YF127ST 10374 6.0 PPA 0 0 7632 7841 Slow for 10 7.0 PPA 39.0 39.3 7994 8097 7841 11 8.0 PPA 2 Seat 50 20.2 2.8 YF127ST 2100 37.2 38.1 0 8056 7740 Resume Spacer 30.0 38.3 5395 8051 P583 14 IB all 2.307" 21.1 3 PAD 130 39.1 3.3 YF127ST 5460 0 p 4 1.0 PPA 110 39.7 2.8 YF127ST 4437 CarboLite w/ 5% CSG 16/20 1 0.4 4091 5 2.0 PPA 144.9 39.9 3.6 YF127ST 5609 CarboLite w/ 5% CSG 16/20 2 1.3 1078 6 3.0 PPA 179.8 39.8 4.5 YF127ST 6686 CarboLite w/ 5% CSG 16/20 3 2.5 1961 7 4.0 PPA 179.7 39.7 4.5 YF127ST 64351 CarboLite w/ 5% CSG 16/20 41 0 25246 8 5.0 PPA 179.7 39.6 4.5 YF127ST 6202 CarboLite w/ 5% CSG 16/20 5.1 3.8 3048 9 6.0 PPA 179.6 39.4 4.6 YF127ST 5985 CarboLite w/ 5% CSG 16/20 6.1 0.4 3538 10 7.0 PPA 144.6 39 3.7 YF127ST 4659 CarboLite w/ 5% CSG 16/20 7.1 1 32141 11 8.0 PPA 119.7 38 3.2 YF127ST 3731 CarboLite w/ 5% CSG 16/20 8.1 0.6 2941 Clear 12 Lines 24. 37. 0.7 YF127ST 94 CarboLite w/ 5% CSG 16/20 8 0 1857 13 Spacer 23 30. 0.9 YF127ST 966 0 0 Ball 14 2.307 " 3 21.1 0.1 YF127ST 126 0 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 PAD 2 35.6 37.6 526 7007 2929 2 Slowfor Seat 20.2 32.9 108 5315 2984 Resume PAD 39.1 40.0 6319 6577 5355 1.0 PPA 39.7 40.1 6511 6577 i444 5 2.0 PPA 39.9 40.1 6404 6495 6376 3.0 PPA 39.8 39.9 6441 6522 3376 4.0 PPA 39.7 39.8 6732 6893 i522 8 5.0 PPA 39.6 39.7 7179 17375 16893 6.0 PPA 39.4 39.6 7632 7841 7378 10 7.0 PPA 39.0 39.3 7994 8097 7841 11 8.0 PPA 38.0 38.5 8070 8097 8029 12 Clear Lines 37.2 38.1 7885 8056 7740 13 Spacer 30.0 38.3 5395 8051 P583 14 IB all 2.307" 21.1 21.2 141 192 032 Schlumberger Stage 3: Summary Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Stage 3 consisted of a PAD, 7 proppant steps (1 -IPPA), a ball drop and a flush. The 8 PPA step was cut from this stage as it looked like net pressure was building. Flush at the WH was called at 4272 bbls and the 2.379" Rapidball DM ball was dropped at 4,298 bbls to open Port 3 for Stage 4. The ball seated at 4,535 bbls of total slurry. Total Proppant Pumped (lb) Summary of 159,266 Stage 3 Max pumping Rate (bpm) 40.3 Total Proppant in Formation (lb) 159,266 Average Pumping Rate (bpm) 37.0 Total Slurry Pumped (bbl) 1,597 Maximum Treating Pressure (psi) 7,612 YF127ST Pumped (bbl) 1,430 Average Treating Pressure (psi) 6,070 WF127 Pumped (bbl) 0 Average Viscosity of WF127 (cP) 18.1 Freeze Protect 0 il a Stage 3 Tr. Pressure IA Pressure BHP Caelus Energy Alaska ODSN-Ola 03-26-2016 50 -20 �18 40 16 14 W 30 12 a o a 10 n 3 0 20 ' 8 < v N � 6 D c 10 4 3 2 -0 0 13:51:14 14:07:54 14:24:34 14:41:14 14:57:54 Time - hh:mm:ss Schlumberger Stage 3: As Measured Pump Schedule Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuigsut District. Prudhoe Bay Country: United States 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) As d Pump Schedule 35.2 7.3 3581 7099 3559 2 Slow for Seat 20.1 1.3 3728 4587 2723 Step Step Slurry Slurry Pump 4682 Fluid 1.0 PPA Max Prop Prop Prop 6051 Name Volume Rate Time Fluid Name Volume Proppant Name 5767 Cone Mass 39.5 39.6 (bbl) (bbl/min) (min) (gal) 39.4 Cone (PPA) (Ib) 5973 8 5.0 PPA 39.2 39.4 6641 6820 6394 (PPA) 6.0 PPA 39.0 1 PAD 3 234 35.A 6.7 YF127ST 9827 39.0 a 0 7168 11 Slowfor 39.1 39.6 17510 7584 7474 12 Spacer 31.0 39.9 2 Seat 50 20.1 2. YF127ST 2100 0734 3882 0 0 Resume 3 PAD 145 39 3.7 YF127ST 6090 0 0 4 1.0 PPA 110 39.4 2.8 YF127ST 4437 CarboLite w/ 5% CSG 16/20 1 0.9 408 5 2.0 PPA 144.9 39.q 3.7 YF127ST 5609 CarboLite w/ 5% CSG 16/20 4 1.1 10781 6 3.0 PPA 179.8 39. 4.5 YF127ST 6687 CarboLite w/ 5% CSG 16/20 31 1.7 19597 7 4.0 PPA 179.7 39.2 4.6 YF127ST 6437 CarboLite w/ 5% CSG 16/20 3.1 25221 8 1 5.0 PPA 1 179.7 39, 4.6 YF127ST 6202 CarboLite w/ 5% CSG 16/20 5.11 4 30491 9 6.0 PPA 179.6 3 4.6 YF127ST 5984 CarboLite w/ 5% CSG 16/20 6.1 3.5 3539 10 7.0 PPA 147.7 38.E 3,8 YF127ST 4763 CarboLite w/ 5% CSG 16/20 7 0 32705 Clear 11 Lines 20. 1 39.1 0. YF127ST 1 815 CarboLite w/ 5% CSG 16/20 7 0 99 12 Spacer 23 31 0.8 YF127ST 966 0 0 Ball 13 2.379 " 3 20. 0.1 YF127ST 126 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 PAD 3 35.2 7.3 3581 7099 3559 2 Slow for Seat 20.1 1.3 3728 4587 2723 Resume PAD 39.0 40.1 3819 6060 4682 1.0 PPA 39.4 40.1 5883 6051 5767 5 2.0 PPA 39.6 39.7 i799 5840 5767 3.0 PPA 39.5 39.6 5856 5973 5767 4.0 PPA 39.4 39.5 6215 6389 5973 8 5.0 PPA 39.2 39.4 6641 6820 6394 9 6.0 PPA 39.0 39.2 7028 7168 6820 10 7.0 PPA 38.8 39.0 7334 7493 7168 11 Clear Lines 39.1 39.6 17510 7584 7474 12 Spacer 31.0 39.9 004 7584 3153 13 Ball 2.379" 20.9 20.9 0734 3882 P666 Schlumberger Stage 4: Summary Client: Caelus Energy Alaska Well: ODSN-la Formation: Nuiqsut District: Prudhoe Bay Country: United States Stage 4 consisted of a PAD, 8 proppant steps (1-8PPA), a ball drop and a flush. Approximately 30K lbs of proppant was added into this stage that had been taken away from Stage 3. The proppant was added by adding 25 bbls in Step 4, 25 bbls in Step 5, 25 bbls in Step 6, and 40 bbls in Step 7. Flush at the WH was called at 6,646 bbls and the 2.452" Rapidball DM -XT ball was dropped at 6,672 bbls to open Port 3 for Stage 4. The ball seated at 6,892 bbls of total slurry. a Stage 4 Tr. Pressure IA Pressure Caelus Energy Alaska ODSN-01 a BHP 03-26-2016 50 40 30 0 c 3 20 ' a 10 3 0 14:27:51 14:48:41 15:09:31 15:30:21 15:51:11 Time - hh:mm:ss 20 18 16 �14 12 0 10 0 0 �8 v 6 a �4 �2 0 Summary of Stage Total Proppant Pumped (lb) 279,807 Max pumping Rate (bpm) 40.3 Total Proppant in Formation (lb) 279,807 Average Pumping Rate (bpm) 38.1 Total Slurry Pumped (bbl) 2,816 Maximum Treating Pressure (psi) 8,060 YF127ST Pumped (bbl) 2,201 Average Treating Pressure (psi) 6,374 WF127 Pumped (bbl) 242 Average Viscosity of WF127 (cP) 18.1 Freeze Protect (bbls) 79 a Stage 4 Tr. Pressure IA Pressure Caelus Energy Alaska ODSN-01 a BHP 03-26-2016 50 40 30 0 c 3 20 ' a 10 3 0 14:27:51 14:48:41 15:09:31 15:30:21 15:51:11 Time - hh:mm:ss 20 18 16 �14 12 0 10 0 0 �8 v 6 a �4 �2 0 SchlumbepUep Stage 4: As Measured Pump Schedule Client: Caelus Energy Alaska Well: DDSN-1a Formation: Nuigsut District: Prudhoe Bay Country: United States 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) As Measured Pump Schedule PAD 4 35.2 37.5 5944 Ste p Ste Slurry Slurry Pump 33.5 Fluid 4607 PMraax op Prop Prop 39.7 Name Volume Rate Time Fluid Name Volume Proppant Name Conc Conc Mass 5607 5 (bbl) (bbl/min) (min) 5529 (gal) 5488 (PPA) (Ib) 40.0 5763 5968 5497 4.0 PPA 39.8 39.9 (PPA) 6431 5973 1 PAD 4 226 35.2 6.5 YF127ST 9493 9 0 0 0 7301 Slow for 7017 10 7.0 PPA 39.3 39.5 7686 7818 7506 11 2 Seat 50 21. 2.7 YF127ST 2100 Clear Lines 39.3 0 0 8024 Resume 13 Spacer 31.0 39.8 7982 3327 14 B all 2.452" 3 PAD 275 39.7 6.9 YF127ST 11550 133.8 a 0 0 4 1.0 PPA 139.9 39.4 3.6 YF127ST 5644 CarboLite w/ 5% CSG 16/20 1 0.5 5273 5 2.0 PPA 189.8 39.1 4.9 YF127ST 7345 CarboLite w/ 5% CSG 16/20 2 0.9 14251 6 3.0 PPA 234.7 39.5 5.9 YF127ST 8727 CarboLite w/ 5% CSG 16/20 3 1.2 2566 7 4.0 PPA 1 260.1 39.4 6.5 YF127ST 93091 CarboLite w/ 5% CSG 16/20 4.11 0 3669 8 5.0 PPA 260. 39.-, 6.6 YF127ST 8980 CarboLite w/ 5% CSG 16/20 5.1 0 44279 9 6.0 PPA 260 39. 6.6 YF127ST 8660 CarboLite w/ 5% CSG 16/20 6.1 0 51336 10 7.0 PPA 229. 39. 5.q YF127ST 7401 CarboLite w/ 5% CSG 16/20 7.1 0 51210 11 8.0 PPA 207. 38. 5.3 YF127ST 6462 CarboLite w/ 5% CSG 16/20 8.5 0 50916 Clear 12 Lines 15.8 39. 0.4 YF127ST 656 CarboLite w/ 5% CSG 16/20 3.9 0 186 13 Spacer 23 31 0.8 YF127ST 966 0 0 0 Ball 14 2.452" 21.1 0.1 YF127ST 126 0 0 15 XL Flush 12 33.8 3.6 YF127ST 5040 0 0 16 LG flush 93 37.3 2.5 WF127 3906 0 0 Slow for 17 Seat 5 24.1 2.4 WF127 2100 0 0 DVPCMsh 18 98. 3 2. WF127 415 0 0 r19 Freeze 7E 31. 2. Freeze Protect 3315 0 0 Protect 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 4 35.2 37.5 5944 6449 3560 Slow for Seat 21.5 33.5 748 4607 2384 Resume PAD 39.7 40.1 5752 15900 4723 1.0 PPA 39.4 40.1 5704 5863 5607 5 2.0 PPA 39.1 39.3 5529 5607 5488 3.0 PPA 39.5 40.0 5763 5968 5497 4.0 PPA 39.8 39.9 6236 6431 5973 8 5.0 PPA 39.7 39.9 6756 7017 6431 9 6.0 PPA 39.5 39.7 7301 7506 7017 10 7.0 PPA 39.3 39.5 7686 7818 7506 11 8.0 PPA 38.9 39.3 7892 8047 7557 12 Clear Lines 39.3 39.7 986 8024 7955 13 Spacer 31.0 39.8 7982 3327 14 B all 2.452" 21.1 121.1 J5261 909 14041 P771 15 lXL Flush 133.8 137.4 130 16724 000 Schlumberger Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country United States Step # Time Message„ Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Step Name Stage Average Slurry Rate (bbl/min) Pressures & Maximum Slurry Rate (bbl/min) Rates 1 Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 16 LG flush 37.3 37.5 6285 6733 3262 17 Slowfor Sea 24.1 35.6 3421 4506 2434 18 lOverflush PCM 139.0 0.3 499 4870 3382 19 Freeze Protect 01.9 132.3 P646 14169 11075 Job Messages # Time Message„ Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 09:59:39 POD primed up on freeze protect 40 0 0 0 0 2 10:16:00 All pumps primed, disconnecting recirc line 36 0 0 3 10:17:11 LRS to PT the IA line 4 4 10:18:56 Warming lines 54 3. 5 10:25:50 Start Low PT 3 6 10:27:16 Pumps down, brakes set 29 7 10:30:02 Coming up to 6k psi 2228 0 0. 8 10:33:44 Pumps down, brakes set, watching pressure 6051 9 10:35:23 Coming up to 9,500psi 5987 0 0.4 a 10 10:40:38 Found drip near popoff manifold, bleeding pressure down to repair 850 11 10:41:45 Pressure bled off -2 12 10:58:21 Popoff manifold put back together 36 0 0 13 10:58:31 Pushing freeze protect through the lines 31 0 0 14 1 11:00:37 Going to Low PT 402 0 1. 15 11:03:53 Coming up to 6k psi 4490 0 0 0.3 0 16 11:07:23 Coming up to 9,500 psi 6138 0 0 0.6 0 17 11:10:37 Pumps down, brakes set, watching pressure 9470 0 0 0 0 18 11:16:00 Good PT, bleeding pressure down 7474 00 0 0 19 11:19:30 Safety Meeting 31 00 0 20 11:45:44 LRS bringing IA up to 3,OOOpsi 40 67 0 0 21 11:46:01 Opening Swab and Master Valve, leaving Hydraulic closed 40 111 0 0 0 22 11:51:48 Master valve open, 23.5 turns 31 1013 0 0 23 11:59:09 Priming POD on gel 27 2979 0 0 24 11:59:29 Gel sample from PCM = 27# gel 22 2979 0 0 0 25 1 12:00:27 Confirmed popoff pressure @ 9,300psi 59 2975 0 0 26 12:01:14 Getting ready all around 54 297 0 0 0 27 12:01:35 Bringing line up to 1,OOOpsi to open well 49 297 0 0 0 28 12:02:24 WH Hydraulic valve open 489 297 0 0 0 29 12:02:32 Clearing surface lines 493 297 0 1.5 30 12:05:40 Going to pump 2 1711 3054 0 1.3 0 31 1 12:11:07 IShutdown for 10 mins 1574 286 0 32 12:22:23 Start Stage 1 (Per Automatically 1537 2878 0 0 33 12:22:23 Started Pumping 1537 287 0 34 12:22:31 Start pump check 1537 287 0. Schlumbugep Client: Caelus Energy Alaska Well: ODSN-la Formation: Nuiqsut District: Prudhoe Bay Country: United States Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 35 12:32:03 Start PAD Automatically 1592 3277 300.4 38.3 36 12:34:19 Ball 2.236" loaded 1450 3222 301 0 0 37 12:41:45 PAD XL pH = 8.6 5675 3492 426.1 39.9 0 38 12:42:33 Started Pumping Prop 5836 3501 458 39. 39 12:42:37 Start 1.0 PPA Automatically 5845 3501 460.6 39.E 0 40 12:43:37 Start 2.0 PPA Automatically 6064 3524 500.1 RE 1 41 12:45:00 Start 3.0 PPA Automatically 6248 3528 555.5 4 1. 42 12:46:45 Start 4.0 PPA Automatically 6495 35IN 625.4 39. 3 43 12:47:05 2 PPA XL pH = 8.6 6541 3506 638.7 39.8 4 44 12:47:48 Bringing ball dropper van up to 5k psi 6600 3487 667.2 39.8 4.1 45 12:48:30 Start 5.0 PPA Automatically 6632 3501 695.1 39. 46 12:50:16 Start 6.0 PPA Automatically 6957 3528 765.2 39. 47 12:52:01 Start 7.0 PPA Automatically 7314 3524 834.7 39.7 48 12:53:24 Start 8.0 PPA Automatically 7676 3487 889.6 39.6 7 49 12:54:32 Start Clear Lines Automatically 7882 3451 934.4 39.4 8.1 50 12:55:10 Start Spacer Manually 7900 3524 959.3 40.1 51 12:55:32 Stopped Pumping Prop 3487 3213 972.2 25.6 52 12:56:04 Start Ball 2.236" Automatically 412q 3249 983.7 21 53 12:56:13 Start PAD 2 Automatically 4357 3258 0 21 54 12:57:16 Ball away 986 6472 3391 29.6 34.1 55 12:58:33 Offloading prop into bin 3 of tank side chief 6898 3432 75.1 36.8 0 56 13:01:31 PAD2 XL pH = 8.6 6733 3437 185.8 37.5 0 57 13:03:16 Start Slow for Sea Automatically 2933 3144 246.8 15.9 0 58 13:04:48 Ball seated 1246 bbls total slurry 3611 316 265.9 12.7 59 13:05:59 Ball 2.307' loaded 5378 327 294.4 33.3 60 13:06:04 Start Resume PAD Automatically 5369 3251 297.2 34.4 0 61 13:09:23 Start 1.0 PPA Automatically 6573 346 427.1 39. 0 62 13:12:09 Start 2.0 PPA Automatically 6495 3501 537 40.1 1 63 13:15:47 Start 3.0 PPA Automatically 6376 346 682.1 39. 64 13:18:49 2 PPA XL pH = 8.6 6472 350 802.9 39.9 3 65 13:20:18 Start 4.0 PPA Automatically 6522 346 862 39A 3 66 13:24:49 Start 5.0 PPA Automatically 6893 340 1041.1 39. 67 13:29:22 Start 6.0 PPA Automatically 7378 337 1221.3 39. 68 13:33:55 Start 7.0 PPA Automatically 7850 3434 1400.4 39.4 6 69 13:34:17 Bringing ball dropper van up to 5k psi 7863 342 1414.8 39.3 7 70 13:37:38 Start 8.0 PPA Automatically 8056 354 1545.1 38.5 7 71 13:40:47 Start Clear Lines Automatically 8005 351 1664.8 37. 72 13:41:26 Start Spacer Manually 7987 350E 1689 38. 73 13:41:30 Stopped Pumping Prop 7950 3501 1691.6 38.4 0 74 13:42:18 Start Ball 2.307' Automatically 4192 321 1712.1 21 0 75 13:42:27 Start PAD 3 Automatically 4119 3201 0 21.1 76 13:42:38 Ball away 2700 total slurry 4664 323' 4 22.7 77 13:43:20 Ball dropper van bled off 6197 3331 2 32.3 0 78 13:46:18 Stage at Perfs: 8.0 PPA 7072 352 128.3 37.2 0 79 13:46:26 PAD XL pH= 8.6 7053 352 133.2 37.2 0 80 13:49:10 Start Slow for Sea Automatically 2434 3107 233.9 20.3 0 81 13:50:38 Ball seat 2946 total slurry 3199 3167 252.4 12.4 0 82 115121 IBall 2.379" loaded 4165 324 265.5 24.3 83 1 13:51:59 IStart Resume PAD Automatically 471q 32811 283.q 32.4 0 schiumbe,poep Client: Caelus Energy Alaska Well. ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 84 13:55:42 Start 1.0 PPA Automatically 6046 3492 429.2 40 0 85 13:58:30 Start 2.0 PPA Automatically 5808 3542 539.3 39.4 1 86 14:01:56 2PPA XL pH = 8.6 5758 3451 675.4 39. 87 14:02:09 Start 3.0 PPA Automatically 5771 3441 683.9 39.1 2 88 14:06:42 Start 4.0 PPA Automatically 5973 3446 863.7 39. 89 14:11:16 Start 5.0 PPA Automatically 6394 3519 1043.6 39. 90 14:12:54 4PPA XL pH = 8.6 6605 346 1107.7 39.3 4. 91 14:15:51 Start 6.0 PPA Automatically 682Q 351 1223.3 39.2 9 92 14:20:27 Start 7.0 PPA Automatically 7172 349 1402.7 38.9 6 93 14:24:01 Skipping 8 PPA stage 7488 34V 1541 38.8 7 94 14:24:15 Start Clear Lines Manually 7493 340 1550.1 38.8 7 95 14:24:46 Start Spacer Manually 7520 341 1570.4 39.9 0 96 14:25:37 Start Ball 2.379" Automatically 3698 313C 1593.4 21 97 14:25:46 Start PAD 4 Automatically 3995 3144 0 21 98 14:25:59 Ball away 4298 4201 3158 4.6 22. 99 14:27:58 Bringing rate up to 37 bpm 5982 3533 66.7 34.7 100 14:28:23 Stopped Pumping Prop 6243 3547 81.5 3 101 14:29:07 PAD XL pH = 8.6 6426 3542 108.6 37. 102 14:33:40 Ball seat 4535 total slurry 34411 3240 243.8 14. 103 14:34:46 Ball 2.452" loaded 4595 3318 270.4 3 104 14:34:56 Start Resume PAD Automatically 4888 3290 275.9 33.7 105 14:41:52 Start 1.0 PPA Automatically 5858 3524 551.3 4 106 14:41:58 Started Pumping Prop 5863 351S 555.3 40.1 107 14:45:25 Start 2.0 PPA Automatically 5607 3387 691.1 39.3 1 108 14:50:16 Start 3.0 PPA Automatically 5501 3519 880.9 39.1 109 14:56:12 Start 4.0 PPA Automatically 5982 3451 1115.6 39.8 3.1 110 14:56:45 PPA XL pH = 8.6 6023 3423 1137. 39.7 111 15:00:04 Extending 4 PPA step by 25bbls, total of 260bbls for step 6248 346 1269.2 39. 3. 112 15:02:44 Deactivated Extend Stage 6435 3441 1375. 39. 113 15:02:44 Start 5.0 PPA Manually 643 3441 1375. 39. 114 15:07:07 Activated Extend Stage 6879 3510 1549.7 39.7 4. 115 15:07:45 Extending 5 PPA step by 25bbls, total step vol of 260bbls 6920 3483 1574.8 39.7 116 15:09:17 Deactivated Extend Stage 7026 3432 1635.7 39.7 5 117 15:09:17 Start 6.0 PPA Manually 7026 3432 1635.7 39.7 118 15:13:18 Activated Extend Stage 7383 3432 1794.4 39.5 6 119 15:15:52 Deactivated Extend Stage 7511 3492 1895.7 39.5 6 120 15:15:52 Start 7.0 PPA Manually 7511 3492 1895.7 39.5 6 121 15:16:28 Extended 6 PPA step by 25bbls, total step vol of 260bbls 7520 3464 1919.4 39.4 7.1 122 15:16:44 Bringing ball dropper van up to 5k psi 7557 3455 1929.9 39.3 6. 123 15:19:08 Extending 7 PPA step 40bbls to total vol of 230bbls 7754 3533 2024.2 39.3 7.1 124 15:21:43 Start 8.0 PPA Manually 7827 3428 2125.7 39.3 6. 125 15:27:03 Start Clear Lines Manually 7941 3396 2332.8 38.9 1.1 126 15:27:27 Start Spacer Manually 7932 3464 2348.6 39.8 127 15:27:44 Stopped Pumping Prop 3524 3226 2359.1 29.2 0 128 15:28:18 Start Ball 2.452" Automatically 3950 2371.7 21.1 129 15:28:27 Start XL Flush Automatically 399 322 2374. 20. Schlumbergep Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States # Time Message Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate Prop. Conc. (bbl/min) (PPA) 130 15:29:51 Ball away 6672 total slurry 6096 3341 2415.7 33.9 0 131 15:32:02 Start LG flush Automatically 6719 3487 2494.7 37.3 0 132 15:32:45 Stopped mixing gel in PCM 6637 3464 2521.4 37. 133 15:32:54 J218 up to conc of 4ppt 6531 3455 2527 37. 134 15:35:27 Ball seat 6892 total slurry 2741 3126 2599.5 13 135 15:36:54 Start Overflush PC Automatically 4655 3249 2637.8 36. 136 15:37:27 Running out the PCM 4842 340 2659.2 40. 137 15:39:27 Deactivated Extend Stage 3354 335 2736.5 32.1 138 15:39:27 Start Freeze Prote Manually 3354 335 2736.5 32.1 139 15:42:46 801bbls of freeze protect pumped from X -port 1601 3071 2815.4 0 140 16:02:21 WH Hydraulic valve closed 1043 294 2815.4 0 141 16:02:43 Bleeding down surface lines 951 29381 2815. 0 142 16:03:33 Surface lines bled off 4 2938 2815.4 0 143 16:04:25 LRS to bleed down the IA to 500 psi 27 2933 2815.4 8.7 144 16:05:53 Fanning pumps 127 2572 2815.4 2 Schlumbeplep FracCAT Treatment Report Well : ODSN-01 a, Stages 5-7 Field :Oooguruk Formation : Nuigsut Prepared for 434 Client : Caelus Energy Alaska Client Rep : Mike Martin Date Prepared : 04/18/16 Prepared by Surface Shut in Pressure(psi) Name : Alexander Martinez Division : Schlumberger Phone :561-389-5006 Pressure (All .- Initial Wellhead Pressure (psi) 434 Initial BHP at Gauge (psi) 2,869 Final Surface ]SIP (psi) 1,601 Final ISIP at Gauge (psi) 4,107 Surface Shut in Pressure(psi) 1,368 BH Shut in Pressure (psi) 3,881 Maximum Treating Pressure (psi) TotalsTreatment 7,886 BH Gauge at 10,204' MD, 6,045' TVD Total Slurry Pumped Water+Adds+Pro ant bbls 6,202 Total YF127ST Past Wellhead (bb]s) 4,909 Total WF125 Past Wellhead (bbls) 506 Total Freeze Protect Past Wellhead bbls 41 Total Proppant Pumped (lbs.) Total Chemical Additives F103 (gal) 238 704,000 238 Total Proppant in Formation (lbs.) M275 (lbs.) 0 704,000 0 L065 (gal) 468 468 J218 (lbs.) 165 165 J580 (lbs.) 6160 6137 J475 (lbs.) 1320 1320 J922(mgal) 206 206 J134 (lbs.) 106 0 J510(bbls) 0 1.2 J450 (gal) 59 59 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. Schlumhugep Summary Client: Caelus Energy Alaska Well: 0DSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States On March 27, 2016, Schlumberger finished stages 5-7 for the ODSN-01 a well. The treatment consisted of 3 stages with 2 Rapidball DM ball drops and one DM -XT ball drop. Approximately 704,000 lbs of proppant in 6,202 bbls of slurry was pumped during this treatment. The well was freeze protected using physical straps from the freeze protect transport and it was determined that 41 bbls of freeze protect fluid made it into the well. All stages were pumped as designed and the summary for the totals is noted below. a. Pressure Test Materials Actual (Design) Slurry Volume- All Volumes (bbl) 6,202 (6,163) Clean Fluid- All Volumes (bbl) 5,415 (5,374) Proppant, lbs. 704,000 (704,000) Tr. Pressure IA Pressure BHP Caelus Energy Alaska ODSN-01 i 03-27-2016 50 v 40 fD a c 3 30- :5 : Ca ,o 20 20 18 16 v 140 a 0 120= 10v a 8 10 4 2 0 0 15:28:20 15:35:00 15:41:40 15:48:20 15:55:00 Time - hh:mm:ss fn CL 8000 M Main Treatment Tr. Pressure IA Pressure BHP 5; 11 irry Ra4a Caelus Energy Alaska ODS N-01 i 03-27-2016 2000 0 16:5a:Zu 1 /:462U 18:38:20 19:28:20 Time - hh:mm:ss 50 W 40 fD s a 3 30- 20 0<20 20 18 -16 -0 140 M 0 12� r10� D I 0 20:18:20 C 6 10 4 2 0 20:18:20 C Stage 5: Summary Stage 5 consisted of a PAD, 8 proppant steps (1-8PPA), a ball drop and a flush. Three pumps had seat/valve issues during this stage and 2 of the pumps fixed themselves after slowing down to rate. The one pump that didn't fix itself was shut in for the remainder of the job. Flush at the WH was called at 2,584 bbls and the 2.527" Rapidball DM ball was dropped at 2,610 bbls to open Port 5 for Stage 6. The ball seated at 2,826 bbls of total slurry. Total Proppant Pumped (lb) Summary 264,761 of Stage 5 Max pumping Rate (bpm) 40.5 Total Proppant in Formation (lb) 264,761 Average Pumping Rate (bpm) 37.4 Total Slurry Pumped (bbl) 2,611 Maximum Treating Pressure (psi) 7,516 YF127ST Pumped (bbl) 2078 Average Treating Pressure (psi) 5,733 WF127 Pumped (bbl) 259 Average Viscosity of WF127 (cP) 18.4 a - Stage 5 Tr. Pressure Caelus Energy Alaska IA Pressure ODSN-01i BHP 03.27.2016 50 d 407 0' Cr 3 30- 20 0<20 10 17:11:12 17:32:02 17:52.52 18:13:42 18:34:32 Time - hh:mm:ss i 20 -18 -16 v -140 v n 120 �10 v D F8 6 4 2 0 schlumbepoep Stage 5: As Measured Pump Schedule Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates I Average Treating Pressure (psi) As Measured Pump Schedule 1 Break Down Ste p Ste Slurry Slurry Pump Fluid Max Prop Prop # Name Volume Rate Time Fluid Name Volume Proppant Name Mass 39.3 40.1 (bbl) (bbl/min) (min) (gal) Conc (Ib) 39.3 39.5 5435 5515 5392 (PPA) 3.0 PPA 39.1 Break 5541 5666 5410 0 PPA 39.1 1 down 259.1 37. 7.8 WF127 1088 38.9 39.2 2 PAD 5 590 38.E 15.8 YF127ST 24780 38.9 6452 3 1.0 PPA 150.3 39. 3.8 YF127ST 6050 CarboLite w/ 5% CSG 16/20 1.2 600 4 2.0 PPA 200.1 39. 5.1 YF127ST 7741 CarboLite w/ 5% CSG 16/20 2 15218 5 3.0 PPA 250 39.1 6.4 YF127ST 9294 CarboLite w/ 5% CSG 16/20 3 27689 6 4.0 PPA 250.3 39.1 6.4 YF127ST 8958 CarboLite w/ 5% CSG 16/20 4.1 3568 7 5.0 PPA 249.9 38.9 6.4 YF127ST 8624 CarboLite w/ 5% CSG 16/20 5.11 4299 8 6.0 PPA 250 38.2 6.5 YF127ST 8323 CarboLite w/ 5% CSG 16/20 6.11 49989 9 7.0 PPA 199.9 37.1 5.4 YF127ST 6434 CarboLite w/ 5% CSG 16/20 7.11 4503 10 8.0 PPA 160.7 37.3 4.3 YF127ST 5007 CarboLite w/ 5% CSG 16/20 8.11 3998 Clear 11 Lines 25. 38.1 0.7 YF127ST 97 CarboLite w/ 5% CSG 16/20 8 214 12 Spacer 23 33.8 0.7 YF127ST 1 9661 0 Ball 13 3 22 0.1 YF127ST 12 2.527" Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates I Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 Break Down 37.5 40.8 5123 6518 539 2 PAD 5 38.8 40.4 5113 5694 1171 1.0 PPA 39.3 40.1 5554 5694 5511 2.0 PPA 39.3 39.5 5435 5515 5392 5 3.0 PPA 39.1 39.3 5541 5666 5410 0 PPA 39.1 39.2 5856 5964 5666 5.0 PPA 38.9 39.2 6165 6321 5964 8 6.0 PPA 38.2 38.9 6452 6646 6321 9 7.0 PPA 37.1 37.7 6630 6884 6417 10 8.0 PPA 37.3 37.7 7067 7355 6408 11 Clear Lines 38.1 38.9 7380 7479 7255 12 Spacer 33.8 39.1 5522 7456 414 13 Ball 2.527" 22.0 22.2 724 13812 P570 Schlumberger Stage 6: Summary Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Stage 6 consisted of a PAD, 6 proppant steps (1-10PPA), a ball drop and a flush. Flush at the WH was called at 4,123 bbls and the 2.603" Rapidball DM ball was dropped at 4,149 bbls to open Port 6 for Stage 7. The ball seated at 4,353 bbls of total slurry. Total Proppant Pumped (lb) Summary of 213,569 Stage 6 Max pumping Rate (bpm) 40.6 Total Proppant in Formation (lb) 213,569 Average Pumping Rate (bpm) 37.7 Total Slurry Pumped (bbl) 1,539 Maximum Treating Pressure (psi) 7,886 YF127ST Pumped (bbl) 1,318 Average Treating Pressure (psi) 6,042 WF127 Pumped (bbl) 0 Average Viscosity of WF127 (cP) 18.0 IL Stage 6 Tr.Pressure Caelus Energy Alaska IAPressure ODSN-01i BHP 03-27-2016 50 d 407 6 3 30- 0 0<0 „ 20 10 0 18:20:10 18:32:40 18:45:10 18:57:40 19:10:10 Time - hh:mm:ss 20 �18 X16 140 �12� 10v n r8 6 4 �2 0 Schlumberger Stage 6: As Measured Pump Schedule Client Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States 7Step 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) As Measured Pump Schedule PAD 6 36.1 38.8 Step Step Slurry Slurry Pump Fluid 35.0 Drax Prop # Name Volume Rate Time Fluid Name Volume Proppant Name op Mass 1.0 PPA 39.5 (bbl) (bbl/min) (min) (gal) 5 Conc (Ib) 39.7 5250 5350 5208 6 5.0 PPA 39.9 (PPA) 5924 1 PAD 6 203 36.1 5.7 YF127ST 8526 6985 0 0 9.0 PPA Slowto 39.6 7283 529 6985 9 10.0 PPA 38.9 39.2 2 Seat 50 21.7 2.7 YF127ST 2100 7747 0 0 11 Resume 31.0 40.4 4878 7831 2997 12 2.603" 21.1 3 PAD 120 39.4 3 YF127ST 5040 0 4 1.0 PPA 159.7 39.5 4 YF127ST 6439 CarboLite w/ 5% CSG 16/20 1.1 6145 5 3.0 PPA 1 159.5 39.4 4.1 YF127ST 594N CarboLite w/ 5% CSG 16/20 31 1722 6 5.0 PPA 220.6 39. 5.5 YF127ST 7625 CarboLite w/ 5% CSG 16/20 N 37651 7 7.0 PPA 199. 39.- 5 YF127ST 6442 CarboLite w/ 5% CSG 16/20 7.11 44821 8 9.0 PPA 199.3 39. 5.1 YF127ST 6019 CarboLite w/ 5% CSG 16/20 9.A 5402 9 10.0 PPA 175. 38. 4.5 YF127ST 5133 CarboLite w/ 5% CSG 16/20 10.11 5129 Clear 10 Lines 25. 39. 0. YF127ST 97 CarboLite w/ 5% CSG 16/20 1 2418 11 Spacer 23 31 0.81 YF127ST 966 00 Ball 12 2.603 " 3 21.1 0.1 YF127ST 126 0 7Step 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) PAD 6 36.1 38.8 5980 6513 300 2 Slow to Seat 21.7 35.0 3588 4627 2448 Resume PAD 39.4 40.2 5168 5451 444 1.0 PPA 39.5 40.2 5293 5465 5199 5 3.0 PPA 39.3 39.7 5250 5350 5208 6 5.0 PPA 39.9 40.1 5924 6281 5350 7.0 PPA 39.7 40.0 6667 6985 6284 8 9.0 PPA 39.2 39.6 7283 529 6985 9 10.0 PPA 38.9 39.2 7665 7758 7534 10 Clear Lines ]Ball 39.2 40.2 7747 7854 7648 11 Spacer 31.0 40.4 4878 7831 2997 12 2.603" 21.1 121.1 3626 3739 3460 schlumbepoep Stage 7: Summary Client: Caelus Fnergy Alaska Well. ODSN-la Formation: Nuigsut District: Prudhoe Bay Country: United States Stage 7 consisted of a PAD, 8 proppant steps (1-8PPA), a ball drop and a flush. Flush at the WH was called at 5,772 bbls and the 2.681" Rapidball DM ball was dropped at 5,798 bbls to open Port 7 for Stage 8. The ball seated at 5,993 bbls of total slurry. a Stage 7 Tr. Pressure Caelus Energy Alaska IA Pressure ODSN-01 i BHP 03-27-2016 50 z d 40rrtD c 3 30 < N v 20 10 0 i a: u i :u5 19:1 /:45 19:34:25 19:51:05 20:07:45 Time - hh:mm:ss 20 18 16 -8 6 4 2 0 Total Proppant Pumped (lb) Summary of 225,669 Stage 7 Max pumping Rate (bpm) 40.9 Total Proppant in Formation (lb) 225,669 Average Pumping Rate (bpm) 38.1 Total Slurry Pumped (bbls) 2,052 Maximum Treating Pressure (psi) 7,662 YF127ST Pumped (bbls) 1,513 Average Treating Pressure (psi) 5,888 WF127 Pumped (bbls) 247 Average Viscosity of WF127 (cP) 17.9 Freeze Protect (bbls) 57 a Stage 7 Tr. Pressure Caelus Energy Alaska IA Pressure ODSN-01 i BHP 03-27-2016 50 z d 40rrtD c 3 30 < N v 20 10 0 i a: u i :u5 19:1 /:45 19:34:25 19:51:05 20:07:45 Time - hh:mm:ss 20 18 16 -8 6 4 2 0 Schlumberger Stage 7: As Measured Pump Schedule Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) As Measured Pump Schedule PAD 7 37.0 39.1 Step Step Slurry Slurry Pump Fluid 7.6 Drax Prop # Name Volume Rate Time Fluid Name Volume Proppant Name 4243 1.0 PPA 40.1 (bbl) (bbl/min) (min) (gal) 5 Conic (lb) (lb) 40.3 5241 5323 5140 5.0 PPA 40.0 (PPA) 861 1 PAD 7 194 371 5.3 YF125ST 8139 6607 6898 6188 Slow for 39.8 40.0 7156 7374 6536 10.0 PPA 2 Seat 50 24.7 2.4 YF127ST 2099 Clear Lines 40.3 40.7 7616 Resume 7570 11 Spacer 31.5 40.8 1747 7534 3 PAD 160 39.3 4.1 YF127ST 6720 3431 3222 13 4 1.0 PPA 175.4 40.1 4.4 YF127ST 70681 CarboLite w/ 5% CSG 16/20 1.1 678 5 3.0 PPA 175.4 40.11 4.4 YF127ST 65341 CarboLite w/ 5% CSG 16/20 3 1904 6 5.0 PPA 240.1 41 6 YF127ST 82971 CarboLite w/ 5% CSG 16/20 5 41021 7 7.0 PPA 215.5 39. 5.4 YF127ST 6948 CarboLite w/ 5% CSG 16/20 7.11 4831 8 9.0 PPA 214.7 39A 5.4 YF127ST 6480 CarboLite w/ 5% CSG 16/20 9.A 5821 9 10.0 PPA 180.3 39. 4.5 YF127ST 5313 CarboLite w/ 5% CSG 16/20 10.11 5203 Clear 10 Lines 16.2 40. 0.4 YF127ST 671 CarboLite w/ 5% CSG 16/20 41 261 11 Spacer 23 31.q 0.8 YF127ST 9661 12 Ball 2.681 3 20. 0.1 YF127ST 126 13 XL Flush 100 35. 2.9 YF127ST 4200 14 LG Flush 85 4 2.1 WF127 3570 Slow for 15 Seat 50 25. 2. WF127 210 16 MT PCM 112 38.9 2.9 WF127 4704 Freeze 17 Protect 57. 29.1 2.1 Freeze Protect 2403 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 7 37.0 39.1 5975 6422 3661 Slow for Seat 24.7 7.6 3597 4233 2453 Resume PAD 39.3 40.5 5070 5341 4243 1.0 PPA 40.1 40.5 j205 5327 5154 5 3.0 PPA 40.1 40.3 5241 5323 5140 5.0 PPA 40.0 40.1 861 6185 5318 0 PPA 39.9 40.0 6607 6898 6188 9.0 PPA 39.8 40.0 7156 7374 6536 10.0 PPA 39.7 39.9 7513 7374 10 Clear Lines 40.3 40.7 7616 7630 7570 11 Spacer 31.5 40.8 1747 7534 2906 12 Ball 2.681 20.9 21.0 3278 3431 3222 13 XL Flush 35.5 39.9 5771 6435 P524 14 LG Flush 40.0 40.2 5893 16362 155 15 Slowfor Seat 25.9 39.5 3237 087 12233 Schlumberger Client: Caelus Energy Alaska Well: ODSN-ta Formation: Nuiqsut District: Prudhoe Bay Country: United States Job Messages 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) 16 MT PCM 38.9 40.4 3734 4142 2540 17 Freeze Protect 29.1 30.0 2918 3277 1386 Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 14:48:35 Priming POD -1 61 2 14:58:20 Priming pumps 40 61 4.3 0 3 15:19:19 All pumps primed, moving fluid up overthe top 45 61 00 0 4 1 15:20:52 Warming lines 63 61 4. 0 5 15:26:13 Lines warmed, fluid used during prime up/warm lines = 50bbls 49 61 6 15:27:47 Going to low PT 45 61 0 0 7 15:31:08 Bringing pressure up to 6k psi 1743 61 0 1.E 0 8 15:35:35 Coming up to 9,500psi 546 61 9 1 15:40:04 Start high PT 9454 619 0 0 10 15:46:39 PT good, client approved, bleeding surface pressure. 6925 619 C 0 0 11 15:47:30 Gathering for safety meeting 13 619 0 0 12 16:37:00 Priming POD on Gel 8 747 00 0 13 16:38:19 Brining IA to 3000psi 36 120q 0 14 16:39:44 Wellhead Open 457 1704 0 15 17:00:53 Start Breakdown Automatically 855 3008 0 16 17:00:53 Start Stage 5 Automatically 855 3008 a 0 17 17:00:53 Started Pumping 855 3008 0 0 18 17:06:45 Good zero's on POD 4819 3484 182. 40.6 0 19 17:06:55 Good zero's on in-line densos 4723 348 189.1 40.7 0 20 17:10:15 Pre -job XL sample = 8.6 pH 1253 326 259.1 0 0 21 17:10:35 Ball 2.527" loaded 1244 326 259.1 22 17:13:11 Start PAD 5 Manually 1180 327 259.1 0 0 23 17:19:07 Getting out of pump 2 4828 354z 451.1 39.2 0 24 17:19:16 Bringing on pump 7 4819 353 456.9 38.8 0 25 17:26:21 PAD XL pH = 8.6 5671 349 737.7 40 0 26 17:29:06 Started Pumping Prop 5689 3503 847.7 40.1 0 27 17:29:09 Start 1.0 PPA Automatically 5694 350 849.7 40.1 0.1 28 17:32:58 Start 2.0 PPA Automatically 5511 3491 999.7 39.4 1 29 17:38:04 Start 3.0 PPA Automatically 5414 343 1200 39.3 2 30 17:44:27 Start 4.0 PPA Automatically 5671 347 1449.7 39.1 3 31 17:45:31 XL pH = 8.6 5781 348 1491. 39.2 4 32 17:50:51 Start 5.0 PPA Automatically 5955 349 170 39.2 4 33 17:57:16 Start 6.0 PPA Automatically 6321 3461 1949. 38.9 5 Schlumberger Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States # Time Message Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 34 18:03:49 Start 7.0 PPA Automatically 6472 3484 2199.9 37.4 6 35 18:04:50 Adjusting rate to try and clean up the pumps 6577 348 2237.q 37.5 7 36 18:09:12 Start 8.0 PPA Automatically 6646 343 2399.8 36.7 7. 37 18:09:38 Adjusting rates 6655 344 2415.4 35.8 E 38 18:09:46 Bringing ball dropper van to 5k psi 6577 343 2420.2 36.1 7.9 39 18:13:31 Start Clear Lines Automatically 7406 3481 2560.6 37.6 E 40 18:13:53 Stopped Pumping Prop 7479 3480 2574.5 38.4 0.1 41 18:14:10 Start Spacer Manually 7323 3507 2585. 39 0 42 18:14:55 Start Ball 2.527' Automatically 3785 3251 2608. 21. 0 43 18:15:03 Start PAD 6 Automatically 3707 3251 21. 0 44 18:15:03 Start Propped Frac Automatically 3707 3251 21. 0 45 18:15:03 Start Stage 6 Automatically 3707 3251 21.8 46 18:15:45 Ball away 2610 total slurry 4696 3301 16.9 27.7 0 47 18:20:30 PAD XL pH = 8.6 5941 3471 193.1 38.8 0 48 18:20:47 Start Slow to Seat Automatically 2270 3237 203.2 23. 49 18:22:07 Ball seat 2826 total slurry 2769 3255 220.4 12.1 0 50 18:23:28 Start Resume PAD Automatically 4481 3361 253.5 35.6 0 51 18:26:30 Start 1.0 PPA Automatically 5465 3475 373. 40.1 0 52 18:26:30 Started Pumping Prop 5465 3475 373. 40.1 0 53 18:30:33 Start 3.0 PPA Automatically 5231 3498 533.1 39.q 1 54 18:34:36 Start 5.0 PPA Automatically 5355 3461 692. 39.8 3 55 18:38:52 5 PPA XL pH = 8.6 6197 3481 862.6 40.1 5 56 18:40:08 Start 7.0 PPA Automatically 6298 349 913. 40 5 57 18:45:10 Start 9.0 PPA Automatically 6985 3481 1112. 39.5 6.9 58 18:50:15 Start 10.0 PPA Automatically 7525 348 1312.1 39.2 9.1 59 18:52:54 Ball dropper van pressured up to 5k psi 7690 348 1415. 38.9 1 60 18:54:46 Start Clear Lines Automatically 7758 347 1481 38.9 1 61 18:56:24 Start PAD 7 Automatically 3661 321 21 0 62 18:56:24 Start Propped Frac Automatically 3661 321 0 21 63 18:56:24 Start Stage 7 Automatically 3661 3219 21 0 64 19:01:42 Start Slow for Sea Automatically 1949 316 193128.6 0 65 19:02:49 Ball away 4149 total slurry 3313 324 208. 14.3 a 66 19:02:57 Ball seat 4353 total slurry 3602 331 211.1 19.4 0 67 19:03:08 PAD XL pH = 8.6 3757 328E 215.1 23.4 0 68 19:03:56 Ball 2.681" loaded 4229 332 239.3 35 0 69 19:04:04 Start Resume PAD Automatically 4243 332 244 35.7 0 70 19:04:09 Rolling pump 5 4407 333 247 36.4 q 71 19:05:34 Coming down on pump 5 4856 3388 301.1 36.3 0 72 19:08:08 Start 1.0 PPA Automatically 5327 343 404.2 40.4 0 73 19:08:08 Started Pumping Prop 5327 343 404.2 40.4 0 74 19:12:30 Start 3.0 PPA Automatically 5158 344E 579.1 40.1 1 75 19:16:53 Start 5.0 PPA Automatically 5318 343 754.9 40.1 3 76 1 19:17:59 XL pH = 8.6 5616 343 798.91 40.1 5 77 19:22:53 Start7.OPPA Automatically 6188 3481 995 39. 5 78 19:28:17 Start 9.0 PPA Automatically 6563 349 1210.7 39J 7 79 19:33:40 Start 10.0 PPA Automatically 7383 3471 1424.9 39.8 9 80 19:39:36 Start XL Flush Automatically 3593 321 1647.6 20.E 0 81 19:42:28 Start LIS Flush Automatically 1 6348 343 1747.8 40 82 19:44:36 IStart Slow for Sea Automatically 1 1839 3124 1832.71 281 0 schlumbugep Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country United States # Time Message Log Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 83 19:45:37 Ball away 5798 total slurry 2819 3214 1846.6 14.3 0 84 19:45:49 Ball seat 5993 total slurry 2878 3214 1850.1 21.5 85 19:49:46 Start Freeze Protect Manually 2746 319q 1994.3 30 0 [-1-6 20:01:02 LRS bringing IA to 500psi 141 270 2051.5 87 20:03:42 Wellhead is shut. -1 145 2051. 0 0 ale bu ep FracCAT Treatment Report Well ODSN-01 a, Stages 8-10 Field Oooguruk Formation Nuigsut Prepared for 212 Client Client Rep Caelus Energy Alaska Mike Martin Date Prepared 04/20/16 Prepared by Final ISIP at Gauge (psi) Name : Alexander Martinez Division Schlumberger Phone :561-389-5006 Pressure (All Zones) Initial Wellhead Pressure (psi) 212 Initial BHP at Gauge (psi) 2,686 Final Surface ISIP (psi) 1,765 Final ISIP at Gauge (psi) 4,243 Surface Shut in Pressure(psi) 1,570 BH Shut in Pressure (psi) 4,018 Maximum Treating Pressure (psi) Treatment Totals (All Zones As Per FracCAT) 7,915 BH Gauge at 10,204' MD, 6,045' TVD Total Slurry Pumped Water+Adds+Proantbbls 5,441 Total YF127ST Past Wellhead (bbls) 4,181 Total WF127 Past Wellhead (bbls) 448 Total Freeze Protect Past Wellhead bbls 46 Total Proppant Pumped (Ibs.) Total Chemical Additives F103 (gal) Invoiced 199 726,400 Past WH 199 Total Proppant in Formation (Ibs.) Invoiced J510(bbls) 0 726,400 Past WH 1.1 L065 (gal) 409 409 J218 (lbs.) 132 132 J580 (Ibs.) 5215 5198 J475 (lbs.) 1155 1155 J922(mgal) 176 176 J134 (lbs.) 0 0 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. schiumbugep Summary Client: Caelus Fnergy Alaska Well ODSN-la Formation: Nuiqsut District: Prudhoe Bay Country: United States On March 29, 2016, Schlumberger finished stages 8-10 for the ODSN-01 a well. The treatment consisted of 3 stages with 2 Rapidball DM ball drops and one DM -XT ball drop. Approximately 726,400 lbs of proppant in 5,441 bbls of slurry was pumped during this treatment. The well was freeze protected using physical straps from the freeze protect transport and it was determined that 46 bbls of freeze protect fluid made it into the well. All stages were pumped as designed and the summary for the totals is noted below. d Pressure Test 10000 f Tr. Pressure IA Pressure BHP Slurry Rate PCM Vis cosi Caelus Energy Alaska ODSN-01 a 03.29-2016 750 40 10 3 0 09:34:32 09:40:22 09:46:12 09:52:02 09:57:52 Time - hh:mm:ss 20 18 16 14 10000 M N c 6000 CD L U) U) p L a 2000 0 11:16:13 Main Treatment Tr. Pressure IA Pressure BHP Slurry Rate Caelus Energy Alaska ODSN-01 a 03-29-2016 50 11:57:53 12:39:33 13:21:13 Time - hh:mm:ss 40 30 cr a 20 N� n a a 10 20 18 16 14 12 -o 0 10 n 0 0 8 6 a 4 2 0 0 14:02:53 Stage 8: Summary Stage 8 consisted of a PAD, 7 proppant steps (1-12PPA), a ball drop and a flush. Flush at the WH was called at 1,774 bbls and the 2.761" Rapidball DM ball was dropped at 1,801 bbls to open Port 8 for Stage 9. The ball seated at 1,992 bbls of total slurry. a Total Proppant Pumped (lb) Summary of 237,614 Stage 8 Max pumping Rate (bpm) 40.9 Total Proppant in Formation (lb) 237,614 Average Pumping Rate (bpm) 37.3 Total Slurry Pumped (bbl) 1,801 Maximum Treating Pressure (psi) 7,709 YF127ST Pumped (bbl) 1,326 Average Treating Pressure (psi) 5,644 WF127 Pumped (bbl) 231 Average Viscosity of WF 127 (cP) 18.0 Stage 8 Tr. Pressure Caelus Energy Alaska IAPressure ODSN-01a BHP 03-29-2016 — Slurry Rate 50 40 0 11:33:43 11:50:23 12:07:03 12:23:43 12:40:23 Time -hh:mm:ss 20 18 16 14 Schlumberger Stage 8: As Measured Pump Schedule Client: Caelus Fnergy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Step # Step Name Stage Pressures & Average Slurry Maximum5SIurryAverage Rate RatPressure (bbl/min) (bbl/m Rates Treating (psi) As Measured Pump Schedule 1 Pump Check 37.8 Step Step Slurry Slurry Pump Fluid PAD 8 PMraax op Prop Name Volume Rate Time Fluid Name Volume Proppant Name 40.4 Mass 5122 4948 (bbl) (bbl/min) (min) (gal) 40.4 Conc (Ib) 15090 5 4.0 PPA 40.0 40.1 5475 (PPA) 5150 6 Pump 39.9 40.0 i199 6497 5736 8.0 PPA 1 Check 231 37.8 6.9 WF127 9704 10.0 PPA 39.9 0 2 PAD 8 31 37. YF127ST 13230 40.0 7598 17695 3 1.0 PPA 144. 39. 3. YF127ST 5839 CarboLite w/ 5% CSG 16/20 1.1 5728 4 2.0 PPA 159. 40. YF127ST 6187 CarboLite w/ 5% CSG 16/20 Ball 2.761" 1220 5 4.0 PPA 184.7 4 4. YF127ST 6626 CarboLite w/ 5% CSG 16/20 4.1 26181 6 6.0 PPA 184.6 39. 4. YF127ST 6160 CarboLite w/ 5% CSG 16/20 6.1 3687 7 8.0 PPA 184. 4 4. YF127ST 5753 CarboLite w/ 5% CSG 16/20 8. 4622 8 10.0 PPA 184. 39. 4. YF127ST 5403 CarboLite w/ 5% CSG 16/20 10. 5425 9 12.0 PPA 159. 39.7 YF127ST 4404 CarboLite w/ 5% CSG 16/20 12. 53081 10 Clear Lines 26. 39. 0. YF127ST 979 CarboLite w/ 5% CSG 16/20 1 307 11 Spacer 23 30.6 O.q YF127ST 967 12 Ball 2.761 " 21 0.1 YF127ST 126 Step # Step Name Stage Pressures & Average Slurry Maximum5SIurryAverage Rate RatPressure (bbl/min) (bbl/m Rates Treating (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 Pump Check 37.8 0.5662 5699 815 PAD 8 37.9 40.3434 5067 1295 1.0 PPA 39.8 40.4 5056 5122 4948 2.0 PPA 40.2 40.4 5114 5150 15090 5 4.0 PPA 40.0 40.1 5475 5736 5150 6 6.0 PPA 39.9 40.0 i199 6497 5736 8.0 PPA 40.0 40.2 i853 7091 6500 8 10.0 PPA 39.9 40.1 325 7507 7086 9 12.0 PPA 39.7 40.0 7598 17695 P494 10 Clear Lines 39.4 40.3 7536 7690 7375 11 Spacer 30.6 40.7 4628 7640 2921 12 Ball 2.761" 21.0 21.0 3465 3639 3378 schlumbepp Stage 9: Summary Client. Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Stage 9 consisted of a PAD, 7 proppant steps (1-12PPA), a ball drop and a flush. Flush at the WH was called at 3,528 bbls and the 2.842" Rapidball DM ball was dropped at 3,551 bbls to open Port 9 for Stage 10. The ball seated at 3,728 bbls of total slurry. a Total Proppant Pumped (lb) Summary 266,541 of Stage 9 Max pumping Rate (bpm) 41.3 Total Proppant in Formation (lb) 266,541 Average Pumping Rate (bpm) 37.9 Total Slurry Pumped (bbl) 1,751 Maximum Treating Pressure (psi) 7,915 YF127ST Pumped (bbl) 1,477 Average Treating Pressure (psi) 5,860 WF127 Pumped (bbl) 0 Average Viscosity of WF127 (cP) 18.0 Stage 9 Tr. Pressure IA Pressure BHP Caelus Energy Alaska ODSN-01 a 03-29-2016 50 20 �18 40 16 X C1 30 fD a 20 CA a 10 0 12:24:01 12:40:41 12:57:21 13:14:01 13:30:41 Time - hh:mm:ss 14 12 0 10 , 0 F8 r � �6 n 4 2 0 Schlumbep,gep Stage 9: Measured Pump Schedule Client: Caelus Energy Alaska Well: UDSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States Step I 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) As d Pump Schedule PAD 9 36.1 38.4 Step Step Slurry Slurry Pump Fluid 8.3 Ma Prop t Name Volume Rate Time Fluid Name Volume Proppant Name 4294 Mass 1.0 PPA 40.0 (bbl) (bbl/min) (min) (gal) 5 Conc (Ib) 40.5 4958 5008 4926 6 4.0 PPA 40.1 (PPA) 5370 1 PAD 9 175 36.1 4.9 YF127ST 7349 6459 0 0 8.0 PPA Slow for 40.2 6833 7118 6436 9 10.0 PPA 40.0 40.1 2 Seat 5 20A 2.8 YF127ST 210 7686 7819 0 11 Resume 39.9 40.8 7758 7878 7645 12 Spacer IB 32.4 3 PAD 13 39.E 3.3 YF127ST 5460 21.2 3336 13520 4 1.0 PPA 159.9 4C 4 YF127ST 6450 CarboLite w/ 5% CSG 16/20 1.1 617 5 2.0 PPA 179.9 40.4 4.5 YF127ST 696q CarboLite w/ 5% CSG 16/20 2 1374 6 4.0 PPA 204.7 40.11 5.1 YF127ST 7342 CarboLite w/ 5% CSG 16/20 4 2901 7 6.0 PPA 204.6 4 5.1 YF127ST 6825 CarboLite w/ 5% CSG 16/20 6.11 40891 8 8.0 PPA 1 209. 4 5.2 YF127ST 6531 CarboLite w/ 5% CSG 16/20 8.A 5245 9 10.0 PPA 209.3 4 5.2 YF127ST 6133 CarboLite w/ 5% CSG 16/20 10.1 61596 10 12.0 PPA 179. 39.7 4.51 YF127ST 4955 CarboLite w/ 5% CSG 16/20 12.2 5970 Clear 11 Lines 26 39. 0.7 YF127ST 975 CarboLite w/ 5% CSG 16/20 12.1 2958 12 Spacer 20 32.4 0.7 YF127ST 841 13 Ball 2.842" 3 21.1 0.1 YF127ST 126 0 0 Step I 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 9 36.1 38.4 5658 6042 3722 Slow for Seat 20.8 8.3 357 4358 2422 Resume PAD 39.5 40.1 4822 5003 4294 1.0 PPA 40.0 40.5 4943 5008 4834 5 2.0 PPA 40.3 40.5 4958 5008 4926 6 4.0 PPA 40.1 40.4 5370 5672 5013 6.0 PPA 40.0 40.2 6126 6459 5676 8 8.0 PPA 40.0 40.2 6833 7118 6436 9 10.0 PPA 40.0 40.1 7390 7622 7118 10 12.0 PPA 39.7 40.1 7686 7819 7590 11 Clear Lines 39.9 40.8 7758 7878 7645 12 Spacer IB 32.4 41.1 4931 17846 2980 13 all 2.842" 21.1 21.2 3336 13520 P214 schiumbepp Stage 10: Summary Client: Caelus Energy Alaska Well ODSN-la Formation: Nuiqsut District Prudhoe Bay Country: United States Stage 10 consisted of a PAD, 7 proppant steps (1-12PPA), a ball drop and a flush. Flush at the WH was called at 5,034 bbls and the 2.925' Rapidball DM ball was dropped at 5,057 bbls to open Port 10 for Stage 11 which would be pumped on a later day. The ball seated at 5,231 bbls of total slurry. Approximately 46 bbls of freeze protect made it past the wellhead leaving 20 bbls in the surface lines. Total Proppant Pumped (lb) Summary of 222,244 Stage 1 Max pumping Rate (bpm) 40.8 Total Proppant in Formation (lb) 222,244 Average Pumping Rate (bpm) 37.7 Total Slurry Pumped (bbl) 1,889 Maximum Treating Pressure (psi) 7,576 YF127ST Pumped (bbl) 1,378 Average Treating Pressure (psi) 5,707 WF127 Pumped (bbl) 217 Average Viscosity of WF127 (cP) 18.2 Freeze Protect 66 1 Z G N d M Stage 10 Tr. Pressure IA Pressure BHP Caelus Energy Alaska ODSN-01 a 03-29-2016 50 r 20 �18 40 16 r14 CI r 30 fD -12 � o � a 3 10 n 0 20 8 v N � 6 D rr 10 -4 �2 0 0 13:07:46 13:24:26 13:41:06 13:57:46 14:14:26 Time - hh:mm:ss Schlumbep,gep Stage 10: As Measured Pump Schedule Client. Caelus Energy Alaska Well: ODSN-la Formation: Nuiqsut District: Prudhoe Bay Country: United States Step # Step Name Stage Pressures & Average Slurry Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) As Measured Pump Schedule 1 PAD 10 Step Step Slurry Slurry Pump Fluid PMraax op Prop t Name Volume Rate Time Fluid Name Volume Proppant Name Mass 39.4 40.2 (bbl) (bbl/min) (min) (gal) Conc (lb) 39.5 40.2 t878 5003 4779 (PPA) 2.0 PPA 1 PAD 10 165 36.4 4.6 YF127ST 692 0 PPA 40.1 40.3 Slow for 5675 4935 6.0 PPA 40.1 40.3 2 Seat 50 21.1 . 2YF127ST 210 40.1 0 6963 Resuma 10.0 PPA 40.0 40.1 7203 7402 3 PAD 95 39.4 2.4 YF127ST 399 7562 7388 4 1.0 PPA 139.9 39.5 3.5 YF127ST 5643 CarboLite w/ 5% CSG 16/20 1.1 5401 5 2.0 PPA 159.9 40.11 4 YF127ST 61871 CarboLite w/ 5% CSG 16/20 2.11 12188 6 4.0 PPA 179.7 40.1 4.5 YF127ST 6450 CarboLite w/ 5% CSG 16/20 4.1 2539 7 6.0 PPA 1 179.6 40.1 4.5 YF127ST 5993 CarboLite w/ 5% CSG 16/20 6.1 3589 8 8.0 PPA 179.5 39. 4.5 YF127ST 5601 CarboLite w/ 5% CSG 16/20 8.1 4489 9 10.0 PPA 179. 4 4.5 YF127ST 5255 CarboLite w/ 5% CSG 16/20 10.2 5282 10 12.0 PPA 137.8 39.8 3.5 YF127ST 3837 CarboLite w/ 5% CSG 16/20 12.3 4531 Clear 11 Lines 17. 39. 0. YF127ST 71 CarboLite w/ 5% CSG 16/20 5. 337 12 1 Spacer 1 20 32 0.7 YF127ST 841 13 Ball 2.925 3 21 0.1 YF127ST 126 0 14 XL Flush 100 35.8 2.8 YF127ST 4200 15 LG flush 56 38.8 1.5 WF127 2351 Slow for 16 Seat 21.3 14.5 1.7 WF127 893 17MT PCM 139.5 36. WF127 5861 Freeze 18 Protect 66. 29.7 2. Freeze Protect 2782 C 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 10 36.4 38.2 5727 6367 2970 2 SlowforSeat 21.1 35.3 3296 4257 2417 Resume PAD 39.4 40.2 t792 5003 4266 1.0 PPA 39.5 40.2 t878 5003 4779 5 2.0 PPA 40.1 40.3 917 4939 4903 0 PPA 40.1 40.3 5343 5675 4935 6.0 PPA 40.1 40.3 101 6404 5676 8 8.0 PPA 39.9 40.1 693 6963 6372 10.0 PPA 40.0 40.1 7203 7402 6949 10 12.0 PPA 39.8 40.0 7487 7562 7388 11 Clear Lines 39.9 40.5 7444 7521 7365 12 Spacer 32.0 40.7 4684 7430 2811 13 Ball 2.925 21.0 21.1 3229 3402 3076 14 L Flush 35.8 38.8 15713 6235 3406 15 LG flush 38.8 39.0 5368 5750 2786 16 Slowfor Seat 14.5 33.5 2611 2719 2252 17 JIMT PCM 36.8 40.2 3652 3951 2513 18 IFreeze Protect 29.7 31.2 3076 3493 1698 schlumbepoep Job Messages Client: Caelus Energy Alaska Well: ODSN-1a Formation: Nuiqsut District: Prudhoe Bay Country: United States # Time Message Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 08:45:54 Preparing to prime POD 0 0 2 09:23:49 All pumps primed 4 3 09:24:39 LRS PT on IA good 5 9 4 09:26:59 Warming lines 64 4. 5 09:31:32 Lines warmed 46 2. 6 09:33:47 Coming up to low PT 114 0 7 09:36:03 Getting clear all around, coming up to 6,000 psi 76 0 8 09:37:36 Pumps down, brakes set 6020 9 0 9 09:39:17 Coming up to 9,500psi 5653 10 09:49:43 Successful pressure test, bleeding pressure 9146 0 12 09:52:23 Gathering for safety meeting 60 9 0 13 10:28:09 Mixing gel in PCM 18 298 0 14 10:29:30 WH Master valve open, 23.5 turns 14 298 0 01 15 10:29:47 Swab valve open 14 298 0 16 10:45:23 Checking popoff cable 14 288 0 17 10:51:38 LRS bringing IA up to 3,000psi 14 2146 18 10:56:48 Priming POD on gel 14 3023 19 10:57:49 Swapped cables on popoff 14 3019 0 0 20 11:00:42 Putting 500 psi on the lines 279 3005 0 21 11:01:06 Opening hydraulic valve 558 300E 0 0 0 22 11:01:50 Displacing freeze protect fluid 233 300 0 1. 23 11:11:03 Pumps down, brakes set 1515 2991 0 24 11:23:10 Start Pump Check Automatically 819 291 27 11:23:10 Started Pumping 819 291 0 28 11:27:15 Good zero's on main line densos 4994 3458 119.5 40. 31 11:36:16 Start PAD 8 Manually 1295 3371 231 32 1 11:41:17 Ball 2.761" loaded 4578 3531 37T3 39. 33 11:45:27 Started Pumping Prop 5063 3467 543.5 39. 34 11:45:31 Start 1.0 PPA Automatically 5067 3486 546.1 39. 35 11:49:10 Start 2.0 PPA Automatically 5099 3467 691. 40. 1 36 11:52:10 2PPA XL pH = 8.6 5127 3486 812 40.1 37 11:53:09 Start 4.0 PPA Automatically 5154 3490 851.5 40.1 38 1 11:57:46 Start 6.0 PPA Automatically 5740 3476 1036.2 40 3. 39 12:02:23 Start 8.0 PPA Automatically 6509 3476 1220.6 39.8 5. 40 12:06:59 Start 10.0 PPA Automatically 7086 3467 1404.9 40.1 41 12:07:22 Bringing ball dropper van up to 5k psi 7123 3467 1420.2 39.9 1 42 12:11:36 Start 12.0 PPA Automatically 7507 3463 1589.2 40 9. 43 12:15:38 Start Clear Lines Automatically 7690 3458 1749.1 39.4 i 46 12:16:17 Start Spacer Manually 7567 3463 1774.8 40.7 1 12:17:18 Start PAD 9 Automatically 3772 3225 0 21 4 12:17:45 Ball away 1801 total slurry 4898 3280 10.3 27. 5 12:21:58 XL pH = 8.6 5544 3431 165.7 38. 6 12:22:13 Start Slow for Sea Automatically 2087 3138 175.1 30. 7 12:24:06 Ball 2.842" loaded 3081 3266 199.8 15. 8 12:24:14 Ball seat 1992 total slurry 3273 3293 202.1 18.7 10 12:28:21 IStart 1.0 PPA Automatically 5003 3467 355.5 40.1 Schlumberger Client: Caelus Energy Alaska Well: ODSN-la Formation: Nuigsut District: Prudhoe Bay Country: United States # Time Message Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 11 12:28:21 Started Pumping Prop 5003 3467 355.5 40.1 12 12:32:20 Start 2.0 PPA Automatically 4944 3463 514.8 40.4 1 13 12:36:48 Start 4.0 PPA Automatically 5013 3471 694.8 40. 14 12:38:18 2PPA XL pH = 8.6 5264 3481 755 40.1 3.9 15 12:41:54 Start 6.0 PPA Automatically 5681 349 899.3 40. 16 12:47:01 Start 8.0 PPA Automatically 6468 3509 1104.1 39.9 5.9 17 12:52:15 Start 10.0 PPA Automatically 7123 3476 1313.3 4 8 18 12:54:41 Bringing ball dropper van up to 5k psi 7425 3481 1410.4 39.S1 19 12:57:30 Start 12.0 PPA Automatically 7594 3481 1523.2 40.1 10.1 23 13:02:39 Start Spacer Manually 7768 3458 1728 41.1 0 25 13:03:22 Start Ball 2.842' Automatically 3333 3188 1748.1 21 1 13:03:31 Start PAD 10 Automatically 3557 3193 0 20. 5 13:09:52 Ball seat 3728 total slurry 304 3234 187 14.2 01 8 13:13:17 Start 1.0 PPA Automatically 5003 3476 309.7 40.2 0 9 13:13:17 Started Pumping Prop 500 3476 309.7 40.2 1 10 13:16:50 Start 2.0 PPA Automatically 4921 3476 449.8 40. 1 11 13:19:30 2PPA XL pH = 8.6 491 3440 556.7 40.1 2 12 13:20:49 Start 4.0 PPA Automatically 493 3463 609.5 40.1 13 13:25:18 Start 6.0 PPA Automatically 5676 3481 789.4 40. 14 13:29:47 Start 8.0 PPA Automatically 640 3472 96 4 15 13:34:17 Start 10.0 PPA Automatically 6958 3458 1148.4 4 8 16 13:36:44 Bringing ball dropper van up to 5k psi 7251 3440 1246.3 40.1 10.1 17 13:38:47 Start 12.0 PPA Automatically 742 349 1328.4 40.1 1 20 13:42:14 Start Clear Lines Manually 7321 3435 1465.6 39.5 2.8 23 13:42:40 Start Spacer Manually 7333 3449 1483 40.7 24 13:43:02 Stopped Pumping Prop 2829 317 1495.3 23.3 25 13:43:24 Start Ball 2.925 Automatically 328 319"1503.2 21 26 13:43:32 Start XL Flush Automatically 3406 3197 1506 21 0 27 13:46:22 Start LG flush Automatically 5736 3403 1606.2 38. 29 13:49:29 Start MT PCM Manually 2458 3216 1683.2 12. 0 32 13:53:29 Start Freeze Protect Manually 2948 3403 1822.7 31.1 33 13:53:32 Activated Extend Stage 2943 3412 1824.3 30. 0 34 13:54:40 FP at WH 5394 3227 3389 1859. 30.8 0 35 13:55:17 Stage at Perfs: Slow for Seat 3493 3367 1878., 30.8 36 13:56:08 69 bbls of FP pumped from transport 1854 3243 1889 0 37 1 14:15:54 jHydraulic valve shut 14 2959 188 38 1 14:15:59 ISurface pressure bled off 14 2923 1889 0 0 schlumbepuep FracCAT Treatment Report Well : ODSN-01 a, Stages 11-12 Field Oooguruk Formation : Nuigsut Prepared for 365 Client : Caelus Energy Alaska Client Rep Mike Martin Date Prepared 04/20/16 Prepared by Surface Shut in Pressure(psi) Name : Alexander Martinez Division Schlumberger Phone :561-389-5006 Pressure (All Zones) Initial Wellhead Pressure (psi) 365 Initial BHP at Gauge (psi) 2,842 Final Surface ISIP (psi) 2,568 Final ISIP at Gauge (psi) 4,817 Surface Shut in Pressure(psi) 1,894 BH Shut in Pressure (psi) 4,385 Maximum Treating Pressure (psi) Treatment Totals (All Zones As Per FracCAT) 7,657 BH Gauge at 10,204' MD, 6,045' TVD Total Slurry Pumped Water+Adds+Proantbblsast 3,600 Total YF127ST PWellhead ead (bbls) 2,749 Total WF127 Past Wellhead (bbls) 285 Total Freeze Protect Past Wellhead bbls 43 Total Proppant Pumped (lbs.) Total Chemical Additives Invoiced 486,400 Past WH Total Proppant in Formation (lbs.) Invoiced 485,508 Past WH F103 (gal) 134 134 J510(bbis) 0 0.3 L065 (gal) 256 256 J218 (lbs.) 110 110 J580 (lbs.) 3483 3414 J475 (lbs.) 770 770 J922(mgal) 116 115 J134 (lbs.) 0 0 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 interred. Schlumberger Summary Client: Caelus Energy Alaska Well: ODSN-01a Formation: Nuiqsut District: Prudhoe Bay Country: United States On March 30, 2016, Schlumberger finished stages 11-12 for the ODSN-01 a well. The treatment consisted of 2 stages with 1 Rapidball DM ball drop. Approximately 486,400 lbs of proppant in 3,600 bbl of slung was pumped during this treatment. The well was freeze protected using physical straps from the freeze protect transport and it was determined that 43 bbls of freeze protect fluid made it into the well. The PCM viscometer was not functioning properly upon startup, for fluid QAQC purposes a Fann35 was placed in the PCM with a dedicated operator checking the viscosity of the gel periodically. During stage 11, pump 3 had an issue but it was quickly resolved. All stages were pumped as designed and the summary for the totals is noted below. a. Pressure Test Materials Actual (Design) Slurry Volume- All Volumes (bbl) 3,600 (3587) Clean Fluid- All Volumes (bbl) 3,026 (3008) Proppant, lbs. 486,400 (486,400) Tr. Pressure Caelus Energy Alaska IA Pressure ODSN-01a BHP 03-30-2016 1 U: Ub:51 10:15:11 10:23:31 10:31:51 10:40:11 Time - hh:mm:ss 20 18 16 14 z � 12 O CD a n a 10 3 � 8 v n 6 4 2 0 o Q 6000 d N N a 4000 2000 0 11:54:22 Main Treatment Tr. Pressure IA Pressure BHP Shirry Rata Caelus Energy Alaska ODSN-01 a 03-30-2016 50 -20 18 40 r16 12:27:42 13:01:02 13:34:22 Time - hh:mm:ss F14 30 12 c n rr 10 0= 20 8 n 6 10 4 2 0 14:07:42 0 Stage 11: Summary Stage 11 consisted of a PAD, 7 proppant steps (1-12PPA), a ball drop and a flush. A total of 1,840 bbls of slurry was pumped during this stage with 242,608 lbs of proppant. Flush at the WH was called at 1815 bbls and the 3.009" Rapidball DM ball was dropped at 1838 bbls to open Port 11 for Stage 12. The ball seated at 2,001 bbls of total slurry. Total Proppant Pumped (lb) Summary 242,608 of Stage 11 Max pumping Rate (bpm) 40.9 Total Proppant in Formation (lb) 242,608 Average Pumping Rate (bpm) 37.9 Total Slurry Pumped (bbl) 1,840 Maximum Treating Pressure (psi) 7,657 YF127ST Pumped (bbl) 1,363 Average Treating Pressure (psi) 5,523 WF127 Pumped (bbl) 223 Average Viscosity of WF127 (cP) 21 Freeze Protect 0 a Stage 11 Tr. Pressure IA Pressure BHP Caelus Energy Alaska ODSN-01 a 03.30.2016 50 40 30rrd Q 20 3 10 12:15:25 12:32:05 12:48:45 13:05:25 13:22:05 Time - hh:mm:ss 20 18 16 -14 6 4 0 schlumbepoep Stage 11: As Measured Pump Schedule Client: Caelus Energy Alaska Well. ODSN-01a Formation: Nuigsut District: Prudhoe Bay Country: United States As Measured Pump Schedule Step # Step Step Slurry Slurry Pump Fluid Pump Check Drax Prop # Name Volume Rate Time Fluid Name Volume Proppant Name op Mass 1963 1331 (bbl) (bbl/min) (min) (gal) 40.3 Cone (Ib) 1400 1.0 PPA 40.2 40.3 4915 (PPA) 48A2 5 Pump 40.1 40.4 4925 4957 4897 4.0 PPA 1 Check 223 37. 7. WF127 9364 6.0 PPA 40.0 40.2 2 PAD 11 320 38. 8.8 YF127ST 1344 40.2 6441 6692 3 1.0 PPA 149. 40. 3.7 YF127ST 60401 CarboLite w/ 5% CSG 16/20 1.1 585 4 2.0 PPA 169.9 40.1 4.2 YF127ST 65731 CarboLite w/ 5% CSG 16/20 2.1 1278 5 4.0 PPA 189.7 4 4.7 YF127ST 68051 CarboLite w/ 5% CSG 16/20 4.11 2651 6 6.0 PPA 189.6 4 4.7 YF127ST 6327 CarboLite w/ 5% CSG 16/20 6.1 3731 7 8.0 PPA 189.5 39. 4.8 YF127ST 5909 CarboLite w/ 5% CSG 16/20 8.1 4677 8 10.0 PPA 189.4 39. 4.8 YF127ST 5549 CarboLite w/ 5% CSG 16/20 10.1 5490 9 12.0 PPA 169. 39.-, 4.3 YF127ST 4677 CarboLite w/ 5% CSG 16/20 12.2 5563 Clear 10 Lines 25. 39. 0. YF127ST 95 CarboLite w/ 5% CSG 16/20 1 283 11 Spacer 20 3 0.7 YF127ST 1 84 12 Ball 3.0091 31 20. 0.1 YF127ST 1 126 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 Pump Check 37.9 40.5 459 5446 823 2 PAD 11 9.3 12.0 1832 1963 1331 PAD 11 38.7 40.3 4307 4906 1400 1.0 PPA 40.2 40.3 4915 4961 48A2 5 2.0 PPA 40.1 40.4 4925 4957 4897 4.0 PPA 40.0 40.1 5269 5483 4952 6.0 PPA 40.0 40.2 5875 6161 5483 8.0 PPA 39.7 40.2 6441 6692 6161 9 10.0 PPA 39.7 40.0 7125 7424 6536 10 12.0 PPA 39.7 40.1 7509 7593 7424 11 Clear Lines ]Ball 39.9 40.6 7556 7644 7484 12 Spacer 32.0 40.8 4683 7557 2970 13 3.009 20.9 21.0 3276 3463 0171 Schlumberger Stage 12: Summary Client: Caelus Fnergy Alaska Well: ODSN-Ola Formation: Nuiqsut District: Prudhoe Bay Country: United States Stage 12 consisted of a PAD, 7 proppant steps (1-12PPA) and a flush. A total of 1,761 bbls of slurry was pumped during this stage with 243,792 lbs of proppant. Flush at the WH was called at 3429 bbls and the final shutdown total was 3600 bbls that included a 6 bbls underflush. Total Proppant Pumped (lb) Summary of 243,792 Stage 12 Max pumping Rate (bpm) 41.4 Total Proppant in Formation (lb) 242,900 Average Pumping Rate (bpm) 39.1 Total Slurry Pumped (bbl) 1,761 Maximum Treating Pressure (psi) 7,438 YF127ST Pumped (bbl) 1,378 Average Treating Pressure (psi) 5,712 WF127 Pumped (bbl) 62 Average Viscosity of WF127 (cP) 21 Freeze Protect 67 a - Stage 12 Tr. Pressure IA Pressure BHP CI...... 0-6— Caelus Energy Alaska ODSN-01a 03.30-2016 50 40 30 v M Cr 3 20 �. 10 0 12:57:32 13:14:12 13:30:52 13:47:32 14:04:12 Time - hh:mm:ss 0 8 6 4 v 2 '3 a C7 D v D schlumbepoep Stage 12: As Measured Pump Schedule Client: Caelus Energy Alaska Well: ODSN-01a Formation: Nuiqsut District Prudhoe Bay Country United States 7Step Step Name Stage Pressures & Average Slurry 1 Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) As Measured Pump Schedule 1 PAD 12 36.2 38.3 5634 6156 474 Slow for Seat 21.8 Step Step Slurry Slurry Pump Fluid 39.9 Max Pro p # Name Volume Rate Time Fluid Name Volume Proppant Name Pro Mass 5 2.0 PPA (bbl) (bbl/min) (min) (gal) 4545 Conc (lb) 40.0 40.2 5107 5511 4632 6.0 PPA (PPA) 40.2 1 PAD 12 147. 36. 4.1 YF127ST 6173 40.1 0.0 0 6298 Slow for 10.0 PPA 40.2 40.3 7081 7232 6856 10 2 Seat 50. 21. 2.6 YF127ST 210 11 0. 40.5 40.8 Resume 7374 7259 12 XL Flush 40.6 1.3 836 3 PAD 120. 39. 3.0 YF127ST 5040 P051 0.0 a 4 1.0 PPA 149. 40. 3.8 YF127ST 6048 CarboLite w/ 5% CSG 16/20 1.1 566 5 2.0 PPA 169.1 40.1 4.2 YF127ST 6574 CarboLite w/ 5% CSG 16/20 2.0 1275 6 4.0 PPA 189.7 40.0 4.7 YF127ST 6806 CarboLite w/ 5% CSG 16/20 4.1 26461 7 6.0 PPA 189. 40. 4.7 YF127ST 63271 CarboLite w/ 5% CSG 16/20 6.Q 3727 8 8.0 PPA 189.5 39. 4.7 YF127ST 5910 CarboLite w/ 5% CSG 16/20 8.1 4669 9 10.0 PPA 189.4 40., 4.7 YF127ST 5549 CarboLite w/ 5% CSG 16/20 10.2 5484 10 12.0 PPA 188.8 40. 4.71 YF127ST 5310 CarboLite w/ 5% CSG 16/20 12.3 5997 Clear 11 Lines 6. 40. E 0.2 YF127ST 284 CarboLite w/ 5% CSG 16/20 0.9 11 12 XL Flush 42. 40.6 1.0 YF127ST 1761 0.1 13 LG Flush 62. 40.1 1.6 WF127 260 0.0 0 14 FLUSH 66.7 31. 2. Freeze Protect 2800 0. 7Step Step Name Stage Pressures & Average Slurry 1 Maximum Slurry Rate Rate (bbl/min) (bbl/min) Rates Average Treating Pressure (psi) Maximum Treating Minimum Treating Pressure Pressure (psi) (psi) 1 PAD 12 36.2 38.3 5634 6156 474 Slow for Seat 21.8 36.8 305 4225 2558 Resume PAD 39.9 40.2 t681 4778 4233 1.0 PPA 40.0 40.3 t637 4742 4563 5 2.0 PPA 40.1 40.4 1.575 4629 4545 4.0 PPA 40.0 40.2 5107 5511 4632 6.0 PPA 40.0 40.2 5957 6298 5515 8.0 PPA 39.9 40.1 6604 6856 6298 10.0 PPA 40.2 40.3 7081 7232 6856 10 12.0 PPA 40.0 40.3 7248 7296 7195 11 Clear Lines 40.5 40.8 7307 7374 7259 12 XL Flush 40.6 1.3 836 7374 6616 13 LG Flush 40.1 0.7 P051 6600 F531 14 FLUSH 01.6 P3.6 R038 14494 1945 schlumbepoep Job Messages Client: Caelus Energy Alaska Well: ODSN-Ola Formation: Nuiqsut District: Prudhoe Bay Country: United States # Time Message Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 09:37:39 Priming POD on Freeze protectfluid 27 393 0 2 09:41:54 Priming Pumps 31 397 0 0 0 3 09:57:59 Pumps primed 45 39 4 09:58:08 Preparing to warm lines 40 39 0 0 5 10:06:39 Lines warmed 27 39 0 6 10:09:36 Coming up to low PT 36 39 0 0 0 7 10:12:45 Bringing pressure up to 6k psi 736 397 0 0 8 10:22:15 Bumping pressure 9131 39 0 0. 9 10:28:13 Pressure test good, bleeding surface pressure 9049 397 0 0 0 10 10:31:43 Gathering for safety meeting 59 393 0 11 10:54:05 LRS good PT on IA line 17 397 0 0 0 12 11:09:33 Safety meeting done -1 388 0 0 0 13 11:10:54 Master WH valve open, swab valve open -1 649 0 0 14 11:14:30 LRS bringing IA to 3k psi -1 2457 0 0 0 15 11:20:03 Troubleshooting PCM viscometer -1 2975 0 0 16 11:34:24 Setting Fann35 Viscometer up in PCM for visc. monitoring -1 294 3 0 17 11:34:39 POD priming up on gel -1 2938 0 0 18 11:38:34 Wellhead Open: Hydraulic open 402 293 0 0 19 11:39:06 Started displacing lines with gel 722 297 20 11:44:52 Displacing FP fluid 1615 2901 0 2.9 0 21 12:00:27 Start Pump Check Automatically 828 292 0 0 22 12:04:27 Good zero on in-line densos 4627 34U 120. 40.3 23 12:06:20 Activated Extend Stage 3593 3377 196.3 40. 0 24 12:10:46 LG check, 21cP at 94degF 1464 3341 215.3 0 0 25 12:12:15 Start PAD 11 Manually 1441 3345 215.3 0 0 26 12:12:22 XL ads rolled out 1441 3345 215. 0 0 27 12:13:43 PCM engine shutdown, coming down on rate 1317 335 22: 0 0 28 12:16:02 Start PAD 11 Manually 140C 3373 22 0 0 29 12:17:20 PCM restarted, going downhole 3126 3446 239.9 28.1 0 30 12:20:09 PAD XL pH = 8.6 4261 3474 350., 40.1 0 31 12:22:53 LG - 21 cP at 94degF 4856 3441 459.8 40 0 32 12:23:37 Tank 1 final strap, 8'6" 4883 3474 489. 40.1 0 33 12:24:54 Started Pumping Prop 4915 3451 540. 4 0 34 12:24:58 Start 1.0 PPA Automatically 4911 346C 543. 4 0 35 12:28:34 LG - 21 c at 95deg 4902 3441 687.8 40.A 1 36 12:28:42 Start 2.0 PPA Automatically 4906 3441 693.2 40. 1 37 12:31:43 2PPA XL pH = 8.6 4929 3437 814.2 40.1 2 38 12:32:56 Start 4.0 PPA Automatically 4952 344q 862.9 40.1 39 12:35:42 LG - 20c P at 95deg 5359 3414 973.7 40 4.1 40 12:37:03 LG - 19cP at 96deg 5465 3428 1027. 4 4 41 12:37:41 Start 6.0 PPA Automatically 5483 3432 1053.1 4 42 12:40:15 LG - 20cP at 96deg 5982 3451 1155.7 40.1 6 43 12:42:25 Start 8.0 PPA Automatically 6161 3460 1242.6 40.1 6 44 12:46:15 Looking at pumps 1 6504 341 1395.6 38.7 8 45 1 12:47:11 Start 10.0 PPA Automatically 6577 340N 1431.6 38.5 8 46 1 12:48:00 Pump 3 lined out 6930 339N 1463.7 39461 9. Schlumberger Client: Caelus Fnergy Alaska Well. ODSN-Ola Formation: Nuiqsut District: Prudhoe Bay Country: United States # Time Message Message Log Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 47 12:48:42 LG - 21 cP at 87deg 6994 3437 1491.4 39.6 1 48 12:50:34 Bringing ball dropper van up to 5k psi 7314 3419 1565.7 39.9 1 49 12:51:57 Start 12.0 PPA Automatically 742 3419 1621.1 40.1 1 50 12:56:13 Start Clear Lines Automatically 758q 340 1790.4 39.5 12.1 51 12:56:51 Start Spacer Manually 7442 340 1815.7 40.8 52 12:57:35 Start Ball 3.009 Automatically 3235 316 1836 20.9 0 53 12:57:43 Start PAD 12 Automatically 3501 3171 0 20.9 0 54 12:58:22 Ball away 1838 total slurry 5552 3277 17.4 33.3 55 12:59:58 LG - 21cP at 90deg 5913 346 76.4 38.1 0 56 13:01:14 XL pH = 8.6 5544 3455 124.9 38. 57 13:03:20 Ball seat 2001 total slurry 2861 328 169.4 12.1 58 13:04:28 Start Resume PAD Automatically 4302 3377 197.5 37. 59 13:07:28 Start 1.0 PPA Automatically 4732 344E 317.31 40. 60 13:07:28 Started Pumping Prop 4732 3446 317.3 40. 61 13:09:23 LG - 20cP at 96deg 4673 3474 393.4 40. 1 62 13:11:13 Start 2.0 PPA Automatically 4590 3474 467.3 40. 1 63 13:14:31 LG - 19c at 87deg 45951 3428 599.7 40.1 64 13:15:27 Start 4.0 PPA Automatically 4636 3405 637.1 40.1 65 13:18:51 LG - 20c P at 83 deg 5337 3373 773.1 40 4 66 13:20:11 Start 6.0 PPA Automatically 5529 342 826.5 40.1 67 13:23:03 XL pH = 8.6 6096 3405 941.3 4 5. 68 13:24:55 Start 8.0 PPA Automatically 6312 346 1016.1 39. 69 13:25:19 LG - 21 c P at 84deg 63161 3455 1032 39.9 8 70 13:29:40 Start 10.0 PPA Automatically 6861 34091 1205.6 40 8 71 13:34:23 Start 12.0 PPA Automatically 7191 345N 1395.2 40. 9. 72 13:36:17 LG - 22cP at 88deg 7209 3455 1471.3 39.8 11.8 73 13:39:06 Start Clear Lines Manually 7287 3455 1583.7 40.5 0. 74 13:39:16Start XL Flush Manually 737 346 1590.5 41. 0.1 75 13:40:03 Stopped Pumping Prop 6664 3451 1622.3 40.3 76 13:40:19 Start LG Flush Automatically 6573 3455 1633.1 40. 77 13:41:52 Start FLUSH Automatically 4325 3387 1694.5 33.1 78 13:42:44 Activated Extend Stage 3867 3345 1722 31.6 79 13:47:20 Total FP pumped from transport = 60 bbls 1958 3130 1761.2 0 P8--01 13:52:44 LRS bleeding down to 500psi -1 2498 1761. 0 0 13:53:00 H closed, surface pressure bled off 1 2389 1761.2 0 0 schlobeplar Client: Caelus Energy Alaska Well: ODSN-Ola Basin/Field: Ooogu ruk State: Alaska County/Parish: North Slope Borough Case: 631349437 Disclosure Type: Post -Job Well Completed: 3/30/2016 Date Prepared: 4/27/2016 5:57 PM Report ID: RPT -42394 Fluid D- YF127ST,WF127 1,363,152 Gal Contains: Water, Surfactant, Breaker, Stabilizing Agent, Base Oil, Crosslinker, Gelling Agent, Scale Inhibitor, Additive, Solid Scale Inhibitor, Propping Agent The total volume listed in the tables above represents the summation of water and additives. Water is supplied by client. NumberCAS _—W—a—t—e—rTin—cluding Mix Water Supplied bClient' 85.33315 % CAS Not Assigned Potassium salt of maleic acid co -polymer 0.06486% 56-81-5 1, 2, 3 - Pro anetriol 0.04690 % 64-19-7 Acetic acid(impurity) <0.00001 % 67-63-0 Pro an-2-ol 0.00672% 102-71-6 2,2',2"-nitrilotriethanol 0.00346% 107-21-1 Ethylene glycol 0.01689% 111-46-6 2,2" -ox diethanol (impurity) 0.00017% 111-76-2 2-butox ethanol 0.00672 % 112-42-5 1-undecanol 0.00054% 127-08-2 Acetic acid, potassium salt 0.00002% 1303-96-4 Sodium tetraborate decah drate 0.03830% 1310-73-2 Sodium hydroxide (impurity) 0.00248% 7447-40-7 Potassium chloride (impurity) 0.00005 % 7631-86-9 Non -crystalline silica (impurity) 0.00028% 7647-14-5 Sodium chloride 0.00319% 7727-54-0 Diammonium peroxidisulphate 0.02296 % 9000-30-0 Guar gum 0.11063 % 9002-84-0 of tetrafluoroeth lene 0.00006% 9003-35-4 Phenolic resin 0.03603 % 10043-52-4 Calcium Chloride 0.00161% 14807-96-6 Magnesium silicate hydrate talc 0.00013% 25038-72-6 Vinylidene chloricle/methylacrylate copolymer 0.00431 % 34398-01-1 Alcohol, C11 linear, ethox lated 0.00617% 64742-47-8 Distillates, petroleum, hydrotreated light 0.01305 % 66402-68-4 Ceramic materials and wares, chemicals 14.34145 % 68131-39-5 C12-15 alcohol eth ox lated 0.00335 % 129898-01-7 2 -Pro enoic acid of mer with sodium phosQhinate 0.01580% Total ' The evaluation of attached document is performed based on the composition of the identified products to the extent that such compositional information was known to GRC-Chemicals as of the date of the document was produced. Any new updates will not be reflected in this document. © Schlumberger 2016. Used by Caelus Energy Alaska by permission. Page: 1 / 1 ODSN-01A Nuiqsut Production Well Completion I I 1 Landed Upper Packer Fluid mix: Inhibited Kill weight Brine with 2000' TVD diesel car) 1 I Completion 1 I with 40,000 lbs 1 1 Slack -Off 16" Conductor GLM# 3 5 DGLV Iristalled 7 7,000 psi Max rated GLM# 2 DGLV Installed 7,000 psi Max rated GLM#1 5/16" OV Installed 7,000 psi Max rated ES -II Cementer @ 8,632 ft. MD 11-3/4" 60# L-80 BTC Surface Casing @ 4,308' MD / 3,334' TVD cemented to surface hL Whipstock Window: 4,077,-4, 099'MD 9-5/8" Permanent Bridge Plug @ 4,194 MD I 1 I TOC Estimated 1 @ 500 ft above 9-5/8" Shoe kL- 9-5/8" 40# L-80 1 Hydril 521 Intermediate 1 I Casing I @ 7,940' MD / 5,003' TVD 7" Stage 2 TOC Estimated @ 7,459 ft MD I R� 7" Stage 1 TOC Estimated . @ 9,850 ft. MD 7" 26# Hydril 563 Intermediate 2 Casing @ 11,354' M D / 6,272' TVD 4-28-2016 FINAL No. UpperCompleton MID (ft) TVD (ft) 1 Tubing Hanger 34 34 2 4-'/,"12.6#/ft C- 110 Hyd ri 1521 Tu b i ng 3 4Y" Halliburton'XXO' SVLN w/3.813" "X" profile with singlel/4" x 0.049" s/s control line. Cannon Cross -coupling clamps on every joint w/ 15ft Pup BxP Top & Bottom 2'186 2'048 4 4Y,="12.6#/ft C-110 Hydri 1521 Tu bing 5 4Y" x 1" GLM # 3, KBG-45 Hydril 521 w/ 15ft Pup BxP Top & Bottom 2,833 2,531 6 4-W'12.6#/ft C-110 Hyd ri 1521 Tubi ng (2 Joi nts) 7 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 2,952 2,608 8 4Y"12.6#/ft C- 110 Hydril 521 Tu hi ng 11,404 6,276 9 4-Y" x 1" GLM # 2, KBG-45 Hydril 521 w/ 15ft Pup BxP Top & Bottom 5,689 3,974 10 4Y"12.6#/ftC- 110 Hydri 1521 Tu b i ng (2 J o i nts) 11 HES 'X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 5,808 4,028 12 4W'12.6#/ft C-110 Hydril 521 Tubing 13 4-'/," x 1" GLM # 1, KBG-4-5 Hydril 521 w/ 15ft Pup BxP Top & Bottom 10,013 5,958 14 4-Y,,"12.6#/ft C-110 Hydril 521 Tubing (2 Joints) 15 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 10,132 6,013 16 4-W'12.6#/ft C-110 Hydril S21 Tubing 17 41/2"Halliburton'ROC'GaugeCarrierw/ Encapsulated e-IinetoSurfacew/15ft Pup BxPTop& Bottom 10,204 6,045 18 4-Y"12.6#/ft C-110 Hydril 521 Tubing (2 jt) 11,891 6,286 19 HES XN 3.813" (3.725" NoGo) - w/ 15ft Pup BxP Top & Bottom 10,320 6,092 20 4-Y"12.6#/ft C-110 Hydril S21 Tubing 21 4-1/2"x4" Crossover P-110 Locator with a 5.66' long 41/2" handling pup on top, 4" SpacerPupw/ Bullet Seal Assembly+Solid Mule Shoe 11,118 6,251 Bottom of Shoe 11,152 6,254 No, Lower Completion MD (ft) TVD (ft) 22 20 ft 5.25" Tie Back extension 11,098 6,249 Baker5 X T' ZXP Liner Top Packer with Flex Lock Hanger / 20 ft 4.25" Seal Bore Recepticle Below 23 Hanger 11,119 6,251 24 4-X" 12.6#/ft Hyd riI S21 C-110 Liner 25 Res man Internally Vented Carrier# 4 ROS -1525-1 / RWS-1531-1 w/ 15ft Pup BxP Top & Bottom 11,205 6,259 26 4-W' 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 13 (4Y" Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 27 Volant Centralizer Pin End and 6ft Pup 41/2" 126#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 11,404 6,276 Centralizer on Top of Swell Packer Halliburton Swell Packer # 12 (4Y" Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 28 Volant Centralizer Pin End and 6ft Pup 41/2" 126#/ft P-110 Hydril 521 Box x Pin w/Slide On Volant 11,444 6,280 Centralizer on Top of Swell Packer 29 4-Y"12.6#/ft Hydril 521 C-110 Liner HL84-1/2" RapidStage Ball Actuated Sleeve (3.009 ball / 2.955eat) w/ 15ft 41/2" P-110 Pup 41/2" 30 126#/ft P-110 Hydril 521 Box x Pin 11' 618 6,288 31 4-Y" 12.6#/ft Hyd ri 1 521 C-110 Line r Halliburton Swell Packer # 11(42" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 32 Volant Centralizer Pin End and 6ft Pup 41/2"126#/ftP-110 Hydril 521 Box x Pin w/ Slide On Volant 11,891 6,286 Centralizer on Top of Swell Packer 33 4-Y'12.6#/ft Hydri1521 C-110 Liner HLB 41/2"RapiciStage Ball Actuated Sleeve (2.925 ball/ 2.867 Seat) w/ 15ft 4-1/2"P-110 Pup 41/2" 34 12.6#/ft P-110 Hydril 521 Box x Pin 12,271 6,282 35 4-W' 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 10 (4Y" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 36 Volant Centralizer Pin End and 6ft Pup 41/2" 126#/ft P-110 Hydril 521 Box x Pin w/Slide On Volant 12,422 6,280 Centralizer on Top of Swell Packer 37 4-'/,"12.6#/ft Hydril S21 C-110 Liner HL841/2" RapidStage Ball Actuated Sleeve (2.842 ball /Z786 Seat) w/15ft41/2"P-110Pup41/2" 38 126#/ft P-110 Hydril 521 Box x Pin 12,841 6,272 39 4-%"12.6#/ft Hyd ri 1521 C-110 Li ner Halliburton Swell Packer #9 (4-Y," Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 40 Volant Centralizer Pin End and 6ft Pup 41/2" 126#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 13,199 6,266 Centralizer on Top of Swell Packer 41 4-Y" 12.6#/ft Hydril 521 C-110 Liner 32 `�or;;%_r7a-_ 50__ OTu1 DU M 12 4-1/" Hydril 521 / C-110 Liner with Halliburton Ball Actuate Sleeves, & Swell Packers 74 76 80 78 _ _ � 83 - I � `L .. 6-1/8" Hole TD Actuated @ 18,811' MD / 6,338' TVD ODSN-01A Nuiqsut r'roduction Well Completion I I Landed Upper Packer Fluid mix: Inhibited Kill weight Brine with 2000' TVD diesel can I I Completion I I with 40,000 lbs I Slack -Off I 16" Conductor GLM# 3 5 DGLV Installed 7 7,000 psi Max rated GLM# 2 DGLV Installed 7,000 psi Max rated GLM# 1 5/16" OV Installed 7,000 psi Max rated ES -II Cementer @ 8,632 ft. MD I 11-3/4 60# L-80 BTC Surface 3 Casing @ 4,308' MD / 3,334' TVD cemented to surface J I I I Whipstock Window: 4,077'- 4,099' MD 9-5/8" Permanent BridgE Plug @ 4,194 MD I I I TOC Estimated ( @ 500 ft above 9-5/8" Shoe 9-5/8" 40# L-80 Hydril 521 Intermediate 1 I Casing I @ 7,940' MD / 5,003' TVD x7T 7" Stage 2 TOC Estimated I @ 7,459 ft. MD I Roc 7" Stage 1 TOC Estimated @ 9,850 ft. MD ii 7" 26# Hydril 563 Intermediate 2 Casing @ 11,354' MD / 6,272' TVD 4-28-2016 FINAL No. Lower Completion MD(ft) TVD(ft) HLB 41/2" RapidStage Ball Actuated Sleeve(2.761 ball/ 2.706 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 42 12.6#/ft P-110 Hydril 521 Box x Pin 13,495 6,262 43 4-%" 12.6#/ft Hydril S21 C-110 Liner 44 Resman Internally Vented Carrier # 3 ROS -15241 / RWS-1530-1 w/ 15ft Pup BxP Top & Bottom 13,689 6,258 45 4-%"12.6#/ft Hyd ri1521 C-110 Li ner Halliburton Swell Packer # 8 (4-Y." Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 46 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 13,850 6,253 Centralizer on Top of Swell Packer 47 4-Y" 12.6#/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.681 ball/ 2.628 Seat) w/ 15ft 41/2"P-110 Pup 41/2" 48 12.6#/ft P-110 Hydril 521 Box x Pin 14,144 6,247 49 4-Y," 12.6#/ft Hydril S21 C-110 Liner Halliburton Swell Packer # 7 (4-%" Hydril 521) OD SM'- 9 meter long oil activated with Slide on 50 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 14,378 6,240 Centralizer on Top of Swell Packer 51 4-%" 12.6#/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.603 ball / 2.552 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 52 12.6#/ft P-110 Hydril 521 Box x Pin 14,711 6,230 53 4-%" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 6 (4-YV' Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 54 Volant Centralizer Pin End and 6ft Pup 4-V2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 14,945 6,229 Centralizer on Top of Swell Packer 55 4-W'12.6#/ft Hyd n1521 C-110 Li ner HLB 41/2" RapidStage Ball Actuated Sleeve (2.527 ball / 2.477 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 56 12.6#/ft P-110 Hydril 521 Box x Pin 15,321 6,224 57 4-%" 12.6#/ft Hydril 521 C-110 Liner 58 Resman Internally Vented Carrier# 2 ROS -1523-1 / RWS-1529-1 w/ 15ft Pup BxP Top & Bottom 15,512 6,221 59 4-%" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 5 (4-Y." Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 60 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 15,631 6,219 Centmlizeron Top of Swell Packer 61 4-%" 12.6#/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.452 ball / 2.404 Seat) w/ 15ft41/2" P-110 Pup 41/2" 62 12.6#/ft P-110 Hydril 521 Box x Pin ]5,%7 6,216 63 4-%"12.6#/ft Hyd ri1521 C-110 Li ner Halliburton Swell Packer # 4 (4%" Hydril 521) OD 5.85- 9 meter long oil activated with Slide on 64 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 16,367 6,221 Centralizer on Top of Swell Packer 65 4-%" 12.64/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.379 ball / 2.332 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 66 12.6#/ft P-110 Hydril 521 Box x Pin 16,786 6,218 67 4-W' 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 3 (4-%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 68 Volant Centralizer Pin End and 6ft Pup 4-V2" 12.6#/ft P-110 Hydril 521 Box x Pin w/Slide On Volant 17,102 6,216 Centralizer on Top of Swell Packer 69 4-Y=" 12.6#/ft Hydril 521 C-110 Liner HLB41/2" RapidStage Ball Actuated Sleeve (2.307 ball / 2.261 Seat) w/ 15ft41/2" P-110 Pup 41/2" 70 12.6#/ft P-110 Hydril 521 Box x Pin 17,399 6,214 71 4-%" 12.6#/ft Hyd ri 1 521 C-110 Li ne r 72 Resman Internally Vented Carrier # 1 ROS -1522-1 / RWS-1528-1 w/ 15ft Pup BxP Top & Bottom 17,553 6,212 73 4-%"12.6#/ft Hydri1521 C-110 Li ner Halliburton Swell Packer # 2 (4%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 74 Volant Centralizer Pin End and 611 Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 17,672 6,211 Centralizer on Top of Swell Packer 75 4-Y"12.6#/ft Hydri1521 C-110 Li ner HLB 41/2" RapidStage Ball Actuated Sleeve (2.236 ball / 2.192 Seat) w/ 15ft 41/2" P-110 Pup 41/2' 76 12.6#/ft P-110 Hydril 521 Box x Pin 18,255 6,223 77 4-W' 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 1(4'/:" Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 78 Volant Centralizer Pin End and 6ft Pup4,V2"12.6#/ft P-110 Hydril 521 Boxx Pin w/Slide On Volant 18,366 6,231 Centralizeron Top of Swell Packer 79 4-Y="12.6#/ft Hydril 521 C-110 Liner 80 Pre -perforated Pup w/ 4-YV' 12.6#/ft Hydril 521 w/ 15ft 41/2" P-110 Pup BxP Top & Bottom 18,420 6,237 81 Pre -perforated Pup w/ 4%" 12.6#/ft Hydril 521 w/ 15ft 4-1/2" P-110 Pup BxP Top & Bottom 18,424 6,238 82 4-%"12.6#/ft Hydril 521 C-110 Liner 83 4-%" Hydril 521 Eccentric Shoe with Double Float Sub 18,436 6,239 Bottom of Assembly 18,440 6,240 O60 O 68 70 74 - 710a 27 30 - - - - - - - - - 40 4-t/2" Hydril 521 / C-110 Liner with Halliburton Ball Actuated 6-1/8" Hole TD 6- 18,811' MD / Sleeves, &Swell Packers 6,338' TVD Disclosure Lists - NewDisclasure Pending (0) . + i Amending (0) All (10) , Welcome Rachel D, i' Opi Edit Please use the FracFocus XML Caelus Energy 50-703-20648-00-00 ODSN-Ola Hydraulic FracturingF 3/30/2016 submission process or create RNUAWELL ABOUT PROJECT Di5( U?<:iRL Chimieo D« u.Y disclosures online. RV STATE PARTFWFtS Caelus Energy 50-703-20689-00-00 ODSN-03i 4/6/2015 4/20/2015 I -F. �e 5/1/2015 Delete Disclosure Lists - NewDisclasure Pending (0) . + i Amending (0) All (10) , Dashboard Edit Delete Caelus Energy 50-703-20648-00-00 ODSN-Ola 3/26/2016 3/30/2016 6,329 1,353,243 4/28/2016 I Edit Caelus Energy 50-703-20689-00-00 ODSN-03i 4/6/2015 4/20/2015 0 866,034 5/1/2015 Delete E:E:�i Delete 1 Caelus Energy 50-703-20715-00-00 QDSN-061 3/2/2016 3J30/2016 6,526 719,593 4/26/2016 Edit Caelus Energy 50-703-20725-00-00 ODSN-07i 3/9/2016 3/21/2016 0 888,489 4/11/2016 Delettj Edit Delete Caelus Energy 50-703-20685-00-00 ODSN-191 3/7/2015 3/7/2015 6,200 251,011 4/9/2015 it l Delete Caelus Energy 50-703-20708-00-00 ODSN-22 2/21/2016 2/25/2016 6,197 728,506 3/11/2016 Edit Mete Caelus Energy 50-703-20642-00-00 ODSN-26i 4/13/2016 4/13/2016 6,108 215,612 4/28/2016 r Edit L- it Delete Caelus Energy 50-703-20655-00-00 ODSN-27i 2/17/2016 2/17/2016 0 163,939 2/29/2016 3 Caelus Energy 50-703-20605-02-00 ODSN-42b 3/23/2015 3/27/2015 0 650,541 4/13/2015 s=,... Edit rEei J Caelus Energy 50-703-20692-00-00 ODSN-43 3/14/2015 3/21/2015 0 864,833 4/9/2015 :, 1 Etltt Dente Dashboard STATE OF ALASKA Al A_ ru Amp nA(z rr)K1Q� ?\/ATlnnl r1,nnni ; inKI WELL COMPLETION OR RECOMPLETION REPORT AND LOG 1 a. Well Status: Oil Gas SPLUG Other Abandoned E] SuspendedE] 1 b. Well Class: 20AAC 25.105 20AAC 25.110 Development D_,/ Exploratory 1GINJ E] WINJ WAGE WDSPL No. of Completions: Service E ' Stratigraphic Test 2. Operator Name: 6. Date Comp., Susp., or 14. Permit to Drill Number/ Sundry: Caelus Natural Resources Alaska, LLC Aband.: 3/11/2016 216-008 3. Address: 7. Date Spudded: 15. API Number: 3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503 2/5/2016 50-703-20648-01-00 4a. Location of Well (Governmental Section): 8. Date TD Reached: 16. Well Name and Number: Surface: 3035' FSL, 1077' FEL, Sec. 11, T1 3N, R7E, UM 3/4/2016 ODSN-01A Top of Productive Interval: 9. Ref Elevations: KB: 56.2' 17. Field / Pool(s): 3801' FSL, 1919' FEL, Sec. 3, T13N, R7E, UM GL: 13.5' BF: Oooguruk Nuiqsut Oil Total Depth: 10. Plug Back Depth MD/TVD: 18. Property Designation: 4270' FSL, 1306' FEL, Sec. 33, T14N, R7E, UM 14b. N/A ADL 355036 / ADL 389959 Location of Well (State Base Plane Coordinates, NAD 27): 11. Total Depth MD/TVD: 19. Land Use Permit: Surface: x- 469921 y- 6031151 Zone - ASP4 18,811' MD / 6,338' TVD 417497 TPI: x- 463820 y- 6037223 Zone - ASP4 12. SSSV Depth MD/TVD: 20. Thickness of Permafrost MD/TVD: Total Depth: x- 459174 y- 6042995 Zone - ASP4 2,186' MD / 2,048' TVD 882' MD / 875' TVD `• `�"""'`"vu 1.1VI I VLAI V %-J 1 VJ { Y !kCtuQVI luu) MVV] 10. VVdICI ucPLl i, ii viisnore: z -i . Ke-ariiuLaterai i op vvinaow MD/ I VD: Submit electronic and printed information per 20 AAC 25.050 s� N/A (ft MSL) 4,077' MD / 3,228' TVD 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. Acronvms may be used. Attach a separate nage if necessa 1� 0�c r" Lkn - S -e GNV%4.�) /q 1 Gyro, MWD/LWD, DIR, DDSr, DDS, DDS -DGR, ABG/ABI, EWR, PWD, GABI, ALD, CTN, XBAT, ADR, 114D Rah'"CEIVEL) APR 4 5 x.016 23. CASING, LINER AND CEMENTING RECORD A'"(j CASING WT. PER FT. GRADE SETTING DEPTH MD SETTING DEPTH TVD HOLE SIZE CEMENTING RECORD AMOUNT PULLED TOP BOTTOM TOP BOTTOM 1611 109# X-65 Surface 158' Surface 158' 2411 Driven 11-3/4" 60# L-80 Surface 4,308' Surface 3,336' 14-1/211 499 sks PF 'L' 563 sks Class 'G' 9-5/811 40# L-80 3,923' 7,940' 3,155' 5,003' 10-5/8" x 11-3/4" 197 sks Class 'G' 7" 26# L-80 Surface 11,354' Surface 6,272' 8-1/2" x 9-1/2" 419 sks Class' 275 sks Class G G )01" 4-1/211 12.6# C-110 11,098' 18,440' 6,249' 67240' 6-1/811 Uncemented 24. Open to production or injection? Yes No E 1 If Yes, list each interval open (MD/TVD of Top and Bottom; Perforation Size and Number): See attached COMP -ETa0N 0- ATF r t kTRIPM 25. TUBING RECORD SIZE DEPTH SET (MD) PACKER SET (MD/TVD) 4-1/2" 12.6# C-110 11,152' 11,119' MD / 6,251' TVD See attached 26. ACID, FRACTURE, CEMENT SQUEEZE, ETC. Was hydraulic fracturing used during completion? Yes No Per 20 AAC 25.283 Oi (2) attach electronic and printed information DEPTH INTERVAL (MD) AMOUNT AND KIND OF MATERIAL USED 27• PRODUCTION TEST Date First Production: Method of Operation (Flowing, gas lift, etc.): Date of Test: Hours Tested: Production for Oil -Bbl: Gas -MCF: Water -Bbl: Choke Size: Gas -Oil Ratio: Test Period ==40. Flow Tubing Casinq Press: Calculated Oil -Bbl: Gas -MCF: Water -Bbl: Oil Gravity -API (corr): 24 -Hour Rate �► I� ,r- � t . , - . -^ - Y 14Liz"'; "i<' RBDMS LL, APR 0 5 201R �"t 28. CORE DATA Conventional Cc '-): Yes ❑ No ❑✓ Sidewall Cores: tees ❑ No E If Yes, list formations and intervals cored (MD/TVL., . rom/To), and summarize lithology and presence of c. ,as 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 ❑ No If yes, list intervals and formations tested, briefly summarizing test results. Permafrost - Top 843' 837' Permafrost - Base 1,725' 1,668' Attach separate pages to this form, if needed, and submit detailed test Top of Productive Interval 11,098' 6,249' information, including reports, per 20 AAC 25.071. Top West Sak 2,518' 2,308' Cretaceous tuffs 3,460' 2,911' Hue 2 Tuff 4,122' 3,248' Hue 2 Shale 4,181' 3,274' Hue Res C 4,643' 3,495' Hue Res B 5,693' 3,975' Hue Res A 6,276' 4,240' Brookian 2B Marker 6,377' 4,286' Torok Top 7,980' 5,021' Torok Base 8,530' 5,273' Torok Sh 1 Marker 8,901' 5,444' Top HRZ 9,770' 5,845' Base HRZ 10,055' 5,976' Kalubik Marker 10,228' 6,055' Kuparuk C 10,405' 6,122' LCU 10,453' 6,138' BCU 10,916' 6,233' Top Nuiqsut 11,258' 6,263' Nuiqsut Zone 1 11,325' 6,268' Nuiqsut Zone 2 17,330' 6,214' Nuiqsut Zone 3 17,650' 6,211' Nuiqsut Zone 4 18,115' 6,212' Nuiqsut Zone 5d 18,148' 6,215' Nuiqsut Zone 5a 18,453' 6,242' Nechelik SH 18,616' 6,278' Upper Nechelik 18,637' 6,284' Formation at total depth: Upper Nechelik 31. List of Attachments: Summary of daily operations, well schematic diagram, definitive survey(s), casing cement reports 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: Alex Vaughan, 343-2186 Email: alex.vaughan-caelusene[gy.com Printed Name: Alex Vaughan Title: Senior Drilling Engineer Signatur Phone: 343-2186 Date: 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 91. AttarhPd succlemental records should show the details of any multiple stage cementing and the location of the cementing tool. Form 10-407 Revised 11/2015 Submit ORIGINAL Only AOGCC Form 10-407 Well Completion Report Box 24 - Perforation Locations Well: ODSN-01A To MD To TVD 4-1/2" RapidStage Sleeve #11 11,618 6,288 4-1/2" RapidStage Sleeve #10 12,271 6,282 4-1/2" RapidStage Sleeve #9 12,841 6,272 4-1/2" RapidStage Sleeve #8 13,495 6,262 4-1/2" RapidStage Sleeve #7 14,144 6,247 4-1/2" RapidStage Sleeve #6 14,711 6,230 4-1/2" RapidStage Sleeve #5 15,321 6,224 4-1/2" RapidStage Sleeve #4 15,967 6,216 4-1/2" RapidStage Sleeve #3 16,786 6,218 4-1/2" RapidStage Sleeve #2 17,399 6,214 4-1/2" RapidStage Sleeve #1 18,255 6,223 Pre -perforated Pup 18,420 6,237 Pre -perforated Pup 18,424 6,238 Eccentric Shoe 18,436. 6,239 AOGCC Form 10-407 Well Completion Report Box 25 - Packer Locations Well: ODSN-01A MD TVD HES Swell Packer #13 11,404 6,276 HES Swell Packer #12 11,444 6,280 HES Swell Packer #11 11,891 6,286 HES Swell Packer #10 12,422 6,280 HES Swell Packer #9 13,199 6,266 HES Swell Packer #8 13,850 6,253 HES Swell Packer #7 14,378 6,240 HES Swell Packer #6 14,945 6,229 HES Swell Packer #5 15,631 6,219 HES Swell Packer #4 16,367 6,221 HES Swell Packer #3 17,102 6,216 HES Swell Packer #2 17,672 6,211 HES Swell Packer #1 18,366 6,231 Caelus Energy Alaska CASING & CEMENTING REPORT Lease 8 Well No. ODSN-01A Date 13 -Feb -16 County North Slope Burough State Alaska Supv. CASING RECORD - Intermediate #1 TO 7943.00 Shoe Depth: 7940.00 PBTD: Csg Wt. On Hook: _ Csg Wt. On Slips: _ Fluid Description: Liner hanger Info (Make/Model) Liner hanger test pressure: Centralizer Placement: Type Float Collar: Halliburton SSII No. Hrs to Run: 24 Type of Shoe: HES Comp. Eccent. Casing Crew: TESCO Liner top Packer?: X Yes No 3 - 9.625"X 10.375-10.75' Milam Solid Centralizers on Shoe Track CFMFNTINC; RFPORT Preflush (Spacer) Casing (Or Liner) Detail Setting Depths No. of Jts. Size Wt. Grade THD Make Length Bottom Top Float Shoe 9.625 L-80 Hydril 521 HES 2.75 7,940.00 7,937.25 (1-2) Casing 9.625 40 L-80 Hydril 521 Yield (Ft3/sack): 1.17 79.43 7,937.25 7,857.82 Float Collar 9.625 L-80 Hydril 521 HES 1.33 7,857.82 7,856.49 (3) Casing 9.625 40 L-80 Hydril 521 38.95 7,856.49 7,817.54 Landing Collar 9.625 L-80 Hydril 521 1.51 7,817.54 7,816.03 Bowspring Mandrel 9.625 L-80 Hydril 521 3.44 7,816.03 7,812.59 (4-100) Casing 9.625 40 L-80 Hydril 521 3,856.42 7,812.59 3,956.17 Seal Bore 9.625 L-80 Hydril 521 Baker 13.31 3,956.17 3,942.86 In -Line Liner Hanger 9.625 L-80 Hydril 521 Baker 19.43 3,942.86 3,923.43 Tail Slurry w Type: Yield (Ft3/sack): i Density (ppg) Volume (BBLs/sacks): Mixing /Pumping Rate (bpm): m Post Flush (Spacer) o Type: Density (ppg) Rate (bpm): Volume: U m Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: Rig pumps Plug Bumped? _Yes No Bump press Casing Rotated? Yes _No Reciprocated? _Yes _No % Returns during job Cement returns to surface? _No Spacer returns? _Yes _No Vol to Surf: Totals Date: Estimated TOC: Method Used To Determine TOC: t 4,016.57 Csg Wt. On Hook: _ Csg Wt. On Slips: _ Fluid Description: Liner hanger Info (Make/Model) Liner hanger test pressure: Centralizer Placement: Type Float Collar: Halliburton SSII No. Hrs to Run: 24 Type of Shoe: HES Comp. Eccent. Casing Crew: TESCO Liner top Packer?: X Yes No 3 - 9.625"X 10.375-10.75' Milam Solid Centralizers on Shoe Track CFMFNTINC; RFPORT Preflush (Spacer) Type: Tuned Spacer III Density (ppg) 11.0 Volume pumped (BBLs) 60 Lead Slurry Type: Yield (Ft3/sack): Density (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Tail Slurry Type: HalCem IPT Yield (Ft3/sack): 1.17 Density (ppg) 15.8 Volume (BBLs/sacks): 42.0/197 Mixing / Pumping Rate (bpm): 4.3 w Post Flush (Spacer) Type: SeaWater Density(ppg) 8.5 Rate (bpm): 5.5 Volume: 20 LL Displacement: Type: OBM Density (ppg) 10.2 Rate (bpm): 5.93 Volume (actual / calculated): 346.05 / 346.05 FCP (psi): 632.08 Pump used for disp: Rig pumps Plug Bumped? X Yes No Bump press 1500 Casing Rotated? X No Reciprocated? _Yes X No % Returns during job 100 ` _Yes Cement returns to surface? Yes X No Spacer retums? _Yes X No Vol to Surf: 0 Cement In Place At: 23:45 Date: 2/13/2016 Estimated TOC: 7,592 Method Used To Determine TOC: Incremental Lift Calculator Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type: Yield (Ft3/sack): Density (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Tail Slurry w Type: Yield (Ft3/sack): i Density (ppg) Volume (BBLs/sacks): Mixing /Pumping Rate (bpm): m Post Flush (Spacer) o Type: Density (ppg) Rate (bpm): Volume: U m Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: Rig pumps Plug Bumped? _Yes No Bump press Casing Rotated? Yes _No Reciprocated? _Yes _No % Returns during job Cement returns to surface? _No Spacer returns? _Yes _No Vol to Surf: -Yes Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Lease & Well No. Cae/us Energy Alaska CASING & CEMENTING REPORT ODSN-01A Date 24 -Feb -16 County North Slope Burough State Alaska Supv. CASING RECORD - Intermediate #2 TO - 11362.00 Shoe Depth: 11354.80 PBTD: Csg Wt. On Hook: Type Float Collar: Halliburton SSII No. Hrs to Run: 31.5 Casing (Or Liner) Detail Type of Shoe: HES Comp. Eccent. Casing Crew: TESCO Fluid Description: Setting Depths No. of Jts. Size Wt. Grade THD Make Length Bottom Top Float Shoe 7.000 1 26 L-80 Hydril563 HES 2.78 11,354.80 11,352.02 (1-2)Casing 7.000 26 L-80 Hydril563 Density (ppg) 80.39 11,352.02 11,271.63 Float Collar 7.000 26 L-80 Hydril 563 HES 2.54 11,271.63 11,269.09 (3-4)Casing 7.000 26 L-80 Hydril563 4.84 Volume (actual / calculated): 401.0 / 408.57 79.49 11,269.09 11,189.60 Baffle Adapter 7.000 26 L-80 Hydril 563 HES 2.11 11,189.60 11,187.49 (5-68)Casing 7.000 26 L-80 Hydril563 2,551.30 11,187.49 8,636.19 Stage Tool 7.000 26 L-80 Hydri1563 HES 3.42 8,636.19 8,632.77 Pup Joint 7.000 26 L-80 Hydril 563 HES 5.29 8,632.77 8,627.48 (69-283)Casing 7.000 26 L-80 Hydril563 8,585.90 8,627.48 41.58 Pup Joint 7.000 26 L-80 Hydri1563 3.55 41.58 38.03 Mandrel Hanger 7.000 26 L-80 Hydril 563 Vetco Gray 0.62 38.03 37.41 FCP (psi): 742.54 Pump used for disp: Rig pumps Plug Bumped? X Yes _ No Bump press 2,379 Casing Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 Cement returns to surface? _ Yes X No Spacer retums? _Yes X No Vol to Surf: - Cement In Place At: 0:23 Date: 2/25/2013 Estimated TOC: 7 940" Method Used To Determine TOC: BATSonic Log Totals 11,317.39 Csg Wt. On Hook: Type Float Collar: Halliburton SSII No. Hrs to Run: 31.5 Csg Wt. On Slips: Type of Shoe: HES Comp. Eccent. Casing Crew: TESCO Fluid Description: Type: Liner hanger Info (Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: Lead Slurry Centralizer Placement: 1 per Joint from - 11,352.00' to 7,437.2' (Joints #1 - #98) rCR=KlTlklr_ RGO(1RT Remarks: On second stage is at a minimum 7,940', this is the depth of the previous casing shoe. V �S Preflush (Spacer) Type: Tuned Spacer III Density (ppg) 11.5 Volume pumped (BBLs) 43 Lead Slurry Type: Yield (Ft3/sack): Density (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Tall Slurry Type: HalCem IPT Yield (F13/sack): 1.17 ow Density (ppg) 15.8 Volume (BBLs/sacks): 87.6/419 , -Mixing/ Pumping Rate (bpm): 4.1 Post Flush (Spacer) W' of Type: Seawater Density (ppg) 8.5 Rate (bpm): 3.9 4.67 Volume: 20 Z Displacement: Type: LSND Density (ppg) 10.2 Rate (bpm): 4.84 Volume (actual / calculated): 401.0 / 408.57 FCP (psi): 922 Pump used for disp: Rig pumps Plug Bumped? X Yes No Bump press 2,007 Casing Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 Cement returns to surface? Yes X No Spacer retums? X No Vol to Surf: - Cement In Place At: _ 16:20 Date: 2/24/2016 _Yes Estimated TOC: 9,970' Method Used To Determine TOC: BATSonic Log Preflush (Spacer) Type: Tuned Spacer III Density (ppg) 11 Volume pumped (BBLs) 50 Lead Slurry Type: Yield (Ft3/sack): Density (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Tail Slurry Type: HalCem IPT Yield (Ft3/sack): 1.17 w a Density (ppg) 15.8 Volume (BBLs/sacks): 571275 Mixing / Pumping Rate (bpm): 4.06 N Post Flush (Spacer) o Type: Seawater Density (ppg) 8.5 Rate (bpm): 4.61 Volume: 20 wDisplacement: w Type: LSND Density (ppg) 10.2 Rate (bpm): 4.81 Volume (actual / calculated): 310.0 / 310.8 FCP (psi): 742.54 Pump used for disp: Rig pumps Plug Bumped? X Yes _ No Bump press 2,379 Casing Rotated? _Yes X No Reciprocated? _Yes X No % Returns during job 100 Cement returns to surface? _ Yes X No Spacer retums? _Yes X No Vol to Surf: - Cement In Place At: 0:23 Date: 2/25/2013 Estimated TOC: 7 940" Method Used To Determine TOC: BATSonic Log Remarks: On second stage is at a minimum 7,940', this is the depth of the previous casing shoe. V �S ODSN-01A Nuiqsut Production Well Completion I I Landed Upper Packer Fluid mix• Inhibited Kill weight Brine with 2000' TVD diesel cap I I Completion I I with 40,000 lbs I Slack -Off I I I I I ( 11-3/4" 60# L-80 BTC Surface I ••••••• I 3 i Casing @ 4,308' MD / 16" I 3,334' TVD Conductor I cemented to surface GLM# 3 SOV Installed 7,000 psi Max rated GLM# 2 DGLV Installed 7,000 psi Max rated GLM# 1 DGLV Installed 7,000 psi Max rated ES -II Cementer @ 8,632 ft. MD Whipstock Window: 4,077' - 4,099' MD 9 5/8" Permanent Bridge Plug @ 4,194 MD TOC Estimated @ 500 ft above 9-5/8" Shoe 9-5/8" 40# L-80 Hydril 521 Intermediate 1 Casing @ 7,940' MD / 5,003' TVD 7" Stage 2 TOC Estimated ;'. @ 7,459 ft. MD 17 Roy 7" Stage 1 TOC RHC Plug 19 Installed 21 22 di. 25 7" 26# Hydril 563 Intermediate 2 Casing @ 11,354' MD / 27 N 6,272' TVD Estimated '[ @ 9,850 ft. MD � t� 3�T sv 3-12-2016 FINAL No. Upper Completion MD(ft) TVD (ft) 1 Tubing Hanger 34 34 2 4-Y"12.6#/ftC-110 Hydril 521 Tubing 11,119 6,251 3 4-'/=" Halliburton'XXO' SVLN w/3.813" "X" profile with singlel/4" x 0.049" s/s control line. Cannon Cross -coupling damps on everyjoint w/ 15ft Pup BxPTop & Bottom Z 186 Z 048 4 4-Y"12.6#/ftC-110 Hydril521Tubing 5 4-Y" x 1" GLM #3, KBG-4-5 Hydril 521 w/ 15ft Pup BxP Top & Bottom 2,833 2,531 6 4-Y"12.69/ftC-110 Hydril 521Tubing(2Joints) 7 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 2,952 2.608 8 4-Y/"12.6#/ftC-110 Hydril521Tubing 11,404 6,276 9 4-YV x 1" GLM #2, KBG-4-5 Hydril 521 w/ 15ft Pup BxP Top & Bottom 5,689 3,974 10 4-Y'12.6#/ftC-110Hydri1521Tubing(2Joints) 11 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 5,808 4,028 12 4-'/="12.6#/ftC- 110 Hydri 1521 Tu b ng 13 4-Y" x 1" G LM # 1, KBG-4-5 Hydril 521 w/ 15ft Pup BxP Top & Bottom 10,013 5,958 14 4-Y'12.6#/ftC-110 Hydri1521Tubing(2Joints) 11,618 6,288 15 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 10,132 6,013 16 4-W' 12.6#/ft C-110 Hydri 1521 Tubi ng 17 4-1/2"Halliburton'ROC'GaugeCarrierw/Encapsulated e -line to Surface w/ 15ft Pup BxP Top & Bottom 10,204 6,045 18 4-Y"12.6#/ftC-110 Hydri 1521 Tubi ng (2 jt) 11891 6,286 19 HES XN 3.813" (3.725' NoGo) - w/ 15ft Pup BxP Top & Bottom 10,320 6,092 20 4-Y" 12.64/ft C-110 Hydril 521 Tubing r2l4-1/2'x4" Crossover P-110 Locator with a 5.66' long 4-1/2" handling pup on top, 4" Spacer Pup w/ Bullet Seal Assembly+Solid Mule Shoe 11,118 6,251 No. Lower Completion MD(ft) TVD (ft) 22 20 ft 5.25" Tie Back extension 11,098 6,249 Baker 5"X7' ZXP Liner Top Packer with Aex Lock Hanger /20ft 4.25" Seal Bore Receptide Below 11,119 6,251 23 Hanger 24 4- YV' 12.6#/ft Hyd n1521 C-110 Liner 25 Resman Internally Vented Carrier # 4 ROS -1525-1 / RWS-1531-1 w/ 15ft Pup BxP Top & Bottom 11,205 6,259 26 4-Y"12.6#/ft Hydril 521C-110 Liner Halliburton Swell Packer# 13 (4-Y" Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 27 Volant Centralizer Pin End and 6ft Pup 4-1/2" 126#/ft P-110 Hydril 521 Box x Pin w/Slide On Volant 11,404 6,276 Centralizer on Top of Swell Packer Halliburton Swell Packer# 12 (4-Y" Hydril 521) OD 5.85 - 9 meter long oil activated with Slide on 28 Volant Centralizer Pin End and 6ft Pup 4-1/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 11,444 6,280 Centralizer on Top of Swell Packer 29 4-%" 12.6#/ft Hydril 521 C-110 Liner HLB 4-1/2" RapidStage Ball Actuated Sleeve (3.o09ball /2.95 Seat) w/ 15ft 4-1/2" P-110 Pup 4-1/2' 11,618 6,288 30 126#/ft P-110 Hydril 521 Box x Pin 31 4-Y" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 11(4-Y" Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 32 Volant Centralizer Pin End and 6ft Pup 4-1/2"126#/ftP-110 Hydril 521 Box x Pin w/Slide On Volant 11891 6,286 Centralizer on Top of Swell Packer 33 4-Y" 12.6#/ft Hydril 521 C-110 Liner HLB4-1/2' RapidStage Ball Actuated Sleeve (2.925ball /2.867Seat)w/ 15ft4-1/2"P-110 Pup 4-1/2" 12,271 6,2ffi 34 126#/ftP-110 Hydril 521BoxxPin 35 4-Y" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 10(4-Y," Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 36 Volant Centralizer Pin End and 6ft Pup 4-1/2" 126#/ft P-110 Hydril 521 Box x Pin w/Slide On Volant 12,422 6,280 Centralizer on Top of Swell Packer 37 4-%"126#/ft Hydril 521 C-110 Liner HLB4-1/2" RapidStage Ball Actuated Sleeve (2.842ball/Z786Seat) w/15ft4-1/2"P-110Pup4-1/2" 38 12,&41 6,272 126#/ftP-110 Hydril 521 Boxx Pin 39 4-W'12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 9 (4-Y" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 40 Volant Centralizer Pin End and 6ft Pup 4-1/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 13,199 6,266 Centralizer on Top of Swell Packer 41 4-Y=" 12.6#/ft Hydril 521 C-110 Liner �0 - O 4-t/2" Hydril 521 / C-110 Liner with Halliburton Ball Actuate Sleeves, & Swell Packers 74 75 WOODS1 33 6-1/8" Hole TD Actuated @ 18,811' MD / 6,338' TVD ODSN-01A Nuiqsut Nroduction Well Completion '. Landed Upper Packer Fluid mix: Inhibited Kill weight Brine with 2000' TVD diesel cao Completion with 40,000 lbs 1 I Slack -Off 16" Conductor GLM# 3 SOV Installed 7,000 psi Max rated GLM# 2 DGLV Installed 7,000 psi Max rated GLM# 1 DGLV Installed 7,000 psi Max rated i ES -II Cementer @ 8,632 ft. MD RHC Plug( Installed 11-3/4" 60# L-80 BTC Surface Casing @ 4,308' MD / 3,334' TVD 1 cemented to surface J I 1 I Whipstock Window: 4,077' - 4,099' MD 9-5/8" Permanent Bridge Plug @ 4,194 MD Itoo I TOC Estimated @ 500 ft above 9-5/8" Shoe 9-5/8" 40# L-80 Hydril 521 Intermediate 1 I Casing @ 7,940' MD / 5,003' TVD GL x 1 7" Stage 2 TOC Estimated I 'I @ 7,459 ft. MD I ' I aoc 7" Stage 1 TOC Estimated @ 9,850 ft. MD 7" 26# Hydril 563 Intermediate 2 Casing @ 11,354' MD / 6,272' TVD 3-12-2016 FINAL No. Lower Completion MD(ft) TVD (ft) HI -134-1/2" RapidStage BallActuated Sleeve(z.761 ball/2.7065eat)w/15ft 41/2"P-110 Pup 41/2" 13,495 6,262 az 12.6#/ft P-110 Hydril521 Box x Pin 43 4-W'12.6#/ft Hydril 521 C-110 Liner 44 Resman Internally Vented Carrier # 3 ROS -1524-1 / RWS-1530-1 w/ 15ft Pup BxP Top & Bottom 13,689 6,258 45 4-A" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 8 (4-Y." Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 46 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/Slide On Volant 13,850 6,253 Centralizer on Top of Swell Packer 47 4-%"12.6#/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.681 ball / 2.628 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 48 14,144 6,247 12.6#/ft P-110 Hydril 521 Box x Pin 49 4-Y," 12.6#/ft Hydril S21 C-110 Liner Halliburton Swell Packer # 7 (4-YV' Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 50 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 14,378 6,240 Central izer on Top of Swell Packer 51 4-V' 12.6#/ft Hydril 521 C-110 Liner HI RapidStage Ball Actuated Sleeve (2.603 ball /2.552 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 52 -134-1/2" 14,711 6,230 12.6#/ft P-110 Hydril 521 Box x Pin 53 4-%"12.6#/ft Hyd ri1521 C-110 Li n e r Halliburton Swell Packer # 6 (4-Y2" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 54 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 14,945 6,22.9 Centralizer an lop of Swell Packer 55 4-%"12.6#/ft Hyd ri1521 C-110 Li ner HLB 41/2" RapidStage Ball Actuated Sleeve (2.527 ball/2.477 Seat) w/15ft 41/2"P-110 Pup 41/2" 56 15,321 6,224 12.6#/ft P-110 Hydril 521 Box x Pin 57 4-%"126#/ft Hyd ri1521 C-110 Li ner 58 Re sman Internally Vented Carrier # 2 ROS -1523-1 / RWS-1529-1 w/ 15ft Pup BxP Top & Bottom 15,512 6,221 59 4-K" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 5 (4-W' Hydril 521) OD S.85'- 9 meter long oil activated with Slide on 60 Volant Centralizer Pin End and 6ft Pup 41/2"12.6#/ftP-110 Hydril 521 Box x Pin w/Slide On Volant 15,631 6,219 Centralizer on Top of Swell Packer 61 4-Y."126#/ftH dri1521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.452 ball / 2.404Seat) w/ 15ft 41/2" P-110 Pup 41/2" 15,967 6,216 62 12.6#/ft P-110 Hydril 521 Box x Pin 63 4-W'12.6#/ft Hyd ri1521 C-110 Li ner Halliburton Swell Packer #4 (4-YV' Hydril 521) OD 5.85- 9 meter long oil activated with Slide on 64 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P -SIA Hydril 521 Box x Pin w/ Slide On Volant 16,367 6,221 Centralizer on Top of Swell Packer 65 4-Y," 12.6#/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.379 ball/ 2.332 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 66 16,786 6,218 12.6#/ft P-110 Hydril 521 Box x Pin 67 4Y" 12.64/ft Hyd riI S21 C-110 Liner Halliburton Swell Packer# 3 (4-W' Hydril 521) OD 5M'- 9 meter long oil activated with Slide on 68 Volant Centralizer Pin End and 6ft Pup 41/2"12.6#/ftP-110 Hydril 521 Box x Pin w/ Slide On Volant 17,102 6,216 Centralizer on Top of Swell Packer 694-'/:" 12.6#/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.307 ball / 2.261 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 70 17,399 6,214 12.6#/ft P-110 Hydril 521 Box x Pin 71 4-%" 12.6#/ft Hydril 521 C-110 Liner 72 Resman Internally Vented Carrier# 1 ROS -1522-1 / RWS-1528-1 w/ 15ft Pup BxP Top & Bottom 17,553 6,212 73 4-Y" 126#/ft Hydril 521 C-110 Liner Halliburton Swell Packer#2 (4-Y2" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 74 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 17,672 6,211 Centralizer on Top of Swell Packer 75 4-%"12.6#/ft Hydril S21 C-110 Liner HL841/2" RapidStage Ball Actuated Sleeve (2.236 ball/ 2.192 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 76 18,255 6,223 12.6#/ft P-110 Hydril 521 Box x Pin 77 4-'/:"12.6#/ft Hyd ri1521 C-110 Li ner Hall i burton Swe II Packer # 1(4-YV' Hydril 521) OD S.85'- 9 meter long oil activated with Slide on 78 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 18,366 6,231 Centralizer 0n Top of Swell Packer 79 2.6#/ft Hydri1521 C-110 Liner 80 Pre -perforated Pup w/ 4%" 12.6#/ft Hydril 521w/ 15ft 41/2" P-110 Pup BxP Top & Bottom 18,420 6,237 81 Pre -perforated Pup w/ 4%" 12.6#/ft Hydril 521 w/ 15ft 41/2" P-110 Pup BxP Top & Bottom 18,424 6,238 82 4-%" 126#/ft Hydril 521 C-110 Liner 83 4-1/," Hydril 521 Eccentric Shoe with Double Float Sub 18,436 6,2.39 ^ rsoaommwssemoiy ia,wru o,c.v 38 42 46 O-1 u 60 O - - - 68 70 74 - 78 36 0Q 27 30 34� 6-1/8" Hole TD 4-%" Hydril 521 / C-110 Liner with Halliburton Ball Actuated @ 18,811 - MD / Sleeves, & Swell Packers 6,338' TVD CE CAELUS Energy Alaska Operations Summary Report - State Well Name: ODSN-01A Well Name: ODSN-01A Contractor: NABORS DRILLING Rig Number: 19 AC Job Category: ORIG DRILLING Start Date: 1/29/2016 End Date: 3/11/2016 Start Depth FooYmeters Dens Last StartDate End Date (ftKB) (ft) Mud (lb/gal) Summary 1/29/2016 1/30/2016 0.0 8.50 *** Rig accepted on ODSN-01A at 00:01 on 29 January 2016. *** R/U rig on ODSN-01 A. N/D & UD production tree. Install test dart. N/U Vetco Gray drilling adapter, N/U Vetco Gray drilling spool & riser. N/U BOP stack, choke & kill lines. Begin Test BOPE per AOGCC PTD: * Test annular preventer w/ 4" test joint to 250 psi low / 2500 psi high. Discovered leak in the NT -2 Connection between the BOPE and Riser. N/D BOP Stack. C/O Vetco Gray API Seal Ring. N/U BOP Stack & Riser. Continue testing BOPE per AOGCC PTD: * Test upper and lower VBR w/ 5" test joint to 250 / 4500. * Test upper and lower IBOP valves to 250 psi low /4500 psi high. * Test all floor valves to 250 psi low / 4500 psi high. * Begin Testing 15 choke manifold valves to 250 psi low / 4500 psi high. * All tests charted and all tests held for 5 min. * All tests performed with 8.5 ppg seawater. *** AOGCC inspector Jim Regg waived witness of BOPE test at 10:54 hrs 01 /29/16. *** 1/30/2016 1/31/2016 0.0 4,318.00 8.50 PE as -per AOGCC & PTD: Test annular w/ to 250 psi low / 2500 psi high. Test upper and lower VBR to 250 / 4,500.1(,�ti Test upper and lower IBOP valves to 250 psi low / 4,500 psi high. / Test all floor valves to 250 psi low / 4500 psi high. /f j Test 15 choke manifold valves to 250 psi low 14500 psi high. W All tests charted and all tests held for 5 min. * All tests performed with 8.5 ppg seawater. Initial system psi: 3000, 1950 after closure; 200 psi= 28 sec, full pressure 122 sec. *** AOGCC inspector Jim Regg waived witness of BOPE test at 10:54 hrs 01/29/16. *** L/D 4" Test joint w/ Blank plug. Remove Vetco Gray BPV w/ Tee Bar. Monitor well for 30 min. - Static. Circulate Sea Water Surface to Surface x 2 @ 2,564' sending diesel freeze protect to Ops Flowback Tank. R/U GBR. Pull & L/D 4-1/2" tubing hanger. POOH w/ 4-1/2" Freeze protect / Kill string f/ 2,564't/ surf. UD tubing to pipe shed for disposal. RID GBR. Install 6.375" Upper Wear Bushing per Vetco Gray. WU 5 1/2" Baker Multi String Cutter w/ circulating sub U 9.8'. TIH w/ 5 1/2" Baker Multi String Cutter f/ 9.8't/ 4,318'. Locate 7" casing collar @ 4,294'. Cut casing at 4,318' and as per Baker Fishing Rep. Begin displacing wellbore fluid w/ 2 x 50 bbl Barascrub pills & Sea Water taking all returns out the OA into the flowback tanks. *** Gave 48 hr notice of BOP test request to the AOGCC @ 09:21 am 01/30/16 for BOP test on 01/31/16. *** CE /AE- ,, Alaska Operations Summary Report - State Well Name: ODSN-01A Page 2/7 ReportPrinted: 3/29/2016 Start Date End Date Start Depth (ftKB) FootlMeters (ft) Dens Last Mud (Iblgal) Summary 2/1/2016 2/2/2016 4,318.0 0.00 8.50 P/U & M/U 8 1/2" Bit, Scraper and Magnet BHA #2 f/ 40't/ 234'. TIH w/ Bit, Scraper Magnet BHA on 4" DP f/ 234' t/ 4,179'. Rotate casing scraper per Baker Rep f/ 4,179' U 4.211'. TIH & Tag 7" Stump @ 4,318' on depth. Circulate 1.5 x B/U @ 4,318'. UD 4" DP f/ 4,318't/ 234. UD 8 1/2" Bit, Scraper and Magnet BHA #2 f/ 234' t/ surface. Remove Wear Bushing. Install test plug. C/O upper & lower pipe rams t/ 5 1/2". Change out from 4" to 5 1/2" IBOP & saver sub. P/U Test tools. P/U & M/U 5 1/2" Dart, TIW & Pump in Sub. Begin Test BOPE w/ 5 1/2" Test jt as per AOGCC & PTD: * Test annular w/ to 250 psi low / 2500 psi high. * Test upper and lower rams to 250 psi low / 4,500 psi high. * Test upper and lower IBOP valves to 250 psi low / 4,500 psi high. * Test all floor valves to 250 psi low / 4500 psi high. * Test 12 of 15 choke manifold valves to 250 psi low / 4500 psi high. * Test Manual & Super Chokes to 1500 psi high. * Test all gas & pit alarms. * All tests charted and all tests held for 5 min. * All tests performed with 8.5 ppg seawater. * Initial system psi: 3100, 2000 after closure; 200 psi= 18 sec, full pressure 102 sec. Note: BOP Test continued after 24:00 hrs. report time. *** AOGCC inspector Guy Cook witnessed BOPE test. *** 2/2/2016 2/3/2016 4.1940 000 8.50 Complete test BOPE w/ 5 1/2" Test jt as per AOGCC & PTD: * Test annular w/ to 250 psi low / 2500 psi high. * Test upper and lower rams to 250 psi low / 4,500 psi high. * Test upper and lower IBOP valves to 250 psi low / 4,500 psi high. *Test all floor valves to 250 psi low / 4500 psi high. * Test 15 choke manifold valves to 250 psi low / 4500 psi high. * Test Manual & Super Chokes to 1500 psi high. * Test all gas & pit alarms. * All tests charted and all tests held for 5 min. * All tests performed with 8.5 ppg seawater. * Initial system psi: 3100, 2000 after closure; 200 psi= 18 sec, full pressure 102 sec. *** AOGCC inspector Guy Cook witnessed BOPE test. *`* UD Test Tools & Test Plug. Install Wear Bushing. P/U & M/U Baker 9 5/8" Hydro Set Permanent Bridge Plug. TIH w/ 9 5/8" Bridge Plug while P/U 5 1/2" DP f/ 12't/ 4,194'. Set 9 5/8" Bridge Plug per Baker Rep. Pressure Test 11-3/4" casing and 9-5/8" Liner top to bridge plug @ 4194'/ 30 minutes.— Good Test. Test Sperry Geo Span per Halliburton MWD. Slip & Cut Drill Line. TON w/ Baker Setting Tool f/ 4,194't/ 11'. UD Baker 9 5/8" Bridge Plug Setting tool. Remove Wear Bushing. N/D BOPE. ND Spacer Spool, Remove Vetco Gray Multi -Bowl. Install Drilling Spool. N/U BOP Stack, Riser, & Trip Nipple. Test Drilling Adapter t/ 2,700 PSI / 10 Min w/ Vetco Gray.Test Grey Lock & NT- 2 Connection, Choke & Kill Line Connections t/250 PSI low 14500 PSI high for 5 minutes per test and chart same. Remove Test Plug. C/O 4"elevators t/ 5 1/2" elevators. P/U & M/U Baker 10 5/8" Bit, Scraper & Magnet BHA U 150'. 2/3/2016 2/4/2016 4,118.0 0.00 8.50 RIH 10 5/8" bit, scraper and magnet BHA while P/U 5 1/2" drill pipe t/ 4,120' & tag 9-5/8" liner. Circulate 2x bottoms up. Rack back 7 stands of drill pipe, then pick up the remaining 18 joints of drill pipe t/ 4,020'. Circulate 1.25x drill pipe volume to flush the pipe. POOH f/ 4,020'& L/D BHA #4. M/U BHA #5, Baker whipstock, anchor & milling assembly w/ MWD directional tools to 758'. TIH w/ BHA #5 f/ 758't/ 2,154'. 2/4/2016 2/5/2016 4,1180 0.00 10.20 RIH w/ BHA #5 V 3,553' where the assembly took 10K weight. Attempt to work past while maintaining a 10K weight limitation. Unable to work past 3.553'. POOH f/ 3,553't/ 758'. UD BHA #5. M/U BHA #6- cleanout assembly w/ two watermelon mills to 527'. TIH w/ BHA #6 f/ 527't/ 3,553'. Ream f/ 3,553' U 4,118' to clear obstruction in 11-3/4" casing. Displace wellbore f/ 8.5 ppg seawater V 10.2 ppg Bara-ECD MOBM. Circulate 2x bottoms up to ensure casing is clean. POOH f/ 4,118' V 151'. Page 2/7 ReportPrinted: 3/29/2016 CE AEL4.J F .orgy Alaslta Operations Summary Report - State Well Name: ODSN-01A Page 3/7 ReportPrinted: 3/29/2016 M Start Depth Foo7Meters Dens Last Start Date End Date (ftKB) (ft) Mud (Ib/gal) Summary 2/5/2016 2/6/2016 4,118.0 18.00 10.20 L/D BHA #6 f/ 151'. M/U BHA #7 mills, MWD, whipstock & anchor U 758'. TIH w/ BHA #7 f/ 758' U 4,194'. Orient the whipstock face to 55° left of highside. Set whipstock anchor & shear mills from the whipstock. Mill a window in the 11-3/4" casing f/ 4,077't/ 4,095'. ODSN-01A de -completion was working on sundry #316-021 w/ a 7 day BOP test interval. *'* ODSN-01A was sidetracked on 5 February 2016 and began drilling on Permit To Drill #216- 008 & will now follow a 14 day BOP test interval. *" 2/6/2016 2/7/2016 4,095.0 34.00 10.20 Continue milling the window in the 11-3/4" casino f/ 4,095't/ 4,099'. Drill formation w/ the 10-1/2" mills f/ 4,099' U 4,129'. Polish while reaming mills across the window. Circulate the hole clean. Perform FIT to 12.5 ppg EMW - 388 PSI w/ 10.2 ppg MW @ 4,119' MD / 3,238' TVD. POOH & L/D BHA #7. M/U BHA #8 - 1.5' motor kick-off assembly to 616'. TIH w/ BHA #8 f/ 616't/ 4,063'. 2/7/2016 2/8/2016 4,129.0 400.00 10.20 TIH across the whipstock f/ 4,063' U 4,103'. Slide throLgh 10-1/2" under gauge hole f/ 4,103' U 4,129'. Drill 10-5/8" intermediate #1 hole f/ 4,129'V 4,529'. POOH f/ 4,529't/ 4,063'. Circulate the hole clean w/ 3.5x bottoms up. POOH f/ 4,063' U 514'. L/D BHA #8 f/ 514' to surface. M/U BHA #9 - rotary steerable assembly w/ under -reamer to 650'. TIH w/ BHA #9 f/ 650' U 2,513'. 2/8/2016 2/9/2016 4,529.0 356.00 10.20 TIH w/ BHA #9 f/ 2,513't/ 4,004'. Slip & cut drilling line. TIH w/ BHA #9 f/ 4,004't/ 4,142' and set 45K down on assembly. Attempts to work past 4,142' unsuccessful. P/U to 4,070' and circulate 3.5x bottoms up. TIH f/ 4,070't/ 4,042' and took weight again. Work bit & stabilizers past Tuff ledge f/ 4,142' U 4,150' with 15 RPM rotation. TIH f/ 4,127' U 4,529'. Establish circulation to 700 GPM. P/U to 4,498' and activate the 11-3/4" Riptide reamer then enlarge 10-5/8" hole f/ 4,498' U 4,529'. Drill 10-5/8" x 11-3/4" Intermediate #1 hole f/ 4,529' U 4,612'. CCU hopper plugged with cuttings. Stop drilling and clear hopper. Drill 10-5/8" x 11-3/4" Intermediate #1 hole f/ 4,612't/ 4,885'. 2/9/2016 2/10/2016 4,885.0 1,262.00 10.20 Drill 10-5/8" x 11-3/4" Intermediate #1 hole f/ 4,885' U 6,147'. *** Perform weekly function test of BOP equipment as per PTD requirements. *** 2/10/2016 2/11/2016 6,147.0 1,366.00 10.20 Drill 10-5/8" x 11-3/4" Intermediate #1 f/ 6,147't/ 7,513'. 2/11/2016 2/12/2016 7,513.0 430.00 10.20 Drill 10-5/8" x 11-3/4" Intermediate #1 f/ 7,513'V 7,943', TD of the section. De -activate the Riptide reamer. Perform Sperry quadrant ream of 10-5/8" hole f/ 7,943' U 7,817'. Circulate the hole clean w/ 8.5x total bottoms up. Lubricate out of the hole f/ 7,817' U 4,004'. Circulate 3.5x bottoms up inside the 11-3/4" casing. Back ream f/ 4,004't/ 2,979'. 2/12/2016 2/13/2016 7,943.0 0.00 10.20 Back ream in the 11-3/4" casing f/ 2,979' U 650'. UD BHA #9 f/ 650'. P/U additional 18 joints of HWDP for liner run. Flush HWDP & rack back in the derrick. Change lower ram,��Q,�Z- Test 9-5/8" rams against 9-5/8" testjoint. Test to 250 PSI low / 4,500 PSI high - good tests. Tests held for 5 min. each & charted. Tests performed w/ 8.5 ppg seawater. R/U to run 9-5/8" liner. Run 9-5/8" #40 L-80 Hydril 521 liner to 482'. 2/13/2016 2/14/2016 7,943.0 0.00 10.30 Run 9-5/8" #40 L-80 Hvdril 521 liner f/ 482' t/ 3_%83'. M/U Baker 9-5/8" x 11-3/4" liner hanger packer f/ 3,983't/ 4,024'. R/D casing equipment. RIH w/ 9-5/8" liner on 5-1/2" drill pipe f/ 4,024' U 7,940'. Establish circulation to 6 BPM. Perform Intermediate #1 9-5/8" liner cement job. Pump 60 bbls of 11 ppg Tuned Spacer III @ 3.6 BPM, 280 PSI. Mix & pump 42 bbls of 15.8 ppg Premium G cement @ 4.55 BPM, 235 PSI. 197 sacks @ 1.172 ftA3/sack yield. G NL Pump 20 bbls of 8.5 ppg seawater @ 5.9 BPM, 144 PSI. 5 Displace cement w/ rig pumps @ 6 BPM, 1,125 PSI. Observe good lift as cement exited the shoe @ 6 BPM, 1323 PSI to 1,495 PSI. Bumped plug @ 4,105 strokes. CIP @ 23:45. 100% returns throughout the entire cement job. Pressure up to 1,500 PSI & hold for 5 min. to pressure test the liner - good test. Set Baker 9-5/8" x 11-3/4" hanger. Provided AOGCC notification of upcoming BOP test at 10:41 on 13 February 2016. *** l td Page 3/7 ReportPrinted: 3/29/2016 M CE CAELUS Energy Alaska Operations Summary Report - State Well Name: ODSN-01A Page 4/7 Report Printed: 3/29/2016 A Start Date End Date Start Depth (ftKB) Foot/Meters (ft) Dens Last Mud (lb/gal) Summary 2/14/2016 2/15/2016 7,943.0 0.00 10.30 Set Baker 9-5/8" x 11-3/4" packer. Test 9-5/8" x 11-3/4" packer to d test. Release from liner & circulate 1x bottoms up. POOH & L/D Baker liner running tool. N/D BOP stack, riser & drilling spool. N/U Vetco Gray multi -bowl wellhead, riser & BOP stack. Change lower rams from 9-5/8" to 5-1/2". Test lower 5-1/2" pipe rams & BOP breaks. Test lower 5-1/2" pipe rams on 5-1/2" testjoint to 250 PSI low / 4,500 PSI high. Test BOP stack, riser & Vetco Gray multi -bowl connections to 250 PSI low / 4,500 PSI high. Test choke & kill line connections to 250 PSI low / 4,500 PSI high. All test performed w/ 8.5 ppg sea water. Tests held for 5 min. each & charted. R/D test equipment. Pressure test 9-5/8" liner x 11-3/4" surface casing to 3,500 PSI for 30 min. - good test. M/U BHA #10 -mill tooth bit & motor cleanout assembly to 32'. 2/15/2016 2/16/2016 7,9430 2500 10.20 M/U BHA #10 f/ 32' t/ 568'. Single in the hole w/ 5-1/2" drill pipe f/ 568' t/ 3,550'. TIH f/ 3,550' t/ 7,649'. Ream & wash down f/ 7,649' t/ 7,819'. Drill 9-5/8" casing shoe track f/ 7,819' t/ 7,940'. Clean out 10-5/8" rat hole f/ 7,940't/ 7,943'. Displace wellbore f/ 10.2 BaraECD MOBM t/ 10.2 ppg LSND. Drill 25' of new 8-1/2" hole f/ 7,943't/ 7,968'. Perform FIT to 13.3 ppq EMW. FIT performed with 10.2 ppg to 819 PSI at 7,940' MD / 5,003'�TVD casing shoe depth. POOH w/ BHA #10 f/ 7,968't/ 1,687'. i 2/16/2016 2/17/2016 7,968.0 0.00 10.20 POOH w/ BHA #10 f/ 1,687' t/ 568'. UD BHA #10 f/ 568'. Test BOP equipment as per PTD requirements. Test annularw/ 5-1/2" testjoint to 250 PSI / 2,500 PSI. Test upper and lower 5-1/2" rams to 250 PSI / 4,500 PSI. Test blind rams to 250 PSI / 4,500 PSI. Test upper and lower [BOP valves to 250 PSI / 4,500 PSI. Test hydraulic & manual choke & kill valves to 250 PSI / 4,500 PSI. Test all floor valves to 250 PSI / 4,500 PSI. Test 15 choke manifold valves to 250 PSI / 4,500 PSI. All tests charted and all tests held for 5 min. All tests performed with 8.5 ppg seawater. Initial system PSI: 3,000, 2,000 after closure; 200 PSI= 27 sec, full pressure 111 sec. *** AOGCC inspector Bob Noble waived witness of BOPE test at 12:17 hrs 02/13/2016. *** *** AOGCC inspector Brian Bixby waived witness of BOPE test update at 08:36 hrs 02/15/16. *** M/U BHA #11 to 708'. TIH w/ BHA #11 f/ 708't/ 3,969'. 2/17/2016 2/18/2016 7.9680 1,124.00 10.20 TIH w/ BHA #11 f/ 3,969't/ 7,878'. Slip & cut drilling line. TIH V 7,878' t/ 7,968'. Drill 8-1/2" Intermediate #2 hole V 7.968't/ 8,102'. Activate the 9-1/2" Riptide reamer. Drill 8-1/2" x 9-1/2" Intermediate #2 hole f/ 8,102't/ 9,092'. 2/18/2016 2/19/2016 9,092.0 528.00 10.20 Circulate 2x bottoms up. Spot 115 bb[s LCM pill for LCM treatment. POOH f/ 9,092' t/ 7,696'. Perform LCM squeeze treatment across the Torok sand to 13.0 ppg EMW at the top of the Torok. Ream f/ 7,696't/ 9,092'. Circulate 2x bottoms up. Install Managed Pressure Drilling RCD & apply 12.5 ppg EMW via back pressure. Drill 8-1/2" x 9-1/2" Intermediate #2 hole f/ 9,092't/ 9,620'. 2/19/2016 2/20/2016 9,6200 940.00 10.15 Drill 8-1/2" x 9-1/2" Intermediate #2 hole f/ 9,620't/ 10,560'. 2/20/2016 2/21/2016 10,560.0 802.00 10.25 Drill 8-1/2" x 9-1/2" Intermediate #2 hole f/ 10,560' t/ 11,362'- TD of IntPrnnPd'ntP tee interval. De -activate Riptide reamer & perform Sperry quadrant ream procedure. 2/21/2016 2/22/2016 11,3620 000 12.30 Finish quadrant reaming and circulating hole clean. Displace wellbore from 10.2 ppg LSND to 12.3 ppg LSND. Remove Managed Pressure Drilling RCD. Lubricate out of the hole f/ 11,359' t/ 7,940'. POOH f/ 7,940' t/ 708'. UD BHA #11 f/ 708' U 113'. 2/22/2016 2/23/2016 11,362.0 0.00 10.20 L/D BHA #11 from 113'. Change upper rams from 5-1/2" to 7". Test 7" rams against 7" test joint to 250 PSI / 4,500 PSI. Tests performed w/ 8.5 ppg seawater. Tests held for 5 min. & charted. R/U to run 7" casing. Move & level rig. Run 7" 26# L-80 Hydril 563 casing to 4,391'. 2/23/2016 2/24/2016 11,362.0 0.00 10.20 Run 7" 26# L-80 Hydril 563 casing f/ 4,391' t/ 11,354'. Attempt to establish circulation. **` Perform weekly function test of BOP equipment as per AOGCC requirements. *** Page 4/7 Report Printed: 3/29/2016 A CE CAELUS t'net-gyp Ataska Operations Summary Report - State Well Name: ODSN-01A Page 5/7 Report Printed: 3/29/2016 1 PP �* f Start Date End Date Start Depth (ftKB) FootlMeters (ft) Dens Last Mud (lb/gal) Summary 2/24/2016 2/25/2016 11,362.0 0.00 10.20 Continue attempt to establish circulation w/ no success. L/D landing joint & Vetco Gray hanger f/ 11,354' t/ 11,316'. L/D 7 joints of 7" casing f/ 11,316' t/ 11,028'. Establish circ w/ step rate method f/ 11 GPM t/ 126 GPM. No losses observed. RIH w/ 7" casing f/ 11,028't/ 11,354'. Land hanger. Displace 12.3 ppg LSND w/ 10.2 ppg LSND. R/D Tesco casing equipment. M/U Halliburton cement head & cement lines. Pump Intermediate #2 1st stage cement job per HES program. Pump 10 bbls of 8.5 ppg sea water @ 3 BPM. Test lines to 4,500 PSI - good test. Pump 43 bbls of 11.5 ppg Tuned Spacer III @ 3.3 BPM, 400 PSI. Drop bypass plug w/ last 2 bbls of spacer. Mix & pump 87.6 bbls of 15.8 ppq Premium G cement, 419 sks (a) 1.17 FT13/sk yield, 4.0 BPM, N l18 PSI. Drop shut off plug. Pump 20 bbls of 8.5 ppg sea water @ 4.7 BPM, 119 PSI. Displace cement w/ 10.2 ppg LSND using rig pumps, 5 BPM, 1,340 PSI. Slow to 3 BPM, 900 PSI w/ 200 stks prior to calc bump stks. Bump plug @ 4,789 stks, 401 bbls w/ 96% efficiency. Increase pressure to 2,007 PSI & hold for 5 min. - good test. Bleed off & check floats - holding. 100% returns throughout cement iob. CIP 16:20 hrs. Load 2nd stage bottom A top plugs in the cement head. Pump 2 BPM & pressure up to 3,375 PSI. ES cementer shifted open. Displace 10.8 ppg LSND w/ 10.3 ppg Bara ECD MOBM through the ES cementer @ 8,636'. Hold PJSM for Second Stage cement job w/ all relevant parties. Pump Intermediate #2 second stage cement job through ES cementer @ 8,636'. Pump 10 bbls of 11.0 ppg spacer @ 5 BPM, 336 PSI. Pressure test cement lines to 3,500 PSI. Pump 40 bbls of 11.0 ppg spacer @ 5 BPM, 386 PSI. Drop bottom plug. Mix & pump 57 bbls of 15.8 ppg Premium G cement @ 4 BPM, 200 PSI. Drop top plug. Pump 20 bbls of 8.5 ppg sea water @ 5 BPM, 84 PSI. Begin displacing cement w/ 10.2 ppg LSND using the rig mud pumps @ 5 BPM, 800 PSI w/ full returns. 2/25/2016 2/26/2016 11,362.0 000 10.20 Finish displacing cement w/ 10.2 ppg LSND using the rig mud pumps wl 4.8 BPM, 900 PSI w/ Full returns. Slow to 2 BPM, 250 PSI @ 2,909 stks. Shear bottom plug @ 2,951 stks. Increase to 4.8 BPM, 1,010 PSI. Slow t/ 3 BPM, 800 PSI @ 3,488 stks. Bump plug w/ 2,335 PSI @ 3,641 stks, 310 bbls. - 96% efficiency. Held 2,365 PSI & charted for 5 Min. Bled off pressure w/ 4 bbis returned. ES -Cementer closed. Pressure up to 2,439 PSI for 5 Min. Bled off pressure w/ 3.3 bbls returned. Flow check 5 Min. - No Flow. CIP @ 00:23 hrs. R/D cement equipment & blow down lines. UD 7" landing joint. Install Vetco Gray 7" pack off. Test to 5,000 PSI for 10 min. - good test. R/U for Drill pipe management. L/D 13 jts of 5 1/2" HWDP, Jars & Slingers. UD 266 joints of 5 1/2" drill pipe from the derrick in the mouse hole. Repair Iron Roughneck. UD final 100 joints of 5 1/2" drill pipe. Install 4" Vetco Gray Test plug. Change upper & lower rams f/ 7" to 2-7/8" x 5" VBR. C/O upper & lower IBOP, Guides, & Die Blocks on TD to 4". Install 4" Vetco Gray 4" test joint. 2/26/2016 2/27/2016 11,362.0 0.00 10.20 Test BOP equipment as per AOGCC PTD. Test annular preventer on 4" test joint to 250 PSI low / 2,500 PSI high. Test upper & lower 2-7/8"x 5" VBR on 4" test joint to 250 PSI low / 4,500 PSI high. Test upper & lower IBOP to 250 PSI low / 4,500 PSI high. Test dart valve & TIW valve to 250 PSI low / 4,500 PSI high. Test Pit alarms. Tests performed w/ 4" test joint. All test performed w/ 8.5 ppg sea water. Test held for 5 min. each and charted. Test MPD main flow line f/ RCD to MPD HCR to 500 PSI low / 2,500 PSI high. Pull Trip Nipple & install test cap. C/O Air boot. Reinstall Trip Nipple. Install 6.375" I.D. Vetco Gray wear bushing. P/U 240 jts of 4" drill pipe t/ 7,701'. Circulate & flush 1 x DP capacity. TOH f/ 7,701't/ surface. P/U & M/U Cleanout BHA #12 w/ BAT Sonic to 385'. Slip & cut drilling line. TIH w/ BHA #12 while P/U 4" DP f/ 385't/ 771'. 2/27/2016 2/28/2016 11.362.0 0.00 10.25 TIH w/ BHA #12 while P/U 4" DP f/ 771't/ 8,505'. Drill cement f/ 8,605't/ 8,632'. Pressure Test @ 8,632'. (Top of ES Cementer) Held 2,500 PSI for 5 Min. Drill ES Cementer f/ 8.632' t/ 8.634'. Wash & ream cement 8, 68a'. TIH w/ BHA #12 while P/U 4" DP f/ 8,680't/ 11,158'. Wash & Ream cement f/ 11,158' t/ 11,183'. Tag top of Baffle Adapter w/ 10K over. Test 7" casing to 4000 PSI for 30 minutes. - Good Test. Begin drilling shoe track f/ 11,183't/ 11,266'. *** AOGCC notified of BOP test at 11:25 hrs on 27 February 2016. *** Page 5/7 Report Printed: 3/29/2016 1 PP �* f Operations Summary Report -State Well Name: ODSN-01A CE CAELUS Fn rgy Alaska Start Depth Foot(Meters Dens Last Start Date End Date (ftKB) (ft) Mud (Ib/gal) Summary 2/28/2016 2/29/2016 11,362.0 0.00 10.25 Finish drilling shoe track & rat hole f/ 11,266't/ 11,362'. CBU. Perform BAT Sonic Mad Pass of Stage 1 cmt coverage f/ 11,362't/ 9,852'. POOH f/ 9,852' t/ 8,882'. Perform BAT Sonic Mad I _ Pass of Stage 2 cmt coverage f/ 8,882' U 7,426'. POH f/ 7,426't/ 386'. L/D BHA #12 Cleanout L0 Assembly w/ BAT Sonic f/ 386't/ surface. Remove Vetco Gray wear bushing. R/U to test BOPE. AOGCC notified of BOP test @ 11:25 hrs on 27 February 2016. *** AOGCC Inspector Chuck Scheve waived witness @ 11:45 hrs on 28 February 2016. *** t'; KK 2/29/2016 3/1/2016 11,362.0 75.00 8.00 Test BOPE per AOGCC PTD: Test annular w/ 4" test joint to 250 psi low / 2,500 psi high.(% Test upper and lower VBR w/ 4" & 4-1/2" test joints to 250 psi low ! 4,500 psi high. Test all floor valves to 250 psi low / 4,500 psi high. Test 15 choke manifold valves to 250 psi low / 4,500 psi high. / Test upper and lower IBOP valves to 250 psi low /4,500 psi high. P j Test blind rams to 250 psi low / 4,500 psi high. Test Gas, PVT & Flow Alarms. All tests charted and all tests held for 5 min. All tests performed with 8.5 ppg seawater. Initial system psi: 3,000; 2,100 after closure; 200 psi= 24 sec, full pressure 1 min. 37 sec. *** AOGCC notified of BOP test @ 11:25 hrs on 27 February 2016. *** *** AOGCC Inspector Chuck Scheve waived witness @ 11:45 hrs on 28 February 2016. *** Install 6.375" Vetco Gray Wear Bushing. P/U 6 1/8" Lateral Drilling BHA #13 f/ surface t/ 408'. TIH w/ 6 1/8" Lateral Drilling BHA #13 f/ 408't/ 11,277'. Remove trip nipple & install Halliburton MPD RCD. Displace 10.2 ppg LSND to 8.0 ppg Bara-ECD MOBM. Drill 20' new hole f/ 11,362' to 11,382'. Perform 12.5 ppg EMW FIT w/ MPD. Drilling 6 1/8" Lateral f/ 11,382' t/ 11,437'. CE U Eocrgy Alaska Operations Summary Report - State Well Name: 013SN-01A Page 7/7 Report Printed: 3/29/2016 1 Start Date End Date Start Depth (ftKB) Foot(Meters (ft) Dens Last Mud (lb/gal) Summary 3/7/2016 3/8/2016 18,811.0 0.00 10.00 P/U 57 jts 4" HWDP. Pump & flush 1.5 x DP Volume. Pull wear bushing. Set Test plug. Test BOPE with 4" & 4-1/2" Test joints as per AOGCC & PTD: Test upper 2 7/8" x 5" VBR to 250 / 3,500. Pressure test failed on Upper VBR. C/O Upper VBR. Retest w/ 4" & 4-1/2" Test joints. Good test. Test lower 2 7/8" x 5" VBR to 250 / 3,500. Test lower VBR w/ 4-1/2" Test joint. All tests charted and all tests held for 5 min. All tests performed with fresh water. L/D Test joints & tools. Install 6.375" Wear Bushing. R/U GBR Casing Tongs & Equipment. Run 4-1/2" 12.6# C-110 / P-110 Hydril 521 liner as per liner tally U 5,942'. p F 3/8/2016 3/9/2016 18,811.0 0.00 10.00 Run 4-1/2" 12.6# C-110 / P-110 Hydril 521 liner as per liner tally f/ 5,942' t/ 7,280'. P/U Liner Hanger Packer Assembly per Baker Rep. WU Bumper Sub / Magnet Assy. R/D GBR Casing Tongs & Equipment. C/O elevators. Run 4-1/2" 12.6# C/ 12.6# P-110 Hydril 521 liner on 4" DP per liner tally f/ 7,469't/ 18,440'. Drop & pump down Baker 1.5" hanger setting ball. Ball seated @ 1,060 stks. Increase pressure U 4,200 PSI. Shut down pumps, slack off 35K & observe hanger set. Liner set @ 18,440' / TOL @ 11,097'. Pressure test Baker 4-1/2" x 7" Liner Hanger Packer. - 4,000 PSI test held for 5 min. & charted. Circulate 1x B/U 11,097' t/ 10,991. Displace wellbore f/ 10.0 ppg MOBM t/ 10.0 ppg brine. UD 57 jts 4" HWDP f/ 10,991' U 9,262'. POOH w/ Baker liner running tool f/ 9,262't/ 3,840'. 3/9/2016 3/10/2016 18,811.0 0.00 10.00 POOH w/ Baker liner running tool f/ 3,840't/ 69'. UD Baker & inspect liner running tool assembly. Remove Vetco Gray wear bushing. R/U GBR liner running equipment. R/U Halliburton control lines & sheaves for control line & ROC gauge. Troubleshoot GBR computer. Run 4.5" 12.6# C- - 110 HXdr'I 5211 tubing to 11 12n' M/tI Halliburton ROC gauge & test I -wire every 1,000'. M/U HES Safety Valve Landing Nipple. M/U control line, test to 5,000 PSI, then maintain 4,000 PSI while running. Run 4.5" 12.6# C-110 Hydril 521 Frac tubing f/ 11,120' U 11,152'. Run mule shoe into tie -back w/ no issue. Perform No -Go space out. Pressure test IA to 500 PSI for 5 min.- good test. 3/10/2016 3/11/2016 18,811 0 000 10.00 M/U Vetco Gray tubing hanger & landing joint. Perform control line & i -wire feed through the hanger. Orient & land 4.5" frac tubing completion on Vetco Gray hanger. Set hanger w/ 40K down weight. RILDS. Pressure test hanger seals to 10,000 psi for 10 min. Pressure test IA to 500 psi for 5 min. Drop ball & rod. Pressure test tubing to 3,500 PSI for 30 min. Bleed down tubing to 2,700 PSI. Pressure test IA to 4,000 PSI for 30 min. Bleed tubing & shear DCK-2 valve at 800 PSI. Circulate both ways to verify DCK sheared 100%. Vetco Gray Reps set TWC w/ T bar. Pressure test from below to 2,500 PSI for 5 min. R/D GBR casing equipment. R/D HES Control Line Spools & Sheaves. N/D BOP stack & rack back on pedestal. N/D Vetco Gray riser & spacer spool. N/U 10,000 PSI Vetco Gray frac tree. Terminate I Wire & SSSV Control Lines thru Well Head. Test hanger void to 5,000 PSI for 10 min. Test tree to 10,000 PSI for 10 min. P/U lubricator & remove VR Plug & 1 OK Test flange. UD Lubricator.Test wing & Tree 5,000 PSI for 10 min. L/D 273 jts of 4" DP from the derrick in the mouse hole. 3/11/2016 3/12/2016 18,811.0 0.00 10.00 L/D final 91 stands (194 total stds) 4" drill pipe from the derrick in the mouse hole. P/U 90 joints of 5.5" drill pipe & rack back in the derrick. Set Vetco Gray Two Way Check valve w/ lubricator. Secure well. Prepare rig for rig move. *** OPS & P6 Fz Protect IA & Tubing to 2832' and / 2500' tvd with 96 bbls of diesel. AA IA Capcity of 0.186 bpf / 53 bbls and Tubing Capcity of 0.152 bpf / 43 bbls. *** Release from ODSN-01A at 23:59 on 11 March 2016. *** *** Notified AOGCC at 20:21 3/11/16 of upcoming diverter test for 20:30 3/12/16. *** Page 7/7 Report Printed: 3/29/2016 1 Caelus Energy Alaska Oooguruk Development Oooguruk Drill Site ODSN-01A 50-703-20648-01-00 Sperry Grilling Definitive Survey Report 08 March, 2016 Company: Caelus Energy Alaska Project: Oooguruk Development Site: Oooguruk Drill Site Well: ODSN-01 Wellbore: ODSN-01A Design: O DS N-01 A Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well ODSN-01 - Slot ODS 1 42.7' + 13.5' @ 56.20usft (Nabors 19AC) 42.7' + 13.5' @ 56.20usft (Nabors 19AC) True Minimum Curvature EDMPrd Project Oooguruk Development Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Well ODSN-01 - Slot ODS 1 Well Position +N/ -S 0.00 usft Northing: From +E/ -W 0.00 usft Easting: Position Uncertainty 0.00 usft Wellhead Elevation: 100.00 Wellbore ODSN-01A 909.73 Magnetics Model Name Sample Date 4,623.21 MWD _InterpAzi+sag(ODSN-01A) IGRF2010 2/29%2016 Design ODSN-01A 7,911.84 Audit Notes: MWD+IFR2+MS+sag 11,400.36 6,031,151.32 usft Latitude: 469,920.45 usft Longitude: usft Ground Level: Declination (`) Version: 1.0 Phase: ACTUAL Vertical Section: Depth From (TVD) +N/ -S (usft) (usft) 42.70 0.00 Dip Angle C) 18.98 Survey Program Date 3/7/2016 Azi From To +N/ -S (usft) (usft) Survey (Wellbore) Tool Name 100.00 832.00 ODSN-1 KE3 Gyro (ODSN-01 KE3 PB1) SRG-SS 909.73 3,996.14 ODSN-1 KE3 MWD (ODSN-01 KE3 PB1 MWD+IFR2+MS+sag 4,077.00 4,623.21 MWD _InterpAzi+sag(ODSN-01A) MWD_InterpAzi+sag 4,670.06 7,911.84 MWD+IFR2+MS+sag (1) (ODSN-01A) MWD+IFR2+MS+sag 7,911.84 11,327.03 MWD+IFR2+MS+sag (2) (ODSN-01A) MWD+IFR2+MS+sag 11,400.36 18,743.52 MWD+IFR2+MS+sag (3) (ODSN-01A) MWD+IFR2+MS+sag Survey MD Inc Azi TVD TVDSS +N/ -S (usft) V) C) (usft) (usft) (usft) 42.70 0.00 0.00 42.70 -13.50 0.00 100.00 0.10 133.46 100.00 43.80 -0.03 172.00 0.35 132.63 172.00 115.80 -0.23 267.00 0:36 318.57 267.00 210.80 -0.20 358.00 1.95 307.34 357.98 301.78 0.95 451.00 3.70 315.09 450.86 394.66 4.04 545.00 5.05 311.62 544.58 488.38 8.94 640.00 7.00 305.88 639.06 582.86 15.11 736.00 10.96 307.97 733.86 677.66 24.15 832.00 15.96 309.31 827.19 770.99 38.14 Tie On Depth: +E/ -W (usft) 0.00 Description 81.02 70° 29'46.242 N 150° 14'45.465 W 13.50 usft I Field Strength (nT) 57.710 3,996.14 Direction (1) 317.59 Surface readout gyro single shot Fixed:v2:IIFR dec & 3 -axis correction + sag Fixed:v2:std dec with interpolated azimuth + sag Fixed:v2:IIFR dec & 3 -axis correction + sag Fixed:v2:IIFR dec & 3 -axis correction + sag Fixed:v2:IIFR dec & 3 -axis correction + sag 3/8/2016 9:57.10AM Page 2 COMPASS 5000.1 Build 58 Map Map Vertical +E/ -W Northing Easting DLS Section (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 0.00 6,031,151.32 469,920.45 0.00 0.00 UNDEFINED 0.04 6,031,151.29 469,920.49 0.17 -0.05 SRG-SS (1) 0.24 6,031,151.09 469,920.69 0.35 -0.33 SRG-SS (1) 0.26 6,031,151.12 469,920.71 0.75 -0.32 SRG-SS (1) -1.16 6,031,152.28 469,919.29 1.76 1.49 SRG-SS(1) -4.54 6,031,155.38 469,915.93 1.92 6.04 SRG-SS(1) -9.77 6,031,160.29 469,910.72 1.46 13.19 SRG-SS(1) -17.59 6,031,166.50 469,902.92 2.15 23.02 SRG-SS(1) -29.53 6,031,175.59 469,891.02 4.14 37.75 SRG-SS (1) 46.94 6,031,189.64 469,873.66 5.22 59.82 SRG-SS(1) 3/8/2016 9:57.10AM Page 2 COMPASS 5000.1 Build 58 Halliburton Definitive Survey Report Company: Caelus Energy Alaska Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Project: Oooguruk Development TVD Reference: 42.7'+ 13.5' @ 56.20usft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5' @ 56.20usft (Nabors 19AC) Well: ODSN-01 North Reference: True Wellbore: ODSN-01A Survey Calculation Method: Minimum Curvature Design: O DSN-01 A Database: E DM Prd Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) V) (1) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 909.73 16.00 307.66 901.92 845.72 51.45 -63.69 6,031,203.03 469,856.97 0.59 80.95 MWD+IFR2+MS+sag (2) 954.58 14.41 308.36 945.20 889.00 58.69 -72.96 6,031,210.30 469,847.73 3.57 92.54 MWD+IFR2+MS+sag (2) 1,049.32 14.80 309.58 1,036.88 980.68 73.72 -91.53 6,031,225.40 469,829.22 0.52 116.16 MWD+IFR2+MS+sag (2) 1,144.68 16.59 312.90 1,128.68 1,072.48 90.75 -110.90 6,031,242.51 469,809.93 2.10 141.79 MWD+IFR2+MS+sag (2) 1,240.15 16.38 314.81 1,220.23 1,164.03 109.51 -130.43 6,031,261.35 469,790.48 0.61 168.82 MWD+IFR2+MS+sag (2) 1,335.57 18.59 320.35 1,311.24 1,255.04 130.71 -149.68 6,031,282.62 469,771.31 2.90 197.46 MWD+IFR2+MS+sag (2) 1,429.15 19.71 326.02 1,399.65 1,343.45 155.28 -168.02 6,031,307.27 469,753.07 2.32 227.97 MWD+IFR2+MS+sag (2) 1,525.54 23.99 329.20 1,489.10 1,432.90 185.61 -187.15 6,031,337.67 469,734.07 4.61 263.26 MWD+IFR2+MS+sag (2) 1,620.16 25.84 327.61 1,574.91 1,518.71 219.55 -208.05 6,031,371.69 469,713.31 2.08 302.42 MWD+IFR2+MS+sag (2) 1,715.36 28.46 325.38 1,659.61 1,603.41 255.74 -232.06 6,031,407.97 469,689.45 2.95 345.33 MWD+IFR2+MS+sag (2) 1,810.77 33.41 323.07 1,741.43 1,685.23 295.47 -260.77 6,031,447.82 469,660.90 5.33 394.03 MWD+IFR2+MS+sag (2) 1,905.86 33.00 322.13 1,820.99 1,764.79 336.84 -292.40 6,031,489.31 469,629.45 0.69 445.91 MWD+IFR2+MS+sag (2) 2,000.98 34.90 320.29 1,899.89 1,843.69 378.23 -325.69 6,031,530.83 469,596.33 2.27 498.92 MWD+IFR2+MS+sag (2) 2,095.84 37.50 319.06 1,976.44 1,920.24 420.92 -361.95 6,031,573.66 469,560.24 2.85 554.90 MWD+IFR2+MS+sag (2) 2,190.82 36.54 319.24 2,052.27 1,996.07 464.18 -399.36 6,031,617.07 469,523.01 1.02 612.06 MWD+IFR2+MS+sag (2) 2,285.80 36.46 318.38 2,128.62 2,072.42 506.69 -436.56 6,031,659.73 469,485.98 0.55 668.54 MWD+IFR2+MS+sag (2) 2,382.05 38.75 316.43 2,204.87 2,148.67 549.91 -476.33 6,031,703.09 469,446.40 2.68 727.27 MWD+IFR2+MS+sag (2) 2,477.51 40.58 315.60 2,278.35 2,222.15 593.74 -518.65 6,031,747.09 469,404.26 2.00 788.17 MWD+IFR2+MS+sag (2) 2,571.89 43.35 315.51 2,348.52 2,292.32 638.79 -562.83 6,031,792.32 469,360.26 2.94 851.23 MWD+IFR2+MS+sag (2) 2,666.08 45.01 316.12 2,416.07 2,359.87 685.86 -608.58 6,031,839.57 469,314.71 1.82 916.84 MWD+IFR2+MS+sag (2) 2,760.72 46.87 314.55 2,481.88 2,425.68 734.22 -656.39 6,031,888.11 469,267.10 2.30 984.79 MWD+IFR2+MS+sag (2) 2,856.19 48.79 313.27 2,545.97 2,489.77 783.28 -707.37 6,031,937.38 469,216.32 2.24 1,055.40 MWD+IFR2+MS+sag (2) 2,951.27 50.15 313.92 2,607.76 2,551.56 833.11 -759.71 6,031,987.42 469,164.20 1.52 1,127.49 MWD+IFR2+MS+sag (2) 3,046.47 51.26 314.55 2,668.05 2,611.85 884.51 -812.49 6,032,039.02 469,111.63 1.27 1,201.03 MWD+IFR2+MS+sag (2) 3,140.56 52.34 314.66 2,726.24 2,670.04 936.43 -865.13 6,032,091.15 469,059.20 1.15 1,274.87 MWD+IFR2+MS+sag (2) 3,235.24 53.43 314.94 2,783.37 2,727.17 989.63 -918.70 6,032,144.56 469,005.85 1.18 1,350.28 MWD+IFR2+MS+sag(2) 3,330.43 55.25 315.08 2,838.86 2,782.66 1,044.33 -973.38 6,032,199.47 468,951.40 1.92 1,427.54 MWD+IFR2+MS+sag (2) 31425.80 56.47 314.13 2,892.38 2,836.18 1,099.75 -1,029.58 6,032,255.12 468,895.43 1.52 1,506.37 MWD+IFR2+MS+sag (2) 3,521.96 57.29 314.14 2,944.92 2,888.72 1,155.83 -1,087.38 6,032,311.43 468,837.86 0.85 1,586.76 MWD+IFR2+MS+sag (2) 3,616.79 58.35 314.80 2,995.43 2,939.23 1,212.06 -1,144.65 6,032,367.88 468,780.82 1.26 1,666.90 MWD+IFR2+MS+sag(2) 3,712.20 58.29 314.82 3,045.53 2,989.33 1,269.28 -1,202.25 6,032,425.33 468,723.46 0.07 1,748.00 MWD+IFR2+MS+sag (2) 3,807.12 58.37 314.29 3,095.37 3,039.17 1,325.96 -1,259.82 6,032,482.23 468,666.13 0.48 1,828.67 MWD+IFR2+MS+sag (2) 3,902.35 59.68 314.48 3,144.38 3,088.18 1,383.07 -1,318.17 6,032,539.57 468,606.02 1.39 1,910.19 MWD+IFR2+MS+sag(2) 3,996.14 61.88 315.64 3,190.16 3,133.96 1,441.01 -1,375.98 6,032,597.74 468,550.45 2.58 1,991.96 MWD+IFR2+MS+sag (2) 4,077.00 62.33 315.31 3,227.99 3,171.79 1,491.96 -1,426.09 6,032,648.89 468,500.55 0.66 2,063.37 MWD_InterpAzi+sag (3) 4,115.36 64.03 314.46 3,245.30 3,189.10 1,516.12 -1,450.35 6,032,673.14 468,476.39 4.85 2,097.56 MWD_Interp Azi+sag (3) 4,208.71 61.44 312.39 3,288.06 3,231.86 1,573.16 -1,510.59 6,032,730.42 468,416.39 3.40 2,180.31 MWD_InterpAzi+sag(3) 4,302.17 60.68 310.33 3,333.29 3,277.09 1,627.20 -1,571.97 6,032,784.71 468,355.23 2.09 2,261.61 MWD_InterpAzi+sag(3) 4,395.09 60.84 308.27 3,378.68 3,322.48 1,678.55 -1,634.71 6,032,836.31 466,292.71 1.94 2,341.84 MWD_Interp Azi+sag (3) 4,488.29 61.76 306.22 3,423.44 3,367.24 1,728.02 -1,699.78 6,032,886.03 468,227.84 2.17 2,422.25 MWD_Interp Azi+sag (3) 3/8/2016 9:57:10AM Page 3 COMPASS 5000.1 Build 58 Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 4,530.54 61.75 305.29 3,443.44 3,387.24 1,749.77 -1,729.99 6,032,907.90 468,197.73 1.94 2,458.68 MWD_InterpAzi+sag(3) 4,623.21 62.52 303.26 3,486.76 3,430.56 1,795.90 -1,797.68 6,032,954.30 468,130.23 2.11 2,538.39 MWD_1nterpAzi+sag (3) 4,670.05 63.03 302.23 3,508.18 3,451.98 1,818.43 -1,832.72 6,032,976.97 468,095.29 2.24 2,578.65 MWD+IFR2+MS+sag (4) 4,716.91 63.32 302.03 3,529.33 3,473.13 1,840.67 -1,868.13 6,032,999.35 468,059.97 0.73 2,618.96 MWD+IFR2+MS+sag (4) 4,809.95 62.79 301.60 3,571.49 3,515.29 1,884.39 -1,938.61 6,033,043.35 467,989.68 0.70 2,698.77 MWD+IFR2+MS+sag (4) 4,903.39 62.65 302.68 3,614.32 3,558.12 1,928.57 -2,008.92 6,033,087.81 467,919.54 1.04 2,778.82 MWD+IFR2+MS+sag (4) 4,996.32 62.48 303.17 3,657.14 3,600.94 1,973.40 -2,078.16 6,033,132.92 467,850.50 0.50 2,858.61 MWD+IFR2+MS+sag (4) 5,086.87 62.23 306.92 3,699.16 3,642.96 2,019.45 -2,143.81 6,033,179.22 467,785.04 3.68 2,936.89 MWD+IFR2+MS+sag(4) 5,182.36 62.40 310.80 3,743.54 3,687.34 2,072.49 -2,209.63 6,033,232.52 467,719.44 3.60 3,020.44 MWD+IFR2+MS+sag (4) 5,275.81 62.86 313.49 3,786.51 3,730.31 2,128.17 -2,271.16 6,033,288.45 467,658.15 2.60 3,103.05 MWD+IFR2+MS+sag (4) 5,368.22 63.21 316.61 3,828.42 3,772.22 2,186.45 -2,329.33 6,033,346.96 467,600.21 3.03 3,185.31 MWD+IFR2+MS+sag (4) 5,461.45 62.87 318.14 3,870.69 3,814.49 2,247.59 -2,385.60 6,033,408.32 467,544.20 1.51 3,268.41 MWD+IFR2+MS+sag (4) 5,554.17 63.02 319.91 3,912.87 3,856.67 2,309.93 -2,439.75 6,033,470.88 467,490.31 1.71 3,350.95 MWD+IFR2+MS+sag (4) 5,647.37 63.07 319.27 3,955.11 3,898.91 2,373.19 -2,493.60 6,033,534.34 467,436.72 0.61 3,433.97 MWD+IFR2+MS+sag (4) 5,740.60 63.23 319.46 3,997.22 3,941.02 2,436.31 -2,547.77 6,033,597.68 467,382.81 0.25 3,517.11 MWD+IFR2+MS+sag (4) 5,833.87 62.98 319.36 4,039.41 3,983.21 2,499.48 -2,601.89 6,033,661.05 467,328.95 0.28 3,600.25 MWD+IFR2+MS+sag (4) 5,927.33 62.85 318.96 4,081.97 4,025.77 2,562.43 -2,656.31 6,033,724.22 467,274.80 0.41 3,683.43 MWD+IFR2+MS+sag (4) 6,020.14 62.94 318.14 4,124.25 4,068.05 2,624.35 -2,711.00 6,033,786.36 467,220.36 0.79 3,766.04 MWD+IFR2+MS+sag (4) 6,113.34 63.22 317.18 4,166.45 4,11025 2,685.77 -2,766.97 6,033,848.00 467,164.65 0.97 3,849.14 MWD+IFR2+MS+sag (4) 6,207.22 63.13 318.18 4,208.82 4,152.62 2,747.72 -2,823.37 6,033,910.17 467,108.50 0.96 3,932.91 MWD+IFR2+MS+sag(4) 6,300.45 62.86 317.44 4,251.15 4,194.95 2,809.26 -2,879.15 6,033,971.93 467,052.97 0.76 4,015.97 MWD+IFR2+MS+sag (4) 6,393.15 62.46 316.62 4,293.72 4,237.52 2,869.51 -2,935.28 6,034,032.40 466,997.09 0.90 4,098.31 MWD+IFR2+MS+sag (4) 6,486.35 62.37 316.76 4,336.88 4,280.68 2,929.62 -2,991.94 6,034,092.73 466,940.68 0.16 4,180.91 MWD+IFR2+MS+sag (4) 6,579.23 62.38 316.77 4,379.95 4,323.75 2,989.58 -3,048.31 6,034,152.91 466,884.56 0.01 4,263.19 MWD+IFR2+MS+sag (4) 6,672.65 62.38 315.82 4,423.26 4,367.06 3,049.41 -3,105.50 6,034,212.97 466,827.62 0.90 4,345.94 MWD+IFR2+MS+sag (4) 6,766.02 62.61 316.34 4,466.38 4,410.18 3,109.07 -3,162.95 6,034,272.85 466,770.42 0.55 4,428.73 MWD+IFR2+MS+sag (4) 6,858.50 62.86 315.90 4,508.74 4,452.55 3,168.32 -3,219.93 6,034,332.33 466,713.68 0.50 4,510.91 MWD+IFR2+MS+sag (4) 6,952.07 62.99 315.88 4,551.33 4,495.13 3,228.14 -3,277.92 6,034,392.38 466,655.94 0.14 4,594.19 MWD+IFR2+MS+sag (4) 7,045.19 62.85 315.79 4,593.73 4,537.53 3,287.61 -3,335.69 6,034,452.08 466,598.42 0.17 4,677.06 MWD+IFR2+MS+sag (4) 7,138.49 63.20 315.18 4,636.05 4,579.85 3,346.90 -3,393.98 6,034,511.60 466,540.37 0.69 4,760.15 MWD+IFR2+MS+sag (4) 7,231.25 62.99 314.82 4,678.02 4,621.82 3,405.40 -3,452.47 6,034,570.32 466,482.12 0.41 4,842.79 MWD+IFR2+MS+sag (4) 7,324.36 63.05 315.74 4,720.26 4,664.06 3,464.35 -3,510.86 6,034,629.51 466,423.98 0.88 4,925.70 MWD+IFR2+MS+sag (4) 7,417.84 62.84 315.29 4,762.78 4,706.58 3,523.75 -3,569.19 6,034,689.13 466,365.90 0.48 5,008.89 MWD+IFR2+MS+sag (4) 7,511.36 62.73 315.15 4,805.55 4,749.35 3,582.78 -3,627.78 6,034,748.40 466,307.56 0.18 5,091.99 MWD+IFR2+MS+sag (4) 7,604.66 62.57 314.89 4,848.42 4,792.22 3,641.40 -3,686.35 6,034,807.25 466,249.23 0.30 5,174.78 MWD+IFR2+MS+sag(4) 7,697.46 62.45 314.69 4,891.25 4,835.05 3,699.40 -3,744.78 6,034,865.47 466,191.04 0.23 5,257.00 MWD+IFR2+MS+sag (4) 7,790.72 62.35 314.87 4,934.46 4,878.26 3,757.61 -3,803.44 6,034,923.92 466,132.62 0.20 5,339.55 MWD+IFR2+MS+sag (4) 7,884.00 62.71 314.96 4,977.49 4,921.29 3,816.05 -3,862.05 6,034,982.59 466,074.25 0.40 5,422.22 MWD+IFR2+MS+sag (4) 7,911.84 62.97 315.35 4,990.20 4,934.00 3,833.61 -3,879.52 6,035,000.22 466,056.86 1.56 5,446.97 MWD+IFR2+MS+sag (4) 7,989.33 62.92 316.57 5,025.44 4,969.24 3,883.22 -3,927.49 6,035,050.01 466,009.09 1.40 5,515.95 MWD+IFR2+MS+sag (5) 3/8/2016 9:57:10AM Page 4 COMPASS 5000.1 Build 58 i Halliburton Definitive Survey Report Company: Caelus Energy Alaska Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Project: Oooguruk Development TVD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Well: ODSN-01 North Reference: True Wellbore: ODSN-01A Survey Calculation Method: Minimum Curvature Design: ODS N-01 A Database: E D M Prd Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 4,530.54 61.75 305.29 3,443.44 3,387.24 1,749.77 -1,729.99 6,032,907.90 468,197.73 1.94 2,458.68 MWD_InterpAzi+sag(3) 4,623.21 62.52 303.26 3,486.76 3,430.56 1,795.90 -1,797.68 6,032,954.30 468,130.23 2.11 2,538.39 MWD_1nterpAzi+sag (3) 4,670.05 63.03 302.23 3,508.18 3,451.98 1,818.43 -1,832.72 6,032,976.97 468,095.29 2.24 2,578.65 MWD+IFR2+MS+sag (4) 4,716.91 63.32 302.03 3,529.33 3,473.13 1,840.67 -1,868.13 6,032,999.35 468,059.97 0.73 2,618.96 MWD+IFR2+MS+sag (4) 4,809.95 62.79 301.60 3,571.49 3,515.29 1,884.39 -1,938.61 6,033,043.35 467,989.68 0.70 2,698.77 MWD+IFR2+MS+sag (4) 4,903.39 62.65 302.68 3,614.32 3,558.12 1,928.57 -2,008.92 6,033,087.81 467,919.54 1.04 2,778.82 MWD+IFR2+MS+sag (4) 4,996.32 62.48 303.17 3,657.14 3,600.94 1,973.40 -2,078.16 6,033,132.92 467,850.50 0.50 2,858.61 MWD+IFR2+MS+sag (4) 5,086.87 62.23 306.92 3,699.16 3,642.96 2,019.45 -2,143.81 6,033,179.22 467,785.04 3.68 2,936.89 MWD+IFR2+MS+sag(4) 5,182.36 62.40 310.80 3,743.54 3,687.34 2,072.49 -2,209.63 6,033,232.52 467,719.44 3.60 3,020.44 MWD+IFR2+MS+sag (4) 5,275.81 62.86 313.49 3,786.51 3,730.31 2,128.17 -2,271.16 6,033,288.45 467,658.15 2.60 3,103.05 MWD+IFR2+MS+sag (4) 5,368.22 63.21 316.61 3,828.42 3,772.22 2,186.45 -2,329.33 6,033,346.96 467,600.21 3.03 3,185.31 MWD+IFR2+MS+sag (4) 5,461.45 62.87 318.14 3,870.69 3,814.49 2,247.59 -2,385.60 6,033,408.32 467,544.20 1.51 3,268.41 MWD+IFR2+MS+sag (4) 5,554.17 63.02 319.91 3,912.87 3,856.67 2,309.93 -2,439.75 6,033,470.88 467,490.31 1.71 3,350.95 MWD+IFR2+MS+sag (4) 5,647.37 63.07 319.27 3,955.11 3,898.91 2,373.19 -2,493.60 6,033,534.34 467,436.72 0.61 3,433.97 MWD+IFR2+MS+sag (4) 5,740.60 63.23 319.46 3,997.22 3,941.02 2,436.31 -2,547.77 6,033,597.68 467,382.81 0.25 3,517.11 MWD+IFR2+MS+sag (4) 5,833.87 62.98 319.36 4,039.41 3,983.21 2,499.48 -2,601.89 6,033,661.05 467,328.95 0.28 3,600.25 MWD+IFR2+MS+sag (4) 5,927.33 62.85 318.96 4,081.97 4,025.77 2,562.43 -2,656.31 6,033,724.22 467,274.80 0.41 3,683.43 MWD+IFR2+MS+sag (4) 6,020.14 62.94 318.14 4,124.25 4,068.05 2,624.35 -2,711.00 6,033,786.36 467,220.36 0.79 3,766.04 MWD+IFR2+MS+sag (4) 6,113.34 63.22 317.18 4,166.45 4,11025 2,685.77 -2,766.97 6,033,848.00 467,164.65 0.97 3,849.14 MWD+IFR2+MS+sag (4) 6,207.22 63.13 318.18 4,208.82 4,152.62 2,747.72 -2,823.37 6,033,910.17 467,108.50 0.96 3,932.91 MWD+IFR2+MS+sag(4) 6,300.45 62.86 317.44 4,251.15 4,194.95 2,809.26 -2,879.15 6,033,971.93 467,052.97 0.76 4,015.97 MWD+IFR2+MS+sag (4) 6,393.15 62.46 316.62 4,293.72 4,237.52 2,869.51 -2,935.28 6,034,032.40 466,997.09 0.90 4,098.31 MWD+IFR2+MS+sag (4) 6,486.35 62.37 316.76 4,336.88 4,280.68 2,929.62 -2,991.94 6,034,092.73 466,940.68 0.16 4,180.91 MWD+IFR2+MS+sag (4) 6,579.23 62.38 316.77 4,379.95 4,323.75 2,989.58 -3,048.31 6,034,152.91 466,884.56 0.01 4,263.19 MWD+IFR2+MS+sag (4) 6,672.65 62.38 315.82 4,423.26 4,367.06 3,049.41 -3,105.50 6,034,212.97 466,827.62 0.90 4,345.94 MWD+IFR2+MS+sag (4) 6,766.02 62.61 316.34 4,466.38 4,410.18 3,109.07 -3,162.95 6,034,272.85 466,770.42 0.55 4,428.73 MWD+IFR2+MS+sag (4) 6,858.50 62.86 315.90 4,508.74 4,452.55 3,168.32 -3,219.93 6,034,332.33 466,713.68 0.50 4,510.91 MWD+IFR2+MS+sag (4) 6,952.07 62.99 315.88 4,551.33 4,495.13 3,228.14 -3,277.92 6,034,392.38 466,655.94 0.14 4,594.19 MWD+IFR2+MS+sag (4) 7,045.19 62.85 315.79 4,593.73 4,537.53 3,287.61 -3,335.69 6,034,452.08 466,598.42 0.17 4,677.06 MWD+IFR2+MS+sag (4) 7,138.49 63.20 315.18 4,636.05 4,579.85 3,346.90 -3,393.98 6,034,511.60 466,540.37 0.69 4,760.15 MWD+IFR2+MS+sag (4) 7,231.25 62.99 314.82 4,678.02 4,621.82 3,405.40 -3,452.47 6,034,570.32 466,482.12 0.41 4,842.79 MWD+IFR2+MS+sag (4) 7,324.36 63.05 315.74 4,720.26 4,664.06 3,464.35 -3,510.86 6,034,629.51 466,423.98 0.88 4,925.70 MWD+IFR2+MS+sag (4) 7,417.84 62.84 315.29 4,762.78 4,706.58 3,523.75 -3,569.19 6,034,689.13 466,365.90 0.48 5,008.89 MWD+IFR2+MS+sag (4) 7,511.36 62.73 315.15 4,805.55 4,749.35 3,582.78 -3,627.78 6,034,748.40 466,307.56 0.18 5,091.99 MWD+IFR2+MS+sag (4) 7,604.66 62.57 314.89 4,848.42 4,792.22 3,641.40 -3,686.35 6,034,807.25 466,249.23 0.30 5,174.78 MWD+IFR2+MS+sag(4) 7,697.46 62.45 314.69 4,891.25 4,835.05 3,699.40 -3,744.78 6,034,865.47 466,191.04 0.23 5,257.00 MWD+IFR2+MS+sag (4) 7,790.72 62.35 314.87 4,934.46 4,878.26 3,757.61 -3,803.44 6,034,923.92 466,132.62 0.20 5,339.55 MWD+IFR2+MS+sag (4) 7,884.00 62.71 314.96 4,977.49 4,921.29 3,816.05 -3,862.05 6,034,982.59 466,074.25 0.40 5,422.22 MWD+IFR2+MS+sag (4) 7,911.84 62.97 315.35 4,990.20 4,934.00 3,833.61 -3,879.52 6,035,000.22 466,056.86 1.56 5,446.97 MWD+IFR2+MS+sag (4) 7,989.33 62.92 316.57 5,025.44 4,969.24 3,883.22 -3,927.49 6,035,050.01 466,009.09 1.40 5,515.95 MWD+IFR2+MS+sag (5) 3/8/2016 9:57:10AM Page 4 COMPASS 5000.1 Build 58 Halliburton Definitive Survey Report Company: Caelus Energy Alaska Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Project: Oooguruk Development TVD Reference: 42.7'+ 13.5' @ 56.20usft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Well: ODSN-01 North Reference: True Wellbore: ODSN-01A Survey Calculation Method: Minimum Curvature Design: ODSN-01A Database: EDMPrd Survey Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) V) (usft) (usft) (usft) (usft) (ft) (ft) (-1100') (ft) Survey Tool Name 8,036.91 62.29 316.43 5,047.34 4,991.14 3,913.86 -3,956.57 6,035,080.77 465,980.14 1.35 5,558.18 MWD+IFR2+MS+sag (5) 8,130.33 62.21 316.20 5,090.83 5,034.63 3,973.65 -4,01367 6,035,140.78 465,923.29 0.23 5,640.84 MWD+IFR2+MS+sag(5) 8,223.57 62.85 315.96 5,133.84 5,077.64 4,033.24 -4,071.06 6,035,200.60 465,866.15 0.72 5,723.54 MWD+IFR2+MS+sag (5) 8,316.30 63.60 315.63 5,175.62 5,119.42 4,092.58 -4,128.78 6,035,260.17 465,808.67 0.87 5,806.28 MWD+IFR2+MS+sag (5) 8,409.08 62.90 314.35 5,217.38 5,161.18 4,151.16 -4,187.37 6,035,318.97 465,750.33 1.44 5,889.05 MWD+IFR2+MS+sag (5) 8,501.60 62.40 314.76 5,259.89 5,203.69 4,208.81 -4,245.93 6,035,376.86 465,692.01 0.67 5,971.11 MWD+IFR2+MS+sag (5) 8,594.78 62.33 314.44 5,303.11 5,246.91 4,266.77 -4,304.70 6,035,435.05 465,633.47 0.31 6,053.55 MWD+IFR2+MS+sag (5) 8,688.23 62.92 314.32 5,346.08 5,289.88 4,324.81 -4,364.01 6,035,493.33 465,574.40 0.64 6,136.40 MWD+IFR2+MS+sag(5) 8,781.82 62.52 313.97 5,388.97 5,332.77 4,382.75 -4,423.70 6,035,551.50 465,514.95 0.54 6,219.43 MWD+IFR2+MS+sag (5) 8,874.96 62.22 313.78 5,432.17 5,375.97 4,439.94 -4,483.19 6,035,608.92 465,455.71 0.37 6,301.77 MWD+IFR2+MS+sag (5) 8,967.30 62.00 314.03 5,475.36 5,419.16 4,496.54 -4,541.99 6,035,665.75 465,397.14 0.34 6,383.22 MWD+IFR2+MS+sag (5) 9,060.72 62.36 314.41 5,518.96 5,462.76 4,554.16 -4,601.20 6,035,723.61 465,338.17 0.53 6,465.70 MWD+IFR2+MS+sag (5) 9,153.38 62.78 314.08 5,561.64 5,505.44 4,611.54 -4,660.12 6,035,781.22 465,279.49 0.55 6,547.80 MWD+IFR2+MS+sag (5) 9,246.90 62.28 314.17 5,604.78 5,548.58 4,669.31 -4,719.68 6,035,839.23 465,220.17 0.54 6,630.63 MWD+IFR2+MS+sag (5) 9,340.01 62.78 314.75 5,647.73 5,591.53 4,727.17 -4,778.64 6,035,897.32 465,161.45 0.77 6,713.11 MWD+IFR2+MS+sag (5) 9,433.27 62.62 314.64 5,690.51 5,634.31 4,785.46. -4,837.55 6,035,955.84 465,102.78 0.20 6,795.88 MWD+IFR2+MS+sag (5) 9,525.94 62.75 314.42 5,733.03 5,676.83 4,843.20 -4,896.25 6,036,013.81 465,044.32 0.25 6,878.10 MWD+IFR2+MS+sag (5) 9,620.30 62.33 315.37 5,776.54 5,720.34 4,902.29 -4,955.56 6,036,073.14 464,985.26 1.00 6,961.73 MWD+IFR2+MS+sag (5) 9,713.43 62.92 315.33 5,819.37 5,763.17 4,961.13 -5,013.68 6,036,132.20 464,927.38 0.63 7,044.37 MWD+IFR2+MS+sag (5) 9,805.10 62.22 315.45 5,861.60 5,805.40 5,019.05 -5,070.82 6,036,190.35 464,870.48 0.77 7,125.68 MWD+IFR2+MS+sag (5) 9,899.34 62.57 316.70 5,905.27 5,849.07 5,079.20 -5,128.75 6,036,250.73 464,812.80 1.23 7,209.16 MWD+IFR2+MS+sag(5) 9,992.02 62.71 317.55 5,947.86 5,891.66 5,139.52 -5,184.76 6,036,311.27 464,757.04 0.83 7,291.46 MWD+IFR2+MS+sag (5) 10,084.74 62.01 316.05 5,990.88 5,934.68 5,199.40 -5,240.98 6,036,371.37 464,701.07 1.62 7,373.59 MWD+IFR2+MS+sag (5) 10,177.85 63.33 315.56 6,033.62 5,977.42 5,258.70 -5,298.64 6,036,430.90 464,643.65 1.49 7,456.27 MWD+IFR2+MS+sag (5) 10,271.42 66.40 315.87 6,073.36 6,017.16 5,319.34 -5,357.78 6,036,491.77 464,584.77 3.29 7,540.92 MWD+IFR2+MS+sag (5) 10,365.46 69.14 315.33 6,108.94 6,052.74 5,381.52 -5,418.68 6,036,554.19 464,524.12 2.96 7,627.91 MWD+IFR2+MS+sag (5) 10,459.28 72.03 314.13 6,140.12 6,083.92 5,443.78 -5,481.54 6,036,616.70 464,461.52 3.31 7,716.27 MWD+IFR2+MS+sag (5) 10,551.34 73.96 313.74 6,167.04 6,110.84 5,504.86 -5,544.94 6,036,678.03 464,398.38 2.14 7,804.12 MWD+IFR2+MS+sag (5) 10,643.91 77.10 312.86 6,190.17 6,133.97 5,566.32 -5,610.16 6;036,739.74 464,333.41 3.51 7,893.49 MWD+IFR2+MS+sag(5) 10,738.14 79.30 313.44 6,209.44 6,153.24 5,629.40 -5,677.45 6,036,803.09 464,266.38 2.41 7,985.45 MWD+IFR2+MS+sag (5) 10,830.60 82.38 313.88 6,224.16 6,167.96 5,692.41 -5,743.48 6,036,866.36 464,200.62 3.36 8,076.50 MWD+IFR2+MS+sag(5) 10,924.01 85.17 313.39 6,234.29 6,178.09 5,756.48 -5,810.68 6,036,930.70 464,133.68 3.03 8,169.13 MWD+IFR2+MS+sag (5) 11,016.96 84.90 312.99 6,242.33 6,186.13 5,819.86 -5,878.19 6,036,994.34 464,066.43 0.52 8,261.46 MWD+IFR2+MS+sag (5) 11,110.91 85.09 312.68 6,250.53 6,194.33 5,883.49 -5,946.83 6,037,058.25 463,998.07 0.39 8,354.73 MWD+IFR2+MS+sag (5) 11,203.61 84.96 311.99 6,258.57 6,202.37 5,945.69 -6,015.09 6,037,120.71 463,930.06 0.75 8,446.69 MWD+IFR2+MS+sag (5) 11,296.51 85.27 313.01 6,266.48 6,210.28 6,008.22 -6,083.34 6,037,183.51 463,862.08 1.14 8,538.89 MWD+IFR2+MS+sag (5) 11,327.03 84.96 312.90 6,269.08 6,212.88 6,028.94 -6,105.59 6,037,204.32 463,839.91 1.08 8,569.20 MWD+IFR2+MS+sag (5) 11,400.36 84.65 314.00 6,275.72 6,219.52 6,079.17 -6,158.61 6,037,254.75 463,787.10 1.55 8,642.04 MWD+IFR2+MS+sag (6) 11,496.77 85.95 313.17 6,283.62 6,227.42 6,145.41 -6,228.21 6,037,321.27 463,717.78 1.60 8,737.88 MWD+IFR2+MS+sag (6) 11,592.82 88.80 312.61 6,288.01 6,231.81 6,210.70 -6,298.50 6,037,386.84 463,647.76 3.02 8,833.50 MWD+IFR2+MS+sag (6) 3/8/2016 9:57:10AM Page 5 COMPASS 5000.1 Build 58 Halliburton Definitive Survey Report Company: Caelus Energy Alaska Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Project: Oooguruk Development TVD Reference: 42.7' + 13.5' @ 56.20usft (Nabors 19AC) Site: Oooguruk Drill Site MD Reference: 42.7' + 13.5'@ 56.20usft (Nabors 19AC) Well: ODSN-01 North Reference: True Wellbore: ODSN-01A Survey Calculation Method: Minimum Curvature Design: ODSN-01 A Database: E D M Prd Survey 3/8/2016 9:57:10AM Page 6 COMPASS 5000.1 Build 58 Map Map Vertical MD Inc Azi TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (1) V) (usft) (usft) (usft) (usft) (ft) (ft) (°1100') (ft) Survey Tool Name 11,689.43 90.59 312.62 6,288.53 6,232.33 6,276.11 -6,369.59 6,037,452.53 463,576.93 1.85 8,929.74 MWD+IFR2+MS+sag (6) 11,785.83 90.77 312.32 6,287.38 6,231.18 6,341.20 -6,440.69 6,037,517.90 463,506.10 0.36 9,025.75 MWD+IFR2+MS+sag (6) 11,882.61 90.59 314.35 6,286.24 6,230.04 6,407.60 -6,511.08 6,037,584.58 463,435.99 2.11 9,122.25 MWD+IFR2+MS+sag (6) 11.977.73 90.52 314.03 6,285.31 6,229.11 6,473.90 -6,579.28 6,037,651.15 463,368.07 0.34 9,217.20 MWD+IFR2+MS+sag(6) 12,074.23 90.71 314.90 6,284.28 6,228.08 6,541.49 -6,648.15 6,037,719.01 463,299.49 0.92 9,313.55 MWD+IFR2+MS+sag (6) 12,170.46 90.77 314.03 6,283.04 6,226.84 6,608.89 -6,716.82 6,037,786.68 463,231.09 0.91 9,409.63 MWD+IFR2+MS+sag (6) 12,266.74 90.90 312.66 6,281.63 6,225.43 6,674.97 -6,786.83 6,037,853.04 463,16.1.36 1.43 9,505.63 MWD+IFR2+MS+sag (6) 12,362.18 90.59 312.29 6,280.39 6,224.19 6,739.41 -6,857.21 6,037,917.76 463,091.24 0.51 900.68 MWD+IFR2+MS+sag (6) 12,459.14 90.34 310.95 6,279.60 6,223.40 6,803.81 -6,929.69 6,037,982.44 463,019.03 1.41 9,697.11 MWD+IFR2+MS+sag (6) 12,554.21 90.90 313.95 6,278.58 6,222.38 6,867.97 -6,999.83 6,038,046.87 462,949.16 3.21 9,791.78 MWD+IFR2+MS+sag (6) 12,651.49 91.20 317.53 6,276.79 6,220.59 6,937.61 -7,067.70 6,038,116.79 462,881.58 3.69 9,888.98 MWD+IFR2+MS+sag (6) 12,747.59 91.45 316.33 6,274.57 6,218.37 7,007.79 -7,133.31 6,038,187.23 462,816.26 1.28 9,985.04 MWD+IFR2+MS+sag(6) 12,843.64 91.51 315.52 6,272.09 6,215.89 7,076.78 -7,200.10 6,038,256.47 462,749.76 0.85 10,081.02 MWD+IFR2+MS+sag (6) 12,939.46 91.64 315.27 6,269.46 6,213.26 7,144.97 -7,267.36 6,038,324.93 462,682.78 0.29 10,176.73 MWD+IFR2+MS+sag (6) 13,035.62 90.40 311.70 6,267.74 6,211.54 7,211.12 -7,337.10 6,038,391.36 462,613.31 3.93 10,272.61 MWD+IFR2+MS+sag (6) 13,131.88 90.65 311.20 6,266.86 6,210.66 7,274.84 -7,409.25 6,038,455.36 462,541.43 0.58 10,368.32 MWD+IFR2+MS+sag(6) 13,228.22 90.28 313.12 6,266.08 6,209.88 7,339.50 -7,480.66 6,038,520.30 462,470.29 2.03 10,464.22 MWD+IFR2+MS+sag (6) 13,324.87 90.15 315.76 6,265.72 6,209.52 7,407.16 -7,549.66 6,038,588.24 462,401.57 2.73 10,560.71 MWD+IFR2+MS+sag (6) 13,421.10 91.58 320.99 6,264.26 6,208.06 7,479.06 -7,613.55 6,038,660.38 462,337.98 5.63 10,656.89 MWD+IFR2+MS+sag (6) 13,516.46 91.33 321.86 6,261.84 6,205.64 7,553.59 -7,672.99 6,038,735.14 462,278.85 0.95 10,752.00 MWD+IFR2+MS+sag (6) 13,613.29 91.27 321.21 6,259.64 6,203.44 7,629.38 -7,733.21 6,038,811.18 462,218.94 0.67 10,848.58 MWD+IFR2+MS+sag (6) 13,709.96 91.70 321.62 6,257.14 6,200.94 7,704.92 -7,793.48 6,038,886.95 462,158.98 0.61 10,945.00 MWD+IFR2+MS+sag (6) 13,806.24 91.57 323.20 6,254.39 6,198.19 7,781.18 -7,852.18 6,038,963.44 462,100.59 1.65 11,040.90 MWD+IFR2+MS+sag (6) 13,901.87 90.71 323.08 6,252.49 6,196.29 7,857.68 -7,909.53 6,039,040.16 462,043.56 0.91 11,136.06 MWD+IFR2+MS+sag (6) 13,998.21 91.20 324.13 6,250.88 6,194.68 7,935.22 -7,966.69 6,039,117.92 461,986.72 1.20 11,231.85 MWD+IFR2+MS+sag (6) 14,094.95 91.33 325.61 6,248.75 6,192.55 8,014.31 -8,022.34 6,039,197.23 461,931.40 1.54 11,327.79 MWD+IFR2+MS+sag(6) 14,191.35 92.44 325.98 6,245.58 6,189.38 8,093.99 -8,076.50 6,039,277.13 461,877.56 1.21 11,423.15 MWD+IFR2+MS+sag (6) 14,287.26 91.27 321.99 6,242.47 6,186.27 8,171.51 -8,132.86 6,039,354.87 461,821.53 4.33 11,518.39 MWD+IFR2+MS+sag (6) 14,383.75 92.38 321.79 6,239.40 6,183.20 8,247.40 -8,192.38 6,039,430.98 461,762.32 1.17 11,614.56 MWD+IFR2+MS+sag(6) 14,479.92 92.56 322.53 6,235.25 6,179.05 8,323.27 -8,251.32 6,039,507.09 461,703.69 0.79 11,710.33 MWD+IFR2+MS+sag(6) 14,576.41 91.82 322.03 6,231.57 6,175.37 8,399.54 -8,310.31 6,039,583.59 461,645.02 0.93 11,806.43 MWD+IFR2+MS+sag (6) 14,672.76 90.03 321.25 6,230.01 6,173.81 8,475.08 -8,370.09 6,039,659.36 461,585.55 2.03 11,902.52 MWD+IFR2+MS+sag (6) 14,768.30 90.52 323.16 6,229.55 6,173.35 8,550.57 -8,428.64 6,039,735.08 461,527.31 2.06 11,997.74 MWD+IFR2+MS+sag (6) 14,865.04 90.28 324.16 6,228.88 6,172.68 8,628.49 -8,485.96 6,039,813.22 461,470.31 1.06 12,093.94 MWD+IFR2+MS+sag (6) 14,960.60 90.09 324.73 6,228.57 6,172.37 8,706.23 -8,541.53 6,039,891.18 461,415.06 0.63 12,188.81 MWD+IFR2+MS+sag (6) 15,057.22 90.71 324.94 6,227.89 6,171.69 8,785.22 -8,597.17 6,039,970.38 461,359.74 0.68 12,284.66 MWD+IFR2+MS+sag (6) 15,153.86 90.22 325.87 6,227.11 6,170.91 8,864.77 -8,652.04 6,040,050.15 461,305.21 1.09 12,380.40 MWD+IFR2+MS+sag (6) 15,250.27 91.20 325.08 6,225.92 6,169.72 8,944.19 -8,706.68 6,040,129.78 461,250.90 1.31 12,475.89 MWD+IFR2+MS+sag (6) 15,346.58 91.14 327.40 6,223.95 6,167.75 9,024.24 -8,760.18 6,040,210.04 461,197.72 2.41 12,571.08 MWD+IFR2+MS+sag(6) 15,443.82 90.59 322.57 6,222.48 6,166.28 9,103.84 -8,815.96 6,040,289.86 461,142.28 5.00 12,667.47 MWD+IFR2+MS+sag (6) 3/8/2016 9:57:10AM Page 6 COMPASS 5000.1 Build 58 Company: Project: Site: Well: Wellbore: Design: Survey Caelus Energy Alaska Oooguruk Development Oooguruk Drill Site ODSN-01 ODSN-01A ODSN-01A Halliburton Definitive Survey Report Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Database: Well ODSN-01 - Slot ODS 1 42.7'+ 13.5' @ 56.20usft (Nabors 19AC) 42.7'+ 13.5' @ 56.20usft (Nabors 19AC) True Minimum Curvature EDMPrd brian.wheeler@hallibur,, "`„"x �°„�M,m•�^°�••"^••,„.•gym 03/08/2016Checked By: ton.com Approved By: ",ill ".na"a@`ae'°`e eryr.c°" Date: 3/8/2016 9:57:10AM Page 7 COMPASS 5000.1 Build 58 Map Map Vertical MD Inc Az( TVD TVDSS +N/ -S +E/ -W Northing Easting DLS Section (usft) (°) (°) (usft) (usft) (usft) (usft) (ft) (ft) (°/100') (ft) Survey Tool Name 15,540.04 91.51 322.38 6,220.72 6,164.52 9,180.14 -8,874.55 6,040,366.39 461,083.99 0.98 12,763.32 MWD+IFR2+MS+sag(6) 15,636.94 91.27 321.12 6,218.37 6,162.17 9,256.21 -8,934.52 6,040,442.69 461,024.34 1.32 12,859.93 MWD+IFR2+MS+sag(6) 15,733.29 90.52 320.77 6,216.86 6,160.66 9,331.02 -8,995.22 6,040,517.74 460,963.95 0.86 12,956.11 MWD+IFR2+MS+sag (6) 15,829.30 90.53 322.54 6,215.98 6,159.78 9,406.32 -9,054.78 6,040,593.27 460,904.70 1.84 13,051.87 MWD+IFR2+MS+sag (6) 15,925.74 90.15 323.70 6,215.41 6,159.21 9,483.46 -9,112.66 6,040,670.63 460,847.14 1.27 13,147.85 MWD+IFR2+MS+sag (6) 16,021.64 88.42 325.01 6,216.61 6,160.41 9,561.38 -9,168.54 6,040,748.77 460,791.58 2.26 13,243.07 MWD+IFR2+MS+sag(6) 16,118.14 88.30 325.37 6,219.37 6,163.17 9,640.58 -9,223.60 6,040,828.18 460,736.84 0.39 13,338.69 MWD+IFR2+MS+sag (6) 16,214.57 89.04 325.10 6,221.61 6,165.41 9,719.77 -9,278.57 6,040,907.59 460,682.20 0.82 13,434.23 MWD+IFR2+MS+sag(6) 16,310.68 90.53 324.90 6,221.97 6,165.77 9,798.50 -9,333.70 6,040,986.53 460,627.40 1.56 13,529.54 MWD+IFR2+MS+sag (6) 16,407.03 90.53 321.84 6,221.07 6,164.87 9,875.81 -9,391.17 6,041,064.07 460,570.24 3.18 13,625.38 MWD+IFR2+MS+sag (6) 16,503.52 90.28 317.91 6,220.39 6,164.19 9,949.57 -9,453.34 6,041,138.07 460,508.38 4.08 13,721.77 MWD+IFR2+MS+sag (6) 16,599.71 90.84 316.99 6,219.45 6,163.25 10,020.43 -9,518.39 6,041,209.19 460,443.63 1.12 13,817.96 MWD+IFR2+MS+sag(6) 16,696.40 89.97 317.09 6,218.77 6,162.57 10,091.19 -9,584.28 6,041,280.21 460,378.03 0.91 13,914.64 MWD+IFR2+MS+sag (6) 16,792.20 90.77 318.18 6,218.15 61161.95 10,161.97 -9,648.83 6,041,351.24 460,313.77 1.41 14,010.44 MWD+IFR2+MS+sag (6) 16,888.89 90.65 320.34 6,216.95 6,160.75 10,235.22 -9,711.92 6,041,424.74 460,250.98 2.24 14,107.07 MWD+IFR2+MS+sag (6) 16,985.34 90.34 324.91 6,216.12 6,159.92 10,311.84 -9,770.45 6,041,501.59 460,192.77 4.75 14,203.12 MWD+IFR2+MS+sag (6) 17,080.98 90.15 328.24 6,215.71 6,159.51 10,391.65 -9,823.13 6,041,581.60 460,140.42 3.49 14,297.57 MWD+IFR2+MS+sag (6) 17,177.07 90.15 328.72 6,215.46 6,159.26 10,473.56 -9,873.36 6,041,663.71 460,090.52 0.50 14,391.93 MWD+IFR2+MS+sag (6) 17,275.60 90.77 330.18 6,214.67 6,158.47 10,558.41 -9,923.44 6,041,748.75 460,040.79 1.61 14,488.35 MWD+IFR2+MS+sag (6) 17,370.86 89.91 331.22 6,214.10 6,157.90 10,641.48 -9,970.06 6,041,832.00 459,994.52 1.42 14,581.12 MWD+IFR2+MS+sag (6) 17,465.84 90.65 331.81 6,213.64 6,157.44 10,724.96 -10,015.36 6,041,915.65 459,949.56 1.00 14,673.31 MWD+IFR2+MS+sag(6) 17,562.97 91.45 330.67 6,211.86 6,155.66 10,810.09 -10,062.08 6,042,000.97 459,903.19 1.43 14,767.68 MWD+IFR2+MS+sag(6) 17,658.99 89.23 327.61 6,211.29 6,155.09 10,892.50 -10,111.32 6,042,083.57 459,854.28 3.94 14,861.74 MWD+IFR2+MS+sag (6) 17,755.11 90.15 327.07 6,211.81 6,155.61 10,973.42 -10,163.19 6,042,164.69 459,802.75 1.11 14,956.47 MWD+IFR2+MS+sag (6) 17,851.28 91.82 327.75 6,210.15 6,153.95 11,054.43 -10,214.98 6,042,245.90 459,751.29 1.87 15,051.21 MWD+IFR2+MS+sag (6) 17,948.11 90.65 326.98 6,208.07 6,151.87 11,135.95 -10,267.19 6,042,327.62 459,699.42 1.45 15,146.61 MWD+IFR2+MS+sag(6) 18,044.80 88.24 324.79 6,209.00 6,152.80 11,215.99 -10,321.41 6,042,407.87 459,645.53 3.37 15,242.27 MWD+IFR2+MS+sag(6) 18,141.47 85.27 323.51 6,214.47 6,158.28 11,294.21 -10,377.93 6,042,486.31 459,589.34 3.34 15,338.14 MWD+IFR2+MS+sag (6) 18,236.52 86.20 322.49 6,221.54 6,165.34 11,369.91 -10,434.97 6,042,562.23 459,532.60 1.45 15,432.50 MWD+IFR2+MS+sag(6) 18,333.57 86.01 322.50 6,228.14 6,171.94 11,446.72 -10,493.92 6,042,639.28 459,473.97 0.20 15,528.97 MWD+IFR2+MS+sag (6) 18,429.93 81.73 320.51 6,238.42 6,182.22 11,521.69 -10,553.53 6,042,714.48 459,414.67 4.89 15,624.53 MWD+IFR2+MS+sag(6) 18,524.84 76.44 318.75 6,256.39 6,200.19 11,592.67 -10,613.86 6,042,785.70 459,354.63 5.86 15,717.63 MWD+IFR2+MS+sag (6) 18,621.38 74.92 318.67 6,280.27 6,224.07 11,662.96 -10,675.59 6,042,856.22 459,293.20 1.58 15,811.15 MWD+IFR2+MS+sag(6) 18,717.66 75.10 319.27 6,305.17 6,248.97 11,733.11 -10,736.64 6,042,926.62 459,232.44 0.63 15,904.12 MWD+IFR2+MS+sag (6) 18,743.52 75.23 319.26 6,311.79 6,255.59 11,752.06 -10,752.95 6,042,945.63 459,216.20 0.50 15,929.11 MWD+IFR2+MS+sag (6) 18,811.00 75.23 319.26 6,329.00 6,272.80 11,801.49 -10,795.53 6,042,995.23 459,173.82 0.00 15,994.33 PROJECTED to TO brian.wheeler@hallibur,, "`„"x �°„�M,m•�^°�••"^••,„.•gym 03/08/2016Checked By: ton.com Approved By: ",ill ".na"a@`ae'°`e eryr.c°" Date: 3/8/2016 9:57:10AM Page 7 COMPASS 5000.1 Build 58 RECEIVED APR 0 4 2016 AOGMft —qc=CA -PLUS Energy Alaska LETTER OF TRANSMITTAL DATA LOGGED q /di /201rn M. K. BENDER DATE: March 31, 2016 ❑ Maps FROM: TOM Shannon Koh AOGCC Caelus Energy AlaskaAttn: Makana Bender 3700 Centerpoint Dr., Suite 500 333 W. 7th Avenue, Suite 100 Anchorage, AK 99503 nchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ CD -R ❑ Agreement ® Other — Logs, Report nFTA11 QTY DESCRIPTION Well Name: ODSN-01A (50-703-20648-0100) 1 Report Surface Data Logging — End of Well Report Surface Data Logging - 2" MD Gas Ratio Log, CVE 4 Well Logs Gas Extraction (1:600); Surface Data Logging 2" MD Formation Evaluation Log, CVE Gas Extraction (1:600); Surface Data Logging 2" MD Drilling Engineering Log, CVE Gas Extraction (1:600) Surface Data Logging 5" MD Formation Evaluation Log, CVE Gas Extraction 1:240 Received b Date: Please sitfn and return one copy to: Caelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.koh(a)caelusenergy.com c CAELUS Energy Alaska /Sys qECEIVED MAR 2 9 2016 Letter of TransmittkOGCC Date: March 22, 2016 FROM TO Shannon Koh AOGCC Caelus Energy Alaska Attn: Meredith Guhl 3700 Centerpoint Dr., Suite 500 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ Report ❑ Agreement X Other— Dry samples DETAIL QTY DESCRIPTION Well Name: ODSN-01A (50-703-20648-0100) 3 Boxes of Well Cutting Samples Details on next page Receivedb : Date: Y \,___ Qbelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.koh@caelusenergy.com Well Name: oDSN-01A -- API. — 703-20648-01-00 Legend: Mud types - AFE: 160005 RECEive r 2 16 0 08 MAR 2 4 2016 26 9 8 1 AOGGC CCAIPLUSLETTER OF TRANSMITTAL Energy Alaska DATA LOGGED A/ t /2016) 10 K. BENDER DATE: March 23, 2016 ❑ Maps FROMO TOM Shannon Koh AOGCC Caelus Energy AlaskaAttn: 3700 Centerpoint Dr., Suite 500 Anchorage, AK 99503 Makana Bender 333 W. 7th Avenue, Suite 100 nchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ CD -R ❑ Agreement Other — CD, Logs nFTAn QTY DESCRIPTION Well Name: ODSN-01A (50-703-20648-01-00) 1 CD Digital Graphic Logs, Digital Log Data, Definitive Surveys, Geosteering Data 4 Well Logs ABG, DGR, EWR-Phase 4, ADR, ALD, CTN Inverted/Reverted Intervals (1:240, 1:600) TVD; ROP, ABG, DGR, EWR-Phase 4, ADR, ALD, CTN Horizontal Presentation (1:240, 1:600 MD Received by: �v 6-e4t4Date: Please sign and return one copy to: Caelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.kohCa�caelusenergy.com THE STATE of, --,LAS -K-A- GOVERNOR BILL WALKER Jack Kralick Wells Superintendent Caelus Natural Resources Alaska, LLC 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Re: Oooguruk Field, Nuiqsut Oil Pool, ODSN-O 1 A Permit to Drill Number: 216-008 Sundry Number: 316-194 Dear Mr. Kralick: Alaska Oil and Gas 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. DATEDthis Gf' day of March, 2016. Sincerely, / � r Cathy . Foerster Chair RBDMS MAR 2 5 2016 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 RECEIVED MAR 16 2016 AOG SC 1. Type of Request: Abandon ❑ Plug Perforations ❑ Fracture Stimulate E - 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 Caelus Natural Resources Alaska, LLC, Exploratory ❑ Development 21. Stratigraphic ❑ Service ❑ 216-008 3. Address: 6. API Number: 3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503 50-703-20648-01-00 7. If perforating: 8. Well Name and Number. What Regulation or Conservation Order governs well spacing in this pool? N/A ODSN-01A Will planned perforations require a spacing exception? Yes ❑ No ❑✓ 9. Property Designation (Lease Number): 10. Fieid/Pool(s): ADL 355036 / ADL 389959 Ooo uruk Nuiqsut Oil 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): 18,811' 6,329' 18,440' 6,240' N/A 4,194' NIA Casing Length Size MD TVD Burst Collapse Structural Conductor 110' 16" 158' 158' N/A NIA Surface 4,060' 11-3/4" 4,099' 3,238' 5,830 psi 3,180 psi Intermediate 1 4,017' 9-5/8" 7,940' 5,003' 5,750 psi 3,090 psi Intermediate 2 11,318' 7" 11,354' 6,272' 7,240 psi 5,410 psi Liner 7,432' 4-1/2" 18,440' 6,240' 11,590 psi 9,200 psi Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: Tubing MD (ft): See attachment 2 See attachment 2 4-1/2", 12.6# C 110, Hydlil 521 11,152' Packers and SSSV Type: Packers and SSSV MD (ft) and TVD (ft): See attachment 3 See attachment 3 ' 12. Attachments: Proposal Summary ❑✓ Wellbore schematic 13. Well Class after proposed work: Detailed Operations Program BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for 15. Well Status after proposed work: Commencing Operations: 3/23/2016 OIL ❑� WINJ ❑ WDSPL ❑ Suspended ❑ GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ 16. Verbal Approval. Date: Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approval. Contact Jack Kralick, 343-2185 Email jack.kralickCccaelusener vq, com Printed Name Jack lic Title Wells Superintendent Signature Phone 907-343-2185 Date COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: 316. r qL _Z Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test ❑ Location Clearance ❑ Other: t'd'a--t= � H'w1'+-7 G� Post Initial Injection MIT Req'd? Yes ❑ No ❑ Spacing Exception Required? Yes ❑ No Subsequent Form Required: APPROVED BY Approved by: COMMISSIONER THE COMMISSION Date:– Z� Submit Form and Form 10-403 evise 11/2 5� Approved application is valid for 12 rot r f val Attachments in Duplicate RECEIVED i\�AR 16 20"i CE CAELIJS Alaska AOGCC ODSN-01A Sundry Application Requirements (1) Affidavit of Notice — Attachment A (2) Plat showing well location, as well as'/2 mile radius around well with all well penetrations, fractures, and faults within that radius — Attachment B (3) Identification of freshwater aquifers within'/2 mile radius — no freshwater aquifers in this area (4) Plan for freshwater sampling — no freshwater wells, therefore no sampling planned (5) Detailed casing and cementing information — Attachment C (6) Assessment of casing and cementing operations The ODSN-01A 9-5/8" cement job was pumped with 100% returns during displacement. The subsequent 3,500 psi pressure test was held for 30 min and a 13.3 EMW FIT was achieved below the 9-5/8" shoe. The 7" Intermediate cement job was pumped in 2 stages. The first stage was pumped with 100% returns. The plug was pumped and pressure was applied to 3,375 psi to open the 2nd stage ES -Cementer. The 2nd stage cement job was pumped with 100% returns. A successful 4,000 psi pressure test was held for 30 min and charted. The FIT below the 7" shoe was held to 12.5 EMW. (7) Casing and tubing pressure test information Date Void Tested Pressure Duration Charted 2/27/2016 7" Casing 4000 psi 30 min Yes 4-1/2" Tubing 3500 psi 30 min Yes 3/10/2016 IA Trip Treating IA 4000 psi 30 min Yes (8) Pressure ratings for wellbore, wellhead, BOPE and treating head — Attachment D Pressure Pump Test Held IA IA Trip Treating Pressure PRV GORV Pressure Line IA Test (psi) (psi) (psi) (psi) (psi) Pressure Stages 1-12 3500 3700 9000 8600 9000 4000 (8) Pressure ratings for wellbore, wellhead, BOPE and treating head — Attachment D (9) a — d Lithological and geological descriptions of each zone — Attachment E, Figures 9A, 9B, and 9C e. Estimated fracture pressure for each zone Stage MD Perf Depth (feet) ND Perf Depth (feet) Max Propped Height (feet) Frac 1/2 Length (feet) Max Rate (bpm) Max Surface Pressure (psi) Max Prop Conc (ppa) 1 18778 6330 84 150 40 7270 8.0 2 18401 6238 93 335 40 8660 8.0 3 17740 6209 98 468 40 8670 8.0 4 17081 62121 98 467 40 8500 8.0 5 16422 6216 99 409 401 8460 10.0 6 15763 6217 101 441 40 8150 10.0 7 15104 6223 99 409 40 7760 10.0 8 14445 6229 99 364 40 7580 12.0 9 13786 6245 99 411 40 7240 10.0 10 13127 6265 99 411 40 6940 10.0 11 12469 6275 95 357 40 6680 12.0 121 11810 6275 981 358 40 6350 12.0 *These depths are preliminary locations. Final depths will be shifted, but will not affect modeling results. (10) Mechanical condition of wells transecting the confining zones - Attachment F (11) Location of faults and fractures in wellbore % mile radius — Attachment E, Figure 11 (12) Detailed proposed fracturing program - Attachments G and H (13) Flowback procedure —Attachment I Section (b) We will not be treating through production or intermediate casing strings Section (c) Attachment I and below: ODSN-01A 10-403 Sundry App. For Fracture Stimulation March 14, 2016 Page 2 of 3 SLICKLINE PROCEDURES Pre Fracture Stimulation - Slickline Program: 1. Record Tubing, IA, and OA pressures. Record BHP and Temp. Note on Wellview Report. 2. Complete well handover form from Operations to Wells Group. 3. Conduct a pre -job safety meeting with HES, Wells Group Supervisor, and all personnel involved in the job scope. 4. MIRU HES Combo Unit w/.125 wire. Hang load cell, and necessary sheaves. 5. Pick up lubricator, toolstring, and 3.83" gauge ring. 6. Make up lubricator to wellhead and pressure test as per HES policy & procedure. (1.5 times expected WH pressure) 7. RIH w/ 3.83" gauge ring to "XXO" SVLN @ 2186' MD. 8. RIH w/4.5 GS to 4.5" FXE SSSV in SVLN @ 2,186' MD. 9. LRS to load tubing w/ 156 bbls to XN nipple @ 10,320' MD. (Slick) water below with freeze protect (slick) diesel to 2500' TVD 10. RIH w/3.80" gauge ring (3/4" Internal SR), 2' weight bar, and 4.5 BLB to XN nipple @ 10,320' MD. 11. Make up HES DPU w/4.5 Evo-Trieve RBP. Set travel & still time as per HES recommendation. Or move to step 12. 12. Set a XXN plug in XN nipple at 10,320' if conditions allow. 13. RIH to pull SOV at 2761'— POOH 14. RIH to set DV at 2761'- POOH 15. Perform MIT -T to 6050 psi for 30 minutes. Record results in Wellview Report. Bleed tubing pressure to zero. 16. Perform MIT -IA to 4000 psi for 30 minutes. Record results in Wellview Report. Bleed IA to zero. 17. Report MIT results to Anchorage team before proceeding w/program. 18. Pull XXN plug @ 10300' with GR pulling tool 19. RIH w/ 4-1/2" GS & 4.5" Frac Isolation Sleeve (3.12" ID) to "XXO" SVLN @ 2,186' MD. Drop 3.009" ball through sleeve with witnesses on the surface prior to RIH 20. Pressure test control line to 4500 psi to verify control line integrity. 21. RIH w/KJ, 2' weight bar, and 3.00" Swage to as deep as possible to verify tubing is free of any obstructions. Note final depth in Wellview report. 22. RDMO HES Slickline. Well ready for frac. Section (d) High Pressure Line Pressure Relief Valve (PRV) Rig Up — Attachment J Final Wellbore Schematic — Attachment K ODSN-01A 10-403 Sundry App. For Fracture Stimulation March 14, 2016 Page 3 of 3 Top MD Bottom(MD) Length(ft) To TVD Bottom (TVD) 4-1/2" RapidStage Sleeve #11 11,618 11,621 2.71 6,288 6,289 4-1/2" RapidStage Sleeve #10 12,271 12,274 2.71 6,282 6,282 4-1/2" RapidStage Sleeve #9 12,841 12,844 2.71 6,272 6,272 4-1/2" RapidStage Sleeve #8 13,495 13,498 2.71 6,262 6,262 4-1/2" RapidStage Sleeve #7 14,144 14,147 2.71 6,247 6,247 4-1/2" RapidStage Sleeve #6 14,711 14,714 2.71 6,230 6,230 4-1/2" RapidStage Sleeve #5 15,321 15,324 2.71 6,224 6,224 4-1/2" RapidStage Sleeve #4 15,967 15,970 2.71 6,216 6,216 4-1/2" RapidStage Sleeve #3 16,786 16,789 2.71 6,218 6,218 4-1/2" RapidStage Sleeve #2 17,399 17,402 2.71 6,214 6,214 4-1/2" RapidStage Sleeve #1 18,255 18,258 2.71 6,223 6,223 Pre -Perforated Pup 18,420 18,425 4.69 6,237 6,237 Pre -Perforated Pup 18,424 18,429 4.69 6,238 6,238 Attachment 3 AOGCC Form 10-403 Application for Sundry Box 11- Packers & SSSV Well: ODSN-01A SSSV MD TVD 4-1/2" Halliburton 'XXO' SVLN 2,186' 2,048' PACKERS 5" x 7" Baker ZXP Liner Top Packer 11,119' 6,251' HES Swell Packer #13 11,404' 6,276' HES Swell Packer #12 11,444' 6,280' HES Swell Packer #11 11,891' 6,286' HES Swell Packer #10 12,422' 6,280' HES Swell Packer #9 13,199' 6,266' HES Swell Packer #8 13,850' 6,253' HES Swell Packer #7 14,378' 6,240' HES Swell Packer #6 14,945' 6,229' HES Swell Packer #5 15,631' 6,219' HES Swell Packer #4 16,367' 6,221' HES Swell Packer #3 17,102' 6,216' HES Swell Packer #2 17,672' 6,211' HES Swell Packer #1 18,366' 6,231' CE CS Ataska Mr. Guy Schwartz AOGCC - PE Re: ODSN-01A PTD: 216-008 Dear Mr. Schwartz, Caelus Energy Alaska would like to request a variance to the pressure testing guidelines for the ODSN- 01a tubing pressure test pre -frac. The area that is not exposed to the internal tubing pressure test is from the 'XN' nipple @ 10320' MD where the pressure test plug will be set, to the top of the linertop seals @ 11119' MD. We believe that a test from the 'XN' to the surface would give us the confidence that the lower untested section would also pass the test. In summary we would like to request the variance for the internal tubing pressure test for the area from 10320' MD to 11119' MD. The Inner Annulus (MITIA) will be tested to 4000 psi. Actual pressure held during the job on the IA will be 3500 psi with the IA Pressure Relief Valve set at 3700 psi. The high pressure treating line will be tested to 9000 psi. With the GORY set at 9000 psi the maximum pressure seen during the HPBD job will be 8600 psi (pump trip pressure) the calculation is: (9000-3500) *1.1 = 6050 psi on the internal tubing test. The casing from surface to the permanent packer @ 11119' will be tested externally by the MITIA pressure test to 4000 psi. Sincerely, Jack Kralick Caelus Wells Superintendent 907 343-2185 office AFFIDAVIT STATE OF ALASKA ) ) ss. THIRD JUDICIAL DISTRICT ) Rachel Davis, being duly sworn, states: 1. That I am the Engineering Technician for Caelus Natural Resources Alaska, LLC, ("Caelus"), Operator of the Oooguruk Unit, with offices at 3700 Centerpoint Dr., Suite 500, Anchorage, Alaska, 99503, and am acquainted with the facts associated with the drilling of the ODSN-01A well ("Well"). 2. That all owners, landowners, surface owners, and operators within one-half mile radius of the current wellbore trajectory have been provided a Notice of Operations that is in compliance with the requirements of 20 AAC 25.283. A copy of the notice is attached hereto. 3. 1 have reviewed the Application for Sundry Approvals for the proposal that the Well be stimulated by hydraulic fracturing as defined 20 AAC 25.283 (m). 4. On March 14, 2016, pursuant to 20 AAC 25.283 (1) Caelus sent a copy of the Notice Letter by electronic mail to the last known address of all owners, landowners, surface owners and operators within a one half mile radius of the current proposed trajectory providing Caelus' contact information and stating that upon request Caelus will make a complete copy of the application available. These names and addresses are set forth on Attachment A attached to Caelus' Application for Sundry Approvals under 20 AAC 25.283 dated March 14, 2016. I, Rachel Davis, swear under penalty of perjury that to the best or my knowledge and belief that the foregoing is true. Rachel Davis, Engineering Technician THIS IS TO CERTIFY that on the 14"� day of M Oar C-" , 2016, at Anchorage, Alaska before me, a notary public in and for the State of Alaska, duly commissioned and sworn as such, personally appeared Rachel Davis, known to be the individual named herein, who acknowledged to me that she executed the foregoing instrument freely and voluntarily for the uses and purposes mentioned therein, and that the same was her act. IN WITNESS WHEREOF I have hereunto set my hand and official seal on the day and year above written. Npfary Public in and for Alaska Not,: P. JEAN ; , C!�'." HELL ste,e o, - �a My Comm— on F � Jul 21. 2019 My commission expires: I Z ATTACHMENT A From: Rachel Davis To: "DNR. Notifications (a)alas ka.00v"; robert.provinceaenioetroleum.com Cc: Dale Hoffman Subject: CNRA, LLC ODSN-01A Notice of Upcoming Operations Date: Monday, March 14, 2016 1:54:00 PM RE: ODSN-01A AOGCC API 50-703-20648-01-00 Oooguruk Unit—Tracts 13 and 17 Lease Numbers ADL 355036 and ADL 389959 Pursuant to the requirements set forth by 20 AAC 25.283, 1 am hereby notifying you that Caelus Natural Resources Alaska, LLC plans to commence operations to perform a Fracture Stimulation on ODSN-01A beginning March 24, 2016. If you would like to review the complete AOGCC 10-403 Sundry Application for these operations, please contact me at the address below, or via a return email. Please also respond if you do not want to be included on the distribution of this notice for additional activities. Thanks, Rat_� F,>aN-E,y Engineering Technician Caelus Energy Alaska LLC 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Direct: 907-343-2159 rachel.davisftcaelusenergy.com ATTACHMENT A ODSN 3 OD - N-07 ODS N-04 I o } T14NR7E OCA T NR$E C DSN-01AODSN-2 i ODS -01• ODSN- $ ODSN- 9i ( ODSN-27i • ODSN-24 ODS ODSN-31 MIN v ODSN-10i 4k 0 h c k ODSN Q41---. —jL \ r Q, ODSN-161-1 ODS ODSN-16 ODS \DSN-' 1 N1 I _ T7r3N)i7E ---0 ODSN-40 45i ODS 42B • ODSN- !_._._ ODS 17 • ODSN-171-1 8 } S N-06 i CAELL S Alaska 2016 ODS Target Stimulation Program 0 0.25 0.5 1 Miles A"1'TACHMENT B Casing &Cement Well Name: ODSN-01A CG C AE- LU S 1 Atas'ka For String: Surface Casing Detail: Casing Description Surface Run Date 1/20/2012 02:00 Set Depth (ftKB) 4,099.0 WellboreCentralizers Original Hole 67 Scratchers Proposed Run? No Casing Components Joints 1 Item Description Hanger Icon Casing hanger OD Nominal (in) 11 3/4 ID (in) 10.772 Wt (Ib/ft) 60.00 Grade L-80 Top Thread Length (ft) 1.28 Top Depth (ftKB) 38.9 Bottom Depth (ftKB) 40.2 Joints 1 Item Description Hanger Pup Icon Casing (black) OD Nominal (in) 11 3/4 ID (in) 10.772 Wt (Ib/ft) 60.00 Grade L-80 Top Thread Length (ft) 2.12 Top Depth (ftKB) 40.2 Bottom Depth (ftKB) 42.3 Joints 12 Item Description Casing Icon Casing (black) OD Nominal (in) 11 3/4 ID (in) 10.772 Wt (Ib/ft) 60.00 Grade L-80 Top Thread Hydril 521 Length (ft) 492.60 Top Depth (ftKB) 42.3 Bottom Depth (ftKB) 534.9 Joints 1 Item Description Tamm Port Collar Icon Float collar OD Nominal (in) 11 3/4 ID (in) 10.772 Wt (Ib/ft) 60.00 Grade L-80 Top Thread Length (ft) 1.88 Top Depth (ftKB) 534.9 Bottom Depth (ftKB) 536.8 Joints 1 Item Description PxP Pup Icon Casing (black) OD Nominal (in) 11 3/4 ID (in) 10.772 Wt (Ib/ft) 60.00 Grade L-80 Top Thread Length (ft) 1.12 Top Depth (ftKB) 536.8 Bottom Depth (ftKB) 537.9 Joints 88 Item Description Casing Icon Casing (black) OD Nominal (in) 113/4 ID (in) 10.772 Wt (Ib/ft) 60.00 Grade L-80 Top Thread Hydril 521 Length (ft) 3,539.13 Top Depth (ftKB) 537.9 Bottom Depth (ftKB) 4,077.0 Joints 1 Item Description Baker Whipstock I Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (1)1 22.00 Top Depth (ftKB) 4,077.0 Bottom Depth (ftKB) 4,099.0 Leak Off and Formation Integrity Tests Test Date 2/6/2016 Depth (ftKB)P 4,119.0 Surf Applied (psi) 388.0 Dens Fluid (I... 10.20 Leak off? No Vol Pumped (.. Last Casing String Run Surface, 4,099.OftKB P LeakOff (psi) 2,108.4 Dens Fluid (I... 12.50 Comment 12.5 ppg EMW - good test. Test Date 2/15/2016 Depth (ftKB)P 7,940.0 Surf Applied (psi) 819.0 Dens Fluid (I... 10.20 Leak off? No Vol Pumped (.. 3.01 Last Casing String Run Intermediate #1, 7,940.0ftK6 P LeakOff (psi) 3,469.9 Dens Fluid (I... 13.35 Comment 13.3 ppg EMW - good test. Test Date 2/29/2016 Depth (ftKB) 11,354.0 P Surf Applied (psi) 1,474.0 Dens Fluid (I... 8.00 Leak off? No Vol Pumped (.. 2.2 Last Casing String Run Intermediate #2, 11,354.0ftK6 P LeakOff (psi) 1 4,080.3 Dens Fluid (I... 12.52 Comment 12.5 ppg EMW - good test. Cementing Job Details: Description Type String Wellbore Cementing Start Date Cementing End Date Cementing Company Comment Cement Stage#<Stage Number?> Description: Stage Number Top Depth (ftKB) Bottom Depth (ftKB) Cement Volume Return (bbl) Float Failed? Plug Failed? Full Return? Pipe Reciprocated? Pressure Held (psi) Top Plug? Bottom Plug? Initial Pump Rate (bblhnin) Final Pump Rate (bbl/min) Avg Pump Rate (bbl/min) Final Pump Pressure (psi) Plug Bump Pressure (psi) Pressure Release Date <Fluid Type?> Fluid Details for Stage#<Stage Number?>: Fluid Type Fluid Description Amount(sacks) Class Volume Pumped (bbl) Estimated Top (fIKB) Estimated Bottom Depth (ftKB) Yield (W/sack) Mix H2O Ratio (gal/sack) Free Water r/6) Density (Ib/gal) Plastic Viscosity (cp) Thickening Time (hr) 1st Compressive Strength (psi) Comment Additive Details Add Conc Conc Units Page 1/1 ReportPrinted: 3/14/2016 I ATTACHMENT C CE CAELUS Ener,y Alaska Casing & Cement Well Name: ODSN-01A For String: Intermediate #1 Casing Detail: Casing Description Run Date Set Depth (ftKB) Wellbore Centralizers Scratchers Proposed Run? Intermediate #1 2/14/2016 02:00 7,940.0 Original Hole 3 No Casing Components Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth(ftKB) 1 Baker "HRD-E" In -Line Liner hanger 10.44 8.535 40.00 L-80 Hydril 521 19.43 3,923.4 3,942.9 Liner Hanger Packer Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Baker Seal Bore Cross- Liner hanger 9.99 8.535 40.00 L-80 Hydril 521 13.31 3,942.9 3,956.2 Over Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 97 Casing Joints Casing 95/8 8.835 40.00 L-80 Hydril 521 3,856.42 3,956.2 7,812.6 (black) Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Mandrel w/ bowspring Casing (red) 9.66 40.00 L-80 Hydril 521 3.44 7,812.6 7,816.0 centralizer removed Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Baker Landing Collar Casing shoe 9.97 40.00 L-80 Hydril 521 1.51 7,816.0 7,817.5 Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Casing Joints w/ 10.4375" Casing 95/8 8.835 40.00 L-80 Hydril 521 38.95 7,817.5 7,856.5 rigid centralizer (black) Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Halliburton Float Collar Float collar 9.97 40.00 L-80 Hydril 521 1.33 7,856.5 7,857.8 Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 2 Casing Joints w/ 10.4375" Casing 95/8 8.835 40.00 L-80 Hydril 521 79.43 7,857.8 7,937.3 rigid centralizer (black) Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB)- 1 Halliburton Eccentric Casing shoe 9.98 40.00 L-80 I Hydril 521 2.75 7,937.3 7,940.0 Composite Float Shoe Leak Off and Formation Integrity Tests Test Date Depth (ftKB)P Surf Applied (psi) Dens Fluid (I... Leak off? Vol Pumped (.. Last Casing String Run P LeakOff (psi) Dens Fluid (I... 2/6/2016 4,119.0 388.0 1 10.20 No Surface, 4,099.0ftKB 2,108.41 12.50 Comment 12.5 ppg EMW - good test. Test Date Depth (ftKB)P Surf Applied (psi) Dens Fluid (I... Leak off? Vol Pumped (.. Last Casing String Run P LeakOff (psi) Dens Fluid (I... 2/15/2016 7,940.0 819.0 10.20 No 3.0 Intermediate #1, 7,940.0ftKB 1 3,469.9 13.35 Comment 13.3 ppg EMW - good test. Test Date Depth (ftKB)P Surf Applied (psi) Dens Fluid (I... Leak off? Vol Pumped (.. Last Casing String Run P LeakOff (psi) Dens Fluid (I... 2/29/2016 11,354.0 1,474.0 8.00 No 2.2 Intermediate #2, 11,354.0ftKB 4,080.31 12.52 Comment 12.5 ppg EMW - good test. Cementing Job Details: Description Type String Wellbore Intermediate #1 Liner Cement Casing Intermediate #1, 7,940.0ftKB Original Hole Cementing Start Date Cementing End Date Cementing Company 2/24/2016 13:00 2/24/2016 16:20 Halliburton Energy Services Comment No losses during cement job. Cement Stage#1 Description: Stage Number Top Depth (ftKB) Bottom Depth (ftKB) Cement Volume Return (bbl) 1 Float Failed? Plug Failed? Full Rehm? Pipe Reciprocated? Pressure Held (psi) No No Yes No Top Plug? Bottom Plug? Initial Pump Rate (bbVmin) Final Pump Rate (bbl/min) Yes No 4 4 Avg Pump Rate (bbl/min) Final Pump Pressure (psi) Plug Bump Pressure (psi) Pressure Release Date 2/13/2016 Tuned Spacer III Fluid Details for Stage#1 Fluid Type Fluid Description Amount(sacks) Class Volume Pumped (bbl) Tuned Spacer III Tuned Spacer III Spacer 60.0 Estimated Top (WB) Estimated Bottom Depth (ftKB) Yield (ft' /sack) Mix H2O Ratio (gallsack) Free Water(% ) 5.31 Density (Ib/gal)Plastic Viscosity (cp) Thickening Time (hr) 1st Compressive Strength (psi)11.00 Comment Additive Details Add Conc Conc Units D -Air 5000 0.5 lbs/bbl Page 1/2 ReportPrinted: 3/14/2016 I ATTACHMENT C CE CAELUS t -Tv Alaska Casing & Cement DSN-01A For String: Intermediate #1 Additive Details Add Conc Conc Units SEM -8 0.7 gal/bbl Musol A 0.7 gal/bbl Tuned Spacer III 38.0 Ibs/bbl Barite 106.848 lbs/bbl Cement Fluid Details for Stage#1 Fluid Type Cement Fluid Description Premium G Cement Amount (sacks)Class 197 Class G Volume Pumped (bbl) 42.0 Estimated Top (fl<B) Estimated Bottom Depth (ftKB) Yield (ft'/sack) 1.17 Mix H2O Ratio (gal/sack) 5.10 Free Water (% ) Density (Ib/gal) 15.80 Plasfic Viscosity (cp) 81.7 Thickening Time (hr) 4.52 1st Compressive Strength (psi) 500.0 Comment Additive Details Add Conc Conc Units Class G 100.0 %BWOC CFR -3 0.2 %BWOC Halad 344 0.5 %BWOC Haled 344 0.15 %BWOC SCR -100 0.3 %BWOC Flush Fluid Details for Stage#1 Fluid Type Flush Fluid Description Amount(sacks) Class Seawater Volume Pumped (bbl) 20.0 Estimated Top (fLKB) Estimated Bottom Depth (ftKB) Yield (ft' /sack) Mix H2O Ratio (gal/sack) Free Water (% ) Density (Ib/gal) Plastic Viscosity (cp) Thickening Time (hr) 1st Compressive Strength (psi)8.40 Comment ATTACHMENT C CG ELU Energy Alaska Casing & Cement Well Name: For String: Intermediate #2 Casing Detail: Casing Description Run Date Set Depth (ftKB) Wellbore Centralizers Scratchers Proposed Run? Intermediate 42 2/24/2016 09:30 11,354.0 Original Hole 99 No Casing Components Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Casing Hanger Casing 101/4 6.688 26.00 L-80 0.75 36.5 37.2 hanger Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Casing Pup Joint on Casing (red) 7 6.276 26.00 L-80 Hydril 563 3.55 37.2 40.8 Hanger Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 215 Casing Joints Casing 7 6.276 26.00 L-80 Hydril 563 8,585.92 40.8 8,626.7 (black) Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Casing Pup Joint Casing (red) 7 6.276 26.00 L-80 Hydril 563 5.29 8,626.7 8,632.0 Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Halliburton ES Cementer 81/4 6.171 26.00 L-80 Hydril 563 3.42 8,632.0 8,635.4 Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 64 Casing Joints Casing 7 6.276 26.00 L-80 Hydril 563 2,551.29 8,635.4 11,186.7 (black) Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Halliburton Baffle Adapter Casing 75/8 6.250 26.00 L-80 Hydril 563 2.11 11,186.7 11,188.8 (black) Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 2 Casing Joints Casing 7 6.276 26.00 L-80 Hydril 563 79.49 11,188.8 11,268.3 (black) Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Halliburton Float Collar Float collar 71 6.276 26.00 L-80 Hydril 563 2.54 11,268.3 11,270.8 Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 2 Casing Joints Casing 7 6.276 26.00 L-80 Hydril 563 80.39 11,270.8 11,351.2 (black) Joints Item Description Icon OD Nominal (in) ID (in) Wt (Ib/ft) Grade Top Thread Length (ft) Top Depth (ftKB) Bottom Depth (ftKB) 1 Halliburton Eccentric Float I Casing shoe 7.67 6.276 26.00 L-80 Hydril 563 2.78 11,351.2 11,354.0 Shoe Leak Off and Formation Integrity Tests Test Date Depth (ftKB)P Surf Applied (psi) Dens Fluid (I... Leak off? Vol Pumped (.. Last Casing String Run P LeakOff (psi) Dens Fluid (I... 2/6/2016 4,119.0 388.0 10.20 No Surface, 4,099.0ftKB 2,108.4 12.50 Comment 12.5 ppg EMW - good test. Test Date Depth (ftKB)P Surf Applied (psi) Dens Fluid (I... Leak off? Vol Pumped (.. Last Casing String Run P LeakOff (psi) Dens Fluid (I... 2/15/2016 7,940.0 819.0 10.20 No 3.0 Intermediate #1, 7,940.0ftKB 3,469.9 13.35 Comment 13.3 ppg EMW - good test. Test Date Depth (ftKB)P Surf Applied (psi) Dens Fluid (I... Leak off? Vol Pumped (.. Last Casing String Run P LeakOff (psi) Dens Fluid (I... 2/29/2016 11,354.0 1,474.0 8.00 No 1 2.2 Intermediate #2, 11,354.OftKB 4,080.3 12.52 Comment 12.5 ppg EMW - good test. Cementing Job Details: Description Type String Wellbore Intermediate #2 Casing Cement Casing Intermediate #2, 11,354.OftKB Original Hole Cementing Start Date Cementing End Date Cementing Company 2/24/2016 22:00 2/25/2016 00:22 Halliburton Energy Services Comment No losses during 1st stage or 2nd stage. Cement Stage#1 Description: Stage Number Top Depth (ftKB) Bottom Depth (ftKB) Cement Volume Return (bbl) 1 9,906.0 11,362.0 0.0 Float Failed? Plug Failed? Full Return? Pipe Reciprocated? Pressure Held (psi) No No Yes No 2,000.0 Top Plug? Bottom Plug? Initial Pump Rale (bbrmin) Final Pump Rate (bbl/min) Yes Yes 5 4 Avg Pump Rate (bbl/min) Final Pump Pressure (psi) Plug Bump Pressure (psi) Pressure Release Date 41 1,370.0 2,000.0 2/24/2016 Spacer Fluid Details for Stage#1 Fluid Type Fluid Description Amount(sacks) Class Volume Pumped (bbl) Spacer Spacer 55.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Yield (W/sack) Mix H2O Ratio (gal/sack) Free Water I%) Density (Ib/gal) Plastic Viscosity (cp) Thickening Time (hr) 1st Compressive Strength (psi) 11.50 Comment Page 1/3 ReportPrinted: 3/14/2016 ATTACHMENT C CG CAELUS nel-Fy A(aska Casing 8, Cement Well Name: ODSN-01A For String: Intermediate #2 Additive Details Add Conc Conc Units D -Air 5000 0.5 lbs/bbl SEM -8 0.4 gal/bbl Tuned Spacer III 40.0 lbs/bbl Dual Spacer Surfactant B 0.4 gal/bbl Barite 132.0 lbs/bbl Tail Cmt Fluid Details for Stage#1 Fluid Type Tail Cmt Fluid Description Tail - Class G Cement Amount(sacks) 419 Class Class G Volume Pumped (bbl) 117.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Yield (ft'/sack) 1.17 Mix H2O Ratio (gal/sack) 5.08 Free Water (%) Density (Ib/gal) Density Plastic Viscosity (cp) 91.5 Thickening Time (hr) 7.00 1st Compressive Strength (p 500.0 Comment Full returns & bumped plug. Additive Details Add Conc Conic units Class G 100.0 %BWOC CFR -3 0.2 %BWOC Halad 344 0.5 %BWOC Halad 344 0.15 %BWOC SCR -100 0.45 %BWOC Spacer Fluid Details for Stage#1 Fluid Type Spacer Fluid Description Amount(sacks) Class Volume Pumped (bbl) 1 20.0 Estimated Top (fIKB) Estimated Bottom Depth (ftKB) Yield (ft' /sack) Mix H2O Ratio (gal/sack) Free Water (% ) Density (Ib/gal) 8.50 Plastic Viscosity (cp) Thickening Time (hr) 1st Compressive Strength (psi) Comment Additive Details Add Conic Conc units Dsplmt Fluid Details for Stage#1 Fluid Type Dsplmt Fluid Description Amount(sacks) Class Volume Pumped (bbl) 562.0 Estimated Top (ftKB) Estimated Bottom Depth (ftKB) Yield (ft'/sack) Mix H2O Ratio (gal/sack) Free Water (% ) Density (Ib/gal) 10.20 Plastic Viscosity (cp) Thickening Time (hr) 1st Compressive Strength (psi) Comment Additive Details Add Conc Conc Units Cement Stage#2 Description: Stage Number 2 Top Depth (ftKB) 7,480.0 Bottom Depth (ftKB) 8,632.0 Cement Volume Return (bbl) 0.0 Float Failed? No Plug Failed? No Full Return? Yes Pipe Reciprocated? No Pressure Held (psi) 2,439.0 Top Plug? Yes Bottom Plug? Yes Initial Pump Rate (bbVmin) 4 Final Pump Rate (bbl/min) 4 Avg Pump Rate (bbl/min) 41 Final Pump Pressure (psi) 900.01 Plug Bump Pressure (psi) 2,365.0 Pressure Release Date 2/25/2016 Page 2/3 ReportPrinted: 3/14/2016 ATTACHMENT C CE CAELUS Alaska Casing & Cement Well Name: ODSN-01A For String: Intermediate #2 Spacer Fluid Details for Stage#2 : Fluid Type Spacer Fluid Description Spacer Amount (sacks) 0 Class Volume Pumped (bbl) 55.0 Estimated Top (fIKB) Estimated Bottom Depth (ftKB) Yield (ft'/sack) Mix H2O Ratio (gal/sack) Free Water (% ) Density (Ib/gal) 11.50 Plastic Viscosity (cp) Thickening Time (hr) 1st Compressive Strength (psi) Comment Additive Details Add Conc Conc Units D -Air 5000 0.5 Ibs/bbl SEM -8 0.7 gal/bbl Musol A 0.7 gal/bbl Tuned Spacer III 38.0 Ibs/bbl Barite 106.848 Ibs/bbl Lead Cmt Fluid Details for Stage#2 Fluid Type Lead Cmt Fluid Description Tail - Class G Cement Amount (sacks)Class 275 Class G Volume Pumped (bbl) 66.0 Estimated Top (f[KB) I Estimated Bottom Depth (ftKB) I Yield (ft' /sack) Mix H2O Ratio (aal/sack) I Free Water(%) ATTACHMENT C 0 G Oil & Gas This drawing Is Ne property of GE Oil 8 Gas Pressure Conbal LP antl is considered contltlentlalAnless oNenvise approved In wdtlng, I CAELUS newernnprdsee-M11ynepeed.pppie,--road«rep,deeed —pt f ft sae p-— fGEOil aGasPreaepreCpnb1 OoogurukFRAC DRAWNGR 17 MB -233 Conventional Multibowl Assembly, 'PPF KN 17 With MB -233 4-1/2" Tubing Hanger, I FOR REFERENCE ONLY With 4-1/16" 10M x 4-1/16" 10M Spacer Spool I DRAWING NO. HP150203 KALUBIK-1 0 NA SS There are three reservoirs (pools) being developed in the ODS area, Albian Nuna turbidites, Hauterivian Kup C transgressive marine sands, and Oxfordian Nuiqsut lower shoreface sands. The primary reservoir is the Nuiqsut and is the target of this fracture stimulation application. Fracture stimulation modeling suggests that the expected fracture height is on the order of 75' to 100' and that 10' of shale will limit vertical fracture growth. There are significant shales above and below the Nuiqsut that effectively limit fracture stimulation to within the Nuiqsut pool. The Nuiqsut varies in thickness from 50-150' in the development area and is subdivided into a number of zones which are named from top to base as Nuiqsut 1 (30-40'of sand), Nuiqsut 2 (2-10' of silt and shale), Nuiqsut 3 (5-15' of sand), Nuiqsut 4 (4-10' of silt and shale), Nuiqsut 5d (15-35' of sand), Nuiqsut 5a (0-30' of sand, silt and shale) . Most of the Nuiqsut horizontals target the Nuiqsut 1 zone. Underlying the Nuiqsut reservoir is the 7-15' Nuiqsut shale which modeling indicates limits ksh downward growth of the fracture stimulation. Below this is the Nechelik which consists of 30-60' of nonreservoir sand, silt and shale. Below the Nechelik are thick Lower Kingak marine shales. HRZ Above the Nuiqsut are two confining shales which isolate the Nuiqsut fracture from the sh Kuparuk and an additional three confining shales isolating it from the Nuna Torok Pool. Two _HRZ erosional events , the Base Cretaceous Unconformity (BCU) and Lower Cretaceous bik sh Unconformity (LCU) controls the thickness of the specific overlying shales for any given Nuiqsut lateral. The Upper Kingak marine shale varies in thickness from 0-150' depending on BCU erosion, while the Milluveach marine shale varies from 0-150' thick depending on LCU erosion. Overlying the LCU is typically about 175' of Kalubik marine shale, —150' of HRZ high iveach' organic shale (hot GR), and 250-300' of Torok basinal marine shale. QS Upr1 To -date there is no evidence that hydraulic fracturing or sustained injection pressures above 1-5 parting pressure in the Nuiqsut wells have developed pathways through the confining layers. ;HELIK The average bottomhole fracturing pressure of 4,700 psi is well below the sustained average elik injection well bottomhole pressure of 5,500 psi; additionally, the fracture treatment is of very short duration compared to the years of injection at 5,500 psi. In the process of drilling ask Lwr 35 development wells (Kuparuk and Nuiqsut) and conducting 253 Nuiqsut hydraulic fracturing treatments, no anomalous reservoir pressure or fracture performance data have been observed that would indicate vertical communication between the Nuiqsut and overlying stratigraphic intervals outside the pool, even in areas with faulting. ATTACHMENT E: Figure 9A N01A Formation Tops Formation Top HRZ Top Kalubik shale Kup C LCU/Top Milluveach shale BCU/Top Kingak shale Top Nuiqsut Base Nuiqsut/Top Nuiq shale M TVD FTVDSS 9770 5845 -5789 10060 5979 -5923 10402 6121 -6065 10453 6138 -6082 10916 6233 -6177 11258 6263 -6207 —18800 6326 --6270 ATTACHMENT E: Table 9B NW Frac modeling suggests 84-101' propped frac height N01A frac SE 7000 8000 9000 16000 11000 12000 13000 14000 15000 16000 on—SN 0 i .R�t4 1 i 0 � r 5900 HRZ Shale 7 0 -60001 Kalubik Shale 3 r Kup C Kalubik Shale 0 LCU -6100' Miluveach Shale i •�: _ LCU BCU Nuiqsut 1 su 0 Upper Kingak Sh le D +37as gsut 3 riD;!eaor Nuiqsut Sd -6200 D r '0 - 2469 Max Nuiqsut 5 MD Perf TVD Perf Propped Depth Depth Height NID 18778 Stage (feet) (feet) (feet) Nechelik Upr non -reservoir 1 18778 6330 84 -6300 2 18401 6238 93 _ _.._....... __....__- 3 17740 6209 98 4 17081 6212 98 5 16422 6216 99 6 157631 6217 101 7 1.5104 6223 99 -6400 8 14445 6229 99 9 13786 6245 99 10 13127 626.5 99 9000 10000 11000 12000 13000 14000 15000 16000 11 12469 6275 95 12 118101 6275 98 ATTACHMENT E: Figure 9C Max MD Perf ND Perf Propped Frac 1/2 DepthDepth Height Length (feet) (feet) (feet) (feet) 1 18778 6330 84 1501 tt,� 2 18401 6238 93 3351�� 3 17740 6209 98 4681 4 17081 6212 98 4671 �•���. 5 16422 6216 99 4091 6 15763 6217 101 441 7 15104 6223 99 409;' ti\` 8 14445 6229 99 364,E \_ 9 13786 6245 99 4111 ti 10 13127 6265 991 411 11 12469 6275 95 3571 12 11810 6275 98 3581 I Ar 4 N25 `a * tv261 0 N a > a 119iTQ 2 i N01A frac Estimated half length for N01A fracs are 150- 470'. The minimum stress field is perpendicular to the well bore orientation and the fracs are assumed to be primarily longitudinal along the " well -bore. There is a fault (F-A)intersected in the N19 well y that appears to die out about 450' from the N01A Stage 1. There is also a seismic fault (F -B) `- that parallels the N01 lateral near the heel. These faults are not considered to be a leak -� point for the Nuiqsut pool because: 1) there were no losses when fault F -A was s, drilled in the N19i and N1913132 wells where there is about 40' of offset. 2) Fault F -B did not seem to effect the drilling or fracking of N01 �•' 3) in the process of drilling 35 development Jt?f wells (Kuparuk and Nuiqsut) and X conducting 253 Nuiqsut hydraulic ra2� fracturing treatments, no anomalous } reservoir pressure or fracture performance �� data have been observed that would N 24 ''� �n. indicate vertical communication between z ��, t ;� � ,, � -• . the Nuiqsut and overlying stratigraphic intervals outside the pool, even in areas ` with faulting. s The N01A lateral is about 500' from the N01 lateral. Any frac leakage from N01A into N01 would still be confined within the Nuiqsut pool �`IN •N34i�\ because the N01 has been effectively abandoned and isolated. r r 0 raaar ■r ATTACHMENT E: Figure 11 Caelus Natural Resources Alaska, LLC CASING & CEMENTING REPORT Lease & Well No. ODSN-19i County USA State Alaska Supv. CASING RECORD -7 " Intermediate 2 casing TO 12,427' MD / 6,290' TVD Shoe Depth: 12,416' MD / 6,289' TVD PBTD: Date August 22, 2014 Rod Kelpzig 12,266',MD / 6,266',TVD Csg Wt. On Hook: 80,000 Type Float Collar: N-o.of-Jts. Size wt. Grade • Make LengthC'®®" Csg Wt. On Slips: N/A Type of Shoe: HdEcc.M,I, .,p..u. Casing Crew: Tesco Fluid Description: 10.2 LSND WBM Liner hanger Info (Make/Model): NIA Liner top Packer?: _Yes X No Liner hanger test pressure: N/A Csg Wt. On Hook: 80,000 Type Float Collar: Haliburton SSII No. Hrs to Run: 40.8 Csg Wt. On Slips: N/A Type of Shoe: HdEcc.M,I, .,p..u. Casing Crew: Tesco Fluid Description: 10.2 LSND WBM Liner hanger Info (Make/Model): NIA Liner top Packer?: _Yes X No Liner hanger test pressure: N/A Centralizer Placement: 1 Solid body Centralizer floating at 11jt onjts 1-47 —500' MD above Kuparuk CEMENTING REPORT Preflush (Spacer) Type: Tuned Spacer III Density (ppg) 12.5 Volume pumped (BBLs) 50 Lead Slurry Type: Premium G Yield (Ft3/sack): 1.17culft.per sack Density (ppg) 15.8 Volume (BBLs/sacks): 1121526 Mixing / Pumping Rate (bpm): 3.5 Tail Slurry Type: Yield (Ft3/sack): 0� Density (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): a y Post Flush (Spacer) y Type: Seawater Density (ppg) 8.6 Rate (bpm): 3.5 Volume: 20 M Displacement: Type: LSND Density (ppg) 10.2 Rate (bpm): 7 Volume (actual / calculated): 471/471 FCP (psi): 1100 Pump used for disp: Rig pumps Plug Bumped? X Yes No Bump press 3500 Casing Rotated? Yes X No Reciprocated? X No % Returns during job 100 Cement returns to surface? Yes _Yes X No Spacer returns? —Yes X No Vol to Surf: N/A Cement In Place At: 2:45 Date: 81312014 Estimated TOC: 9473'MD Method Used To Determine TOC: Halliburton BAT SONIC run post cement job Preflush (Spacer) Type: Density (ppg) Volume pumped (BBLs) Lead Slurry Type: Yield (Ft3/sack): Density (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): Tail Slurry Lu Type: Yield (Ft3/sack): Density (ppg) Volume (BBLs/sacks): Mixing / Pumping Rate (bpm): m 0 Post Flush (Spacer) o Type: Density (ppg) Rate (bpm): Volume: ro Displacement: Type: Density (ppg) Rate (bpm): Volume (actual / calculated): FCP (psi): Pump used for disp: Plug Bumped? _Yes No Bump press Casing Rotated? Yes _No Reciprocated? _Yes _No % Returns during job Cement returns to surface? Yes _No Spacer returns? _Yes _ No Vol to Surf: Cement In Place At: Date: Estimated TOC: Method Used To Determine TOC: Remarks: ATTACHMENT F Caelus Energy Alaska CASING & CEMENTING REPORT Lease & Well No. ODSN-34i Date 23 -Feb -09 County North Slope Bumugh State Alaska Supv. CASING RECORD - Intermediate Casing TD 14252.00 Shoe Depth: 14200.70 PBTD: Csg Wt. On Hook: Type Float Collar: Halliburton SSII No. Hrs to Run: Csg Wt. On Slips: Type of Shoe: HES SSII Casing Crew: Fluid Description: Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: Centralizer Placement: 3 in shoe track 1:1 next 25 joints, 1 above DV Tool, 2 below r`CK,ICAITIxIr_ DCDn DT Preflush (Spacer) Casing (Or Liner) Detail Setting Depths No. of As. Size Wt. Grade THD Make Length Bottom Top Flaot Shoe 7.00 26 L-80 HES 2.00 8,517.50 8,515.50 1 Joint 7.00 26 L-80 41.22 8,515.50 8,474.28 Float Collar 7.00 26 L-80 HES 1.00 8,474.28 8,473.28 1 Joint 7.00 26 L-80 40.38 8,473.28 8,432.90 Baffle Adapter 7.00 26 L-80 HES 1.00 8,432.90 8,431.90 43 Joint 7.00 26 L-80 X No Vol to Surf: 0 1,636.80 8,431.90 6,795.10 DV Tool 7.00 26 L-80 HES 2.80 6,795.10 6,792.30 167 Joints 7.00 26 L-80 12.5 Volume pumped (BBLs) 30 6,754.48 6,792.30 37.82 Pup Joint 7.00 26 L-80 Yield (Ft3/sack): 2.4 4.57 37.82 33.25 VG Hgr 7.00 26 L-80 0.62 33.25 32.63 Yield (Ft3/sack): na FDensity (ppg) na Volume (BBLs/sacks): na Mixing / Pumping Rate (bpm): na w a Post Flush (Spacer) o Type: Sea Water Density (ppg) 8.3 Rate (bpm): 4 Volume: 10 bbl w Displacement: m Type: LSND Density (ppg) 11.5 Rate (bpm): 7 Volume (actual / calculated): 256.86/252 FCP (psi): Pump used for disp: Rig pumps Totals Casing Rotated? _Yes x No Reciprocated? _Yes _ x No % Returns during job 100 8,484,87 Cement returns to surface? _Yes x No Spacer retums? Csg Wt. On Hook: Type Float Collar: Halliburton SSII No. Hrs to Run: Csg Wt. On Slips: Type of Shoe: HES SSII Casing Crew: Fluid Description: Liner hanger Info(Make/Model): Liner top Packer?: _Yes X No Liner hanger test pressure: Centralizer Placement: 3 in shoe track 1:1 next 25 joints, 1 above DV Tool, 2 below r`CK,ICAITIxIr_ DCDn DT Remarks: ATTACHMENT Preflush (Spacer) Type: Dual Spacer Density (ppg) 12.5 Volume pumped (BBLs) 55 Lead Slurry Type: Premium Cement Yield (Ft3/sack): 2.44 Density (ppg) 12.5 Volume (BBLs/sacks): 42/96 Mixing/ Pumping Rate (bpm): 4.0 Tail Slurry Type: Premium Cement Yield (Ft3/sack): 1.17 Density (ppg) 15.8 Volume (BBLs/sacks): 21.35/103 Mixing / Pumping Rate (bpm): 4.0 N Post Flush (Spacer) Type: N/A Density(ppg) NA Rate (bpm): NA Volume: NA LL Displacement: Type: LSND Density (ppg) 11.5 Rate (bpm): 7 Volume (actual / calculated): 322.75/327 FCP (psi): Pump used for disp: Rig pumps Plug Bumped? X Yes Bump press 2200 psi Casing Rotated? _Yes X No Reciprocated? _Yes -No X No % Returns during job 100 Cement returns to surface? _Yes X No Spacer returns? X No Vol to Surf: 0 Cement In Place At: 20:00 Date: 2/23/2009 _Yes Estimated TOC: 7,997 Method Used To Determine TOC: Planned Preflush (Spacer) Type: Dual Spacer Density (ppg) 12.5 Volume pumped (BBLs) 30 Lead Slurry Type: Pnmium Cement Yield (Ft3/sack): 2.4 Density (ppg) 12.5 Volume (BBLs/sacks): 78.14/173 Mixing / Pumping Rate (bpm): 4 Tail Slurry w Type: na Yield (Ft3/sack): na FDensity (ppg) na Volume (BBLs/sacks): na Mixing / Pumping Rate (bpm): na w a Post Flush (Spacer) o Type: Sea Water Density (ppg) 8.3 Rate (bpm): 4 Volume: 10 bbl w Displacement: m Type: LSND Density (ppg) 11.5 Rate (bpm): 7 Volume (actual / calculated): 256.86/252 FCP (psi): Pump used for disp: Rig pumps Plug Bumped? x Yes No Bump press 900 Casing Rotated? _Yes x No Reciprocated? _Yes _ x No % Returns during job 100 Cement returns to surface? _Yes x No Spacer retums? x No Vol to Surf: 0 Cement In Place At: 5:30 Date: 2/24/2009 _Yes Estimated TOC: 5,050 Method Used To Determine TOC: Planned Remarks: ATTACHMENT schlumbeplep FracCADE STIMULATION PROPOSAL Operator Caelus Energy Alaska Well ODSN-1a Field Oooguruk Formation Nuigsut Well Location Oooguruk County North Slope State Alaska Country United States Prepared for Mike Martin Service Point Prudhoe Bay, AK Date Prepared 02-27-2016 Business Phone 907-659-2434 FAX No. 907-659-2538 Prepared by ScottLeahy Phone 907-330-4595 E -Mail Address SLeahy@slb.com " Mark of Schlumberger 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 an input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the ass umpti Dns 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 bythe treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well orwells accordingly. Prices quoted are estimates only and are goad 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 notto be inferred. Client Caelus Energy Alaska Well OOSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 1) Schlumberger Formation Mechanical Properties Zone Name Top TO (ft) Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.inO.5) SHALE 6260.0 10.0 0.800 5012 5.000E+5 0.33 1000 Clean Sandstone 6270.0 25.0 0.650 4084 1.600E+6 0.25 1200 Dirty Sandstone 6295.0 15.0 0.670 4223 2.000E+6 0.33 1000 Shale 6310.0 5.0 0.700 4419 2.000E+6 0.29 1000 Clean Sandstone 6315.0 35.0 0.650 4116 1.600E+6 0.22 1000 Dirty Sandstone 6350.0 5.0 0.670 4256 2.000E+6 0.33 1000 SHALE 6355.0 15.0 0.800 5088 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TO (ft) Net Height (ft) Perm (md) Porosity 1%1 Res. Pressure (psi) SHALE 6260.0 1.0 0.001 1.0 2932 Clean Sandstone 6270.0 25.0 2.000 16.0 2940 Dirty Sandstone 6295.0 12.0 0.500 12.0 2906 Shale 6310.0 2.0 0.200 10.0 2912 Clean Sandstone 6315.0 35.0 2.000 15.0 2920 Dirty Sandstone 6350.0 4.0 0.500 12.0 2906 SHALE 6355.0 1.0 0.001 1.0 2976 Propped Fracture Schedule (Stage 1) Pumping Schedule Attachment G Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 40.0 YF125ST 45 25.0 0.00 1.0 PPA 40.0 YF125ST 14 25.0 CarboLite 16/20 1.00 2.0 PPA 40.0 YF125ST 14 25.0 CarboLite 16/20 2.00 3.0 PPA 40.0 YF125ST 18 25.0 CarboLite 16/20 3.00 4.0 PPA 40.0 YF125ST 17 25.0 CarboLite 16/20 4.00 5.0 PPA 40.0 YF125ST 16 25.0 CarboLite 16/20 5.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States sc IlOger Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Cone. (Ib/mgal) Prop. Type and Mesh Prop. Cone. (PPA) 6.0 PPA 40.0 YF125ST 16 25.0 CarboLite 16/20 6.00 7.0 PPA 40.0 YF125ST 11 25.0 CarboLite 16/20 7.00 8.0 PPA 40.0 YF125ST 11 25.0 CarboLite 16/20 8.00 FLUSH 40.0 YF125ST 1 281 1 25.0 1 0.00 Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 444 bbl of YF125ST Proppant Totals 21400 Ib of CarboLite 16/20 Pad Percentages % PAD Clean 27.7 % PAD Dirty 24.3 Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 45 45 45.0 45.0 0 0 6982 1.1 1.1 1.0 PPA 14 59 15.0 60.0 604 604 6982 0.4 1 1.5 2.0 PPA 14 73 15.0 75.0 1159 1762 7001 0.4 1.9 3.0 PPA 18 91 20.0 95.0 2228 3990 7016 0.5 2.4 4.0 PPA 17 108 20.0 115.0 2859 6849 7008 0.5 2.9 5.0 PPA 16 124 20.0 135.0 3446 10295 7008 0.5 3.4 6.0 PPA 16 140 20.0 155.0 3992 14287 7013 0.5 3.9 7.0 PPA 11 1 152 1 15.0 170.0 3376 17663 1 7020 0.4 4.3 8.0 PPA 11 163 15.0 185.0 3733 21396 7032 0.4 4.6 FLUSH 281 444 1 281.2 466.2 0 21396 6976 1 7.0 11.7 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 1) schlcmbcrocr The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 1 MD ------------------------------------------ 18778.0 ft Initial Fracture Top TVD----------------------- 6315.0 ft Initial Fracture Bottom TO ------------------ 6350.0 ft Propped Fracture Half -Length --------------- 149.7 ft Average Propped Width--------------- ------- 0.088 in Max Surface Pressure------------------------- 7263 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 37.4 8.5 0.114 75.0 1.02 316.9 2206 37.4 74.9 6.7 0.103 84.4 0.92 346.6 1791 74.9 112.3 4.8 0.088 84.4 0.79 377.9 1344 112.3 149.7 1.5 0.053 73.3 0.53 505.8 855 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 2) schlu Berger Formation Mechanical Properties Zone Name Top TO (ft) Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.ino.5) SHALE 6195.0 10.0 0.800 4960 5.000E+5 0.33 1000 Clean Sandstone 6205.0 25.0 0.650 4041 1.600E+6 0.25 1200 Dirty Sandstone 6230.0 15.0 0.670 4179 2.000E+6 0.33 1000 Shale 6245.0 5.0 0.700 4373 2.000E+6 0.29 1000 Clean Sandstone 6250.0 35.0 0.650 4074 1.600E+6 0.22 1000 Dirty Sandstone 6285.0 5.0 0.670 4213 2.000E+6 0.33 1000 SHALE 6290.0 15.0 0.800 5036 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TVD (ft) Net Height (ft) Perm (md) Porosity (%I Res. Pressure (psi) SHALE 6195.0 1.0 0.001 1.0 2902 Clean Sandstone 6205.0 25.0 2.000 16.0 2910 Dirty Sandstone 6230.0 12.0 0.500 12.0 2906 Shale 6245.0 2.0 0.200 10.0 2912 Clean Sandstone 6250.0 35.0 2.000 15.0 2920 Dirty Sandstone 6285.0 4.0 0.500 12.0 2906 SHALE 6290.0 1.0 0.001 1.0 2946 Propped Fracture Schedule (Stage 2) Pumping Schedule Attachment G Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 2 40.0 YF125ST 270 25.0 0.00 1.0 PPA 40.0 YF125ST 67 25.0 CarboLite 16/20 1.00 2.0 PPA 40.0 YF125ST 83 25.0 CarboLite 16/20 2.00 3.0 PPA 40.0 YF125ST 101 25.0 CarboLite 16/20 3.00 4.0 PPA 40.0 YF125ST 97 25.0 CarboLite 16/20 4.00 5.0 PPA 40.0 YF125ST 94 25.0 CarboLite 16/20 5.00 6.0 PPA 40.0 YF125ST 90 25.0 CarboLite 16/20 6.00 7.0 PPA 40.0 YF125ST 68 25.0 CarboLite 16/20 7.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Schlcmhcrgcr Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 8.0 PPA 40.0 YF125ST 55 25.0 CarboLite 16/20 8.00 FLUSH 40.0 YF125ST 275 25.0 270 0.00 Please note thatthis pumping schedule is under -displaced by 4.9 bbl. Fluid Totals 1201 bbl of YF125ST Proppant Totals 119900 lb of CarboLite 16/20 Pad Percentages % PAD Clean 29.2 % PAD Dirty 25.6 Job Execution Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 2 270 270 270.0 270.0 0 0 5854 6.8 6.8 1.0 PPA 67 337 70.0 340.0 2813 1 2813 5844 1.8 8.5 2.0 PPA 83 419 90.0 430.0 6932 9745 5856 2.3 10.8 3.0 PPA 101 521 115.0 545.0 12757 22502 6027 2.9 13.6 4.0 PPA 97 618 115.0 660.0 16357 38859 6497 2.9 16.5 5.0 PPA 94 712 115.0 775.0 19691 58550 7068 2.9 19.4 6.0 PPA 90 802 115.0 890.0 22788 81338 7589 2.9 22.3 7.0 PPA 68 871 1 90.0 1 980.0 20091 101429 8054 2.3 24.5 8.0 PPA 55 926 75.0 1055.0 18498 119927 8383 1.9 26.4 FLUSH 275 1.201 275.4 1330.4 0 119927 7894 6.9 33.3 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 2) Schlumberger The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 2 MD ------------------------------------------18401.0 ft Initial Fracture Top TVD ----------------------- 6230.0 ft Initial Fracture Bottom TVD ---------- 6245.0 ft -- Propped Fracture Half -Length --------------- 335.1 ft Average Propped Width----------------------- 0.215 in Max Surface Pressure_________________________ 8659 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc, at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 83.8 8.2 0.246 92.8 2.20 333.1 5799 83.8 167.5 7.2 0.243 92.6 2.18 349.9 5432 167.5 251.3 5.9 0.229 89.0 2.02 366.7 5090 251.3 335.1 2.5 0.153 78.2 1.35 1 529.8 3303 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 3) Schlu hupgcp Formation Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.ino.5) SHALE 6176.0 25.0 0.800 4951 5.000E+5 0.33 1000 Clean Sandstone 6201.0 30.0 0.650 4040 1.600E+6 0.25 1200 Dirty Sandstone 6231.0 15.0 0.670 4180 2.000E+6 0.33 1000 Shale 6246.0 5.0 0.700 4374 2.000E+6 0.29 1000 Clean Sandstone 6251.0 30.0 0.650 4073 1.600E+6 0.22 1000 Dirty Sandstone 6281.0 5.0 0.670 4210 2.000E+6 0.33 1000 SHALE 6286.0 15.0 0.800 5035 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TO (ft) -(ft) Net Height Perm (md) Porosity I%► Res. Pressure (psi) SHALE 6176.0 1.0 0.001 1.0 2896 Clean Sandstone 6201.0 30.0 2.000 16.0 2909 Dirty Sandstone 6231.0 12.0 0.500 12.0 2906 Shale 6246.0 2.0 0.200 10.0 2912 Clean Sandstone 6251.0 30.0 2.000 15.0 2920 Dirty Sandstone 6281.0 4.0 0.500 12.0 2906 SHALE 6286.0 1.0 0.001 1.0 2945 Propped Fracture Schedule (Stage 3) Pumping Schedule Attachment G Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (lb/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 3 40.0 YF125ST 500 25.0 0.00 1.0 PPA 40.0 YF125ST 120 25.0 CarboLite 16/20 1.00 2.0 PPA 40.0 YF125ST 156 25.0 CarboLite 16/20 2.00 3.0 PPA 40.0 YF125ST 185 25.0 CarboLite 16/20 3.00 4.0 PPA 40.0 YF125ST 178 25.0 CarboLite 16/20 4.00 5.0 PPA 40.0 YF125ST 171 25.0 CarboLite 16/20 5.00 6.0 PPA 40.0 YF125ST 165 25.0 CarboLite 16/20 6.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Scic6crocr Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 7.0 PPA 40.0 YF125ST 129 25.0 CarboLite 16/20 7.00 8.0 PPA 1 40.0 YF125ST 99 25.0 CarboLite 16/20 8.00 FLUSH 1 40.0 1 YF125ST 1 270 1 25.0 12.5 0.00 Fluid Totals 1973 bbl of YF125ST Proppant Totals 2201001b of CarboLite 16/20 Pad Percentages % PAD Clean 29.4 % PAD Dirty 25.8 Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (lb) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 3 500 500 500.0 500.0 0 0 5716 12.5 12.5 1.0 PPA 120 620 125.0 625.0 5023 1 5023 5747 3.1 15.6 2.0 PPA 156 775 170.0 795.0 13094 18117 5792 4.3 19.9 3.0 PPA 185 960 210.0 1005.0 23295 41412 6185 5.3 25.1 4.0 PPA 178 1138 210.0 1215.0 29869 71281 6729 5.3 30.4 5.0 PPA 171 1309 210.0 1425.0 35958 107239 7224 5.3 35.6 6.0 PPA 165 1475 210.0 1635.0 41613 148852 7727 1 5.3 1 40.9 7.0 PPA 129 1604 170.0 1805.0 37950 186802 8162 4.3 45.1 8.0 PPA 99 1703 135.0 1 1940.0 33297 220099 8429 3.4 48.5 FLUSH 270 1973 270.3 2210.3 0 220099 8013 6.8 55.3 Attachment G Client Caelus Energy Alaska �c�IN��r�Yr Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 3) The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 3 MD -------------------------- Initial Fracture Top TVD_________ Initial Fracture Bottom TO Propped Fracture Half -Length. Average Propped Width_________ Max Surface Pressure___________ 17740.0 ft 6201.0 ft 6231.0 ft 468.2 ft 0.270 in ____________ 8667 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Cone. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Cone. (Ib/ft2) Frac. Gel Cone. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 117.1 8.1 0.303 97.8 2.69 330.2 7688 117.1 234.1 7.1 0.296 97.0 2.63 360.8 7237 234.1 351.2 5.8 0.290 86.3 2.50 366.6 7087 351.2 468.2 2.5 0.203 79.3 1.76 662.5 4829 Attachirnent G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 4) schlumb rgcr Formation Mechanical Properties Zone Name Top TO (ft) ZoneFrac Height (ft) Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.in0.5) SHALE 6172.0 25.0 0.800 4948 5.000E+5 0.33 1000 Clean Sandstone 6197.0 30.0 0.650 4038 1.600E+6 0.25 1200 Dirty Sandstone 6227.0 15.0 0.670 4177 2.000E+6 0.33 1000 Shale 6242.0 5.0 0.700 4371 2.000E+6 0.29 1000 Clean Sandstone 6247.0 30.0 0.650 4070 1.600E+6 0.22 1000 Dirty Sandstone 6277.0 5.0 0.670 4207 2.000E+6 0.33 1000 SHALE 6282.0 15.0 0.800 5032 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TO (ft) Net Height (ft) Perm (m d) Porosity 1%1 Res. Pressure (psi) SHALE 6172.0 1.0 0.001 1.0 2894 Clean Sandstone 6197.0 30.0 2.000 16.0 2907 Dirty Sandstone 6227.0 12.0 0.500 12.0 2906 Shale 6242.0 2.0 0.200 10.0 2912 Clean Sandstone 6247.0 30.0 2.000 15.0 2920 Dirty Sandstone 6277.0 4.0 0.500 12.0 2906 SHALE 6282.0 1.0 0.001 1.0 2943 Propped Fracture Schedule (Stage 4) Pumping Schedule Attachment G Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 4 40.0 YF125ST 500 25.0 0.00 1 PPA 40.0 YF125ST 120 25.0 CarboLite 16/20 1.00 2 PPA 40.0 YF125ST 156 25.0 CarboLite 16/20 2.00 3 PPA 40.0 YF125ST 185 25.0 CarboLite 16/20 3.00 4 PPA 40.0 YF125ST 178 25.0 CarboLite 16/20 4.00 5 PPA 40.0 YF125ST 171 25.0 CarboLite 16/20 5.00 6 PPA 40.0 YF125ST 165 25.0 CarboLite 16/20 6.00 7 PPA 1 40.0 YF125ST 1 129 25.0 CarboLite 16/20 7.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States schlubcrocr Job Description % PAD Clean Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 8 PPA 40.0 YF125ST 99 25.0 CarboLite 16/20 8.00 FLUSH 40.0 WF125 260 30.2 500 0.00 Fluid Totals 1703 bbl of YF125ST 260 bbl of WF125 Proppant Totals 220100 Ib of CarboLite 16/20 Pad Percentages % PAD Clean 29.4 % PAD Dirty 25.8 Job Execution Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 4 500 500 500.0 500.0 0 0 5739 12.5 12.5 1 PPA 120 620 125.0 625.0 5023 5023 5775 3.1 15.6 2 PPA 156 775 170.0 795.0 13094 1 18117 5808 4.3 1 19.9 3 PPA 185 960 210.0 1005.0 23295 41412 6180 5.3 25.1 4 PPA 178 1138 210.0 1215.0 29869 71281 6691 5.3 30.4 5 PPA 171 1309 210.0 1425.0 35958 107239 7143 5.3 35.6 6 PPA 165 1475 210.0 1635.0 41613 148852 7600 5.3 40.9 7 PPA 129 1604 170.0 1805.0 37950 186802 7997 4.3 45.1 8 PPA 99 1 1703 1 135.0 1 1940.0 1 33297 1 220099 1 8280 3.4 1 48.5 FLUSH 260 1 1963 1 260.3 1 2200.3 1 0 1 220099 1 6480 6.5 1 55.0 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 4) Schlum6eroer The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 4 MD ---------------------------- . 17081.0 ft Initial Fracture Top TVD --_--_--------------- 6197.0 ft Initial Fracture Bottom TVD ------------------ 6227.0 ft Propped Fracture Half -Length--------------- 466.7 ft Average Propped Width----------------------- 0.270 in Max Surface Pressure------------------------- 8500 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 116.7 8.1 0.301 98.1 2.67 332.5 7608 116.7 233.3 7.1 0.296 97.2 2.64 361.1 7235 233.3 350.0 5.8 0.289 87.2 2.49 367.7 7055 350.0 466.7 2.5 0.207 79.7 1.82 585.2 4930 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 5) Schlumberger Formation Mechanical Properties Zone Name Top TO (ft) Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.inD.5) SHALE 6146.0 50.0 0.800 4937 5.000E+5 0.33 1000 Dirty Sandstone 6196.0 5.0 0.664 4118 2.000E+6 0.33 700 Clean Sandstone 6201.0 30.0 0.650 4040 1.600E+6 0.25 1200 Dirty Sandstone 6231.0 15.0 0.670 4180 2.000E+6 0.33 1000 Shale 6246.0 5.0 0.700 4374 2.000E+6 0.29 1000 Clean Sandstone 6251.0 30.0 0.650 4073 1.600E+6 0.22 1000 Dirty Sandstone 6281.0 5.0 0.670 4210 2.000E+6 0.33 1000 SHALE 6286.0 15.0 0.800 5035 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TVD Ift) Net Height (ft) Perm (md) Porosity 1%1 Res. Pressure (psi) SHALE 6146.0 1.0 0.001 1.0 2888 Dirty Sandstone 6196.0 4.0 0.500 12.0 2877 Clean Sandstone 6201.0 30.0 2.000 16.0 2909 Dirty Sandstone 6231.0 12.0 0.500 12.0 2906 Shale 6246.0 2.0 0.200 10.0 2912 Clean Sandstone 6251.0 30.0 2.000 15.0 2920 Dirty Sandstone 6281.0 4.0 0.500 12.0 2906 SHALE 6286.0 1.0 0.001 1.0 2945 Propped Fracture Schedule (Stage 5) Pumping Schedule Attachment G Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (lb/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 5 40.0 YF125ST 420 25.0 0.00 1 PPA 40.0 YF125ST 172 25.0 CarboLite 16/20 1.00 3 PPA 40.0 YF125ST 158 25.0 CarboLite 16/20 3.00 5 PPA 40.0 YF125ST 204 25.0 CarboLite 16/20 5.00 7 PPA 40.0 YF125ST 171 25.0 CarboLite 16/20 7.00 9 PPA 40.0 YF125ST 160 25.0 CarboLite 16/20 9.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Schlumbagcr Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 10 PPA 40.0 YF125ST 138 25.0 CarboLite 16/20 10.00 FLUSH 40.0 YF125ST 245 25.0 420 0.00 Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 1668 bbl of YF125ST Proppant Totals 2385001b of CarboLite 16/20 Pad Percentages % PAD Clean 29.5 % PAD Dirty 25.0 Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 5 420 420 420.0 420.0 0 0 5568 10.5 10.5 1 PPA 172 592 180.0 600.0 7232 7232 5590 4.5 15.0 3 PPA 158 751 180.0 780.0 19967 27200 5751 4.5 19.5 5 PPA 204 955 250.0 1030.0 42807 70007 6575 6.3 25.8 7 PPA 171 1125 225.0 1255.0 50228 120235 7457 5.6 31.4 9 PPA 160 1285 225.0 1480.0 60423 180658 8075 5.6 37.0 10 PPA 138 1 1423 1 200.0 1 1680.0 1 57817 238475 1 8381 5.0 42.0 FLUSH 1 245 1 1668 1 245.3 1 1925.3 1 0 1 238475 1 7729 6.1 48.1 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 5) schlcbcrocr The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 5 MD --------------------------------------- ,__16422.0 ft Initial Fracture Top TVD_______________________ 6201.0 ft Initial Fracture Bottom TVD ------------------ 6231.0 ft Propped Fracture Half -Length--------------- 408.8 ft Average Propped Width----------------------- 0.323 in Max Surface Pressure ---------------- --- ---- 8460 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Cone. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Cone. (Ib/ft2) Frac. Gel Cone. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 102.2 10.7 0.352 72.5 3.15 280.5 9789 102.2 204.4 10.0 0.364 99.3 3.24 283.0 1 10126 204.4 306.6 8.1 0.340 89.1 2.94 296.7 9481 306.6 408.8 3.2 0.247 75.0 2.14 421.4 6702 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 6) Schlchcrp Formation Mechanical Properties Zone Name Top TVD (ft) ZoneFrac Height (ft) Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.ino.5) SHALE 6147.0 50.0 0.800 4938 5.000E+5 0.33 1000 Dirty Sandstone 6197.0 5.0 0.664 4118 2.000E+6 0.33 700 Clean Sandstone 6202.0 30.0 0.650 4041 1.600E+6 0.25 1200 Dirty Sandstone 6232.0 15.0 0.670 4180 2.000E+6 0.33 1000 Shale 6247.0 5.0 0.700 4375 2.000E+6 0.29 1000 Clean Sandstone 6252.0 30.0 0.650 4074 1.600E+6 0.22 1000 Dirty Sandstone 6282.0 5.0 0.670 4211 2.000E+6 0.33 1000 SHALE 6287.0 15.0 0.800 5036 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TVD (ft) Net Height (ft) Perm Porosity (md) I%1 Res. Pressure (psi) SHALE 6147.0 1.0 0.001 1.0 2888 Dirty Sandstone 6197.0 4.0 0.500 12.0 2877 Clean Sandstone 6202.0 30.0 2.000 16.0 2910 Dirty Sandstone 6232.0 12.0 0.500 12.0 2906 Shale 6247.0 2.0 0.200 10.0 2912 Clean Sandstone 6252.0 30.0 2.000 15.0 2920 Dirty Sandstone 6282.0 4.0 0.500 12.0 2906 SHALE 6287.0 1.0 0.001 1.0 2946 Propped Fracture Schedule (Stage 6) Pumping Schedule Attachtnent G Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 6 40.0 YF125ST 500 25.0 0.00 1 PPA 40.0 YF125ST 120 25.0 CarboLite 16/20 1.00 3 PPA 40.0 YF125ST 150 1 25.0 1 CarboLite 16/20 3.00 5 PPA 40.0 YF125ST 171 25.0 CarboLite 16/20 5.00 7 PPA 40.0 YF125ST 159 25.0 CarboLite 16/20 7.00 9 PPA 40.0 YF125ST 149 25.0 CarboLite 16/20 9.00 Attachtnent G 1 Caeluz N01A the irf group, inc. Palynostratigraphy of a Short Section in the Caelus N01A Well, Oooguruk Area Alaska North Slope, (17,400 ft – 18,811 ft) the irf group, inc. May 2016 Synthesis A biostratigraphic profile is developed for a short interval in the Caelus N01A well (Figure 1), North Slope, Alaska, based on organic-walled microfossils. The goals of the study are to build a chronostratigraphic framework (Figure 2) for the well section and to develop a comprehensive suite of biological attributes (Figures 3, 4 and 5) that can be utilized in future sequence stratigraphic, depositional framework, and regional correlation models. The entire section examined between 17,400 ft and 18,811 ft lies within the upper Kingak Formation, and is Oxfordian (Late Jurassic) to questionablyl Callovian (Middle Jurassic) in age. The samples contain well-preserved and diverse palynomorph populations (consisting of dinoflagellates, acritarchs, pollen, spores, fungal cells, and miscellaneous algae). A total of 176 microfossil taxa were identified in the well; the palynology assemblages also contain a moderately diverse population of reworked specimens. Quantitative palynological census data were collected for all samples. These data sets, along with a variety of summary paleontological tracks and statistical analyses, are used both to develop the initial age interpretation for the well, and to provide a robust and useful framework for future regional correlation studies. Results The presence in the uppermost sample of the key marine dinoflagellate cyst Nannoceratopsis pellucida signifies that the section begins within the Oxfordian stage of the Upper Jurassic. Virtually everywhere in the North Slope region, this age interval is characterized by a very rich and diverse marine dinocyst population, and many other characteristic forms are present, including Chytroeisphaeridia hyalina, C. cerastes, Atopodinium prostatum, Pluriarvalium osmingtonense, Scriniodinium galeritum reticulatum. and Fromea tornatilis. Also present, and characteristic of the North Slope area, is a marine acritarch form believed not to be described formally in published literature, here designated Nummus sp. 1. The marine assemblage through this stratigraphically short interval is relatively homogeneous, with the important exceptions of the occurrences of two as-yet-undescribed dinoflagellate taxa in its lower portion of the well. These, designated here as Balcattia-1 and Chytroeisphaeridia 2 Caeluz N01A the irf group, inc. “verrucosa”. Both of these forms have been seen in many wells around the Colville Delta area, but among the wells examined recently (K13PB2, N07i and N03i) Balcattia-1 was not observed. It is highly distinctive, but generally rare, and an unusual number of specimens were observed in N01A, through an interval from 17,900 ft to18400 ft. C. “verrucosa,” usually a more common form, is normally encountered at a slightly lower horizon than Balcattia-1, and that is true in this well, where it occurs from 18,520 ft to18,700 ft, being abundant in the two samples from 18,580 ft to18,640 ft. Together, these forms constitute two of the more important stratigraphic indicators in this section. Both everywhere occupy very narrow stratigraphic intervals, and we regard their uppermost observed occurrences and the abundance peak of C. “verrucosa” as highly useful and reliable indicators for correlation. In chronostratigraphic terms, we also consider them as questionably indicative of the Callovian stage. Terrestrial forms (pollen and spores) are also abundant, but most are long-ranging types that are known to extend upward into Cretaceous strata. One exception is another undescribed probable gymnosperm pollen designated here as “monosaccate trilete sp. 1,” only seen in Upper Jurassic strata in the region. Reworked Mississippian plant spores derived from the Kekiktuk Formation are abundant, typical for the upper Kingak section everywhere. Chytroeisphaeridia “verrucosa” Nannoceratopsis pellucida 3 Caeluz N01A the irf group, inc. Balcattia-1 Palynological analysis was performed by Robert L. Ravn (the irf group), while report integration, numerical analyses, and graphics were completed by David Goodman (the irf group). Analytical Approach Our intent is to present the biological data within the context of a dynamic interpretation environment in which all original and derived data sets are documented and displayed in a style that permits evaluation of the results of this study and re-interpretation at any time in the future. These data sets are the result of a complex set of biological and physical parameters, and a suite of reasonable interpretations can be formulated within the constraints of the acquired data. Thus, we propose our preferred interpretations, but both realize and invite alternate views by other analysts and interpreters. We strongly feel that this dynamic interpretive mode is vastly superior to the more typical (and effectively static) approach of providing an age interpretation over a specified stratigraphic interval with little or no supporting documentation other than listing several range events that occur within the interval. Our fundamental approach to biostratigraphy differs from that utilized by many other consulting groups. We purposely separate the tasks of data acquisition (sample analysis) and interpretation (chronostratigraphic models, statistical analyses, and biofacies calculations). all biological components in the samples based on detailed systematic identification, and (2) attention to detail in collecting census data on all species, or other taxonomic entities, identified. This results in an initial data set for the well which exhibits considerable dimensionality and for which no a priori decisions have been made by the analyst that would exclude taxa with biostratigraphic, chronostratigraphic, or paleoenvironmental significance. The assemblage summary attributes (group total abundances, percentage abundances, selected ratios) and other statistical parameters (similarity coefficients, diversity indexes,) derived from the initial data matrix exploit this more complex dimensionality and therefore have enhanced potential for more detailed stratigraphic characterization, subdivision, and correlation than is possible with reduced occurrence data sets. 4 Caeluz N01A the irf group, inc. Analytical Parameters Each sample was evaluated in terms of a quantitative census analysis of the organic-walled microfossils. Quantitative census data increase the “dimensionality” of the final data set and allow a wide range of numerical and statistical analyses to be performed on the data set, in contrast to either “presence-absence” or “semi-quantitative” (also known as abundance estimates), for which further statistical analyses are either not possible, or produce invalid or misleading results. A sample set of approximately 200 identifiable specimens was counted for each sample wherever possible; additional species not encountered in the initial 200 grain count, but identified during subsequent examination of the microscope slides, were added to the final counts, thereby affecting the number of specimens and increasing the counts to more than 200 in most of the samples. A complete listing of all 125 species identified in the well is given in Appendix 1. Primary data include the quantitative and stratigraphic distribution of the microfossils. Twenty-three derivative data sets, or assemblage attributes, are also included in this report (Figure 3). These derivative tracks are used to enhance the primary data and to summarize the geological and biological history of the well section in terms that are more useful than simple range data alone. These tracks can be used to make more detailed interpretations of depositional system architecture, identify possible stratal discontinuities, and to characterize stratigraphic intervals using biological content. The summary tracks recorded for the N01A section include: • Marine Percentage Abundance • Marine Total Abundance • Dinoflagellate Total Abundance • Acritarch Total Abundance • Microforam Total Abundance • Terrestrial Total Abundance • Pollen Total Abundance • Spore Total Abundance • Miscellaneous Algae Total Abundance • Total In Situ Diversity • Marine Species Diversity • Terrestrial Species Diversity • Marine Richness Ratio • Terrestrial Richness Ratio • Marine Simpson Diversity Index • Terrestrial Simpson Diversity Index • Marine Shannon-Weaver Diversity Index • Terrestrial Shannon-Weaver Diversity Index • Reworked Total Abundance • Reworked Devonian Abundance • Reworked Kekituk (Mississippian) Abundance • Reworked Lower Mesozoic Abundance • Reworked Diversity 5 Caeluz N01A the irf group, inc. Display Panels Biostratigraphic results for the well section are illustrated in the following display panels: Figure 1. Location Map. Figure 2. Well Summary. Figure 3. Palynology Assemblage Parameters. Figure 4. Palynomorph Quantitative Distribution Chart. Figure 5. Palynomorph Interval Range Chart. Appendixes Appendix 1. Species list, sorted by major microfossil group. Appendix 2. Range events. Data Archive (CD) All hardcopy components of this report are included as digital files on the attached CD. The files are platform-independent files: RICH TEXT FORMAT (.rtf), EXCEL (.xls), or PORTABLE DOCUMENT FORMAT (.pdf). The CD files include: N01ARept.doc - Report Text N01AApp1.r doc - Appendix 1 N01AApp2. doc - Appendix 2 N01AData.xls - Occurrence Data N01ASums.xls - Assemblage Statistics N01AFig1.pdf - Figure 1 N01AFig2.pdf - Figure 2 N01AFig3.pdf - Figure 3 N01AFig4.pdf - Figure 4 N01AFig5.pdf - Figure 5 Local Correlation 6 Caeluz N01A the irf group, inc. A local correlation model based on biostratigraphic data will follow. The model incorporates data from a number of earlier wells in the area, and will include a detailed statistical RASC (RAnking & SCaling) model to identify and sequence additional range events (range tops and bases) recognized to provide enhanced age calibration and regional correlation parameters for the Kimmeridgian through Callovian Kingak section in the area of interest. The following twelve wells (four new wells analyzed in 2016 and eight earlier regional control wells) are included in the RASC analysis and regional synthesis : Colville Delta 2 DW144 Ivik 1 K13PB2 2016 K42i Kalubik 1 Kalubik 3 N01A 2016 N03i 2016 N07i 2016 Oooguruk 1 Thetis Island 1 Figure 1. Caelus N01A. Location map. N01A Relative Age Caelus N01A Figure 2. Caelus N01A North Slope, Alaska. Schematic biostratigraphic framework. Selected biological assemblage summary tracks are taken from a complete suite illustrated on Figure 3. MD (ft) Numerical Age Oxfordian Late JurassicGamma ?Callovian Middle Jurassic 0 60 120 Marine Percentage Abundance50 Dinoflagellate Abundance50 Acritarch AbundancePollen Abundance50 100 Spore AbundanceReworked Abundance50 17400/500 18520/50 159.4 Ma 154.1 Ma (or older) 17400 17450 17500 17550 17600 17650 17700 17750 17800 17850 17900 17950 18000 18050 18100 18150 18200 18250 18300 18350 18400 18450 18500 18550 18600 18650 18700 18750 18800 18850 Relative Age Oxfordian Caelus N01A 18790/8011ft basal sample Figure 3. Caelus N01A, North Slope, Alaska. Palynological assemblage parameters.Late Jurassicthe irf group, inc. consulting paleontologists May 2016 17400/500 ft Numerical Age ?Callovian M. Jurassic18520/50 ft 154.1 Ma (or older) AAEM48PC 0 2.4 4.8 7.2 9.6 12 GR 0 30 60 90 120 150 17400 17450 17500 17550 17600 17650 17700 17750 17800 17850 17900 17950 18000 18050 18100 18150 18200 18250 18300 18350 18400 18450 18500 18550 18600 18650 18700 18750 18800 18850Marine Percentage Abundance20 40 60 Marine Total Abundance20 40 60 80 Dinoflagellate Total Abundance20 40 60 80 Acritarch Total AbundanceMicroforam Total AbundanceTerrestrial Total Abundance20 40 60 80 100 120 140 Pollen Abundance20 40 60 80 100 Spore Abundance20 40 Miscellaneous Algae AbundanceTotal In Situ Diversity20 Marine Species DiversityTerrestrial Species DiversityMarine Richness Ratio20 Terrestrial Richness Ratio20 Marine Simpson Diversity Index20 40 60 80 Terrestrial Simpson Diversity Index20 40 60 80 Marine Shannon-Weaver Diversity Index20 40 60 80 Terrestrial Shannon-Weaver Diversity Index20 40 60 80 Reworked Total Abundance20 40 Reworked Devonian TotalReworked Kekituk Total20 40 Reworked Lower Mesozoic TotalReworked Diversity20 17400 17450 17500 17550 17600 17650 17700 17750 17800 17850 17900 17950 18000 18050 18100 18150 18200 18250 18300 18350 18400 18450 18500 18550 18600 18650 18700 18750 18800 18850 159.4 Ma Relative Age Oxfordian Caelus N01A 18790/8011ft basal sample Figure 4. Caelus N01A, North Slope, Alaska. Quantitative distribution of organic-walled palynomorphs.Late Jurassicthe irf group, inc. consulting paleontologists May 2016 17400/500 ft Numerical Age ?Callovian M. Jurassic154.1 Ma (or older) AAEM48PC 0 2.4 4.8 7.2 9.6 12 GR 0 30 60 90 120 150 17400 17450 17500 17550 17600 17650 17700 17750 17800 17850 17900 17950 18000 18050 18100 18150 18200 18250 18300 18350 18400 18450 18500 18550 18600 18650 18700 18750 18800 18850 17400 17450 17500 17550 17600 17650 17700 17750 17800 17850 17900 17950 18000 18050 18100 18150 18200 18250 18300 18350 18400 18450 18500 18550 18600 18650 18700 18750 18800 18850bisaccate gymnosperm pollen - indet.20 40 60 80 Deltoidospora spp. - indet.20 Osmundacidites wellmaniiRetitriletes spp. - indet.Corollina torosaStereisporites spp. - indet.Cerebropollenites macroverrucosus20 40 Cycadopites nitidusAntulsporites clavusExesipollenites tumulusFoveosporites spp. - indet.Chytroeisphaeridia hyalina20 40 60 Scriniodinium galeritum reticulatum20 40 Valensiella magna20 Egmontodinium diminutumRhynchodiniopsis spp. - indet.Caddasphaera halosaChytroeisphaeridia cerastesFromea tornatiliscf. Comparodinium sp. - granuloseScriniodinium crystallinumcf. Gorgonisphaeridium spp. - indet.Nannoceratopsis pellucidaPareodinia sp. E of Wiggins 1975Nummus sp.Horologinella spinosigibberosaDensosporites spp. - indet.20 Lophozonotriletes spp. - indet.Densosporites variomarginatusAnapiculatisporites spp. - indet.Cingujlizonates bialatusLycospora pusillaPunctatisporites spp. - indet.Vallatisporites cf. ciliarisLophozonotriletes triangulatusPlatyptera incisotrilobaCorbulispora margodentataRetispora lepidophytaGrandispora spp. - indet."Cristatisporites sp. - indet., large, thick"Punctatisporites globosus (= Todispora major)Tubotuberella luridaLithodinia borealisValensiella ovulaMeiourogonyaulax cf. decapitataPareodinia spp. - indet.taeniate bisaccate pollen - indet.Triadispora sp. - indet.Murospora cf. conduplicataStenozonotriletes spp. - indet.Retusotriletes spp. - indet.Corbulispora cancellataMurospora sublobataSpelaeotriletes spp. - indet.monosaccate trilete sp. 1Laevigatosporites sp. - indet.Velamisporites sp. - indt.Vitreisporites pallidusCallialasporites triletusRetusotriletes nigritellusSentusidinium verrucosumPareodinia brachythelisStriatopollis rhaeticusGorgonispora multiplicabilisPlatyptera complanataLycospora noctuinaKnoxisporites hederatusKnoxisporites literatusSpelaeotriletes cf. triangulusCirratriradites? sp. 2 of Ravn 1991Lophozonotriletes appendicesMurospora complicata"Monilospora sp. - indet., large"Eucommiidites troedssoniiSculptisporis sp. - indet.Crassitudisporites problematicusNeoraistrickia truncataLeiofusa jurassicaPareodinia ceratophoraSirmiodiniopsis orbisMicrhystridium spp. - indet.Limbosporites lundbladiiGordonispora “laevigata”Convolutispora sp. - indet.Radiizonates cf. aligerensMurospora auritaMurospora intortaCyrtospora cristiferAtopodinium prostatumLundbladispora sp. - indet.Labiadensites fimbriatusPerinopollenites elatoidesIschyosporites spp. - indet.Antulsporites sp. - indetLycopodiacidites rugulatusAlisporites grandisCallialasporites dampieriAnaplanisporites cf. telephorusSestrosporites pseudoalveolatusRhynchodiniopsis cladophoraEscharisphaeridia spp. - indet.Sentusidinium asymmetricumPluriarvalium osmingtonenseParagonyaulacysta calloviensisBalcattia sp. 1Pareodinia cf. antennataCamarozonosporites rudisCornutisporites seebergensis"apiculate trilete indet. gen., Rhaetian"Lunatisporites noviaulensisLabiadensites spp. - indet.Plicatispora cf. scolecophoraCrassispora spp. - indet.Murospora altilisMonilospora triungensisAuroraspora? hyboAnnulispora spp. - indet.Knoxisporites “decoratus”Knoxisporites “delicatus”Knoxisporites cinctusMurospora dupla"Verrucosisporites spp. - indet., large, thick"Callialasporites turbatusRosswangia holotabulataEscharisphaeridia pocockiiDensosporites subserratusTetraporina horologiaepicystal indet. sp. 1Lithodinia cf. callomoniiUvaesporites imperialisLophozonotriletes undulimarginatusReticulatisporites labiatusEquisetosporites sp. - indet.Domasia liassicaVallatisporites spp. - indet.Cingulizonates flammulusReticulatisporites margarethaeCibotiumspora spp. - indet.Foraminisporis jurassicusGorgonispora sp. - indet.Corollina meyerianaAratrisporites sp. - indet.Deltoidospora mesozoicaRetitriletes semimurisLycopodiacidites sp. - indet.Scriniodinium galeritum galeritumVelamisporites tessellatusRetispora cassiculaCallialasporites lucidusChytroeisphaeridia “verrucosa”20 Lithodinia spp. - indet.Corbulispora sp. - indet.Potoniespores delicatusUvaesporites spp. - indet.Scriniocassis? sp. - indet.cf. Ellipsoidictyum sp. 1 - wide cingulumDiatomozonotriletes saetosusExesipollenites scabrosusDictyophyllidites harrisiiCycadopites spp. - indet.Jansonia jurassicaCristatisporites indignabundusGrandispora cf. echinata of Ravn 1991Kalyptea stegastaLophotriletes sp. - indet.Cirratriradites? sp. 1 of Ravn 1991Prolycospora sp. - indet.Undulatisporites sp. - indet.Rogalskaisporites cicatricosusDictyophyllidites toralisConbaculatisporites cf. triassicusCallialasporites segmentatusCallialasporites trilobatusWaltzispora albertensisBiretisporites potonieiGonyaulacysta oligacantha18520/50 ft 159.4 Ma Figure 5. Caelus N01A, North Slope, Alaska. Interval range chart. Relative Age Caelus N01A Oxfordian the irf group, inc. consulting paleontologists May 2016 ?CallovianLate JurassicMiddle JurassicDepth (ft) 17400-17500 17400-17500 17500-17600 17500-17600 17600-17700 17600-17700 17700-17800 17700-17800 17800-17900 17800-17900 17900-18000 17900-18000 18000-18100 18000-18100 18100-18160 18100-18160 18160-18220 18160-18220 18220-18280 18220-18280 18280-18340 18280-18340 18340-18400 18340-18400 18400-18430 18400-18430 18430-18460 18430-18460 18460-18490 18460-18490 18490-18520 18490-18520 18520-18550 18520-18550 18550-18580 18550-18580 18580-18610 18580-18610 18610-18640 18610-18640 18640-18670 18640-18670 18670-18700 18670-18700 18700-18730 18700-18730 18730-18760 18730-18760 18760-18790 18760-18790 18790-18811 18790-18811bisaccate gymnosperm pollen - indet.Deltoidospora spp. - indet.Osmundacidites wellmaniiRetitriletes spp. - indet.Corollina torosaStereisporites spp. - indet.Cerebropollenites macroverrucosusCycadopites nitidusAntulsporites clavusExesipollenites tumulusFoveosporites spp. - indet.Chytroeisphaeridia hyalinaScriniodinium galeritum reticulatumValensiella magnaEgmontodinium diminutumRhynchodiniopsis spp. - indet.Caddasphaera halosaChytroeisphaeridia cerastesFromea tornatiliscf. Comparodinium sp. - granuloseScriniodinium crystallinumcf. Gorgonisphaeridium spp. - indet.Nannoceratopsis pellucidaPareodinia sp. E of Wiggins 1975Nummus sp.Horologinella spinosigibberosaDensosporites spp. - indet.Lophozonotriletes spp. - indet.Densosporites variomarginatusAnapiculatisporites spp. - indet.Cingujlizonates bialatusLycospora pusillaPunctatisporites spp. - indet.Vallatisporites cf. ciliarisLophozonotriletes triangulatusPlatyptera incisotrilobaCorbulispora margodentataRetispora lepidophytaGrandispora spp. - indet."Cristatisporites sp. - indet., large, thick"Punctatisporites globosus (= Todispora major)Tubotuberella luridaLithodinia borealisValensiella ovulaMeiourogonyaulax cf. decapitataPareodinia spp. - indet.taeniate bisaccate pollen - indet.Triadispora sp. - indet.Murospora cf. conduplicataStenozonotriletes spp. - indet.Retusotriletes spp. - indet.Corbulispora cancellataMurospora sublobataSpelaeotriletes spp. - indet.monosaccate trilete sp. 1Laevigatosporites sp. - indet.Velamisporites sp. - indt.Vitreisporites pallidusCallialasporites triletusRetusotriletes nigritellusSentusidinium verrucosumPareodinia brachythelisStriatopollis rhaeticusGorgonispora multiplicabilisPlatyptera complanataLycospora noctuinaKnoxisporites hederatusKnoxisporites literatusSpelaeotriletes cf. triangulusCirratriradites? sp. 2 of Ravn 1991Lophozonotriletes appendicesMurospora complicata"Monilospora sp. - indet., large"Eucommiidites troedssoniiSculptisporis sp. - indet.Crassitudisporites problematicusNeoraistrickia truncataLeiofusa jurassicaPareodinia ceratophoraSirmiodiniopsis orbisMicrhystridium spp. - indet.Limbosporites lundbladiiGordonispora “laevigata”Convolutispora sp. - indet.Radiizonates cf. aligerensMurospora auritaMurospora intortaCyrtospora cristiferAtopodinium prostatumLundbladispora sp. - indet.Labiadensites fimbriatusPerinopollenites elatoidesIschyosporites spp. - indet.Antulsporites sp. - indetLycopodiacidites rugulatusAlisporites grandisCallialasporites dampieriAnaplanisporites cf. telephorusSestrosporites pseudoalveolatusRhynchodiniopsis cladophoraEscharisphaeridia spp. - indet.Sentusidinium asymmetricumPluriarvalium osmingtonenseParagonyaulacysta calloviensisBalcattia sp. 1Pareodinia cf. antennataCamarozonosporites rudisCornutisporites seebergensis"apiculate trilete indet. gen., Rhaetian"Lunatisporites noviaulensisLabiadensites spp. - indet.Plicatispora cf. scolecophoraCrassispora spp. - indet.Murospora altilisMonilospora triungensisAuroraspora? hyboAnnulispora spp. - indet.Knoxisporites “decoratus”Knoxisporites “delicatus”Knoxisporites cinctusMurospora dupla"Verrucosisporites spp. - indet., large, thick"Callialasporites turbatusRosswangia holotabulataEscharisphaeridia pocockiiDensosporites subserratusTetraporina horologiaepicystal indet. sp. 1Lithodinia cf. callomoniiUvaesporites imperialisLophozonotriletes undulimarginatusReticulatisporites labiatusEquisetosporites sp. - indet.Domasia liassicaVallatisporites spp. - indet.Cingulizonates flammulusReticulatisporites margarethaeCibotiumspora spp. - indet.Foraminisporis jurassicusGorgonispora sp. - indet.Corollina meyerianaAratrisporites sp. - indet.Deltoidospora mesozoicaRetitriletes semimurisLycopodiacidites sp. - indet.Scriniodinium galeritum galeritumVelamisporites tessellatusRetispora cassiculaCallialasporites lucidusChytroeisphaeridia “verrucosa”Lithodinia spp. - indet.Corbulispora sp. - indet.Potoniespores delicatusUvaesporites spp. - indet.Scriniocassis? sp. - indet.cf. Ellipsoidictyum sp. 1 - wide cingulumDiatomozonotriletes saetosusExesipollenites scabrosusDictyophyllidites harrisiiCycadopites spp. - indet.Jansonia jurassicaCristatisporites indignabundusGrandispora cf. echinata of Ravn 1991Kalyptea stegastaLophotriletes sp. - indet.Cirratriradites? sp. 1 of Ravn 1991Prolycospora sp. - indet.Undulatisporites sp. - indet.Rogalskaisporites cicatricosusDictyophyllidites toralisConbaculatisporites cf. triassicusCallialasporites segmentatusCallialasporites trilobatusWaltzispora albertensisBiretisporites potonieiGonyaulacysta oligacanthaPresent Very rare Rare Common Abundant Very abundant Dominant Flood 1-1 2-3 4-9 10-24 25-49 50-99 100-999 !1000 Legend Technical Report Title Date Client: Caelus Energy Alaska Field: Oooguruk Development Rig: Nabors 19AC Date: March 15, 2016 Surface Data Logging End of Well Report ODSN-01A TABLE OF CONTENTS 1. General Information 2. Daily Summary 3. Days vs. Depth 4. After Action Review 5. Formation Tops 6. Mud Record 7. Bit Record 8. Morning Reports 9. Survey Report Digital Data to include: Final Log Files Final End of Well Report Final LAS Exports Halliburton Log Viewer EMF Log Viewer GENERAL WELL INFORMATION Company: Caelus Energy Alaska, LLC Rig: Nabors 19AC Well: ODSN-01A Field: Oooguruk Borough: North Slope Borough State: Alaska Country: United States API Number: 50-703-20648-01-00 Sperry Job Number: AK-XX-0903090400 Job Start Date: 29 January 2016 Spud Date: 5 February 2016 Total Depth: 18811’ MD, 6329’ TVD North Reference: True Declination: 18.658° Dip Angle: 81.055° Total Field Strength: 57568 nT Date of Magnetic Data: 29 January 2016 Wellhead Coordinates N: North 70° 29’ 46.242” Wellhead Coordinates W: West 150° 14’ 45.465“ Drill Floor Elevation 56.20’ Ground Elevation: 13.50’ Permanent Datum: Mean Sea Level SDL Engineers: Kerry Garner, Martin Nnaji, Beverly Hur, David Durst. SDL Sample Catchers: Matthew Wavra, Christopher Medeiros Company Geologist: John Hill, Mindaugas Kuzminskas, Fletcher England, Paul Cozma Company Representatives: Joe Polya, Rod Klepzig, Joe Petitjean, C.A. Demoski, SSDS Unit Number: 123 DAILY SUMMARY 01/29/2016 Moved the rig to ODSN-01A then nipple down the production tree. Nippled up the riser, blowout preventer, stack, choke and kill lines and installed the trip nipple and turnbuckles. Picked up the test tools and began testing the blowout preventer. Tested the annulus and discovered a leak in the connection between the blowout preventer and the riser. Nippled down the stack and changed the seal. Nippled up the stack and all the lines, reinstalled the test joint and resumed testing the blowout preventer. 01/30/2016 Continued to test the blowout preventers. Laid down testing equipment and monitored the well. Circulated diesel freeze protect from the well, taking returns to the flow back tank. Began pulling 4.5” tubing from 2564’ MD to surface and laid down all the kill string. Picked up the Baker casing cutter tool and tripped in the hole with 7” casing cutter from surface to 4318’ MD. Located and cut the casing. Confirmed the casing cut, lined up to pump down kill and establish circulation. Pumped a 50 barrel Barascrub pill, cleaned out the drag valve and began displacing with 500 barrels of clean seawater. 01/31/2016 Continued to circulate out freeze protect with clean seawater. Tripped out of the hole from 4318’ MD to surface and changed and tested the upper rams. Laid down test tools and pulled the test plug. Rigged up to pull 7” casing. Pulled 73 joints and laid down casing equipment. Flushed the stack, changed out and tested upper rams. Serviced the top drive, blocks, and crown, and picked up the casing scraper bottom hole assembly to 40’ MD. 02/01/2016 Picked up the casing scraper bottom hole assembly, tripped in the hole to 4274’ MD, and circulated 1.5 bottoms up. Laid down 4” drill pipe and the bottom hole assembly. Cleaned and cleared the rig floor. Pulled the wear bushing, installed the test plug, and began testing the blowout preventers. 02/02/2016 Finished testing the blowout preventers, then tripped in the hole with 5.5” drill pipe to 4194’ MD. Pressure tested the casing to 3500 pounds per square inch for 30 minutes. Serviced the rig, cut and slip the drill line, serviced the top drive, blocks and crown. Tripped out of the hole from 4194’ MD to 11’ MD and laid down the bottom hole assembly. Tested the blowout preventers, held a pre-job safety meeting for picking up the bottom hole assembly, and began picking up the casing scraper bottom hole assemble for the scraper run. 02/03/2016 Picked up the bottom hole assembly, picked up drill pipe from 480’ MD to 4120’ MD, and circulated two bottoms up. Tripped out of the hole from 4020’ MD to 1877’ MD, then serviced the top drive and blocks and laid down the bottom hole assembly from 480’ MD to surface. Cleaned and cleared the rig floor. Brought up the tools for the whipstock bottom hole assembly and picked up the whipstock bottom hole assembly from surface to 2154’ MD. Gas: The max circulation gas was 74 units and the average circulation gas was 11 units. Fluids: There were 0 barrels of seawater lost down hole. 02/04/2016 Tripped in the hole from 2154’ MD to 3553’ MD and couldn’t work past 3553’ MD without risk of shearing the whipstock. Tripped out of the hole and laid down the bottom hole assembly. Picked up the clean out down the bottom hole assembly, serviced the top drive and blocks and tripped in the hole from 525’ MD to 3506’ MD. Reamed and washed down from 3506’ MD to 4118’ MD at 700 gallons per minute, 1000 pounds per square inch standpipe pressure, 70 revolutions per minute, and 4k foot-pounds torque. Circulated two bottoms up at 700 gallons per minute and 1700 pounds per square inch standpipe pressure and tripped out of the hole and began laying down the bottom hole assembly. Gas: The max circulation gas was 10 units and the average circulation gas was 6 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/05/2016 Laid down the bottom hole assembly and serviced the top drive and blocks. Picked up the whipstock bottom hole assembly and tripped in the hole from 758’ MD to 4122’ MD. Orientated and set the whipstock. Milled the window through the 11 ¾” casing from 4077' MD to 4095' MD at 750 gallons per minute, 1950 pounds per square inch standpipe pressure, 100 revolutions per minute, and 7-8k pounds weight on bit. Gas: The max drill gas was 16 units and the average drill gas was 13 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/06/2016 Milled the window from 4095’ MD to 4099’ MD and drilled new hole at 750 gallons per minute, 1950 pounds per square inch standpipe pressure and 100 revolutions per minute. Pulled up into the 11 ¾” casing to 4056’ MD and performed a formation integrity test to 12.5 pounds per gallon equivalent mud weight. Tripped out of the hole and laid down the bottom hole assembly. Performed a kick while tripping drill, cleaned and cleared the rig floor, serviced the top drive and blocks. Picked up the bottom hole assembly and tripped in the hole to 4063’ MD. Gas: The max drill gas was 0 units and the average drill gas was 0 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/07/2016 Orientated the bottom hole assembly through the window from 4095' MD to 4129' MD. Drilled ahead from 4129' MD to 4529' MD at 750 gallons per minute, 2750 pounds per square inch standpipe pressure, 60 revolutions per minute, 6k foot-pounds torque, and 13k pounds weight on bit. Circulated 3.5 bottoms up and tripped out of the hole. Serviced the top drive and blocks and continued to trip out of the hole. Laid down the bottom hole assembly then cleaned and cleared the rig floor. Picked up the bottom hole assembly then function and tested the MWD tools and under reamer. Tripped in the hole to 2513’ MD. Gas: The max drill gas was 137 units and the average drill gas was 2 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/08/2016 Tripped in the hole from 2513' MD to 2979' MD, filled the drill pipe, and continued to trip in the hole to 4004' MD. Worked in the hole from 4018' MD to 4143' MD with pack off issues. Used the step rate method up to 5 barrels per minute, then circulated 3.5 bottoms up from 4070' MD to 4004' MD at 800 gallons per minute and 3300 pounds per square inch standpipe pressure. Tripped in the hole from 4004' MD to 4529' MD and step rated up the pumps to 700 gallons per minute, 2500 pounds per square inch standpipe pressure, then drilled ahead to 4612' MD at 750 gallons per minute, 2280 pounds per square inch standpipe pressure, 120 revolutions per minute, 6.5k foot-pounds torque, and 3-5k pounds weight on bit. Cuttings control unit had a pack off in their cuttings hopper and worked to clear it. Serviced the top drive and blocks and continued to drill ahead to 4885' MD at 800 gallons per minute, 2500 pounds per square inch standpipe pressure, 140 revolutions per minute, 7.4k foot-pounds torque and 3-11k pounds weight on bit. Gas: The max drill gas was 44 units and the average drill gas was 41 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/09/2016 Drilled ahead from 4885' MD to 4958' MD at 800 gallons per minute, 2500 pounds per square inch standpipe pressure, 140 revolutions per minute, 7.5k foot-pounds torque and 3-11k pounds weight on bit. Took check shot surveys and continued to drill ahead to 5308' MD and obtained slow pump rates. Serviced the top drive and blocks, then continued to drill ahead to 5494' MD at 800 gallons per minute, 2480 pounds per square inch standpipe pressure, 140 revolutions per minute, 9k foot-pounds torque, 7-9k pounds weight on bit. Obtained slow pump rates, then continued to drill ahead to 6147' MD at 800 gallons per minute, 2520 pounds per square inch standpipe pressure, 140 revolutions per minute, 6-8k foot-pounds torque, and 7-8k pounds weight on bit. Gas: The max drill gas was 123 units and the average drill gas was 59 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/10/2016 Drilled ahead from 6147' MD to 6799' MD at 800 gallons per minute, 2580 pounds per square inch standpipe pressure, 140 revolutions per minute, 7-10k pounds weight on bit. Obtained slow pump rates. Serviced the top drive and blocks. Performed a kick while drilling drill then drilled ahead to 6850' MD at 800 gallons per minute, 2580 pounds per square inch standpipe pressure, 140 revolutions per minute, 7-10k pounds weight on bit. Continued to drill ahead to 7513' MD at 800 gallons per minute, 2560 pounds per square inch standpipe pressure, 140 revolutions per minute, 10k foot-pounds torque and 4-8k pounds weight on bit. Gas: The max drill gas was 192 units and the average drill gas was 91 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/11/2016 Drilled ahead from 7525' MD to 7916' MD at 800 gallons per minute, 2660 pounds per square inch standpipe pressure, 140 revolutions per minute, 13k foot-pounds torque, 7-18k pounds weight on bit and obtained slow pump rates. Serviced the top drive and blocks. Drilled ahead to 7943' MD at 800 gallons per minute, 2690 pounds per square inch standpipe pressure, 140 revolutions per minute, 13k foot-pounds torque, 7-18k pounds weight on bit. Dropped 6 closing tags and circulated them down and verified the reamer was closed with a pressure increase. Quadrant reamed at 800 gallons per minute, 3100 pounds per square inch standpipe pressure, and 140 revolutions per minute from 7943' MD to 7817' MD. Lubricated out of the hole to 7817' MD at 88 gallons per minute, 190 pounds per square inch standpipe pressure, 40 revolutions per minute, 9k foot-pounds torque. Circulated 3.5 bottoms up while working a full stand then back reamed from 4004' MD to 2979' MD at 800 gallons per minute, 2630 pounds per square inch standpipe pressure, 100 revolutions per minute, 5.6k foot-pounds torque. Gas: The max drill gas was 105 units and the average drill gas was 71 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/12/2016 Back reamed from 2979' MD to 650' MD at 800 gallons per minute, 2500 pounds per square inch standpipe pressure and 140 revolutions per minute. Laid down the bottom hole assembly from 650' MD to 74' MD and downloaded the MWD tools. Finished laying down the bottom hole assembly, then cleaned and cleared the rig floor. Serviced the top drive then changed the rams to 9 5/8" and tested them. Rigged up the Tesco running equipment and held a pre job safety meeting for running the liner. Ran the liner from surface to 482' MD. Gas: No significant gas was detected. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/13/2016 Tripped in the hole with the 9 5/8" liner from 482' MD to 3963' MD. Rigged down the Tesco equipment and changed out elevators. Picked up and installed the liner packer hanger from 3983' MD to 4024' MD, serviced the top drive and blocks. Tripped in the hole to 7943' MD on 5.5" drill pipe, then installed the cement head and cement lines. Staged up the pumps to 255 gallons per minute with 1155 pounds per square inch pump pressure and performed the cement job per Halliburton cement pumping schedule. Bumped the plug at 4105 strokes and pressured up to 1450 pounds per square inch standpipe pressure. Gas: The max circulation gas was 105 units and the average was 8 units. Fluids: There were 0 barrels of Bara ECD lost down hole for 100 percent returns on cement job. 02/14/2016 Set the 9-5/8" liner top hanger. Pressure tested the liner packer and circulated 1 bottoms up. Tripped out of the hole from 3868' MD to 39' MD. Laid down the Baker liner running tool, cleaned and cleared the rig floor, and nippled down the blowout preventers. Installed the multi bowl and tested it. Set the blowout preventer stack and finished nippling up the blowout preventers. Changed the rams to 5.5" and tested them. Laid down testing equipment and installed the wear ring. Picked up the bottom hole assembly and staged it on the floor. Pressure tested the casing to 3500 pounds per square inch. Gas: The max circulation gas was 75 units and the average was 4 units. Fluids: There were 0 barrels of Bara ECD lost down hole. 02/15/2016 Picked up the bottom hole assembly from surface to 568' MD. Picked up drill pipe to 3550' MD. Tripped in the hole to 7649' MD. Serviced the top drive. Reamed and washed down from 7649' MD to 7819' MD at 300 gallons per minute, 800 pounds per square inch standpipe pressure, 40 revolutions per minute, and 12k pounds weight on bit. Drilled cement from 7819' MD to 7943' MD at 600 gallons per minute, 2450 pounds per square inch standpipe pressure, 40 revolutions per minute, 10k foot-pounds torque, 5-22k pounds weight on bit. Displaced the well from 10.3 pounds per gallon Bara ECD to 10.2 pounds per gallon LSND. Drilled new hole from 7943' MD to 7968' MD at 600 gallons per minute, 1500 pounds per square inch standpipe pressure, 60 revolutions per minute, 12.9k foot-pounds torque and 3k pounds weight on bit. Performed a Formation Integrity Test to 13 pounds per gallon (728 pounds per square inch standpipe pressure.) Tripped out of the hole to 1687' MD. Gas: No significant gas was detected. Fluids: There were 0 barrels of LSND lost down hole. 02/16/2016 Tripped out of the hole to 568’ MD. Laid down Bottom Hole Assembly # 10 from 568’ MD to surface. Serviced the top drive and change out dies on the Iron Roughneck. Removed the wear ring, picked up testing tools and tested the blowout preventers. Picked up, made up, and tested the MPD equipment. Laid down all testing equipment. Picked up Bottom Hole Assembly #11. Found the PCDC wasn't working. Swapped out the PCDC. Continued picking up the bottom hole assembly and tested the RipTide reamer and MWD tools. Tripped in the hole from to 3969’ MD. Gas: No significant gas was detected. Fluids: There were 0 barrels of LSND lost down hole. 02/17/2016 Tripped in the hole from 3969’ MD to 7882’ MD. Cut and slipped the drilling line and serviced the top drive. Reamed and washed down from 7882’ MD to 7968’ MD, then drilled ahead from 7968’ MD to 8102’ MD at 700 gallons per minute, 2250 parts per square inch standpipe pressure, 17k foot-pounds torque, 60 revolutions per minute, 25k pounds weight on bit. Dropped the reamer tags and opened the RipTide reamer. Drilled ahead from 8102’ MD to 9092’ MD at 750 gallons per minute, 2250 pounds per square inch standpipe pressure, 16-17k foot-pounds torque, 25-28k pounds weight on bit and serviced the top drive. Gas: The max drill gas was 302 units at 8499’ MD; average drill gas of 131 units. Max connection gas of 301 units at 8440’ MD; average connection gas of 144 units. Fluids: There were 0 barrels of LSND lost down hole. 02/18/2016 Circulated two bottoms up at 9092' MD at 750 gallons per minute. Spotted a lost circulation material pill across the Torok formation, pumping at 225 gallons per minute. Rotated out of the hole without pumps from 9092' MD to 7696' MD. Performed a lost circulation material squeeze per Caelus representative. Reamed and washed down from 7696' MD to 7882’ MD. Ran in the hole on elevators from 7882' MD to 9092' MD. Circulated two bottoms up using the step rate method up to 300 gallons per minute. Removed trip nipple and installed the MPD RCD head. Drilled ahead from 9092' MD to 9620' MD at 750 gallons per minute, 2770 pounds per square inch standpipe pressure, 140 revolutions per minute, 16k foot-pounds torque, 22-27k pounds weight on bit. Serviced the top drive and checked the shaker screens. Gas: The max drill gas was 258 units at 9604’ MD; average drill gas of 87 units. Max connection gas of 135 units at 9558’ MD; average connection gas of 104 units. Fluids: There were 0 barrels of LSND lost down hole. 02/19/2016 Drilled ahead from 9620' MD to 9651' MD at 750 gallons per minute, 2770 pounds per square inch standpipe pressure, 20-21k foot-pounds torque, 140 revolutions per minute, 20-28k pounds weight on bit. Serviced the rig and installed a new Iron Roughneck. Drilled ahead from 9651' MD to 10560' MD at 750 gallons per minute, 2810 pounds per square inch standpipe pressure, 20-22k foot-pounds torque, 25-30k pounds weight on bit. Serviced the top drive and blocks. Gas: The max drill gas was 496 units at 10340’ MD; average drill gas of 176 units. Max connection gas of 453 units at 10490’ MD; average connection gas of 290 units. Fluids: There were 0 barrels of LSND lost down hole. 02/20/2016 Drilled ahead from 10573’ MD to 10862’ MD at 750 gallons per minute, 2880 pounds per square inch standpipe pressure, 23-25k foot-pounds torque, 140 revolutions per minute, 27-30k pounds weight on bit and serviced the top drive. Drilled ahead from 10862’ MD to 11049’ MD at 750 gallons per minute, 2900 pounds per square inch standpipe pressure, 25-27k foot-pounds torque, 140 revolutions per minute, 24-30k pounds weight on bit, then performed a kick while drilling drill. Drilled ahead from 11049’ MD to 11362’ MD at 675 gallons per minute, 2520 pounds per square inch standpipe pressure, 120 revolutions per minute, 27k foot-pounds torque, 28-30k pounds weight on bit. Serviced the top drive and blocks and pumped down the reamer closing tags, closing the reamer. Pumped a 50 barrel, 12.2 pound per gallon, high- viscosity sweep. Performed a quadrant ream from 11362’ MD to 11258’ MD at 675 gallons per minute, 2950 pounds per square inch standpipe pressure, 100 revolutions per minute, 19k foot- pounds torque. Repaired the MPD choke line and continued quadrant reaming from 11362’ MD to 11258’ MD at 730 gallons per minute, 100 revolutions per minute, 19k foot-pounds torque. Gas: The max drill gas was 458 units at 11316’ MD; average drill gas of 103 units. Max connection gas of 241 units at 11142’ MD; average connection gas of 173 units. Max circulation gas of 233 units; average circulation gas of 120 units. Fluids: There were 0 barrels of LSND lost down hole. 02/21/2016 Quadrant reamed from 11362' MD to 11220' MD at 775 gallons per minute, 100 revolutions per minute. Displaced the well from 10.2 pound per gallon LSND to 12.3 pound per gallon LSND kill weight mud. Removed the MPD RCD bearing and installed the trip nipple. Lubed out of the hole from 11359' MD to 8100' MD. Pulled into the shoe with no pumps from 8100' MD to 7940' MD. Blew down the top drive and kill lines. Tripped out of the hole from 7940' MD to 708' MD. Laid down Bottom Hole Assembly #11 from 708' MD to 113' MD. Gas: The max trip gas was 121 units; average trip gas of 19 units. Fluids: There were 23 barrels of LSND lost down hole. 02/22/2016 Laid down Bottom Hole Assembly #11 from 113' MD to surface and serviced the top drive. Removed the wear ring and installed the blowout preventer test plug. Tested the blowout preventer. Rigged down test equipment and pulled the test plug. Rigged up Tesco to run casing. Rigged down and centered the rig over the well. Rigged back up and began running 7" casing from surface to 4391' MD. Gas: No significant gas was detected Fluids: There were 0 barrels of LSND lost down hole. 02/23/2016 Ran 7" casing from 4391' MD to 7772' MD, filling every joint and topping off every 5 joints. Serviced the top drive and greased the crown. Ran casing from 7772' MD to 7931' MD. Function tested the blowout preventer rams. Ran 7" casing from 7931' MD to 11317' MD. Made up the landing joint and landed the 7" casing. Attempted to circulate unsuccessfully using the step rate method. Pulled the hanger off the load shoulder and attempted to circulate with 1100 pounds per square inch max standpipe pressure. Gas: The max trip gas was 20 units; average trip gas of 0 units. Fluids: There were 0 barrels of LSND lost down hole 02/24/2016 Attempted to break circulation unsuccessfully. Pulled 7" casing from 11355' MD to 11028’ MD, working to establish circulation. Established circulation at 11 gallons per minute using the step rate method. Ran in the hole with 7" casing from 11028’ MD to 11355’ MD and landed the hanger. Displaced the annulus to 10.2 pound per gallon LSND using the step rate method. Blew down the top drive and rigged down Tesco. Made up the cement head. Held a pre-job safety meeting for the 1st stage cement job. Performed the 1st stage by pumping 10 barrels of seawater, 41 barrels of tuned spacer and 88 barrels of cement, followed by 20 barrels seawater. Displaced cement with rig pumps. Bumped the plug and pressured up to 3375 pound per square inch to open the ES cementer. After establishing circulation through the ES cementer, the well was displaced over to 10.2 pound per gallon BaraECD mud. Held a pre-job safety meeting for the 2nd stage cement job. Performed the 2nd stage cement job, pumping 10 barrels of spacer, 40 barrels of tail cement, and 20 barrels of seawater. Began displacing with rig pumps, pumping 10.2 pound per gallon LSND. Gas: The max trip gas was 624 units; average trip gas of 47 units. Fluids: There were 0 barrels of LSND lost down hole 02/25/2016 Continued with the 2nd stage cement job, bumping the plug with 10.2 pound per gallon LSND mud. Rigged down the cement head and blew down the cement lines. Made up the setting sleeve and pulled the landing joint. Drained the stack, set pack off, and tested the cement to 5000 pounds per square inch for 10 minutes. Laid down 13 joints of heavy weight drill pipe. Laid down 266 joints of 5.5" drill pipe in the mouse hole. Changed out a hose on the iron roughneck. Picked up blowout preventer test tools and installed the 4" test joint and plug. Changed out the upper and lower rams, internal blowout preventer and saver sub. Made up the TIW dart and pump. Gas: The max trip gas was 7 units; average trip gas of 1 unit. Fluids: There were 0 barrels of LSND lost down hole 02/26/2016 Tested the blowout preventer. Rigged up and tested the MPD lines. Pulled the test plug, vacuumed out the stack, pulled the trip nipple, and installed the cap. Laid down test tools and rigged down MPD. Removed the test head and installed the trip nipple. Removed the test plug and installed the wear ring. Picked up 4" drill pipe singles from the pipe shed to 7701' MD (240 joints) and flushed the drill pipe volume at 6 barrels per minute. Tripped out of the hole to surface, racking back pipe in the derrick. Picked up clean out Bottom Hole Assembly #12 to 385' MD, then cut and slipped drilling line. Serviced the top drive and tripped in the hole with 4" drill pipe singles. Gas: No significant gas was detected. Fluids: There were 0 barrels of LSND lost down hole 02/27/2016 Picked up 4" drill pipe from 771’ MD to 8505’ MD. Drilled cement from 8505’ MD to 8632’ MD. Pressure tested the 7” casing to 2500 pounds per square inch for 5 min, then drilled out the ES cementer to 8634’ MD at 200 gallons per minute. Continued to pump and rotate to 8680’ MD. Tripped in the hole with 4" drill pipe singles to 10965’ MD, then serviced the top drive and repaired a sensor on the top drive. Tripped in the hole with 4” drill pipe singles to 11158’ MD. Washed and reamed down to 11183’ MD at 200 gallons per minute. Pressure tested the 7” casing to 4000 pounds per square inch for 30 minutes. Drilled out the baffle adapter to 11185’ MD and began drilling out cement to 11266’ MD at 200 gallons per minute, 1950 pounds per square inch standpipe pressure. Gas: The max trip gas was 4 units; average trip gas of 1 unit. Fluids: There were 0 barrels of LSND lost down hole 02/28/2016 Continued to drill out the shoe track and rat hole to 11362’ MD. Circulated one bottoms up at 11362’ MD. Performed Bat Sonic logs from 11362’ MD to 9852’ MD and serviced the top drive. Tripped out of the hole from 9852’ MD to 8882’ MD, then perform Bat Sonic logs from 8882’ MD to 7426’ MD. Pumped a dry job and blew down the top drive. Tripped out of the hole from 7426’ MD to 386’ MD. Laid down Bottom Hole Assembly #12 to surface. Picked up test tools and pulled the wear bushing. Installed the test plug, picked up and made up the TIW dart, and filled the stack with seawater. Gas: The max trip gas was 11 units; average trip gas of 1 unit. Fluids: There were 0 barrels of LSND lost down hole 02/29/2016 Tested the blowout preventer. Pulled the test plug and installed the wear bushing. Picked up bottom hole assembly #13, shallow pulse tested MWD tools and loading nukes to 408' MD. Tripped in the hole to 11277’ MD. Removed the trip nipple and installed the MPD RCD bearing. Serviced the top drive and greased the blocks. Displaced the well from 10.2 pound per gallon LSND to 8.0 pound per gallon BaraECD mud. Drilled ahead from 11362’ MD to 11382’ MD. Tripped out of the hole to 11354’ MD and performed a formation integrity test to 12.5 pounds per gallon equivalent mud weight. Tripped in the hole to 11382’ MD and drilled ahead to 11442’ MD at 230 gallons per minute, 2350 pounds per square inch standpipe pressure, 80 revolutions per minute, 10.8k-12.1k foot-pounds torque, 3-8k pounds weight on bit. Gas: The max drill gas was 203 units at 11432’ MD with an average drill gas of 99 units. The max connection gas was 99 units. The max trip gas was 11 units. Fluids: There were 0 barrels of BaraECD lost down hole Geology: Sandstone (100%): clear, light brown, black, transparent and opaque, medium to coarse grained, elongate to subspherical, angular to rounded, unconsolidated, with trace siderite. 03/01/2016 Drilled ahead from 11442’ MD to 11661’ MD at 227 gallons per minute, 2330 pound per square inch standpipe pressure, 100 revolutions per minute, 11.5k-11.8k foot-pounds torque, 5-10k pounds weight on bit. Circulated a bottoms up and performed a pore pressure test. Drilled ahead from 11661’ MD to 13582’ MD at 230 gallons per minute, 2480 pound per square inch standpipe pressure, 140 revolutions per minute, 9.1k-11k foot-pounds torque, 2-5k pounds weight on bit. Serviced the top drive and greased the blocks. Gas: The max drill gas was 442 units at 12498’ MD with an average drill gas of 236 units. The max connection gas was 454 units at 11661’ MD with an average connection gas of 219 units. Fluids: There were 0 barrels of BaraECD lost down hole Geology: Sandstone (100%): clear, light brown, black, transparent to translucent, very fine to fine grained, subspherical, subrounded to rounded, unconsolidated, with trace siderite, pyrite, and siltstone. 03/02/2016 Circulated at 230 gallons per minute while rebooting the Sperry computer system. Drilled ahead from 13582’ MD to 14562’ MD at 230 gallons per minute, 2650 pounds per square inch standpipe pressure, 140 revolutions per minute, 11.2k foot-pounds torque, 0-10k pounds weight on bit. Obtained slow pump rates. Performed a kick while drilling drill. Drilled ahead from 14548’ MD to 15704’ MD at 230 gallons per minute, 2710 pounds per square inch standpipe pressure, 140 revolutions per minute, 11.3k foot-pounds torque, 4-9k pounds weight on bit. Obtained slow pump rates. Performed a kick while drilling drill. Serviced the top drive and blocks. Gas: The max drill gas was 574 units at 15252’ MD with an average drill gas of 301 units. The max connection gas was 492 units at 15318’ MD with an average connection gas of 343 units. Fluids: There were 0 barrels of BaraECD lost down hole Geology: Sandstone (100%): clear, tan, transparent to translucent, very fine to fine grained, spherical, subrounded to rounded, unconsolidated, quartzitic very slightly silty, with trace siderite and pyrite. 03/03/2016 Drilled ahead from 15704’ MD to 16572’ MD at 230 gallons per minute, 2730 pounds per square inch standpipe pressure, 140 revolutions per minute, 12.4k foot-pounds torque, 5-10k pounds weight on bit, then obtained slow pump rates. Drilled ahead from 16572’ MD to 17224’ MD at 230 gallons per minute, 2760 pounds per square inch standpipe pressure, 140 revolutions per minute, 12.2k foot-pounds torque, 3-10k pounds weight on bit and obtained slow pump rates. Circulated at 230 gallons per minute, 140 revolutions per minute while waiting on orders on what to do about the dog leg. Reamed at 60 feet per hour from 17200’ MD to 17206’ MD two times at 180 gallons per minute, 140 revolutions per minute, and from 17200’ MD to 17212’ MD two times at 180 gallons per minute, 140 revolutions per minute. Drilled ahead from 17224’ MD to 17343’ MD at 230 gallons per minute, 2830 pounds per square inch standpipe pressure, 80 revolutions per minute, 12.2k foot-pounds torque, 3-8k pounds weight on bit. Serviced the top drive and blocks. Gas: The max drill gas was 577 units at 17191’ MD with an average drill gas of 317 units. The max connection gas was 531 units at 16860’ MD with an average connection gas of 361 units. Fluids: There were 0 barrels of BaraECD lost down hole Geology: Sandstone (100%): clear, light brown, transparent to translucent, very fine to fine grained, spherical to subelongate, subangular to rounded, unconsolidated, quartzitic, with occasional siltstone and pyrite. 03/04/2016 Drilled ahead from 17343’ MD to 17661’ MD at 230 gallons per minute, 2800 pounds per square inch standpipe pressure, 100 revolutions per minute, 12.8k foot-pounds torque, 0-10k pounds weight on bit. Reamed from 17640’ MD to 17661’ MD at 100 revolutions per minute, 230 gallons per minute. Drilled ahead from 17661’ MD to 18148’ MD at 230 gallons per minute, 2850 pounds per square inch standpipe pressure, 140 revolutions per minute, 13.4k foot-pounds torque, 5-10k pounds weight on bit. Obtained slow pump rates. Drilled ahead from 18148’ MD to 18562’ MD at 230 gallons per minute, 2850 pounds per square inch standpipe pressure, 140 revolutions per minute, 13.4k foot-pounds torque, 5-10k pounds weight on bit. Obtained slow pump rates. Restarted the MWD computer after it went down. Drilled ahead from 18562’ MD to 18811’ MD at 230 gallons per minute, 2870 pounds per square inch standpipe pressure, 140 revolutions per minute, 12k foot-pounds torque, 3-5k pounds weight on bit. Back reamed from 18811’ MD to 18400’ MD at 200 gallons per minute, 2450 pounds per square inch standpipe pressure, 90 revolutions per minute, 9.5k foot-pounds torque. Gas: The max drill gas was 577 units at 18170’ MD with an average drill gas of 227 units. The max connection gas was 404 units at 18017’ MD with an average connection gas of 235 units. Fluids: There were 0 barrels of BaraECD lost down hole Geology: Sandstone (0-100%): clear, tan, transparent to translucent, very fine to fine grained, spherical to subspherical, subrounded to rounded, well sorted, unconsolidated, quartzitic, with occasional siltstone and pyrite. Siltstone (0-100%): brown, light grey, firm, elongate, well sorted, sandy, with rare pyrite. 03/05/2016 Performed a pore pressure test at 18400’ MD, returned inconclusive results. Circulated and conditioned mud at 240 gallons per minute, 90 revolutions per minute. Performed a second pore pressure test at 18400’ MD, resulting in 8.894 pounds per gallon equivalent mud weight (225 pound per square inch) with 8.2 pound per gallon mud weight. Back reamed at 240 gallons per minute, 140 rpm from 18400’ MD to the shoe at 11277’ MD. No pressure spikes were observed while back reaming. Tripped in the hole from 11277’ MD to 17246’ MD, filling pipe every 30 stands. Gas: The max trip gas was 333 units, the bottoms up from the second pore pressure test; average trip gas was 14 units. Fluids: There were 0 barrels of BaraECD lost down hole 03/06/2016 Tripped in the hole from 17246’ MD to 18440’ MD, then began circulating and conditioning mud at 18440’ MD, staging up pumps to 5 barrels per minute. Displaced from 8.2 pound per gallon mud to 10.0 pound per gallon kill weight mud. 10.0 pound per gallon mud was observed at the surface at 7926 strokes, 20 barrels past calculated volume. Removed the MPD RCD bearing and installed the trip nipple. Lubricated out of the hole from 18440’ MD to 11277’ MD at 2 barrels per minute with 10k pounds over pull while pulling into the shoe. Circulated and conditioned mud and pumped a 40 barrel EP-Mud Lube sweep at 210 gallons per minute. Tripped out of the hole from 11277’ MD to 408’ MD, pumping a dry job at 10888’ MD. Laid down Bottom Hole Assembly #13 to surface. Gas: The max trip gas was 366 units, the bottoms up from circulating before pumping kill weight mud; average trip gas was 6 units. Fluids: There were 0 barrels of BaraECD lost down hole 03/07/2016 Picked up 57 joints of HWDP, circulated 1.5x pipe volume once all the pipe was picked up, and racked the pipe back in the derrick. Pulled the wear bushing, changed the rams, and tested the blowout preventer. Rigged up GBR liner running equipment and ran 4.5” lower completion tubing from surface to 5942’ MD with good displacement. Gas: No significant gas was detected. Fluids: There were 0 barrels of BaraECD lost down hole 03/08/2016 Ran 4.5" completion from 5942' MD to 7280' MD. Made up the liner hanger and the bumper sub magnet assembly to 7469' MD. Circulated 1 liner volume. Ran the 4.5" completion liner in on 4" drill pipe stands from the derrick to 18440' MD. Dropped the ball and pumped it down. Tested to 4000 PSI for 5 minutes. Circulated 1 bottoms up and racked back 1 stand from 11047' MD to 10991' MD. Displaced the well from 10 pounds per gallon MOBM Bara ECD to 10 pounds per gallon Brine. Serviced the top drive. Laid down the 4" heavy weight drill pipe to 9262' MD. Tripped out of the hole racking back 4" drill pipe in the to 3840'MD. Currently pulling out of the hole. Gas: The max trip gas was 94 units and the average trip gas was 5 units. Fluids: There were 0 barrels of BaraECD or Brine lost down hole 03/08/2016 Completed tripping in the hole with 4" drill pipe. Attended the pre-job safety meeting for running the Frac Tubing. Began running in the hole at 04:30 and continued until 23:00. There were no gains or losses and no gas. On standby to perform pressure tests at the time of report. Gas: No significant gas detected. Fluids: There were 0 barrels of Brine lost down hole 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 16000 17000 18000 19000 20000 0 5 10 15 20 25 30 35 40 45Measured Depth Rig Days Actual WELL NAME: ODSN-1A OPERATOR:Caelus Energy MUD CO: Halliburton RIG: Nabors 19AC SPERRY JOB: AK-AM-903090400 Days vs. Depth Halliburton SDL Arrived on Location 29 Jan 2016 LOCATION: Oooguruk AREA: North Slope Borough STATE: Alaska SPUD: TD: WELL NAME: ODSN-1A OPERATOR:Caelus Energy MUD CO: Halliburton RIG: Nabors 19AC SPERRY JOB: AK-AM-903090400 Days vs. Depth LOCATION: Oooguruk AREA: North Slope Borough STATE: Alaska SPUD: TD: WELL NAME: ODSN-1A OPERATOR:Caelus Energy MUD CO: Halliburton RIG: Nabors 19AC SPERRY JOB: AK-AM-903090400 Days vs. Depth LOCATION: Oooguruk AREA: North Slope Borough STATE: Alaska SPUD: TD: WELL NAME: ODSN-1A OPERATOR:Caelus Energy MUD CO: Halliburton RIG: Nabors 19AC SPERRY JOB: AK-AM-903090400 Days vs. Depth LOCATION: Oooguruk AREA: North Slope Borough STATE: Alaska SPUD: TD: WELL NAME: ODSN-1A OPERATOR:Caelus Energy MUD CO: Halliburton RIG: Nabors 19AC SPERRY JOB: AK-AM-903090400 Days vs. Depth LOCATION: Oooguruk AREA: North Slope Borough STATE: Alaska SPUD: TD: WELL NAME: ODSN-1A OPERATOR:Caelus Energy MUD CO: Halliburton RIG: Nabors 19AC SPERRY JOB: AK-AM-903090400 Days vs. Depth LOCATION: Oooguruk AREA: North Slope Borough STATE: Alaska SPUD: TD: WELL NAME: ODSN-01A OPERATOR: Caelus Energy Alaska, LLC MUD CO: Halliburton - Baroid RIG: Nabors 19AC SPERRY JOB: AK-AM-0903090400 Days vs. Depth LOCATION: Oooguruk AREA: North Slope Borough STATE: Alaska SPUD: 5-Feb-2016 TD: 6-Mar-2016 Days vs. Depth TD Production Hole Section 18811' MD, 6329' TVD Off Bot: 21:12 4 Mar 2016 Landed 4.5" Liner 18440' MD, 6239' TVD 08 Mar 2016 Decomplete in Preparation to Sidetrack Well 29 Jan 2016 Commenced 10.625" x 11.75" Intermediate 1 Hole Section On Bot: 00:20 07 Feb 2016 TD Intermediate 1 Hole Section 7943' MD, 5004' TVD Off Bot: 07:40 11 Feb 2016 Landed 9.625" Casing 7940' MD, 5003' TVD 13 Feb 2016 Commenced 8.5" x 9.5" Intermediate 2 Hole Section On Bot: 04:27 17 Feb 2016 LCM Squeeze at Torok 1 Shale Marker Install MPD RCD 18 Feb 2016 TD Intermediate 2 Hole Section 11362' MD, 6272' TVD Off Bot: 21:54 20 Feb 2016 Landed 7" Casing 11354' MD, 6271' TVD 24 Feb 2016 Commenced 6.125" Production Hole Section On Bot: 21:14 29 Feb 2016 WELL NAME:LOCATION: OPERATOR:AREA: SPERRY JOB:STATE: RIG:HOLE SECTION: EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 Difficulties experienced: We did have three times where the Iris or workstation went down. Some trouble shooting has shown that this is not computer issues but rather connection issues. On all three occasions the door was closed or someone bumped the computer rack. The computers would start up immediately and no data was lost. Recommendations: Regularly check all connections. Movement on the rig can shake things loose so it's a good practice to go through all of our connections both in the rack and behind the computers to assure uninterupted service. Innovations and/or cost savings: N/A Nabors 19 AC Intermediate 1 Beverly Hur 13-Feb-2016 What went as, or better than, planned: This section went well as planned, both on the rig and in the unit. Our gas gear performed well and our lag was on target. Also, the calibrations were very accurate as demonstrated by the C1 and Total Hydrocarbon readings having the correct relationship. ODSN-01A Ooguruk Caelus Energy North Slope Borough AK-AM-0903090400 Alaska Surface Data Logging After Action Review Surface Data Logging WELL NAME:LOCATION: OPERATOR:AREA: SPERRY JOB:STATE: RIG:HOLE SECTION: EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 What went as, or better than, planned: This section went well as planned, both on the rig and in the unit. Our gas gear was very accurate, matching between the THA and the chromatograph. No lag adjustment was necessary. While running 7" casing after drilling, the SDL crew caught a leaky valve between pits that would have caused false displacement readings. ODSN-01A Ooguruk Caelus Energy North Slope Borough AK-AM-0903090400 Alaska Nabors 19 AC Intermediate 2 David Durst 25-Feb-2016 Difficulties experienced: The workstation continued to crash occasionally, but after drilling, it crashed and would not restart. Fortunately, we had a backup computer ready to go in the unit, our downtime was minimal. No data was lost. Recommendations: Keep checking the CVE for oil rate and leaks several times per tour. Also, check both dropout jars regularly. The connections in the CVE system need to be checked at least once per tour to make sure that the vibrate function isn't loosening any connections. Innovations and/or cost savings: N/A Surface Data Logging After Action Review WELL NAME:LOCATION: OPERATOR:AREA: SPERRY JOB:STATE: RIG:HOLE SECTION: EMPLOYEE NAME:DATE: Sperry Drilling Confidential Document v 3.0 What went as, or better than, planned: This section went very well, both for SDL and the rig. The sample program went without a hitch, depsite the rig drilling much faster than typical for this section. The CVE continued to work very well. ODSN-01A Oooguruk Caelus Energy North Slope Borough AK-XX-0903058273 Alaska Nabors 19 AC Production David Durst / Kerry Garner 9-Mar-2016 Difficulties experienced: The computer issues seem to be largely resolved, with only a few minor issues only involving a restart of Insite on the workstation; no data was lost. A typical for the production section, a 40 bbl annular correction was applied to adjust for the delay in gas to the surface compared to calculated lag. Recommendations: Make sure to check computer connections to avoid unnecessary restarts. Innovations and/or cost savings: Thinking of a way to build a large version of the spin dryer so that we can spin our large sample volume before drying with heat to speed up dry times. Surface Data Logging After Action Review WELL NAME:ODSN-01A LOCATION:Oooguruk OPERATOR:Caelus Energy Alaska, LLC AREA:North Slope Borough MUD CO:Halliburton - Bariod STATE:Alaska RIG:Nabors 19AC SPUD:5-Feb-2016 SPERRY JOB:AK-AM-0903090400 TD:6-Mar-2016 Marker MD INC AZ TVD TVDSS 10 5/8" Intermediate 1 Hole Section TOW / KOP 4,077 62.3 315.3 3,228.0 3,171.8 Hue 2 (interp from ODSN-1)4,122 63.8 314.3 3,248.2 3,192.0 Hue Res C tied 4,643 62.7 302.8 3,495.9 3,439.7 Hue Res B tied 5,693 63.1 319.4 3,975.8 3,919.6 Hue Res A tied 6,276 62.9 317.6 4,240.0 4,183.8 Brookian 2B Marker 6,377 62.5 316.8 4,286.3 4,230.1 9-5/8" ICP1 Shoe 7,940 63.0 315.8 5,003.0 4,946.8 8 1/2" Intermediate 2 Hole Section Top Torok Sand 7,980 62.9 316.4 5,021.2 4,965.0 Base Torok Sand 8,530 62.4 314.7 5,273.1 5,216.9 Torok 1 Shale 8,901 62.2 313.9 5,444.3 5,388.1 Top HRZ 9,770 62.5 315.4 5,845.3 5,789.1 Base HRZ (Top Kalubik Shale)10,055 62.2 316.5 5,977.0 5,920.8 Kalubik Marker 10,228 65.0 315.7 6,055.5 5,999.3 Top Kuparuk C 10,405 70.4 314.8 6,122.7 6,066.5 LCU (Top Miluveach Shale)10,453 71.8 314.2 6,138.2 6,082.0 BCU (Top Kingak Shale)10,916 84.9 313.4 6,233.6 6,177.4 Top Nuiqsut 11,258 85.1 312.6 6,263.3 6,207.1 Top Nuiqsut::Nuiq_1 11,325 85.1 312.9 6,268.9 6,212.7 7" ICP2 Shoe 11,354 84.8 313.3 6,271.5 6,215.3 6 1/8" Production Hole Section Nuiq_1::Nuiq_2 17,330 90.3 330.8 6,214.2 6,158.0 Nuiq_2::Nuiq_3 17,650 89.4 327.9 6,211.2 6,155.0 Nuiq_3::Nuiq_4 18,115 86.1 323.9 6,212.5 6,156.3 Nuiq_4::Nuiq_5d 18,148 85.3 323.4 6,215.0 6,158.8 Nuiq_5d::Nuiq_5a 18,453 80.4 320.1 6,242.0 6,185.8 Nuiq_5a::Nechelik SH 18,616 75.0 318.8 6,278.9 6,222.7 NechelikSH::Upper Nechelik 18,637 75.0 318.8 6,284.3 6,228.1 Upper Nechelik::Lower Nechelik 18,710 75.1 319.2 6,303.2 6,247.0 TD 6 1/8" Lateral 18,811 75.2 319.3 6,329.0 6,272.8 Formation Tops ODSN-01A Caelus Energy Alaska, LLC Halliburton - Baroid Nabors 19AC AK-AM-0903090400 Date Depth Wt Vis PV YP Gels Filt R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Sd Pm pH MBT Pf/Mf Chlor Hard ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%%ppb Eqv mg/l Ca++ 29-Jan 18011 8.50 ----------------Seawater 30-Jan 18011 8.50 ----------------Displacing to clean seawater 31-Jan 18011 8.50 ----------------PU casing scraper BHA 1-Feb 18011 8.50 ----------------Testing BOPE 2-Feb 18011 8.50 ----------------PU casing scraper BHA 3-Feb 18011 8.50 ----------------RIH with whipstock Date Depth Wt Vis PV YP Gels HTHP R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Alka POM Excess Lime Elec Stab CaCl2 WPS LGS/HGS ASG Remarks ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%ml ppb volts ppb ppm ppb ASG 4-Feb 18011 10.20 65 41 20 10/26/33 - 102/61/46/28/10/8 0/1 9.6 62.5/26.5 0.01 - - - - - - Laying down BHA 5-Feb 4090 10.2 113 42 22 15/32/45 1.8 106/64/45/26/10/8 0/1 9.4 66.3/33.7 - 2.85 440 8.21 144,536 11.04/123.62 3.977 Milling 11 3/4" Window 6-Feb 4129 10.2 125 45 24 18/42/58 1.8 114/69/49/31/10/8 0/1 9.4 66.3/33.7 - 2.33 384 8.21 141,510 11.27/120.83 3.99 Tripping in the hole 7-Feb 4529 10.2 128 44 24 18/45/60 1.6 112/68/51/31/10/9 0/1 9.4 66.3/33.7 - 2.2 496 8.69 144,357 11.3/120.39 3.989 Tripping in the hole 8-Feb 4782 10.2 124 47 26 18/49/61 1.6 120/73/55/34/10/9 0/1 9.3 58.0/31.0 - 4.53 523 8.21 144,439 11.26/119.27 3.988 Drilling Ahead 9-Feb 6033 10.2 86 40 23 20/42/56 1.6 103/63/46/28/10/9 0/1 9.4 59.0/30.0 - 4.14 554 9.18 148,184 11.2/119.5 3.99 Drilling Ahead 10-Feb 7037 10.2 85 33 22 20/46/60 1.6 88/55/42/27/10/9 0/1 9.9 60.5/28.0 - 4.14 513 9.18 157,106 18.92/114.82 3.864 Drilling Ahead 11-Feb 7943 10.2 77 32 21 18/37/53 1.6 85/53/36/25/10/8 0/1 9.8 60.5/28.0 - 4.01 456 8.21 157,478 18.09/115.6 3.868 Backreaming out of the hole 12-Feb 7943 10.2 84 34 20 18/43/54 1.6 88/54/37/26/10/9 0/1 9.8 60.5/28.0 - 4.01 438 8.21 157,478 18.09/115.6 3.877 Running in with 9 5/8" liner 13-Feb 7943 10.3 108 36 21 18/46/55 1.6 91/55/37/24/10/8 0/1 9.8 60.5/28.0 - 3.88 417 8.21 157,478 11.26/126.63 3.999 Cementing 9 5/8" liner 14-Feb 7943 10.3 132 38 19 18/46/53 1.6 95/57/37/24/10/8 0/1 10 61.0/27.5 - 4.01 412 8.21 149,171 12.13/127.48 3.987 Picking up BHA 8-Feb 4782 10.2 124 47 26 18/49/61 1.6 120/73/55/34/10/9 0/1 9.3 58.0/31.0 - 4.53 523 8.21 144,439 11.26/119.27 3.988 Drilling Ahead 9-Feb 6033 10.2 86 40 23 20/42/56 1.6 103/63/46/28/10/9 0/1 9.4 59.0/30.0 - 4.14 554 9.18 148,184 11.2/119.5 3.99 Drilling Ahead 10-Feb 7037 10.2 85 33 22 20/46/60 1.6 88/55/42/27/10/9 0/1 9.9 60.5/28.0 - 4.14 513 9.18 157,106 18.92/114.82 3.864 Drilling Ahead 11-Feb 7943 10.2 77 32 21 18/37/53 1.6 85/53/36/25/10/8 0/1 9.8 60.5/28.0 - 4.01 456 8.21 157,478 18.09/115.6 3.868 Backreaming out of the hole 12-Feb 7943 10.2 84 34 20 18/43/54 1.6 88/54/37/26/10/9 0/1 9.8 60.5/28.0 - 4.01 438 8.21 157,478 18.09/115.6 3.877 Running in with 9 5/8" liner 13-Feb 7943 10.3 108 36 21 18/46/55 1.6 91/55/37/24/10/8 0/1 9.8 60.5/28.0 - 3.88 417 8.21 157,478 11.26/126.63 3.999 Cementing 9 5/8" liner 14-Feb 7943 10.3 132 38 19 18/46/53 1.6 95/57/37/24/10/8 0/1 10 61.0/27.5 - 4.01 412 8.21 149,171 12.13/127.48 3.987 Picking up BHA Date Depth Wt Vis PV YP Gels Filt R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Sd Pm pH MBT Pf/Mf Chlor Hard ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%%ppb Eqv mg/l Ca++ 15-Feb 7968 10.20 56 13 23 7/9/10 2.4 49/36/29/22/9/7 1/0 6.5 4.0/88.3 - - 10.1 - 0.30/0.65 24,000 - Tripping out of the hole 16-Feb 7968 10.20 60 15 20 7/9/10 2.2 50/35/29/21/9/8 1/0 6.8 4.0/88.0 -0.55 10.0 -0.30/0.65 23,500 360 Tripping in the hole 17-Feb 8794 10.20 50 14 26 8/11/13 2.6 54/40/33/25/11/9 2/0 7.4 4.0/87.5 -0.60 9.4 2.5 0.15/0.70 21,500 640 Drilling Ahead 18-Feb 9372 10.20 60 14 35 10/16/18 4.0 63/49/42/33/12/10 2/0 7.9 3.0/88.0 0.01 0.80 10.0 7.0 0.25/0.80 22,000 620 Drilling Ahead 19-Feb 10445 10.15 49 13 30 11/20/24 5.0 56/43/38/29/12/10 2/0 7.9 3.0/88.0 0.01 1.00 10.0 10.0 0.40/1.80 22,000 320 Drilling Ahead 20-Feb 11358 10.25 49 12 34 12/22/28 5.8 58/46/42/32/13/11 2/0 8.8 3.0/87.0 0.01 1.20 10.6 14.0 0.45/1.80 23,000 200 Quadrant Reaming 21-Feb 11362 12.30 52 18 29 7/8/10 2.0 65/47/38/29/9/8 2/0 12.1 4.0/76.0 -1.34 10.5 -0.85/2.00 158,000 200 POOH, L/D BHA 22-Feb 11362 10.20 48 11 19 10/18/21 5.4 41/30/26/20/9/8 2/0 7.0 2.0/89.0 0.01 0.80 10.0 10.0 0.30/1.45 39,000 420 Running 7" Casing 23-Feb 11362 10.20 50 11 21 11/19/23 5.2 43/32/27/22/10/9 2/0 6.8 2.0/89.0 0.01 1.50 10.6 10.0 0.50/1.85 42,500 420 Attempt to circulate casing 24-Feb 11362 10.20 52 13 20 10/16/26 5.8 46/33/29/21/9/8 2/0 7.2 2.0/89.0 0.01 3.20 11.9 10.0 1.20/3.20 36,000 280 Land 7" Casing, perform cement job 25-Feb 11362 10.20 50 14 19 8/13/23 6.0 47/33/26/19/9/8 2/0 7.0 2.0/89.0 0.01 3.50 12.0 10.0 1.30/3.40 39,500 300 L/D DP, Change Rams SPERRY JOB:TD:6-Mar-2016 Intermediate 2 - LSND WBM Surface - Spud Mud Seawater Remarks WELL NAME:LOCATION:Oooguruk OPERATOR:AREA:North Slope Borough MUD CO:STATE:Alaska RIG:SPUD: Intermediate 1 - Bara ECD MOBM 5-Feb-2016 Remarks Water and Oil Based Mud Record 26-Feb 11362 10.20 52 14 20 7/18/20 6.0 48/34/28/20/9/8 2/0 7.2 2.0/89.0 0.01 3.80 12.1 10.0 0.10/2.90 36,000 400 P/U 4" DP, P/U BHA 27-Feb 11362 10.25 56 14 21 7/21/24 5.8 49/35/29/21/9/8 2/0 7.2 2.0/89.0 0.01 3.70 12.2 10.0 1.30/3.10 36,500 420 TIH, Drill Cement 28-Feb 11362 10.15 47 12 18 7/12/20 6.0 42/30/23/16/8/7 2/0 7.6 2.0/88.5 0.01 3.40 12.1 10.0 1.30/3.10 37,500 420 MAD Pass, TOOH, L/D BHA Date Depth Wt Vis PV YP Gels HTHP R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Alka POM Excess Lime Elec Stab CaCl2 WPS LGS/HGS ASG Remarks ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%ml ppb volts ppb ppm ppb ASG 29-Feb 11362 8.00 47 11 12 5/7/8 2.0 34/23/18/13/5/4 0/2 1.4 65.9/31.0 -2.46 189 12.28 158,325 11.62/1.19 2.695 P/U BHA, TIH, FIT Test, Drill Ahead 1-Mar 13337 8.00 51 13 13 6/9/11 2.0 39/26/21/25/6/5 0/2 1.1 65.0/32.0 -3.37 323 13.06 162,095 10.08/0.61 2.658 Drilling Ahead 2-Mar 15470 8.05 54 15 16 8/10/14 2.0 46/31/25/17/7/6 0/2 1.6 65.0/31.8 -2.33 424 15.97 157,610 14.52/0.02 2.601 Drilling Ahead 3-Mar 17317 8.00 54 12 14 6/9/11 2.0 38/26/21/16/6/5 0/2 1.6 67.7/29.0 -2.72 496 13.06 167,135 14.24/0.32 2.622 Drilling Ahead 4-Mar 18811 8.10 49 12 14 6/10/13 2.0 38/26/22/15/6/5 0/2 2.7 68.8/27.0 -2.46 552 11.12 159,064 24.51/0.66 2.626 TD Production, BROOH 5-Mar 18811 8.10 51 12 16 7/11/14 2.2 40/28/23/17/7/6 0/2 2.8 69.7/26.0 -1.42 861 11.51 168,428 25.26/0.21 2.608 PPT, BROOH to shoe, TIH 6-Mar 18811 10.00 82 26 16 13/37/46 1.8 68/42/32/22/9/8 0/2 8.7 63.3/26.5 -2.59 501 9.18 157,971 7.11/116.11 4.056 LOOH, L/D BHA 7-Mar 18811 10.00 88 25 18 13/36/45 1.8 68/43/33/22/9/8 0/2 8.9 63.0/26.5 -2.85 509 8.21 158,363 12.01/112.04 3.964 Run 4.5" Lower Completions Date Depth Wt Vis PV YP Gels HTHP R600/R300/R200/R100/ R6/R3 Cake Solids Oil/Water Alka POM Excess Lime Elec Stab CaCl2 WPS LGS/HGS ASG Remarks ft - MD ppg sec lb/100 lb/100ft2 m/30m Rheometer 32nds %%ml ppb volts ppb ppm ppb ASG 8-Mar 18811 10.00 27 - - - - - - - - - - - - - - - TOOH w/ 4" DP 9-Mar 18811 10.00 28 - - - - - - - - - - - - - - - RIH w/4.5" Tubing Casing Record 16" Conductor @ 158' MD, 158'TVD 9.625" Liner @ 7940' MD, 5003'TVD 11.75" Casing @ 4099' MD, 3238'TVD Production - Bara ECD MOBM Seawater 7" Casing @ 11354' MD, 6271'TVD Water and Oil Based Mud Record BHA#SDL RUN #Bit #Bit Type Bit Size Depth In Depth Out Footage Bit Hours TFA AVG ROP WOB (max) RPM (max) SPP (max) FLOW GPM (max)Bit Grade Comments 5 100 N/A Window Mill 10.50 4077 4077 0 0.00 2.350 0.0 0 0 0 0 -Mill Top Window 6 120 2rr1 Watermelon Mill 10.625 4099 4099 --0.942 ------Mill Bottom Window 7 200 N/A Watermelon Mill 10.625 4129 4129 --0.942 ------Drill Separation 8 300 3 Tricone 10.625 4129 4529 400'8.49 0.942 80.0 35 60 2850 750 0-0-NO-A-E-I-NO BHA Drill Separation 9 400 4 HDBS FXG65s 10.625 4529 7943 3414 75.01 1.353 72.0 10 140 2700 800 1-0-DL-N-X-I-PN-TD Intermediate 1 TD 10 500 5 Hughes GT-C1 8.50 7943 7968 25 0.78 0.920 32.0 12 60 1655 600 2-3-CD-G-E-1-CT-BHA Clean Out Run 11 600 6 HDBS SFE46D 8.50 7968 11362 3394 50.27 1.107 67.5 28 140 2900 775 0-0-ER-N-X-I-NO-TD Intermediate 2 TD 12 700 7 BakerHughes RC216 6.125 11362 11362 0 0.00 0.920 0.0 8 40 2050 200 1-2-ER-G-E-I-PN-BHA Clean Out Run 13 800 8 HDBS MME64 6.125 11362 18811 7449 71.15 0.389 105.0 10 140 2925 230 8-1-BT-N-X-I-LT-TD Production TD WELL NAME:ODSN-01A LOCATION:Oooguruk OPERATOR:Caelus Energy Alaska, LLC AREA:North Slope Borough MUD CO: SPERRY JOB:AK-AM-0903090400 TD:6-Mar-2016 Halliburton - Baroid STATE:Alaska RIG:Nabors 19AC SPUD:5-Feb-2016 Bit Record . . * 24 hr Recap: (lb/bbl)% Rig Activity: Finished moving the rig over to ODSN-01A. Nippled down the production tree. Nippled up the riser, rig Density (ppg) out (sec/qt) Viscosity C-5i 100% Gas In Air=10,000 Units 29-Jan-2016 11:59 PM Current Pump & Flow Data: Max 95% Lime Cor Solids ROP ROP (ft/hr) 3.53 @ Mud Data Tools API FL Depth Morning Report Report # 1 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Job No.: Daily Charges: Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 8.508.50 Size annular and discovered a leak in the connection between the BOPE and the riser. Nippled down the stack and changed the seal. ConditionBit # Nippled up the stack and all the lines, reinstalled the test joint and resumed testing the BOPE. Chromatograph (ppm) C-1 WOB Connection Avg Min Comments Mud RPM ECD (ppg) ml/30min Background (max) Trip Average Mud Type Lst Type Ss Sea Water18011' Depth in / out CementChtSilt C-4i C-4n Hours C-3 J. Polya & J. Peitijean cP 24 hr Max Weight (ppb Eq) YP (lb/100ft2) Footage AK-AM0903090400 Testing BOPE PV ShClyst TuffGvlCoal Gas Summary (current) Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Time: 0' 0' 0' Max @ ft Current Date: BOPE stack, choke and kill lines. Installed the trip nipple and turnbuckles. Picked up test tools and began testing BOPE. Tested the in Minimum Depth Volumes C-5nC-2 SPP (psi) Gallons/stroke TFABit Type Depth MBT Alkal Siltst Units* Casing Summary Lithology (%) 907-670-6636Unit Phone:Beverly Hur Maximum Report By:Logging Engineers:Kerry Garner / Beverly Hur Set AtSize Grade (max)(current) Cly Hole Capacity (bbls) Drillstring Capacity (bbls) Annular Volume (bbls) Lag Correction (bbls) Bottoms Up Strokes Bottoms Up Time . . * 24 hr Recap: Hole Capacity (bbls) Drillstring Capacity (bbls) Annular Volume (bbls) Lag Correction (bbls) Bottoms Up Strokes Bottoms Up Time (max)(current) Cly Size Grade 907-670-6636Unit Phone:Beverly Hur Maximum Report By:Logging Engineers:Kerry Garner / Beverly Hur Units* Casing Summary Lithology (%) Set At Alkal Siltst SPP (psi) Gallons/stroke TFABit Type Depth C-5nC-2 in Minimum Depth Volumes protect from well taking returns to the flow back tank. Began pulling 4.5" tubing from 2564' MD to surface laying down all kill string. 0' 4302' 4302' Max @ ft Current Date: Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Time: Gas Summary (current) TuffGvlCoal Displacing to Clean Seawater PV ShClyst MBT YP (lb/100ft2) Footage J. Polya & J. Peitijean cP Weight (ppb Eq) CementChtSilt C-4i C-4n 18011' Depth in / out Hours Mud Type Lst Type Ss Average Background (max) Trip Comments Mud RPM ECD (ppg) ml/30min Connection C-3 Chromatograph (ppm) C-1 Pumped 50 bbls Barascrub pill, cleaned out the drag valve and began displacing with 500 bbls of clean seawater. 4318' MD. Located and cut the casing. Confirmed the casing cut, lined up to pump down kill and established circulation. Picked up Baker casing cutter tool. Cleaned and cleared the rig floor. Trippd in the hole with 7" casing cutter from surface to ConditionBit # 8.508.50 Size WOB Sea Water Job No.: Daily Charges: Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max AK-AM0903090400 Morning Report Report # 2 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Tools API FL Depth Avg Min 95% Lime Cor Solids ROP ROP (ft/hr) 3.53 @ Mud Data =10,000 Units 30-Jan-2016 11:59 PM Current Pump & Flow Data: Max 100% Gas In Air Density (ppg) out (sec/qt) Viscosity (lb/bbl)% Rig Activity: Finished testing BOPE. Laid down the testing equipment and monitored well. Circulated diesel freeze rig C-5i . . * 24 hr Recap: Hole Capacity (bbls) Drillstring Capacity (bbls) Annular Volume (bbls) Lag Correction (bbls) Bottoms Up Strokes Bottoms Up Time Cly Size Grade 907-670-6636Unit Phone:Beverly Hur Maximum Report By:Logging Engineers:Kerry Garner / Beverly Hur Units* Casing Summary Lithology (%) Set At Alkal Siltst SPP (psi) Gallons/stroke TFABit Type Depth C-5nC-2 in Minimum Depth Volumes surface. Changed and tested upper rams. Laid down test tools and pulled plug. Rigged up to pull 7" casing and pulled 73 joints. 4302' 0' 0' Max @ ft Current Date: Avg to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Time: Gas Summary (current) GvlCoal Cement PU Casing Scraper BHA PV ShClyst MBT YP (lb/100ft2) Footage J. Polya & J. Peitijean cP Weight (ppb Eq) Chromatograph (ppm) Cht Silt C-4i C-4n Tuff Hours Mud Type Lst Type Ss 18011' Average (max) Trip (max)(current) Background Mud RPM ECD (ppg) ml/30min Connection C-3C-1 Comments Picked up casing scraper BHA to 40'. Laid down casing equipment. Flushed stack, changed out and tested upper rams. Serviced top drive, blocks and crown. ConditionBit # 8.508.50 Size WOB Sea Water Depth in / out Job No.: Daily Charges: Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max AK-AM0903090400 Morning Report Report # 3 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Tools API FL Depth Avg Min 95% Lime Cor Solids ROP ROP (ft/hr) 3.53 @ Mud Data =10,000 Units 31-Jan-2016 11:59 PM Current Pump & Flow Data: Max 100% Gas In Air Density (ppg) out (sec/qt) Viscosity (lb/bbl)% Rig Activity: Continued to circulate out freeze protect with clean seawater. Tripped out of the hole from 4318' MD to rig C-5i . . * 24 hr Recap: Hole Capacity (bbls) Drillstring Capacity (bbls) Annular Volume (bbls) Lag Correction (bbls) Bottoms Up Strokes Bottoms Up Time Cly Beverly Hur Maximum Report By:Logging Engineers:Kerry Garner / Beverly Hur 907-670-6636Unit Phone: Units* Casing Summary Lithology (%) Depth Siltst TFABit Type Depth in C-2 SPP (psi) Minimum Laid down 4” drill pipe and BHA. Cleaned and cleared the rig floor. Pulled wear bushing and installed test plug. Began testing 0' 127' 127' Max @ ft Gas Summary Volumes Current Date: Avg 95% Gallons/stroke to Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Time: Chromatograph (ppm) C-5n GvlCoal Cement Testing BOPE PV ShClyst MBT YP (lb/100ft2) J. Polya & J. Peitijean Grade cP Weight (ppb Eq) Hours Footage Cht Silt C-4i C-4n Tuff 18011' Lst Type Ss Set AtSize Average (max) Trip (max)(current) ConnectionBackground (current) RPM ECD (ppg) ml/30min Alkal C-3C-1 Comments BOPE. ConditionBit # 8.508.50 Size WOB Sea Water Depth in / out Job No.: Daily Charges: Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max AK-AM0903090400 Morning Report Report # 4 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Tools API FL Depth Avg Min Mud Lime Cor Solids ROP ROP (ft/hr) 3.53 @ Mud Data Density (ppg) 10,000 Units 1-Feb-2016 11:59 PM Current Pump & Flow Data: Max 100% Gas In Air= out (sec/qt) Viscosity Mud Type (lb/bbl)% Rig Activity: Picked up casing scraper BHA. Tripped in the hole to 4274’ MD and circulated 1.5 bottoms up. rig C-5i . . * 24 hr Recap: Hole Capacity (bbls) Drillstring Capacity (bbls) Annular Volume (bbls) Lag Correction (bbls) Bottoms Up Strokes Bottoms Up Time Cly GvlCoal Beverly Hur Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 907-670-6636Unit Phone: Units* Casing Summary Lithology (%) Depth Siltst TFABit Type Depth in to C-2 SPP (psi) Minimum casing to 3500 psi for 30 minutes. Serviced the rig, cut and slip the drill line, serviced the top drive, blocks and crown. 127' 385' 0' Max @ ft Gas Summary Volumes Current Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) C-5n Cement PU Casing Scraper BHA PV ShClyst (lb/100ft2) J. Polya & J. Peitijean Grade cP Weight (ppb Eq) Hours Footage Cht Silt C-4i C-4n Tuff 18011' Lst Type Ss Set AtSize Average (max)Trip (max)(current) ConnectionBackground (current) RPM ECD (ppg) ml/30min Alkal C-3C-1 Comments for picking up BHA. Began picking up casing scraper BHA. Tripped out of the hole from 4194’ MD to 11’ MD and laid down the BHA. Tested BOPE, held pre-job safety meeting ConditionBit # 8.508.50 Size WOB Sea Water Depth in / out Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools AK-AM0903090400 Morning Report Report # 5 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Depth Avg Min Mud Lime Cor SolidsMBT ROP ROP (ft/hr) 3.53 @ Mud Data Density (ppg)API FLYP 10,000 Units 2-Feb-2016 11:59 PM Current Pump & Flow Data: Max 100% Gas In Air= out (sec/qt) Viscosity Mud Type (lb/bbl)% Rig Activity: Finished testing the BOPE. Tripped in the hole with 5.5” drill pipe to 4194’ MD. Pressure tested rig C-5i . . * 24 hr Recap: Hole Capacity (bbls) Drillstring Capacity (bbls) Annular Volume (bbls) Lag Correction (bbls) Bottoms Up Strokes Bottoms Up Time Cly GvlCoal Beverly Hur Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 907-670-6636Unit Phone: Units* Casing Summary Lithology (%) Depth Siltst TFABit Type Depth in to out C-2 SPP (psi) Minimum bottoms up. Tripped out of the hole from 4020’ MD to 1877’ MD. Serviced the top drive and blocks and laid down BHA 385' 2106' 0' Max @ ft Gas Summary Volumes Current Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) C-5n RIH w/ Whipstock PV ShClyst Grade Cement (lb/100ft2) J. Polya & CA Demoski Tuff cP Weight (ppb Eq) Hours Footage Cht Silt C-4i C-4n Size 18011' LstSs Trip (max)(current) ConnectionBackground(max) (current) Average TypeSet At RPM ECD (ppg) ml/30min Alkal C-3C-1 Comments to 2154’ MD. whipstock BHA from surface to 758’ MD. Performed a kick while tripping drill. Tripped in the hole from 758’ MD from 480’ MD to surface. Cleaned and cleared the rig floor. Brought up the tools for the whipstock BHA. Picked up the ConditionBit # 8.508.50 Size WOB Sea Water Depth in / out Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools AK-AM0903090400 Morning Report Report # 6 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Avg Min Mud Lime Cor SolidsMBT ROP ROP (ft/hr) 3.53 @ Mud Data Density (ppg)API FLYP 10,000 Units 3-Feb-2016 11:59 PM Current Pump & Flow Data: Max 100% Gas In Air= (sec/qt) Viscosity Mud TypeDepth (lb/bbl)% Rig Activity: Picked up BHA. Picked up the drill pipe from 480’ MD to 4120’ MD and circulated two rig C-5i . . * 24 hr Recap: (lb/bbl)% Rig Activity: Tripped in the hole and from 2154’ MD to 3553’ MD and couldn’t work past 3553’ MD rig C-5i Viscosity C Mud TypeDepth 100% Gas In Air=10,000 Units 4-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max - ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg)API FLYP Avg Min Mud Lime Cor SolidsMBT (sec/qt) AK-AM0903090400 Morning Report Report # 7 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools 9.6 10.5 10.20 Window Mill 10.20 Size WOB BaraECD 20 Depth in / out Serviced the top drive and blocks. Tripped in the hole from 525’ MD to 3506’ MD, reamed and washed down from 4318' 4118' Condition - Bit # 5 - Gas Avg: 6 units Gas Max: 10 units 1700 PSI. Tripped out of the hole and began laying down BHA. 3506’ MD to 4118’ MD at 700 GPM, 1000 PSI, 70 RPM, and 4k Torque. Circulated two bottoms up at 700 GPM and Comments - Size Silt C-3 - - Alkal Average TypeSet At RPM ECD (ppg) ml/30min - - Background (max) (current) (current) Trip (max) Connection Cht LstSs Lag Correction (bbls) 18011' cP 41 - Weight (ppb Eq) Hours Footage (lb/100ft2) J. Polya & CA Demoski - 4077' - - Grade CementTuff Laying down BHA PV ShClyst - - Chromatograph (ppm) C-5n Yesterday's Depth: Current Depth: 24 Hour Progress: Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Current Date: Avg 95% Gallons/stroke 2106' 149' 0' Max @ ft Gas Summary Volumes Fluids: 0 barrels lost downhole without risk of shearing the whipstock. Tripped out of the hole and laid down BHA. Picked up the clean out BHA. Minimum C-2 SPP (psi) TFABit Type Depth - 65 in to out Depth 2.350 Siltst 907-670-6636Unit Phone: 0 0 Units* Casing Summary Lithology (%) Beverly Hur Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur Cly GvlCoal - C-1 Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time 11.75" L9.625" Drillstring Capacity (bbls) Annular Volume (bbls) . . * 24 hr Recap: 11.75" L9.625" 19 min Drillstring Capacity (bbls) Annular Volume (bbls) C-1 Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 Cly 191 7 42 GvlCoal 0Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 257 23 0 907-670-6636Unit Phone: 744 210 Units* Casing Summary Lithology (%) 328 Beverly Hur Depth 2.350 0 0 0 Siltst TFABit Type Depth - 113 in to out 4093' 3.9 C-2 16 SPP (psi) 7 4078'Minimum Fluids: 0 barrels lost downhole BHA and tripped in the hole from 758’ MD to 4122’ MD. Orientated and set the whipstock. Milled the window through 13 149' 4099' 21' Max @ ft Gas Summary 0 5 5 Volumes Current 4094'1.8 Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: 3.9 Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) 0 C-5n Milling 11 3/4" Window PV ShClyst - - - 3980 CementTuff J. Polya & CA Demoski - 4077' - - Grade - Weight (ppb Eq) Hours Footage (lb/100ft2) 4090' 100 00 Cht - LstSs Trip (max) Connection12 units 0 (current) Background (max) (current) Average TypeSet At RPM ECD (ppg) ml/30min - - - - Alkal Lag Correction (bbls) cP 42 - 0 287 Comments - Size Silt Gas Avg: 13 units Gas Max: 16 units window at 4095' MD. the 11 ¾” casing from 4077' MD to 4095' MD at 750 GPM, 1950 PSI, 100 RPM, 7-8K WOB. Currently milling the 4318' 4118' Condition - Bit # 5 - 9.4 10.5 10.20 Window Mill 10.20 Size WOB BaraECD 22 Depth in / out Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools AK-AM0903090400 Morning Report Report # 8 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough - - Avg Min Mud Lime Cor SolidsMBT (sec/qt) ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg) - API FLYP 10,000 Units - 5-Feb-2016 11:59 PM Current Pump & Flow Data: 1948 Max - 0 100% Gas In Air= Viscosity C Mud TypeDepth (lb/bbl)% Rig Activity: Laid down the BHA. Serviced the top drive and blocks. Picked up the whipstock rig C-5i . . * 24 hr Recap: 11.75" L9.625" 19 min Drillstring Capacity (bbls) Annular Volume (bbls) C-1 Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 Cly 42 GvlCoal Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 907-670-6636Unit Phone: 505 143 Units* Casing Summary Lithology (%) 328 Beverly Hur Depth 2.350 Siltst TFABit Type Depth - 125 in to out 0.0 C-2 0 SPP (psi) 0Minimum Fluids: 0 barrels lost downhole 1950 PSI and 100 RPM. Pulled up into the 11 ¾” casing to 4056’ MD and performed the formation integrity test 0 4099' 4129' 30' Max @ ft Gas Summary Volumes Current 4127'4.7 Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: 14.6 Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) C-5n Tripping in the hole PV ShClyst - - - 3980 CementTuff J. Polya & CA Demoski - 4077' - - Grade - Weight (ppb Eq) Hours Footage (lb/100ft2) 4129' Cht - LstSs Trip (max) Connection - (current) Background (max) (current) Average TypeSet At RPM ECD (ppg) ml/30min - - - - Alkal Lag Correction (bbls) cP 45 - 287 Comments - Size Silt Gas Avg: 0 units Gas Max: 0 units at 4063’ MD. and cleared the rig floor, serviced the top drive and blocks. Picked up the BHA and currently tripping in the hole to 12.5 ppg EMW. Tripped out of the hole and laid down the BHA. Performed a kick while tripping drill, cleaned 4318' 4118' Condition - Bit # 5 - 9.4 10.5 10.20 Window Mill 10.20 Size WOB BaraECD 24 Depth in / out Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools AK-AM0903090400 Morning Report Report # 9 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough - - Avg Min Mud Lime Cor SolidsMBT (sec/qt) ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg) - API FLYP 10,000 Units - 6-Feb-2016 11:59 PM Current Pump & Flow Data: 1542 Max - 100% Gas In Air= Viscosity C Mud TypeDepth (lb/bbl)% Rig Activity: Milled the window from 4095’ MD to 4099’ MD and drilled new hole at 750 GPM, rig C-5i . . * 24 hr Recap: 11.75" 19 min Drillstring Capacity (bbls) Annular Volume (bbls) C-1 Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 Cly 682 0 42 GvlCoal 0Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 200 0 0 907-670-6636Unit Phone: 0 0 Units* Casing Summary Lithology (%) 328 Beverly Hur Depth 2.350 0 0 0 Siltst TFABit Type Depth - 128 in to out 4130' 0.0 C-2 137 SPP (psi) 0 4129'Minimum Fluids: 0 barrels lost downhole MD to 4529' MD at 750 gallons per minute, 2750 pounds per square inch standpipe pressure, 60 revolutions per minute 32 4129' 4529' 400' Max @ ft Gas Summary 0 0 0 Volumes 10.625 Current 4216'54.0 Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: 199.5 Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) 0 C-5n Tripping in the hole PV ShClyst - - 3980 CementTuff J. Polya & CA Demoski - 4077' - - Grade 60 lbs Weight (ppb Eq) 4129' Hours Footage 8.49 400' (lb/100ft2) 4529' 000 00 Cht - LstSs Trip (max) Connection - 0 (current) Background (max) 4529' Tricone 0.942 (current) Average TypeSet At RPM ECD (ppg) ml/30min - - 60 - 35 - Alkal Lag Correction (bbls) cP 44 0 287 CommentsSize Silt Gas Avg: 32 units Gas Max: 137 units Picked up the BHA then function and tested the MWD and under reamer. Currently tripping in the hole. the top drive and blocks and continued to trip out of the hole. Laid down the BHA then cleaned and cleared the rig floor. 6k foot-pounds torque, and 13k pounds weight on bit. Circulated 3.5 bottoms up and tripped out of the hole. Serviced 4099' Condition - Bit # 5 - 9.4 10.5 10.20 Window Mill 10.20 Size WOB BaraECD 24 Depth in / out Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools AK-AM0903090400 Morning Report Report # 10 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough - - Avg Min Mud Lime Cor SolidsMBT (sec/qt) ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg) - API FLYP 10,000 Units - 7-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max 0-0-NO-A-E-I-NO-BHA - 0 100% Gas In Air= Viscosity C Mud TypeDepth 8 (lb/bbl)% Rig Activity: Orientated the BHA through the window from 4095' MD to 4129' MD. Drilled ahead from 4129' rig C-5i . . * 24 hr Recap: - - - 4 HDBS FXG65s 10.625 1.353 - 4529' 11.75" 24 Drillstring Capacity (bbls) Annular Volume (bbls) C-1 Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 Cly 4974 0 98.14 GvlCoal 42Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 4971 40 0 907-670-6636Unit Phone: 799 225 Units* Casing Summary Lithology (%) 513.49 Beverly Hur Depth 2.350 0 0 0 Siltst TFABit Type Depth - 124 in 4932'to4529' out 4873' 73.8 C-2 44 SPP (psi) 0 4587'Minimum Fluids: 0 barrels lost downhole hole to 4004' MD. Worked in the hole from 4018' MD to 4143' MD with pack off issues. Step rated up the pump to 5 BPM 41 drive and blocks and continued to drill ahead to 4885' MD at 800 GPM, 2500 PSI, 140 RPM, 7.4k Torque and 3-11k WOB. Currently drilling ahead at 4885'. 4529' 4932' 403' Max @ ft Gas Summary 0 0 0 Volumes 10.625 Current 4564'31.1 Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: 134.7 Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) 6 C-5n Drilling Ahead PV ShClyst - - 5500 CementTuff J. Polya & CA Demoski - 4077'4129'52' Grade 60 lbs Weight (ppb Eq) 4129' Hours Footage 8.49 400' (lb/100ft2) - - 4782' 000 00 Cht - LstSs Trip (max) Connection40 35 (current) Background (max) 4529' Tricone 0.942 (current) Average TypeSet At RPM ECD (ppg) ml/30min - - 60 - 35 - Alkal Lag Correction (bbls) cP 47 0 415.36 CommentsSize Silt Gas Avg: 41 units Gas Max: 44 units 120 RPM, 6.5k Torque and 3-5k WOB. CCU had a pack off in their cuttings hopper and worked to clear it. Serviced the top to 4529' MD and step rated up the pumps to 700 GPM, 2500 PSI then drilled ahead to 4612' MD at 750 GPM, 2280 PSI, then circulated 3.5 bottoms up from 4070' MD to 4004' MD at 800 GPM and 3300 PSI. Tripped in the hole from 4004' MD 4099' Condition - Bit # 2rri - 9.3 10.5 10.20 Window Mill 10.20 Size WOB BaraECD 26 Depth in / out Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools HDBS FXG65s AK-AM0903090400 Morning Report Report # 11 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough 10.4410.75 Avg Min Mud Lime Cor SolidsMBT (sec/qt) ROP ROP (ft/hr) 3.86 @ Mud Data Density (ppg) 10.86 API FLYP 10,000 Units36 8-Feb-2016 11:59 PM Current Pump & Flow Data: 2501 Max 0-0-NO-A-E-I-NO-BHA 4.53 4 100% Gas In Air= Viscosity C Mud TypeDepth 3 (lb/bbl)% Rig Activity: Tripped in the hole from 2513' MD to 2979' MD, filled the drill pipe and continued to trip in the rig C-5i . . * 24 hr Recap: - - 4 HDBS FXG65s 10.625 1.353 - 4529' 11.75" 34 Drillstring Capacity (bbls) Annular Volume (bbls) Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 12357 0 125.19 GvlCoal 368 C-1 Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 5956 93 0 907-670-6636Unit Phone: 0 0 Units* Casing Summary Lithology (%) 699.84 Beverly Hur Depth 0 18 0 Siltst Depth - 86 in 6147'to4932' out 6114' 77.0 C-2 123 SPP (psi) 11 5005'Minimum Fluids: 0 barrels lost downhole 3-11k WOB. Took check shot surveys and continued to drill ahead to 5308' MD. Obtained slow pump rates. Serviced the 59 4932' 6147' 1215' Max @ ft Gas Summary 0 37 0 Volumes 10.625 Current 5031'51.8 Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: 160.9 Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) 178 C-5n Drilling Ahead PV ShClyst - 7916 CementTuff - - J. Polya & CA Demoski Grade 60 lbs Cly - (ppb Eq) 4129' Hours Footage 8.49 400' (lb/100ft2) 4782' 090 00 Cht - LstSs Trip (max) Connection103 (current) Background (max) 4529' Tricone 0.942 (current) Average TypeSet At RPM ECD (ppg) ml/30min - - 6035 Alkal Lag Correction (bbls) cP 40 Weight 7 544.65 88 CommentsSize Silt 100 Gas Avg: 59 units Gas Max: 123 units Currently drilling ahead at 6147' MD. Obtained slow pump rates then continued to drill ahead to 6147' at 800 GPM, 2520 PSI, 140 RPM, 6-8k Torque, 7-8k WOB. top drive and blocks the continued to drill ahead to 5494' MD at 800 GPM, 2480 PSI, 140 RPM, 9k Torque, 7-9k WOB. 4099' ConditionBit # - 9.410.2010.20 Size WOB BaraECD 23 Depth in / outTFABit Type Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools Full Service AK-AM-0903090400 Morning Report Report # 12 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough 10.4410.72 Avg Min Mud Lime Cor SolidsMBT (sec/qt) ROP ROP (ft/hr) 3.52 @ Mud Data Density (ppg) 10.81 API FLYP 10,000 Units102 9-Feb-2016 11:59 PM Current Pump & Flow Data: 13 Max 0-0-NO-A-E-I-NO-BHA 4.14 30 100% Gas In Air= Viscosity C Mud TypeDepth 3 (lb/bbl)% Rig Activity: Drilled ahead from 4885' MD to 4958' MD at 800 GPM, 2500 PSI, 140 RPM, 7.5k Torque and rig C-5i . . * 24 hr Recap: 4 HDBS FXG65s 10.625 1.353 - 4529' 11.75" 31 Drillstring Capacity (bbls) Annular Volume (bbls) Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 18424 29 155.27 GvlCoal 790 C-1 Cement Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 9140 23 0 907-670-6636Unit Phone: 795 224 Units* Casing Summary Lithology (%) 843.66 Beverly Hur Depth 0 63 0 Siltst Depth - 84 in 7525'to6147' out MBT 6468' 69.9 C-2 192 SPP (psi) 13 7414'Minimum Fluids: 0 barrels lost downhole Obtained slow pump rates. Serviced the top drive and blocks. Performed a kick while drilling drill then drilled ahead to 91 6147' 7525' 1378' Max @ ft Gas Summary 0 143 28 Volumes 10.625 Current 6404'57.4 Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: 145.5 Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) 461 C-5n Drilling Ahead PV ShClyst - 8135 Tuff - - - - J. Polya & CA Demoski Grade 60 lbs Cly - (ppb Eq) 4129' Hours Footage 8.49 400' (lb/100ft2) 7406' 35 (sec/qt) 217818 00 Cht - LstSs Trip (max) Connection62 (current) Background (max) 4529' Tricone 0.942 (current) Average TypeSet At RPM ECD (ppg) ml/30min - - 60 Lag Correction (bbls) cP 36 Weight 29 688.38 361 CommentsSize Silt 100 Gas Avg: 91 units Gas Max: 192 units 140 RPM, 10k Torque and 4-8k WOB. Currently drilling ahead at 7525' MD. 6850' MD at 800 GPM, 2580 PSI, 140 RPM, 7-10k WOB. Continued to drill ahead to 7513' at 800 GPM, 2560 PSI, 4099' ConditionBit # - 9.910.2010.20 Size WOB BaraECD 22 Depth in / outTFABit Type Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools Full Service AK-AM-0903090400 Morning Report Report # 13 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Avg Min Mud Lime Cor Solids (lb/bbl)% Alkal ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg) 10.85 API FLYP 10-Feb-2016 11:59 PM Current Pump & Flow Data: 2626 Max 0-0-NO-A-E-I-NO-BHA 4.14 10.3910.75 199 100% Gas In Air= Viscosity C Mud TypeDepth 3 C-5i Rig Activity: Drilled ahead from 6147' MD to 6799' MD at 800 GPM, 2580 PSI, 140 RPM, 7-10k WOB. rig 10,000 Units157 . . 24 hr Recap: 4 HDBS FXG65s 10.625 1.353 - 4529' 11.75" 40 Drillstring Capacity (bbls) Annular Volume (bbls) Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 Lag Correction (bbls) 11367 0 164.37 GvlCoal 369 C-1 Cement Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 7026 40 0 907-670-6636Unit Phone: 0 0 Units* Casing Summary Lithology (%) 869.19 Beverly Hur Depth 0 11 0 Siltst Depth - 77 in 7943'to7525' out MBT 7911' 22.5 C-2 105 SPP (psi) 12 7686'Minimum Fluids: 0 barrels lost downhole 7-18k WOB. Obtained slow pump rates. Serviced the top drive and blocks. Drilled ahead to 7943' at 800 GPM, 2690 PSI, 71 a full stand then back reamed from 4004' MD to 2979' MD at 800 GPM, 2630 PSI, 100 RPM, 5.6k Torque. Currently back reaming out of the hole at 2979' MD. 7635' 7525' 7943' 418' Max @ ft Gas Summary 0 23 0 Volumes 10.625 Current 7545'27.0 Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: 129.7 Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) 120 C-5n Back Reaming out of Hole PV ShClyst - - 8649 Tuff - - - - J. Polya & CA Demoski Grade 60 lbs Cly - (ppb Eq) 4129' Hours Footage 8.49 400' (lb/100ft2) 7943' 35 (sec/qt)cP 32 0180 00 Cht - LstSs Trip (max) Connection11 (current) Background (max) 4529' Tricone 0.942 (current) Average TypeSet At RPM ECD (ppg) ml/30min - - 60 Weight 7 731.83 190 CommentsSize Silt 100 Max Connection Gas: 129 units @ 7916' MD Max Drill Gas: 105 units @ 7911' MD out of the hole to 7817' MD at 88 GPM, 190 PSI, 40 RPM, 9k Torque. Circulated 3.5 bottoms up while working a pressure increase. Quadrant reamed at 800 GPM, 3100 PSI, and 140 RPM from 7943' MD to 7817' MD. Lubricated 140 RPM, 13k Torque, 7-18k WOB. Dropped 6 closing tags and circulated them down. Verified the reamer was closed with 4099' ConditionBit # - 9.810.2010.20 Size WOB BaraECD 21 Depth in / outTFABit Type Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools Full Service AK-AM-0903090400 Morning Report Report # 14 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Avg Min Mud Lime Cor Solids (lb/bbl)% Alkal ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg) 10.76 API FLYP 11-Feb-2016 11:59 PM Current Pump & Flow Data: 4 Max 0-0-NO-A-E-I-NO-BHA 4.01 10.4010.63 77 Viscosity C Mud TypeDepth 3 C-5i Rig Activity: Drilled ahead from 7525' MD to 7916' MD at 800 GPM, 2660 PSI, 140 RPM, 13k Torque, rig 129 . . 24 hr Recap: C-5i Rig Activity: Back reamed from 2979' MD to 650' MD at 800 GPM, 2500 PSI and 140 RPM. Laid down the rig - Viscosity C Mud TypeDepth 3 12-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max 0-0-NO-A-E-I-NO-BHA 4.01 - - ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg) - API FLYP Avg Min Mud Lime Cor Solids (lb/bbl)% Alkal AK-AM-0903090400 Morning Report Report # 15 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools Full Service 9.810.2010.20 Size WOB BaraECD 20 Depth in / outTFABit Type floor. Serviced the top drive then changed the rams to 9 5/8" and tested them. Rigged up the Tesco running equipment 4099' ConditionBit # - Max Connection Gas: N/A Max Drill Gas: 0 Currently tripping in the hole with 9 5/8" liner at 482' MD. and held a pre job safety meeting for making up and running the liner. Ran the casing from surface to 482' MD. CommentsSize Silt 100 Weight 731.83 Average TypeSet At RPM ECD (ppg) ml/30min - - 60 Background (max) 4529' Tricone 0.942 (current) (current) Trip (max) Connection - Cht - LstSs Hours Footage 8.49 400' (lb/100ft2) 7943' 35 (sec/qt)cP 34 J. Polya & CA Demoski Grade 60 lbs Cly 10 (ppb Eq) 4129' Tuff 7943' 3414'140 1-0-DL-N-X-I-PN-TD RIH w/ 9 5/8" Liner PV ShClyst - - 8649 Chromatograph (ppm) C-5n Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Current - - Date: Avg 95% Gallons/stroke 7943' 7943' 0' Max @ ft Gas Summary Volumes 10.625 Fluids: 0 barrels lost downhole BHA from 650' MD to 74' MD and downloaded the MWD. Finished laying down the BHA and cleaned and cleared the rig 0 0Minimum 0.0 C-2 0 SPP (psi) Depth - 84 in 7943'to7943' out MBT Depth Siltst 907-670-6636Unit Phone: 0 0 Units* Casing Summary Lithology (%) 869.19 Beverly Hur Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 164.37 GvlCoal C-1 Cement Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 Lag Correction (bbls) 11.75" 40 Drillstring Capacity (bbls) Annular Volume (bbls) 4 HDBS FXG65s 10.625 1.353 75.01 4529' . . 24 hr Recap: 4 HDBS FXG65s 10.625 1.353 75.01 4529' 11.75" L9.625" 40 Drillstring Capacity (bbls) Annular Volume (bbls) Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 Lag Correction (bbls) 12495 0 164.37 GvlCoal 171 C-1 Cement Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 18 0 0 907-670-6636Unit Phone: 0 0 Units* Casing Summary Lithology (%) 869.19 Beverly Hur Depth 0 7 0 Siltst Depth - 108 in 7943'to7943' out MBT - 0.0 C-2 105 SPP (psi) 0 - Minimum Fluids: 100 percent returns on Cement job for 0 barrels lost downhole out elevators. Picked up and installed the liner packer hanger from 3983' MD to 4024' MD. Serviced the top drive and 8 7943' 7943' 0' Max @ ft Gas Summary 0 11 0 Volumes 10.625 Current - - Date: Avg 95% Gallons/stroke Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Chromatograph (ppm) 58 C-5n Cementing 9 5/8" Liner PV ShClyst - - - 8649 Tuff 7943' 3414'140 1-0-DL-N-X-I-PN-TD J. Polya & CA Demoski Grade 60 lbs Cly 10 (ppb Eq) 4129' Hours Footage 8.49 400' (lb/100ft2) 7943' 35 (sec/qt)cP 36 000 00 Cht - LstSs Trip (max) Connection12 (current) Background (max) 4529' Tricone 0.942 (current) Average TypeSet At RPM ECD (ppg) ml/30min - - 60 40 lbs Weight 0 731.83 0 Comments - Size Silt 100 Max Connection Gas: N/A Max Circulation Gas: 105 units strokes and pressured up to 1450 PSI. Currently holding pressure for 5 minutes after bumping the plug. 255 GPM with 1155 PSI. Performed the cement job per Halliburton cementer pumping schedule. Bumped the plug at 4105 blocks. Tripped in the hole to 7943' MD on 5.5" drill pipe. Installed the cement head and cement lines. Staged up pumps to 7939' 4099' ConditionBit # - 9.810.3010.30 Size WOB BaraECD 19 Depth in / outTFABit Type Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools Full Service AK-AM-0903090400 Morning Report Report # 16 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Avg Min Mud Lime Cor Solids (lb/bbl)% Alkal ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg) - API FLYP 13-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max 0-0-NO-A-E-I-NO-BHA 3.88 - - 0 Viscosity C Mud TypeDepth 3 C-5i Rig Activity: Ran the 9 5/8" liner from 482' MD to 3963' MD. Rigged down the Tesco equipment and changed rig - . . 24 hr Recap: C-5i Rig Activity: Set the 9-5/8" liner top hanger. Pressure tested the liner packer and circulated 1 bottoms up. rig - Viscosity C Mud TypeDepth 4 0 14-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max 1-0-DL-N-X-I-PN-TD 4.01 - - ROP ROP (ft/hr) 3.51 @ Mud Data Density (ppg) - API FLYP Avg Min Mud Lime Cor Solids (lb/bbl)% Alkal AK-AM-0903090400 Morning Report Report # 17 Customer: Well: Area: Location: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough Total Charges: MWD Summary Rig Activity: Nabors 19AC Report For: 24 hr Max Rig: Tools Full Service 10.010.3010.30 Size WOB BaraECD 19 Depth in / outTFABit Type nippled down the BOP's. Installed the multi bowl and tested it. Set the stack and finished nippling up the BOP's. 7939' 4099' ConditionBit # - Max Connection Gas: 0 units Max Circulation Gas: 75 units BHA and staged it on the floor. Pressure tested the casing to 3500 PSI. Currently picking up the cement drill out BHA. Changed the rams to 5.5" and tested them. Laid down testing equipment and installed the wear ring. Picked up the Comments - Size Silt 100 40 lbs Weight 0 731.83 0Average TypeSet At RPM ECD (ppg) ml/30min - - 140 Background (max) 7943' HDBS FXG65s 1.353 (current) (current) Trip (max) Connection0 Cht - LstSs 000 00 Hours Footage 75.01 3414' (lb/100ft2) 7943' 10 (sec/qt)cP 38 J. Polya & CA Demoski Grade 60 lbs Cly - (ppb Eq) 4529' Tuff - - - - Picking up BHA PV ShClyst - - - 8649 Chromatograph (ppm) 33 C-5n Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: Job No.: Daily Charges: Current - - Date: Avg 95% Gallons/stroke 7943' 7943' 0' Max @ ft Gas Summary 0 6 0 Volumes 10.625 Fluids: 0 barrels lost downhole Tripped out of the hole from 3868' MD to 39' MD. Laid down the Baker running tool, cleaned and cleared the rig floor and 4 0 - Minimum - 0.0 C-2 75 SPP (psi) Depth - 132 in 7943'to7943' out MBT Depth 0 0 0 Siltst 907-670-6636Unit Phone: 0 0 Units* Casing Summary Lithology (%) 869.19 Beverly Hur Maximum Report By:Logging Engineers:Martin Nnaji / Beverly Hur 41 0 0 9152 0 164.37 GvlCoal 104 C-1 Cement Hole Capacity (bbls) C-4i C-4n Bottoms Up Strokes Bottoms Up Time C-3 Lag Correction (bbls) 11.75" L9.625" 40 Drillstring Capacity (bbls) Annular Volume (bbls) 5 Hughes GT-C1 8.5 0.920 - 7943' . . * 24 hr Recap: Volumes Hole Capacity (bbls) Drillstring Capacity (bbls) Annular Volume (bbls) Lag Correction (bbls) Bottoms Up Strokes Bottoms Up Time 519.66 - 6141689.66 170 29 (max)(current) L Cly Set AtSize 60 lbs - Grade 11.75" 907-670-6636Unit Phone:Beverly Hur Maximum Report By:Logging Engineers:Martin Nnagi / Beverly Hur 9.625" 0 0 Units* Casing Summary Lithology (%) - MBT - pH 1.353 Siltst SPP (psi) Gallons/stroke TFABit Type Depth - 56 C-5n 0.0 C-2 0 in 0Minimum Depth Time: Fluids: 0 barrels lost downhole to 7649' MD. Serviced the top drive. Reamed and washed down from 7649' MD to 7819' MD at 300 GPM, 800 PSI, 0 Tripped out of the hole to 1687' MD. Currently tripping out of the hole. 7943' 7968' 25' Max @ ft Current 7949'29.4 Date: Avg - - Yesterday's Depth: Current Depth: 24 Hour Progress: 67.1 Flow In (gpm) Flow In (spm) Gas Summary (current) J. Polya & CA Demoski ShClyst TuffGvlCoal cP 13 3414' 8.5 0.920 Footage - - 75.01 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Tripping out of Hole PV 24 hr Max 40 lbs Weight Hours C-3 100 CementChtSilt C-4i C-4n YP (lb/100ft2) 10.10 - 140 Hughes GT-C1 LSND 2.4 7943' 7968'23 - Depth in / out Mud Type Lst Type Average - 0Background (max) Trip - - Avg Min Comments - RPM ECD (ppg) ml/30min Tools - API FL Chromatograph (ppm) - 104529' 7943' WOB C 100% Gas In Air=10,000 Units - Connection 5 Max Drill Gas: 0 units Max Circulation Gas: 0 units at 600 GPM, 1500 PSI, 60 RPM, 12.9k Torque and 3k WOB. Performed a Formation Integrity Test to 13 ppg (728 PSI.) 5-22k WOB. Displaced the well from 10.3 ppg Bara ECD to 10.2 ppg LSND. Drilled new hole from 7943' MD to 7968' MD 40 RPM, and 12k WOB. Drilled cement from 7819' MD to 7943' MD at 600 GPM, 2450 PSI, 40 RPM, 10k Torque, 7939' 4099' Condition 1-0-DL-N-X-I-PN-TD Bit # 4 6.5 10.625 10.20 HDBS FXG65s 10.20 Size Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Morning Report Report # 18 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough - - ROP ROP (ft/hr) @ Mud Data Depth 15-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max Chlorides mg/l 24000.00 Rig Activity: Picked up BHA from surface to 568' MD. Picked up drill pipe to 3550' MD. Tripped in the hole rig Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: Volumes Hole Capacity (bbls) Drillstring Capacity (bbls) Annular Volume (bbls) Lag Correction (bbls) Bottoms Up Strokes Bottoms Up Time 506.9 - 5990672.5 165.7 - (max)(current) Intermediate 1 Liner - - Cly - - Set At (MD/TVD)Size 60 ppf L-80 Grade 11.75" 907-670-6636Unit Phone: - David Durst Maximum Report By:Logging Engineers:Martin Nnaji / David Durst - - - 9.625" 0 0 Units* Casing Summary Lithology (%) - L-80 MBT - pH 1.353 - - - Siltst SPP (psi) Gallons/stroke TFABit Type Depth -60 C-5n - - C-2 0 in 0 -Minimum Depth Time: Fluids G/L: 0 bbs lost downhole top drive and change out dies on the Iron Roughneck. Removed the wear ring. Picked up testing tools and tested the 0 7968' 7968' 0' Max @ ft Current -- Date: Avg - - Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) -- Gas Summary - -- (current) J. Polya & CA Demoski ShClyst -- TuffGvlCoal cP 15 3414' 8.5 1.107 Footage - - 75.01 - Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Tripping In the Hole PV - 24 hr Max 40 ppf Weight - Hours C-3 - -- CementChtSilt C-4i C-4n YP (lb/100ft2) 10.0 --- - 140 HDBS SFE46D LSND 2.2 7968' 7968'20 - Depth in / out Mud Type Lst -- Type Average - 0Background (max) Trip - - Avg Min Comments - RPM ECD (ppg) ml/30min Tools Dir/Gamma/EWR/PWD/ABG API FL Chromatograph (ppm) - 104529' 7943' WOB Suface Casing 100% Gas In Air=10,000 Units - Connection - - 6 Circulation Gas: Max: 0 units; Avg: 0 units tools. Tripped in the hole from 708’ MD to 3969’ MD. Currently tripping in the hole at 3969’ MD. the PCDC wasn't working. Swapped out the PCDC. Continued picking up BHA #11 and tested the RipTide reamer and MWD BOPs. Picked up, made up, and tested the MPD equipment. Laid down all testing equipment. Picked up BHA #11. Found 7939' / 5002' 4099' / 3238' Condition 1-0-DL-N-X-I-PN-TD Bit # 4 6.8 10.625 10.20 HDBS FXG65s 10.20 Size Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Morning Report Report # 19 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Burough - - ROP ROP (ft/hr) @ Mud Data Depth 16-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max - Chlorides mg/l 23,500 Tripped out of the hole from 1687’ MD to 568’ MD. Laid down BHA # 10 from 568’ MD to surface. Serviced the rig Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: (max)(current) Intermediate 1 Liner 1849 0 Cly 22178 - Set AtSize 60.0 L-80 Grade 11.75" 907-670-6636Unit Phone: 165 David Durst Maximum Report By:Logging Engineers:Matrin Nnaji / David Durst - 10871 91 9.625" 748 210 Units* Casing Summary Lithology (%) 96 L-80 MBT 9092' pH 1.353 0 207 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 2.550 C-5n 8499' 0.0 C-2 302 in 2 8046'Minimum Depth Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls and washed down from 7882’ MD to 7968’ MD, then drilled ahead from 7968’ MD to 8102’ MD at 700 gpm, 2250 psi, 17k ft-lbs 131 7968' 9092' 1124' Max @ ft Current 8670'88.4 Date: Avg to7968' Yesterday's Depth: Current Depth: 24 Hour Progress: 146.2 Flow In (gpm) Flow In (spm) - - Gas Summary 0 581 163 (current) R. Klepzig & C.A. Demoski ShClyst - - TuffGvlCoal cP 14 3414' 8.5 1.107 Footage - - 75.01 - Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Service Top Drive PV - 24 hr Max 40.0 Weight 864 Hours C-3 - 00 CementCht Silt C-4i C-4n YP (lb/100ft2) 9.4 8928883 - 140.0 HDBS SFE46D LSND 2.6 7968' 8794'26 - Depth in / out Mud Type Lst - - Type Average 086Background (max) Trip 10.9211.34 Avg Min Comments - RPM ECD (ppg) ml/30min Tools Dir/Gamma/EWR/PWD/ABG API FL Chromatograph (ppm) - 10.04529' 7943' WOB Surface Casing 100% Gas In Air=10,000 Units301Connection - 1282 6 Max Trip : 0 units; Avg Trip : 0 units Max Conn : 301 units @ 8440' MD; Avg Conn : 144 units Gas: Max Drill :301 units @ 8499' MD; Avg Drill : 131 units gpm, 2250 psi, 16-17k ft-lbs torque, 25-28k lbs WOB and serviced the top drive. torque, 60 rpm, 25k lbs WOB. Dropped the reamer tags and opened the reamer. Drilled ahead from 8102’ MD to 9092’ MD at 750 7939' MD / 5002' TVD 4099' MD / 3238' TVD Condition 1-0-DL-N-X-I-PN-TD Bit # 4 7.4 10.625 10.20 HDBS FXG65s 10.20 Size Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 11.57 Nabors 19AC Report For: Morning Report Report # 20 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough - - ROP ROP (ft/hr) 3.55 @ Mud Data Depth 17-Feb-2016 11:59 PM Current Pump & Flow Data: 2272 Max 591 Chlorides mg/l 21,500 Tripped in the hole from 3969’ MD to 7882’ MD. Cut and slipped the drilling line and serviced the top drive. Reamed Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Circulated two bottoms up at 9092' MD at 750 gpm. Spotted a LCM pill, pumping at 225 gpm. Rotated out of the hole Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 22,000 247 18-Feb-2016 11:59 PM Current Pump & Flow Data: 2774 Max - - ROP ROP (ft/hr) 3.55 @ Mud Data Depth Morning Report Report # 21 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 13.05 Nabors 19AC Report For: Condition 1-0-DL-N-X-I-PN-TD Bit # 4 7.9 10.625 10.20 HDBS FXG65s 10.20 Size 6 Max Trip : 175 units @ 9:33; Avg Trip : 23 units Max Conn : 135 units @ 9558' MD; Avg Conn : 104 units Gas: Max Drill : 258 units @ 9604' MD; Avg Drill : 87 units 140 rpm, 16k ft-lbs torque, 22-27k lbs WOB. Serviced the top drive and checked the shaker screens. 300 gpm. Removed trip nipple and installed the MPD RCD head. Drilled ahead from 9092' MD to 9620' MD at 750 gpm, 2770 psi, to 7882’ MD. Ran in the hole on elevators from 7882' MD to 9092' MD. Circulated two bottoms up using the step rate method up to 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units135Connection - 509 Tools Dir/Gamma/EWR/PWD/ABG API FL Chromatograph (ppm) - 10.04529' 7943' WOB Surface Casing 11.4412.53 Avg Min Comments - RPM ECD (ppg) ml/30min 198Background (max) Trip Average 175 Mud Type Lst - - Type - 140.0 HDBS SFE46D LSND 4.0 7968' 9372'35 - Depth in / out YP (lb/100ft2) 10.0 5714443 3059 CementCht Silt C-4i C-4n - 24 hr Max 40.0 Weight 413 Hours C-3 -- Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Drilling Ahead PV 3414' 8.5 1.107 Footage - - 75.01 R. Klepzig & C.A. Demoski ShClyst - - TuffGvlCoal cP 14 - - Gas Summary 22 227 59 (current) Avg to9092' Yesterday's Depth: Current Depth: 24 Hour Progress: 172.3 Flow In (gpm) Flow In (spm) 9092' 9634' 542' Max @ ft Current 9188'70.9 Date: Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls without pumps from 9092' MD to 7696' MD. Performed a LCM squeeze per Caelus rep. Reamed and washed down from 7696' MD 87 in 8 9537'Minimum Depth C-5n 9604' 82.4 C-2 258 SPP (psi) Gallons/stroke TFABit Type Depth 7.060 L-80 MBT 9634' pH 1.353 55 51 10 Siltst 9.625" 744 209 Units* Casing Summary Lithology (%) 33 - 7690 221 907-670-6636Unit Phone: 83 David Durst Maximum Report By:Logging Engineers:Matrin Nnaji / David Durst Set AtSize 60.0 L-80 Grade 11.75" (max)(current) Intermediate 1 Liner 1155 37 Cly 25560 - . . * 24 hr Recap: Max Conn : 453 units @ 10490' MD; Avg Conn : 290 units Drilled ahead from 9634' MD to 9651' MD at 750 gpm, 2770 psi standpipe pressure, 20-21k ft-lbs torque, 140 rpm, Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 22,000 475 19-Feb-2016 11:59 PM Current Pump & Flow Data: 2678 Max - - ROP ROP (ft/hr) 3.55 @ Mud Data Depth Morning Report Report # 22 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 13.09 Nabors 19AC Report For: Condition 1-0-DL-N-X-I-PN-TD Bit # 4 7.9 10.625 10.15 HDBS FXG65s 10.15 Size 6 Gas: Max Drill : 496 units @ 10340' MD; Avg Drill : 176 units 2810 psi standpipe pressure, 20-22k ft-lbs torque, 25-30k lbs WOB. Serviced the top drive and blocks. 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units453Connection - 796 Tools Dir/Gamma/EWR/PWD/ABG API FL Chromatograph (ppm) - 10.04529' 7943' WOB Surface Casing 12.1312.52 Avg Min Comments - RPM ECD (ppg) ml/30min 81Background (max) Trip Average - Mud Type Lst - - Type - 140.0 HDBS SFE46D LSND 5.0 7968' 10445'30 - Depth in / out YP (lb/100ft2) 10.0 9226069 2970 CementCht Silt C-4i C-4n - 24 hr Max 40.0 Weight 850 Hours C-3 -- Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Drilling Ahead PV 3414' 8.5 1.107 Footage - - 75.01 R. Klepzig & C.A. Demoski ShClyst - - TuffGvlCoal cP 13 - - Gas Summary 20 336 89 (current) Avg to9634' Yesterday's Depth: Current Depth: 24 Hour Progress: 150.7 Flow In (gpm) Flow In (spm) 9634' 10573' 939' Max @ ft Current 10026'73.9 Date: Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls 20-28k lbs WOB. Serviced the rig and installed a new iron roughneck. Drilled ahead from 9651' MD to 10573' MD at 750 gpm, 176 in 9 9703'Minimum Depth C-5n 10340' 67.1 C-2 496 SPP (psi) Gallons/stroke TFABit Type Depth 10.049 L-80 MBT 10573' pH 1.353 119 95 15 Siltst 9.625" 750 211 Units* Casing Summary Lithology (%) 59 - 15801 979 907-670-6636Unit Phone: 115 David Durst Maximum Report By:Logging Engineers:Matrin Nnaji / David Durst Set AtSize 60.0 L-80 Grade 11.75" (max)(current) Intermediate 1 Liner 1734 159 Cly 48680 - . . * 24 hr Recap: Max Trip/Circ : 233 units @ 23:43; Avg Trip/Circ : 120 units Trip/Circ (max)(current) Intermediate 1 Liner 2057 130 Cly 37517 - Size 60.0 L-80 Grade 11.75" 907-670-6636Unit Phone: 263 David Durst Maximum Report By:Logging Engineers:Matrin Nnaji / David Durst 527373 1192 9.625" 730 205 Units* Casing Summary Lithology (%) - Set At L-80 MBT 11362' pH 1.353 127 214 24 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 14.049 11316' 0.0 C-2 458 730 GPM, 100 RPM, 19k ft-lbs torque. in 12 10648'Minimum Depth C-5n Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls and serviced the top drive. Drilled ahead from 10862’ MD to 11049’ MD at 750 GPM, 2900 PSI, 25-27k ft-lbs torque, 140 RPM, 103 50 PSI, 100 RPM, 19k ft-lbs torque. Repaired the MPD choke line and continued quadrant reaming from 11362’ MD to 11258’ MD at 10573' 11362' 789' Max @ ft Current 10679'64.6 Date: Avg to10573' Yesterday's Depth: Current Depth: 24 Hour Progress: 150.8 Flow In (gpm) Flow In (spm) -- Gas Summary 39 734 222 (current) R. Klepzig & C.A. Demoski ShClyst -- TuffGvlCoal cP 12 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Quadrant Reaming PV 3414' 24 hr Max 40.0 Weight 440 Hours C-3 -- 1.107 CementChtSilt C-4i C-4n - 9020770 56110 11358'34 - Depth in / out YP (lb/100ft2) 8.5 Footage -- Mud Type Lst -- Type Average 233Background (max) - RPM ECD (ppg) ml/30min 73 - 140.0 HDBS SFE46D LSND Surface Casing 12.1312.51 Avg Min Comments 5.8 7968' 10.6 75.01 Tools Dir/Gamma/EWR/PWD/ABG API FL Chromatograph (ppm) - 10.04529' 7943' WOB =10,000 Units241Connection - 1403 6 Max Conn : 241 units @ 11142' MD; Avg Conn : 173 units Gas: Max Drill : 458 units @ 11316' MD; Avg Drill : 103 units reamer. Pumped a 50 bbl, 12.2 ppg, high viscosity sweep. Performed a quadrant ream from 11362’ MD to 11258’ MD at 675 GPM, RPM, 27k ft-lbs torque, 28-30k lbs WOB. Serviced the top drive and blocks and pumped down the reamer closing tags, closing the 24-30k lbs WOB, then performed a kick while drilling drill. Drilled ahead from 11049’ MD to 11362’ MD at 675 GPM, 2520 PSI, 120 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air Condition 1-0-DL-N-X-I-PN-TD Bit # 4 8.8 10.625 10.30 HDBS FXG65s 10.25 Size Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 13.23 Nabors 19AC Report For: Morning Report Report # 23 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough - - ROP ROP (ft/hr) 3.55 @ Mud Data Depth 20-Feb-2016 11:59 PM Current Pump & Flow Data: 3217 Max 323 Chlorides mg/l 23,000 Drilled ahead from 10573’ MD to 10862’ MD at 750 GPM, 2880 PSI, 23-25k ft-lbs torque, 140 RPM, 27-30k lbs WOB Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: Gas: Max Trip/Circ : 121 units @ 00:47; Avg Trip/Circ : 19 units Trip/Circ (max)(current) Intermediate 1 Liner 219 0 Cly 3124 - Size 60.0 L-80 Grade 11.75" 907-670-6636Unit Phone: 119 David Durst Maximum Report By:Logging Engineers:Matrin Nnaji / David Durst 076 0 9.625" 0 0 Units* Casing Summary Lithology (%) - Set At L-80 MBT 11362' pH 1.353 0 47 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth -52 Tools - - C-2 121 in 0 -Minimum Depth C-5n Time: Downhole Fluid Gain/Loss (24 hours): -23 bbls 12.3 ppg LSND kill weight mud. Removed the MPD RCD bearing and installed the trip nipple. Lubed out of the hole from 11359' 19 11362' 11362' 0' Max @ ft Current -- Date: Avg to11362' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) - - Gas Summary 0 205 87 (current) R. Klepzig & C.A. Demoski ShClyst - - TuffGvlCoal cP 18 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Laying Down BHA PV 3414' 24 hr Max 40.0 Weight 0 Hours C-3 -- 1.107 CementCht Silt C-4i C-4n - 68266524.8 00 - Depth in / out YP (lb/100ft2) 8.5 Footage - - Mud Type Lst - - Type Average 121Background (max) - RPM ECD (ppg) ml/30min 0 - 140.0 HDBS SFE46D LSND Surface Casing 12.1912.51 Avg Min Comments 2.0 7968' 10.5 75.01 Dir/Gamma/EWR/PWD/ABG API FL Chromatograph (ppm) - 10.04529' 7943' WOB Condition 1-0-DL-N-X-I-PN-TD =10,000 Units-Connection - 209 6 of the hole from 7940' MD to 708' MD. Laid down BHA #11 from 708' MD to 113' MD. MD to 8100' MD. Pulled into the shoe with no pumps from 8100' MD to 7940' MD. Blew down the top drive and kill lines. Tripped out 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air Bit # 4 12.1 10.625 12.30 HDBS FXG65s 12.30 Size 11362'29 Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 12.70 Nabors 19AC Report For: Morning Report Report # 24 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough - - ROP ROP (ft/hr) 3.55 @ Mud Data Depth 21-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max 0 Chlorides mg/l 158,000 Quadrant reamed from 11362' MD to 11220' MD at 775 gpm, 100 rpm. Displaced the well from 10.2 ppg LSND to Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Laid down BHA #11 from 113' MD to surface and serviced the top drive. Removed the wear ring and installed the Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 39,000 0 22-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max 0-0-ER-N-X-I-NO-TD - ROP ROP (ft/hr) 3.55 @ Mud Data Depth Morning Report Report # 25 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Bit # 4 7.0 10.625 12.30 HDBS FXG65s 10.20 Size 11362'19 6 down and centered the rig over the well. Rigged back up and began running 7", 26# casing from surface to 4391' MD. 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units-Connection - 0 - API FL Chromatograph (ppm) 28 104529' 7943' WOB Condition 1-0-DL-N-X-I-PN-TD Surface Casing -- Avg Min Comments 5.4 7968' 10.0 75.01 - RPM ECD (ppg) ml/30min 0 140 140 HDBS SFE46D LSND Background (max) Average 0 Mud Type Lst - - Type 11362' Depth in / out YP (lb/100ft2) 8.5 Footage 50.27 3394' 000 00 CementCht Silt C-4i C-4n - 24 hr Max 40.0 Weight 0 Hours C-3 -- 1.107 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Running 7" Casing PV 3414' R. Klepzig & C.A. Demoski ShClyst - - TuffGvlCoal cP 11 - - Gas Summary 0 0 0 (current) Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 11362' 11362' 0' Max @ ft Current -- Date: Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls BOP test plug. Tested the BOPs. Rigged down test equipment and pulled the test plug. Rigged up Tesco to run casing. Rigged 0 in 0 -Minimum Depth C-5n - - C-2 0 SPP (psi) Gallons/stroke TFABit Type Depth 10.048 Tools L-80 MBT - pH 1.353 0 0 0 Siltst 9.625" 0 0 Units* Casing Summary Lithology (%) - Set At 00 0 907-670-6636Unit Phone: 0 David Durst Maximum Report By:Logging Engineers:Matrin Nnaji / David Durst 0 - Size 60.0 L-80 Grade 11.75" Gas: Max Trip/Circ : 0 units; Avg Trip/Circ : 0 units Trip/Circ (max)(current) Intermediate 1 Liner 0 0 Cly . . * 24 hr Recap: Gas: Max Trip/Circ : 20 units; Avg Trip/Circ : 0 units Trip/Circ (max)(current) Intermediate 1 Liner 0 0 Cly 1764 - Size 60.0 L-80 Grade 11.75" 907-670-6636Unit Phone: 0 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 023 0 9.625" 19 5 Units* Casing Summary Lithology (%) - Set At L-80 MBT - pH 1.353 0 0 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 10.050 Tools - - C-2 20 in 0 -Minimum Depth C-5n Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls greased the crown. Ran casing from 7772' MD to 7931' MD. Function tested the BOP rams. Ran 7" casing from 7931' MD to 11317' 0 11362' 11362' 0' Max @ ft Current -- Date: Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) - - Gas Summary 0 0 0 (current) R. Klepzig & C.A. Demoski ShClyst - - TuffGvlCoal cP 11 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Attempting to Break Circ PV 3414' 24 hr Max 40.0 Weight 0 Hours C-3 -- 1.107 CementCht Silt C-4i C-4n - 000 00 11362' Depth in / out YP (lb/100ft2) 8.5 Footage 50.27 3394' Mud Type Lst - - Type Average 20Background (max) - RPM ECD (ppg) ml/30min 0 140 140 HDBS SFE46D LSND Surface Casing -- Avg Min Comments 5.2 7968' 10.5 75.01 - API FL Chromatograph (ppm) 28 104529' 7943' WOB Condition 1-0-DL-N-X-I-PN-TD =10,000 Units-Connection - 0 6 hanger off the load shoulder and attempted to circulate with 1100 psi max pressure. MD. Made up the landing joint and landed the 7" casing. Attempted to circulate unsuccessfully using step rate method. Pulled the 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air Bit # 4 6.8 10.625 11.90 HDBS FXG65s 10.20 Size 11362'21 Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Morning Report Report # 26 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough 0-0-ER-N-X-I-NO-TD - ROP ROP (ft/hr) 3.55 @ Mud Data Depth 23-Feb-2016 11:59 PM Current Pump & Flow Data: 1126 Max 0 Chlorides mg/l 42,500 Ran 7" casing from 4391' MD to 7772' MD, filling every joint and topping off every 5 joints. Serviced the top drive and Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Attempted to break circulation unsuccessfully. Pulled 7" casing from 11355' MD to 11028’ MD, working to establish Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 36,000 100 24-Feb-2016 11:59 PM Current Pump & Flow Data: 1060 Max 0-0-ER-N-X-I-NO-TD - ROP ROP (ft/hr) 3.55 @ Mud Data Depth Morning Report Report # 27 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Bit # 4 7.2 10.625 10.20 HDBS FXG65s 10.20 Size 11362'20 6 pumping 10.2 ppg LSND. by pumping 10 bbls of seawater, 41 bbls of tuned spacer, 88 bbls of cement, followed by 20 bbls seawater. Displaced cement with rigged down Tesco. Made up the cement head. Held a pre-job safety meeting for the 1st stage cement job. Performed the 1st stage MD and landed the hanger. Displaced the annulus to 10.2 ppg LSND using the step rate method. Blew down the top drive and 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units-Connection - 965 - API FL Chromatograph (ppm) 28 104529' 7943' WOB Condition 1-0-DL-N-X-I-PN-TD Surface Casing -- Avg Min Comments 5.8 7968' 11.9 75.01 - RPM ECD (ppg) ml/30min 6 140 140 HDBS SFE46D LSND Background (max) Average 624 Mud Type Lst - - Intermediate 2 Casing Type 11362' Depth in / out YP (lb/100ft2) 8.5 Footage 50.27 3394' 11389 00 - CementCht Silt C-4i C-4n - 24 hr Max 40.0 Weight 224 Hours C-3 -- 1.107 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 2nd Stage Cement Job PV 3414' R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 13 26.0 - - Gas Summary 0 324 71 (current) Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 11362' 11362' 0' Max @ ft Current -- Date: Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls circulation. Established circulation at 11 gpm using the step rate method. Ran in the hole with 7" casing from 11028’ MD to 11355’ 47 rig pumps. Bumped the plug and pressured up to 3375 psi to open the ES cementer. After establishing circulation through the ES the 2nd stage cement job, pumping 10 bbls of spacer, 40 bbls of tail cement, 20 bbls of seawater. Began displacing with rig pumps, cementer, displaced the well over to 10.2 ppg BaraECD mud. Held a pre-job safety meeting for the 2nd stage cement job. Performed in 0 -Minimum Depth C-5n - - C-2 624 SPP (psi) Gallons/stroke TFABit Type Depth 10.052 Tools L-80 MBT - pH 1.353 0 93 0 Siltst 9.625" 214 60 Units* Casing Summary Lithology (%) - Set At 105335 0 907-670-6636Unit Phone: 84 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 64761 - Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" Gas: Max Trip/Circ : 624 units; Avg Trip/Circ : 47 units Trip/Circ (max)(current) Intermediate 1 Liner 2480 0 Cly . . * 24 hr Recap: Gas: Max Trip/Circ : 7 units; Avg Trip/Circ : 1 units Trip/Circ (max)(current) Intermediate 1 Liner 15 0 Cly 415 - Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" 907-670-6636Unit Phone: 0 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 091 0 9.625" 0 0 Units* Casing Summary Lithology (%) - Set At L-80 MBT - pH 1.353 0 0 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 10.050 Tools - - C-2 7 in 0 -Minimum Depth C-5n Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls and blew down the cement lines. Made up the setting sleeve and pulled the landing joint. Drained the stack, set pack off, and 1 11362' 11362' 0' Max @ ft Current -- Date: Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 26.0 - - Gas Summary 0 0 0 (current) R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 14 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Testing BOPs PV 3414' 24 hr Max 40.0 Weight 3 Hours C-3 -- 1.107 - CementCht Silt C-4i C-4n - 000 00 11362' Depth in / out YP (lb/100ft2) 8.5 Footage 50.27 3394' Mud Type Lst - - Intermediate 2 Casing Type Average 7Background (max) - RPM ECD (ppg) ml/30min 0 140 140 HDBS SFE46D LSND Surface Casing -- Avg Min Comments 6.0 7968' 12.0 75.01 - API FL Chromatograph (ppm) 28 104529' 7943' WOB Condition 1-0-DL-N-X-I-PN-TD =10,000 Units-Connection - 6 6 upper and lower rams, IBOP and saver sub. Made up the TIW dart and pump. hole. Changed out a hose on the iron roughneck. Picked up BOP test tools and installed the 4" test joint and plug. Changed out the tested to 5000 psi for 10 minutes. Laid down 13 joints of heavy weight drill pipe. Laid down 266 joints of 5.5" drill pipe in the mouse 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air Bit # 4 7.0 10.625 10.20 HDBS FXG65s 10.20 Size 11362'19 Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Morning Report Report # 28 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough 0-0-ER-N-X-I-NO-TD - ROP ROP (ft/hr) 3.55 @ Mud Data Depth 25-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max 2 Chlorides mg/l 39,500 Continued with the 2nd stage cement job, bumping plug with 10.2 ppg LSND mud. Rigged down the cement head Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Tested the BOPs. Rigged up and tested the MPD lines. Pulled the test plug, vacuumed out the stack, pulled the trip Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 36,000 0 26-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max - - ROP ROP (ft/hr) 3.55 @ Mud Data Depth Morning Report Report # 29 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Bit # 6 7.2 8.5 10.20 HDBS SFE46D 10.20 Size 11362'20 7 12 to 385' MD, then cut and slipped drilling line. Serviced the top drive and tripped in the hole with 4" drill pipe singles. flushed the drill pipe volume at 6 bpm. Tripped out of the hole to surface, racking back pipe in the derrick. Picked up clean out BHA Removed the test plug and installed the wear ring. Picked up 4" drill pipe singles from the pipe shed to 7701' MD (240 joints) and 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units-Connection - 0 Directional/XBAT API FL Chromatograph (ppm) - 287968' 11362' WOB Condition 0-0-ER-N-X-I-NO-TD Surface Casing -- Avg Min Comments 6.0 11362' 12.1 50.27 - RPM ECD (ppg) ml/30min 0 - 140 Baker / RC216 LSND Background (max) Average 0 Mud Type Lst - - Intermediate 2 Casing Type - Depth in / out YP (lb/100ft2) 6.125 Footage - - 000 00 - CementCht Silt C-4i C-4n - 24 hr Max 40.0 Weight 0 Hours C-3 -- 0.920 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 TIH on 4" DP PV 3394' R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 14 26.0 - - Gas Summary 0 0 0 (current) Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 11362' 11362' 0' Max @ ft Current -- Date: Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls nipple, and installed the cap. Laid down test tools and rigged down MPD. Removed the test head and installed the trip nipple. 0 in 0 -Minimum Depth C-5n - - C-2 0 SPP (psi) Gallons/stroke TFABit Type Depth 10.056 Tools L-80 MBT - pH 1.107 0 0 0 Siltst 9.625" 0 0 Units* Casing Summary Lithology (%) - Set At 00 0 907-670-6636Unit Phone: 0 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 0 - Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" Gas: Max Trip/Circ : 0 units; Avg Trip/Circ : 0 units Trip/Circ (max)(current) Intermediate 1 Liner 0 0 Cly . . * 24 hr Recap: Gas: Max Trip/Circ : 4 units; Avg Trip/Circ : 1 unit Trip/Circ (max)(current) Intermediate 1 Liner 49 0 Cly 383 - Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" 907-670-6636Unit Phone: 0 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 029 0 9.625" 200 56 Units* Casing Summary Lithology (%) - Set At L-80 MBT - pH 1.107 0 0 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 10.056 Tools - - C-2 4 in 0 -Minimum Depth C-5n Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls casing to 2500 psi for 5 min, then drilled out the ES cementer to 8634’ MD at 200 gpm. Continued to pump and rotate to 8680’ MD. 1 1950 psi. 11362' 11362' 0' Max @ ft Current -- Date: Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 26.0 - - Gas Summary 0 10 0 (current) R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 14 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Drilling Cement PV 3394' 24 hr Max 40.0 Weight 2 Hours C-3 -- 0.920 - CementCht Silt C-4i C-4n - 020 00 - Depth in / out YP (lb/100ft2) 6.125 Footage - - Mud Type Lst - - Intermediate 2 Casing Type Average 4Background (max) - RPM ECD (ppg) ml/30min 3 - 140 Baker / RC216 LSND Surface Casing -- Avg Min Comments 5.8 11362' 12.2 50.27 Directional/XBAT API FL Chromatograph (ppm) - 287968' 11362' WOB Condition 0-0-ER-N-X-I-NO-TD =10,000 Units-Connection - 27 7 to 4000 psi for 30 minutes. Drilled out the baffle adapter to 11185’ MD and began drilling out cement to 11266’ MD at 200 gpm, in the hole with 4” drill pipe singles to 11158’ MD. Washed and reamed down to 11183’ MD at 200 gpm. Pressure tested the 7” casing Tripped in the hole with 4" drill pipe singles to 10965’ MD, then serviced the top drive and repaired a sensor on the top drive. Tripped 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air Bit # 6 7.2 8.5 10.25 HDBS SFE46D 10.25 Size 11362'21 Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Morning Report Report # 30 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough - - ROP ROP (ft/hr) 3.554 @ Mud Data Depth 27-Feb-2016 11:59 PM Current Pump & Flow Data: 1970 Max 3 Chlorides mg/l 36,500 Picked up 4" drill pipe from 771’ MD to 8505’ MD. Drilled cement from 8505’ MD to 8632’ MD. Pressure tested the 7” Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Continued to drill out the shoe track and rat hole to 11362’ MD. Circulated one bottoms up at 11362’ MD. Performed Density (ppg) out (sec/qt) Viscosity Cor Solids % Chlorides mg/l 37,500 3 28-Feb-2016 11:59 PM Current Pump & Flow Data: 0 Max - - ROP ROP (ft/hr) 3.554 @ Mud Data Depth Morning Report Report # 31 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Bit # 6 7.6 8.5 10.25 HDBS SFE46D 10.25 Size 11362'18 7 and made up the TIW dart, and filled the stack with seawater. MD to 386’ MD. Laid down BHA #12 to surface. Picked up test tools and pulled the wear bushing. Installed the test plug, picked up perform Bat Sonic logs from 8882’ MD to 7426’ MD. Pumped a dry job and blew down the top drive. Tripped out of the hole from 7426’ 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units-Connection - 13 Directional/XBAT API FL Chromatograph (ppm) - 287968' 11362' WOB Condition 0-0-ER-N-X-I-NO-TD Surface Casing -- Avg Min Comments 6.0 11362' 12.1 50.27 - RPM ECD (ppg) ml/30min 0 - 140 Baker / RC216 LSND Background (max) Average 11 Mud Type Lst - - Intermediate 2 Casing Type - Depth in / out YP (lb/100ft2) 6.125 Footage - - 020 00 - CementCht Silt C-4i C-4n - 24 hr Max 40.0 Weight 1 Hours C-3 -- 0.920 Ss (ppb Eq) C-1 C-5i AK-AM-0903090400 Preparing to Test BOPs PV 3394' R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 12 26.0 - - Gas Summary 0 9 0 (current) Avg to7380' Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) 11362' 11362' 0' Max @ ft Current -- Date: Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls Bat Sonic logs from 11362’ MD to 9852’ MD and serviced the top drive. Tripped out of the hole from 9852’ MD to 8882’ MD, then 1 in 0 -Minimum Depth C-5n - - C-2 11 SPP (psi) Gallons/stroke TFABit Type Depth 10.047 Tools L-80 MBT 11316' pH 1.107 0 0 0 Siltst 9.625" 0 0 Units* Casing Summary Lithology (%) - Set At 054 0 907-670-6636Unit Phone: 0 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 911 - Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" Gas: Max Trip/Circ : 11 units; Avg Trip/Circ : 1 unit Trip/Circ (max)(current) Intermediate 1 Liner 20 0 Cly . . * 24 hr Recap: Max Trip/Circ : 10 units; Avg Trip/Circ : 1 unit Trip/Circ (max)(current) Intermediate 1 Liner 877 0 Cly 21368 - Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" 907-670-6636Unit Phone: 13 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 1910746 132 9.625" 224 63 Units* Casing Summary Lithology (%) - Set At L-80 Oil / Water 11442' Elec 1.107 0 34 0 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 68.0/32.047 Tools 11432' 84.3 C-2 203 in 7 11364'Minimum Depth C-5n Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls tools and loading nukes to 408' MD. Tripped in the hole to 11277’ MD. Removed the trip nipple and installed the RCD bearing. 99 11362' 11442' 80' Max @ ft Current 11437'80.8 Date: Avg to11362' Yesterday's Depth: Current Depth: 24 Hour Progress: 105.6 Flow In (gpm) Flow In (spm) 26.0 - - Gas Summary 0 78 13 (current) R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 11 Ss Ratio C-1 C-5i AK-AM-0903090400 Drilling Ahead PV 3394' 24 hr Max 40.0 Weight 458 Hours C-3 -- 0.389 - CementCht Silt C-4i C-4n - 6427 00 - Depth in / out YP (lb/100ft2) 6.125 Footage - - Mud Type Lst 100 - Intermediate 2 Casing Type Average 10Background (max) - Stab (V) RPM ECD (ppg) ml/30min 64 - 140 HDBS MME64 BaraECD Surface Casing 9.6310.25 Avg Min Comments 2.0 11362' 189 50.27 Dir/Gamma/Res/PWD/CTN/ALD HTHP Chromatograph (ppm) - 287968' 11362' WOB Condition 0-0-ER-N-X-I-NO-TD =10,000 Units99Connection - 359 8 Max Conn : 99 units @ 11374' MD; Avg Conn : 99 units Gas: Max Drill : 203 units @ 11432' MD; Avg Drill : 99 units MD and drilled ahead to 11442’ MD at 230 gpm, 2350 psi, 80 rpm, 10.8k-12.1k ft-lbs torque, 3-8k lbs WOB. 11362’ MD to 11382’ MD. Tripped out of the hole to 11354’ MD and performed a FIT test to 12.5 ppg EMW. Tripped in the hole to 11382' Serviced the top drive and greased the blocks. Displaced the well from 10.2 ppg LSND to 8.0 ppg BaraECD mud. Drilled ahead from 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air Bit # 6 1.4 8.5 8.00 HDBS SFE46D 8.00 Size 11362'12 Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 11.83 Nabors 19AC Report For: Morning Report Report # 32 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough - - ROP ROP (ft/hr) 3.554 @ Mud Data Depth 29-Feb-2016 11:59 PM Current Pump & Flow Data: 2308 Max 189 Lime lb / bbl 2.46 Tested BOPs. Pulled the test plug and installed the wear bushing. Picked up BHA #13, shallow pulse tested MWD Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: Max Conn : 454 units @ 11661' MD; Avg Conn : 219 units (max)(current) Intermediate 1 Liner 2009 155 Cly 44983 - Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" 907-670-6636Unit Phone: 57 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 7324519 1495 9.625" 0 0 Units* Casing Summary Lithology (%) - Set At L-80 Oil / Water 13582' Elec 1.107 114 101 18 Siltst SPP (psi) Gallons/stroke TFABit Type Depth 67.0/33.051 Tools 12489' 0.0 C-2 442 in 21 11672'Minimum Depth C-5n Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls WOB. Circulated a bottoms up and performed a pore pressure test. Drilled ahead from 11661’ MD to 13585’ MD at 230 gpm, 2480 236 11442' 13582' 2140' Max @ ft Current 13314'128.8 Date: Avg to11442' Yesterday's Depth: Current Depth: 24 Hour Progress: 187.9 Flow In (gpm) Flow In (spm) 26.0 - - Gas Summary 11 258 58 (current) R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 13 Ss Ratio C-1 C-5i AK-AM-0903090400 Drilling Ahead PV 3394' 24 hr Max 40.0 Weight 1266 Hours C-3 -- 0.389 - CementCht Silt C-4i C-4n - 4619246 1046 - Depth in / out YP (lb/100ft2) 6.125 Footage - - Mud Type Lst 100 - Intermediate 2 Casing Type Average -Background (max) Trip/Circ - Stab (V) RPM ECD (ppg) ml/30min 372 - 140 HDBS MME64 BaraECD Surface Casing 9.699.96 Avg Min Comments 2.0 11362' 323 50.27 Dir/Gamma/Res/PWD/CTN/ALD HTHP Chromatograph (ppm) - 287968' 11362' WOB Condition 0-0-ER-N-X-I-NO-TD =10,000 Units454Connection - 889 8 Gas: Max Drill : 442 units @ 12489' MD; Avg Drill : 236 units psi, 140 rpm, 9.1k-11k ft-lbs torque, 2-5k lbs WOB. Serviced the top drive and greased the blocks. 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air Bit # 6 1.1 8.5 8.10 HDBS SFE46D 8.00 Size 13337'13 Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 10.22 Nabors 19AC Report For: Morning Report Report # 33 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough - - ROP ROP (ft/hr) 3.554 @ Mud Data Depth 1-Mar-2016 11:59 PM Current Pump & Flow Data: 0 Max 617 Lime lb / bbl 3.37 Drilled ahead from 11437’ MD to 11661’ MD at 227 gpm, 2330 psi, 100 rpm, 11.5k-11.8k ft-lbs torque, 5-10k lbs Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Circulated at 230 GPM while rebooting the Sperry computer system. Drilled ahead from 13582’ MD to 14562’ MD at Density (ppg) out (sec/qt) Viscosity Cor Solids % Lime lb / bbl 2.33 769 2-Mar-2016 11:59 PM Current Pump & Flow Data: 2755 Max - - ROP ROP (ft/hr) 3.554 @ Mud Data Depth Morning Report Report # 34 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 10.60 Nabors 19AC Report For: Bit # 6 1.6 8.5 8.15 HDBS SFE46D 8.05 Size 15470'16 8 Gas: Max Drill : 574 units @ 15252' MD; Avg Drill : 301 units pump rates. Performed a kick while drilling drill. Serviced the top drive and blocks. Currently drilling ahead at 15705’ MD. Drilled ahead from 14548’ MD to 15705’ MD at 230 GPM, 2710 PSI, 140 RPM, 11.3k ft-lbs Torque, 4-9k lbs WOB. Obtained slow 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units492Connection - 1317 Dir/Gamma/Res/PWD/CTN/ALD HTHP Chromatograph (ppm) - 287968' 11362' WOB Condition 0-0-ER-N-X-I-NO-TD Surface Casing 9.9310.32 Avg Min Comments 2.0 11362' 424 50.27 - Stab (V) RPM ECD (ppg) ml/30min 381 - 140 HDBS MME64 BaraECD Background (max) Trip/Circ Average - Mud Type Lst 100 - Intermediate 2 Casing Type - Depth in / out YP (lb/100ft2) 6.125 Footage - - 7125466 05 - CementCht Silt C-4i C-4n - 24 hr Max 40.0 Weight 1595 Hours C-3 -- 0.389 Ss Ratio C-1 C-5i AK-AM-0903090400 Drilling Ahead PV 3394' R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 15 - - Gas Summary 0 399 94 (current) Avg to13582' Yesterday's Depth: Current Depth: 24 Hour Progress: 224.4 Flow In (gpm) Flow In (spm) 13582' 15704' 2122' Max @ ft Current 14269'123.1 Date: Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls 230 GPM, 2650 PSI, 140 RPM, 11.2k ft-lbs Torque, 0-10k lbs WOB. Obtained slow pump rates. Performed a kick while drilling drill. 301 in 5 14446'Minimum Depth C-5n 15252' 96.0 C-2 574 SPP (psi) Gallons/stroke TFABit Type Depth 67.2/32.854 Tools Oil / Water 15704' Elec 1.107 6 151 0 Siltst 26.0 9.625" 139 39 Units* Casing Summary Lithology (%) - Set At 9331054 151 907-670-6636Unit Phone: 99 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst - Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" L-80 Max Conn : 492 units @ 15318' MD; Avg Conn : 343 units (max)(current) Intermediate 1 Liner 2746 10 Cly 55009 . . * 24 hr Recap: Max Conn : 531 units @ 16860' MD; Avg Conn : 361 units (max)(current) Intermediate 1 Liner 2669 79 Cly 58292 Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" L-80 907-670-6636Unit Phone: 94 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 32776 1153 9.625" 228 64 Units* Casing Summary Lithology (%) - Set At 17343' Elec 1.107 46 144 8 Siltst 26.0 - SPP (psi) Gallons/stroke TFABit Type Depth 70.0/30.054 Tools 17191' 62.7 C-2 577 in 13 15805'Minimum Depth C-5n Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls then obtained slow pump rates. Drilled ahead from 16572’ MD to 17224’ MD at 230 GPM, 2760 PSI, 140 RPM, 12.2k ft-lbs torque, 318 Serviced the top drive and blocks. Currently drilling ahead at 17343’ MD. 15704' 17343' 1639' Max @ ft Current 16976'117.5 Date: Avg to15704' Yesterday's Depth: Current Depth: 24 Hour Progress: 191.3 Flow In (gpm) Flow In (spm) - - Gas Summary 6 378 88 (current) R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 12 Ss Ratio C-1 C-5i AK-AM-0903090400 Drilling Ahead PV 3394' 24 hr Max 40.0 Weight 1575 Hours C-3 -- 0.389 - CementCht Silt C-4i C-4n - 6523961 1022 - Depth in / out YP (lb/100ft2) 6.125 Footage - - Oil / Water Mud Type Lst 100 - Intermediate 2 Casing Type Average -Background (max) Trip/Circ - Stab (V) RPM ECD (ppg) ml/30min 302 - 140 HDBS MME64 BaraECD Surface Casing 10.2110.49 Avg Min Comments 2.0 11362' 496 50.27 Dir/Gamma/Res/PWD/CTN/ALD HTHP Chromatograph (ppm) - 287968' 11362' WOB Condition 0-0-ER-N-X-I-NO-TD =10,000 Units531Connection - 1264 8 Gas: Max Drill : 577 units @ 17191' MD; Avg Drill : 317 units 180 GPM, 140 RPM. Drilled ahead from 17224’ MD to 17343’ MD at 230 GPM, 2830 PSI, 80 RPM, 12.2k ft-lbs torque, 3-8k lbs WOB. dog leg. Reamed at 60 FPH from 17200’ MD to 17206’ MD twice at 180 GPM, 140 RPM, and from 17200’ MD to 17212’ MD twice at 3-10k lbs WOB and obtained slow pump rates. Circulated at 230 GPM, 140 RPM while waiting on orders on what to do about the 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air Bit # 6 1.6 8.5 8.20 HDBS SFE46D 8.00 Size 17317'14 Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 10.72 Nabors 19AC Report For: Morning Report Report # 35 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough - - ROP ROP (ft/hr) 3.554 @ Mud Data Depth 3-Mar-2016 11:59 PM Current Pump & Flow Data: 2828 Max 738 88 Lime lb / bbl 2.72 Drilled ahead from 15704’ MD to 16572’ MD at 230 GPM, 2730 PSI, 140 RPM, 12.4k ft-lbs torque, 5-10k lbs WOB, Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Drilled from 17343’ MD to lateral section TD of 18811’ MD, drilling through the Nuiqsut Zones 2, 3, 4, 5d, and 5a, as Density (ppg) out (sec/qt) Viscosity Cor Solids %lb / bbl 2.46 472 54 Lime 4-Mar-2016 11:59 PM Current Pump & Flow Data: 0 Max Depth ROP ROP (ft/hr) 3.554 @ Mud Data Morning Report Report # 36 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 10.79 Nabors 19AC Report For: Bit # 6 2.7 8.5 8.20 HDBS SFE46D 8.10 Size 18811'14 8 Gas: Max Drill: 577 units @ 18170' MD; Avg Drill: 227 units sandy. 135 units at 18649’ MD, with an average gas of 70 units. Multiple pressure spikes were observed throughout the day, but none resulted Nechelik Shale, the max gas was 228 units at 18616’ MD, with an average gas of 130 units. In the Upper Nechelik, the max gas was annulus. Throughout the Nuiqsut zones, the max gas was 557 units at 18170’ MD (Zone 5d), with an average gas of 250 units. In the 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units404Connection - 1058 Chromatograph (ppm) - 287968' 11362' WOB Condition 0-0-ER-N-X-I-NO-TD - - 10.2610.59 Avg Min Comments 2.0 552 Dir/Gamma/Res/PWD/CTN/ALD HTHP Stab (V) RPM ECD (ppg) ml/30min 14 - 140 HDBS MME64 BaraECD Surface Casing Background (max) Trip/Circ Average 38 Mud Type Lst - - Intermediate 2 Casing Type 30 - Depth in / out YP (lb/100ft2) Footage - Oil / Water C-4n - 4214839 0 0.389 - CementCht Silt 6.125 - - 11362' Weight 1057 Hours C-3 -- C-4i 50.27 C-1 C-5i AK-AM-0903090400 Back Reaming PV 3394' 24 hr Max 40.0 R. Klepzig & J. Petitjean ShClyst - - TuffGvlCoal cP 12 - - Gas Summary 8 284 63 (current) Avg to17343' Yesterday's Depth: Current Depth: 24 Hour Progress: 251.5 Flow In (gpm) Flow In (spm) 17343' 18811' 1468' Max @ ft Current 18623'106.4 Date: Time: Downhole Fluid Gain/Loss (24 hours): 0 bbls well as the Nechelik Shale and the Upper Nechelik formations. As indicated by lag gas time, a 40 bbl correction was applied to the 227 in a significant increase in gas readings over background levels. Cuttings were mainly sandstone throughout the Nuiqsut formation in the Nechelik Shale and Upper Nechelik were similar siltstones with the following properties: brown and light grey, firm, elongate, with the following properties: clear and tan, very fine to fine grained, subrounded to rounded, well sorted, and unconsolidated. Cuttings in 15 17798'Minimum Depth C-5n 18170' 0.0 C-2 577 SPP (psi) Gallons/stroke TFABit Type Depth 71.8/28.249 Tools Set At 18811' Elec 1.107 68 111 10 Siltst 0 0 Units* Casing Summary Lithology (%) 100 26.0 - Ss Ratio 23537 899 907-670-6636Unit Phone: 65 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst Size 60.0 L-80 Grade L-8011354' MD / 6271' TVD 11.75" 7" L-809.625" Max Conn: 404 units @ 18017' MD; Avg Conn: 235 units (max)(current) Intermediate 1 Liner 2643 96 Cly 59929 . . * 24 hr Recap: Cly 35750 7" L-809.625" Gas: Max Trip: 333 units @ 4:10; Avg Trip: 14 units (max)(current) Intermediate 1 Liner 1139 0 907-670-6636Unit Phone: 31 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 452 0 Casing Summary Lithology (%) - 26.0 - Ss Size 60.0 11354' MD / 6271' TVD 11.75" - Elec 1.107 0 50 0 Siltst Ratio L-80 SPP (psi) Gallons/stroke TFABit Type Depth 72.8/27.251 C-5n - - C-2 333 in 0 -Minimum Depth Set At Units* Downhole Fluid Gain/Loss (24 hours): 0 bbls gpm, 90 rpm. Performed a second pore pressure test at 18400’ MD, resulting in 8.894 ppg EMW (225 psi) with a 8.2 ppg mud 14 18811' 18811' 0' Max @ ft Current -- Date: Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: - Gas Summary 0 121 30 (current) TuffGvlCoal cP 12 - Grade L-80 24 hr Max 40.0 R. Klepzig & J. Petitjean ShClyst - Tools 0 0 AK-AM-0903090400 Tripping in the Hole PV 3394' 25 Hours C-3 -- 50.27 C-1 0.389 - CementCht Silt 6.125 - - 11362' 5124 0 Footage - Oil / Water C-4n - Weight C-4i C-5i - Mud Type Lst - - Intermediate 2 Casing Type - Depth in / out Average 333 (max) Trip/Circ6 - 140 HDBS MME64 BaraECD Surface Casing Background Avg Min Comments 2.2 861 Dir/Gamma/Res/PWD/CTN/ALD HTHP Stab (V) RPM ECD (ppg) WOB Condition 0-0-ER-N-X-I-NO-TD - - ml/30min YP (lb/100ft2) Chromatograph (ppm) - 287968' 11362' 0 100% Gas In Air=10,000 Units-Connection - 464 16 8 hole from 11277’ MD to 17246’ MD, filling pipe every 30 stands. No losses were observed while tripping in the hole. while back reaming, however, a gas peak of 333 units was observed at the bottoms up from the pore pressure test. Tripped in the weight. Back reamed at 240 gpm, 140 rpm from 18400’ MD to the shoe at 11277’ MD. No losses or pressure spikes were observed 7939' MD / 5002' TVD 4099' MD / 3238' TVD 8.5 8.15 HDBS SFE46D 8.10 Size 18811' Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: Nabors 19AC Report For: Morning Report Report # 37 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough ROP ROP (ft/hr) 3.554 @ Depth Mud Data Bit # 6 2.8 17 3 Lime 5-Mar-2016 11:59 PM Current Pump & Flow Data: 0 Max lb / bbl 1.42 Performed a pore pressure test at 18400’ MD, returned inconclusive results. Circulated and conditioned mud at 240 Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Tripped in the hole from 17246’ MD to 18440’ MD, then began circulating and conditioning mud at 18440’ MD, Density (ppg) out (sec/qt) Viscosity Cor Solids %lb / bbl 2.59 6-Mar-2016 11:59 PM Current Pump & Flow Data: 0 Max Depth Mud Data Bit # 6 8.7 ROP ROP (ft/hr) 3.554 @ Morning Report Report # 38 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: 12.56 Nabors 19AC Report For: 8.5 10.00 HDBS SFE46D 10.00 Size 18811' 8 with 10k lbs overpull while pulling into the shoe. Circulated and conditioned mud and pumped a 40 bbl EP-Mudlube sweep at 210 Removed the MPD RCD bearing and installed the trip nipple. Lubricated out of the hole from 18440’ MD to 11277’ MD at 2 bpm bottoms up from beginning circulation. 10.0 ppg mud was observed at the surface at 7926 strokes, 20 bbls past calculated volume. 7939' MD / 5002' TVD 4099' MD / 3238' TVD 100% Gas In Air=10,000 Units 0 ml/30min YP (lb/100ft2) Chromatograph (ppm) - 287968' 11362' 0 Condition 0-0-ER-N-X-I-NO-TD - - 10.4711.25 Lime Avg Min Comments 1.8 501 Dir/Gamma/Res/PWD/CTN/ALD HTHP Stab (V) RPM ECD (ppg) 140 HDBS MME64 BaraECD Surface Casing Background WOB - (max) Trip/Circ0 Connection Average 366 Mud Type Lst - - Intermediate 2 Casing Type - Depth in / out - Oil / Water C-4n - Weight C-4i C-5i - -6.125 - - 11362' 010 0 C-3 -- 50.27 C-1 0.389 Silt AK-AM-0903090400 Laying Down BHA PV 3394' Footage 16 24 hr Max 40.0 R. Klepzig & J. Petitjean ShClyst - Tools 0 0 Hours TuffGvlCoal cP 25 - Grade L-80 - Cement - Gas Summary 0 78 19 (current) Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: 18811' 18811' 0' Max @ ft Current -- Date: Downhole Fluid Gain/Loss (24 hours): 0 bbls staging up pumps to 5 bpm. Displaced from 8.2 ppg mud to 10.0 ppg kill weight mud, observing 366 units of trip gas at the 6 gpm. Tripped out of the hole from 11277’ MD to 408’ MD, pumping a dry job at 10888’ MD. No losses were observed during the trip out of the hole. Laid down BHA #13 to surface. in 0 -Minimum Depth Set At Units*C-5n - - C-2 366 SPP (psi) Gallons/stroke TFABit Type Depth 70.5/29.582 - Elec 1.107 0 33 0 Siltst Ratio L-80Casing Summary Lithology (%) - 26.0 - Ss Size 60.0 11354' MD / 6271' TVD 11.75" 412 0 10 3 907-670-6636Unit Phone: 18 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst Gas: Max Trip: 366 units @ 2:30; Avg Trip: 6 units (max)(current) Intermediate 1 Liner 1029 0 Cly 43469 7" L-809.625" Cht - 347 . . * 24 hr Recap: 0 7" L-809.625" Cht - 0 Gas: Max Trip: 0 units; Avg Trip: 0 units (max)(current) Intermediate 1 Liner 0 0 907-670-6636Unit Phone: 0 David Durst Maximum Report By:Logging Engineers:Kerry Garner / David Durst 0 0 0 0 Casing Summary Lithology (%) - 26.0 - Ss Size 60.0 11354' MD / 6271' TVD 11.75" - Elec 1.107 0 0 0 Siltst Ratio L-80 SPP (psi) Gallons/stroke TFABit Type Depth 70.4/29.688 C-5n - - C-2 0 in 0 -Minimum Depth Set At Units* Downhole Fluid Gain/Loss (24 hours): 0 bbls in the derrick. Pulled the wear bushing, changed the rams, and tested the blowout preventer. Rigged up GBR liner running 0 18811' 18811' 0' Max @ ft Current -- Date: Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: - Gas Summary 0 0 0 (current) TuffGvlCoal cP 25 - Grade L-80 - Cement 24 hr Max 40.0 R. Klepzig & J. Petitjean ShClyst - Tools 0 0 Hours AK-AM-0903090400 Running 4.5" Tubing PV 3394' Footage 18 -- 50.27 C-1 0.389 Silt Cly - 11362' 000 0 C-3 Oil / Water C-4n - Weight C-4i C-5i - 14071.15 Mud Type Lst - - Intermediate 2 Casing Type 18811' Depth in / out 7449' Average 0 (max) Trip/Circ0 Connection HDBS MME64 BaraECD Surface Casing Background - 6.125 Avg Min Comments 1.8 509 - HTHP Stab (V) RPM ECD (ppg) 0 Condition 0-0-ER-N-X-I-NO-TD 8-1-BT-N-X-I-LT=TD - -- Lime 140 WOB 0 ml/30min YP (lb/100ft2) Chromatograph (ppm) 10 287968' 11362' 100% Gas In Air=10,000 Units 18811' 8 equipment and ran 4.5” lower completion tubing from surface to 5942’ MD with good displacement and no significant gas observed. 7939' MD / 5002' TVD 4099' MD / 3238' TVD Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Morning Report Report # 39 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough ROP ROP (ft/hr) 3.554 @ Mud Data Bit # 6 8.9 8.5 10.00 HDBS SFE46D 10.00 7-Mar-2016 11:59 PM Current Pump & Flow Data: 0 Max Depth lb / bbl 2.85 Size Picked up 57 joints of HWDP, circulated 1.5x pipe volume once all the pipe was picked up, and racked the pipe back Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap: 7" L-809.625" Cht - Gas: Max Trip: 94 units; Avg Trip: 5 units (max)(current) Intermediate 1 Liner 431 0 907-670-6636Unit Phone: 0 Beverly Hur Maximum Report By:Logging Engineers:Kerry Garner / Beverly Hur 19 0 0 0 Casing Summary Lithology (%) - 26.0 - Ss Size 60.0 11354' MD / 6271' TVD 11.75" 1.107 0 13 0 Siltst L-80 11862 149 TFABit Type Depth - 27 - Ratioin SPP (psi) Gallons/stroke Elec Minimum - - C-2 TuffGvl 0 - 94 C-5nDepth - Gas Summary Downhole Fluid Gain/Loss (24 hours): 0 bbls strokes. Continued to run in the hole with the 4.5" liner on drill pipe. At 67 stands, began filling the pipe every 10 stands. 5 or gains. Began tripping out of the hole at 10984' MD and reached 59 stands to a depth of 6221' MD at midnight. Currently tripping out of the hole. (max) 18811' 18811' 0' Max @ ft Current -- Date: Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: 30 0 (current)- Units* Coal cP - - Grade L-80 - Cement - - 24 hr Max 40.0 R. Klepzig & J. Petitjean ShClyst - Tools 0 0 Hours AK-AM-0903090400 Tripping out of the Hole PV 3394' Footage - Depth in / out WOB C-1 0.389 Silt Cly 11362' Set At 000 000 C-3 Oil / Water C-4n - Weight C-4i C-5i - 50.27 71.15 Mud Type Lst -- Intermediate 2 Casing Type 18811' 7449' Average 94Trip/Circ0 Connection HDBS MME64 Brine Surface Casing Background - 6.125 Avg Min Comments - - - HTHP Stab (V) RPM ECD (ppg) Condition 0-0-ER-N-X-I-NO-TD 8-1-BT-N-X-I-LT=TD - -- Lime 140 140 0 ml/30min YP (lb/100ft2) Chromatograph (ppm) 10 287968' 11362' 100% Gas In Air=10,000 Units 18811' 8 94 units of gas following the ZXP test for the max gas of the day. Displaced 10.1 ppg MOBM to10.0 ppg Brine with no losses At 18440' MD began pumping the ball to set the liner hanger. Performed ZXP Test at 18444' MD to 4038 PSI. Observed Noticed a volume increase at 113 stands and informed the Company Man. A spray bar was on causing the increase. 7939' MD / 5002' TVD 4099' MD / 3238' TVD Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: Morning Report Report # 40 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough ROP ROP (ft/hr) 3.554 @ Mud Data Bit # 6 - 8.5 10.00 HDBS SFE46D 10.00 8-Mar-2016 11:59 PM Current Pump & Flow Data: 0 Max Depth lb / bbl - Size Completed tripping in the hole with 4.5" tubing. Picked up the liner hanger and circulated liner volume of 1356 Density (ppg) out (sec/qt) Viscosity Cor Solids % . . * 24 hr Recap:Completed tripping in the hole with 4" drill pipe. Attended the pre-job safety meeting for running the Frac Tubing. Density (ppg) out (sec/qt) Viscosity Cor Solids %lb / bbl - Size 9-Mar-2016 11:59 PM Current Pump & Flow Data: 0 Max Depth Mud Data Bit # 6 - 8.5 10.00 HDBS SFE46D 10.00 ROP ROP (ft/hr) 3.554 @ Morning Report Report # 41 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: 18811' 8 to perform pressure tests at the time of report. 7939' MD / 5002' TVD 11362' 100% Gas In Air=10,000 Units 140 0 ml/30min YP (lb/100ft2) Chromatograph (ppm) 10 287968' Stab (V) RPM ECD (ppg) Condition 0-0-ER-N-X-I-NO-TD 8-1-BT-N-X-I-LT=TD -- Lime 140 - 6.125 Avg Min Comments - - - Trip/Circ0 ConnectionBackground Average 0 Lst -- Intermediate 2 Casing Type Surface Casing4099' MD / 3238' TVD Weight C-4i C-5i - 50.27 71.15 18811' 7449' - 000 000 0.389 Silt Cly 11362' Set At HDBS MME64 AK-AM-0903090400 RIH w/ 4.5" Completion PV 3394' Footage - Depth in / out WOB 24 hr Max 40.0 J. Polya & J. Petitjean ShClyst - Tools 0 0 Hours cP - - Grade L-80 - Cement - - -- Units*C-1 C-3 Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: 18811' 18811' 0' Max @ ft Current -- Date: Downhole Fluid Gain/Loss (24 hours): 0 bbls Began running in the hole at 04:30 and continued until 23:00. There were no gains or losses and no gas. On standby 0 (max) - Gas Summary 0 (current) 0 - 0 C-5nDepthC-4n Minimum - - C-2 SPP (psi) Gallons/stroke ElecOil / Water HTHP TFABit Type Depth - 28 - Ratioin Mud Type Brine 1.107 0 0 Siltst L-80Casing Summary Lithology (%) - 26.0 - Ss Size 60.0 11354' MD / 6271' TVD 11.75" 0 0 0 907-670-6636Unit Phone: 0 Beverly Hur Maximum Report By:Logging Engineers:Kerry Garner / Beverly Hur Gas: Max Trip: 0 units; Avg Trip: 0 units (max)(current) Intermediate 1 Liner 0 7" L-809.625" Cht - TuffGvlCoal . . * 24 hr Recap: - Casing Summary 4.5"18440' MD / 6328' MD Production Casing 12.6 L-80 Performed an initial annulus pressure test to 500 PSI. Tested the upper completion string inner tubing to a max Density (ppg) out (sec/qt) Viscosity Cor Solids %lb / bbl - Size 10-Mar-2016 11:59 PM Current Pump & Flow Data: 0 Max Depth Mud Data Bit # 6 - 8.5 10.00 HDBS SFE46D 10.00 ROP ROP (ft/hr) 3.554 @ Morning Report Report # 42 Customer: Well: Area: Location: Rig: ODSN-01A Caelus Energy Alaska Oooguruk North Slope Borough Job No.: Daily Charges: Total Charges: MWD Summary 96% Rig Activity: - Nabors 19AC Report For: 18811' 8 all workstations. Rig laying down 4" drill pipe at time of report. maintenance on the CVE and rigged down CVE hose and lines in preparation for the rig move. Currently updating software on 7939' MD / 5002' TVD 11362' 100% Gas In Air=10,000 Units 140 0 ml/30min YP (lb/100ft2) Chromatograph (ppm) 10 287968' Stab (V) RPM ECD (ppg) Condition 0-0-ER-N-X-I-NO-TD 8-1-BT-N-X-I-LT=TD -- Lime 140 - 6.125 Avg Min Comments - - - Trip/Circ0 ConnectionBackground Average 0 Lst -- Intermediate 2 Casing Type Surface Casing4099' MD / 3238' TVD Weight C-4i C-5i - 50.27 71.15 18811' 7449' - 000 000 0.389 Silt Cly 11362' Set At HDBS MME64 Lithology (%) AK-AM-0903090400 Laying Down 4" Drill Pipe PV 3394' Footage - Depth in / out WOB 24 hr Max 40.0 J. Polya & J. Petitjean ShClyst - Tools 0 0 Hours cP - - Grade L-80 - Cement - - -- Units*C-1 C-3 0 Avg to- Yesterday's Depth: Current Depth: 24 Hour Progress: - Flow In (gpm) Flow In (spm) Time: 18811' 18811' 0' Max @ ft Current -- Date: Downhole Fluid Gain/Loss (24 hours): 0 bbls of 3769 PSI for 35 minutes. Made a final test of the annulus to a max of 4139 PSI for 45 minutes. Completed scheduled 0 (max) - Gas Summary 0 (current) - 0 C-5nDepthC-4n Minimum - - C-2 SPP (psi) Gallons/stroke ElecOil / Water HTHP TFABit Type Depth - 28 - Ratioin Mud Type Brine 1.107 0 0 Siltst L-80 - Ss Size 60.0 11354' MD / 6271' TVD 11.75" 7" 0 0 0 907-670-6636Unit Phone: 0 Beverly Hur Maximum Report By:Logging Engineers:Kerry Garner / Beverly Hur Gas: Max Trip: 0 units; Avg Trip: 0 units (max)(current) Intermediate 1 Liner 0 L-809.625" Cht - TuffGvlCoal - 26.0 ! " ! ! #$ %$&'$($$ ) *+ " + ,$ - + ./ + + 01 2+ 21 + -+ !"#$ %!&#'&(! )* + , + 1 + - . + !"#$ %!&#'&(! )* + , # + / 0 "+ 3 "+ ) * 4+ " "+1- + ")23 , + ") 1, 4 5 1 / 3- 1 .333 2 2) , -+ , -+ + # + 5 6$2 5#6$ ) 7 3 -,+ ! ! (6 % 6 & !% (+6+ ! & %!& 2- + ! " 7 +# (! & 7 # &! 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" (6 !< 6+"%! 6 (%! +(6 &&!( (6 6 ( !(+ &+6< !"& ! 6+&(! " /$8: $ $ )(, "6<& ! < + !< % "!"& (6 ! & 6 & ! % 6 !+<(6 &%!+& (6 6 &!+ &+6"& ! + !<" &6 & ! /$8: $ $ )(, "6+ <! + !(& % (!+< (6 <! " 6 %&!+& 6 ("! +(6 & !<" (6 6% "!( &+6(++! ! & &6 (!( /$8: $ $ )(, <6 !< <<! % !"+ (6 +! 6 &!++ 6% ! (6 & !< (6 6 "!<" &+6( &!&% %!%" &6 ! " /$8: $ $ )(, <6 ! " <&! " % %!& (6 ! " 6 + ! 6%""!+%(6 &<! < (6 6 <(!% &+6&<+!% %!% &6%%<! /$8: $ $ )(, <6 %(!& <(! % ! + (6 !& 6%(+!+ 6 % !+"(6 (&!% (6 6&( ! % &+6&% !( ! & &6 % !& /$8: $ $ )(, <6%%%!&" <(! % !& (6 <! 6 (!" 6 +%!+ (6 " !+ (6 6(%+! < &+6 "%!+" ! &6& <!+" /$8: $ $ )(, <6 +!+% < !"% % !& (6 %<! 6& !(+ 6&&%!&%(6 < ! (6 6" ! < &+6 !(" !<+ &6( !&% /$8: $ $ )(, <6& !< "(! % <!"& (6 &(!%+ 6&+ !(" 6( %!<((6 ! + (6 6"<&!" &+6%& !(% &!<( &6" "!(% /$8: $ $ )(, <6( !%< " !+ % <!(" (6 < ! " 6(( !+( 6("&!&+(6 ! " (6 6<&(! &+6 +%! !&< &6< ! & /$8: $ $ )(, <6" "!(( "&! % +! " (6% &! " 6"%%! 6"%(!( (6 <!+" (6 6+ (!( &+6 % ! !(% &6+ ! /$8: $ $ )(, <6" %!& "&! % % +! ( (6% !"+ 6"& ! ( 6"& !+&(6 &&!&+ (6 6+ &!(% &+6 (! !& &6+ +! /$8: $ $ )(, <6< ! "&! % % +! ( (6% +! 6< ! + 6"+&!&%(6 " !< (6 6++&! % &+6 "%!< ! &6++ !%% -E00 .? @=3.? @ @ Client Caelus Energy Alaska Well ODSN-la Formation Nuigsut District Prudhoe Bay, AK Country United States Schlumberger Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 10 PPA 40.0 YF125ST 145 25.0 CarboLite 16/20 10.00 FLUSH 40.0 YF125ST 235 25.0 5023 0.00 Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 1629 bbl of YF125ST Proppant Totals 2238001b of CarboLite 16/20 Pad Percentages % PAD Clean 35.9 % PAD Dirty 30.6 Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Cum. Slurry Slurry Volume Volume (bbl) (bbl) Step Prop (Ib) Cum. Prop. (Ib) Avg. Step Cum. Surface Time Time Pressure (min) (min) (psi) PAD 6 500 500 500.0 500.0 0 0 5426 12.5 12.5 1 PPA 120 620 125.0 625.0 5023 5023 5460 3.1 15.6 3 PPA 150 769 170.0 795.0 18858 23881 5569 4.3 1 19.9 5 PPA 171 940 210.0 1005.0 35958 59839 6350 5.3 25.1 7 PPA 159 1100 210.0 1215.0 46879 106718 7211 5.3 30.4 9 PPA 149 1249 210.0 1425.0 56395 163113 7787 5.3 35.6 10 PPA 145 1394 1 210.0 1635.0 60708 223821 1 8073 5.3 40.9 FLUSH 235 1629 1 235.2 1870.2 0 223821 1 7341 5.9 46.8 Attaclunent G Client Caelus Energy Alaska schIYmho1 oe1 Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 6) The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 6 MD - Initial Fracture Top TVD_________ Initial Fracture Bottom TVD Propped Fracture Half -Length. Average Propped Width ......... Max Surface Pressure 15763.0 ft 6202.0 ft 6232.0 ft 440.5 ft 0.278 in ------ 8143 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 110.1 11.3 0.288 72.1 2.57 309.4 7649 110.1 220.2 10.4 0.298 101.1 2.65 308.3 7935 220.2 330.3 8.2 0.287 90.5 2.46 307.6 7761 330.3 440.5 2.9 0.244 74.2 2.15 1 317.4 7138 Attachment G Client Caelus Energy Alaska Well ODSN-la Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 7) Schluhorgor Formation Mechanical Properties Zone Name Top TO (ft) ZoneFrac Height (ft) Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.ino.5) SHALE 6153.0 50.0 0.800 4942 5.000E+5 0.33 1000 Dirty Sandstone 6203.0 5.0 0.664 4118 2.000E+6 0.33 700 Clean Sandstone 6208.0 30.0 0.650 4045 1.600E+6 0.25 1200 Dirty Sandstone 6238.0 15.0 0.670 4184 2.000E+6 0.33 1000 Shale 6253.0 5.0 0.700 4379 2.000E+6 0.29 1000 Clean Sandstone 6258.0 30.0 0.650 4077 1.600E+6 0.22 1000 Dirty Sandstone 6288.0 5.0 0.670 4215 2.000E+6 0.33 1000 SHALE 6293.0 15.0 0.800 5040 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TO (ft) Net Height (ft) Perm (m d) Porosity 1%► Res. Pressure (psi) SHALE 6153.0 1.0 0.001 1.0 2891 Dirty Sandstone 6203.0 4.0 0.500 12.0 2877 Clean Sandstone 6208.0 30.0 2.000 16.0 2912 Dirty Sandstone 6238.0 12.0 0.500 12.0 2906 Shale 6253.0 2.0 0.200 10.0 2912 Clean Sandstone 6258.0 30.0 2.000 15.0 2920 Dirty Sandstone 6288.0 4.0 0.500 12.0 2906 SHALE 6293.0 1.0 0.001 1.0 2949 Propped Fracture Schedule (Stage 7) Pumping Schedule Attachment G Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 7 40.0 YF125ST 420 25.0 0.00 1 PPA 40.0 YF125ST 172 25.0 CarboLite 16/20 1.00 3 PPA 40.0 YF125ST 1 158 25.0 CarboLite 16/20 3.00 5 PPA 40.0 YF125ST 204 25.0 CarboLite 16/20 5.00 7 PPA 40.0 YF125ST 171 25.0 CarboLite 16/20 7.00 9 PPA 40.0 YF125ST 160 25.0 CarboLite 16/20 9.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States schlubepgcp Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 10 PPA 40.0 YF125ST 138 25.0 CarboLite 16/20 10.00 FLUSH 1 40.0 YF125ST 225 25.0 420 0.00 Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals -1 1648 bbl of YF125ST Proppant Totals 2385001b of CarboLite 16/20 Pad Percentages % PAD Clean 29.5 % PAD Dirty 25.0 Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 7 420 420 420.0 420.0 0 0 5087 10.5 10.5 1 PPA 172 592 180.0 600.0 7232 7232 5111 4.5 15.0 3 PPA 158 751 180.0 780.0 19967 27200 5244 4.5 19.5 5 PPA 204 955 250.0 1030.0 42807 70007 6008 6.3 25.8 7 PPA 171 1125 225.0 1255.0 50228 120235 6805 5.6 31.4 9 PPA 160 1285 225.0 1480.0 60423 180658 7337 5.6 37.0 10 PPA 138 1423 200.0 1680.0 57817 238475 7650 1 5.0 42.0 FLUSH 225 1648 225.2 1905.2 0 1238475 7068 5.6 47.6 Attachment G Client Caelus Energy Alaska �chlu��r��r Well ODSN-1a Propped Width (in) Formation Nuigsut Frac. Gel Conc. (Ib/mgal) District Prudhoe Bay, AK 102.2 Country United States 72.4 Propped Fracture Simulation (Stage 7) The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 7 MD -_ Initial Fracture Top TVD_____________ Initial Fracture Bottom TVD Propped Fracture Half -Length __-__ Average Propped Width_____________ Max Surface Pressure 15104.0 ft 6208.0 ft 6238.0 ft 408.6 ft 0.324 in --__ 7756 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 102.2 10.7 0.353 72.4 3.15 280.6 9789 102.2 204.3 10.0 0.360 99.1 3.22 285.5 9933 204.3 306.5 8.1 0.340 89.0 2.95 296.8 9464 306.5 408.6 3.2 0.254 75.0 2.21 391.6 6992 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 8) Sc Icmbagerl Formation Mechanical Properties Zone Name Top TVD (ft) Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.inO.5) SHALE 6159.0 50.0 0.800 4947 5.000E+5 0.33 1000 Dirty Sandstone 6209.0 5.0 0.670 4162 2.000E+6 0.33 700 Clean Sandstone 6214.0 30.0 0.650 4049 1.600E+6 0.25 1200 Dirty Sandstone 6244.0 15.0 0.670 4189 2.000E+6 0.33 1000 Shale 6259.0 5.0 0.700 4383 2.000E+6 0.29 1000 Clean Sandstone 6264.0 30.0 0.650 4081 1.600E+6 0.22 1000 Dirty Sandstone 6294.0 5.0 0.670 4219 2.000E+6 0.33 1000 SHALE 6299.0 1 15.0 0.800 5045 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TO (ft) Net Height (ft) Perm (md) Porosity Res. 1%► Pressure (psi) SHALE 6159.0 1.0 0.001 1.0 2894 Dirty Sandstone 6209.0 4.0 0.500 12.0 2877 Clean Sandstone 6214.0 30.0 1 2.000 16.0 2915 Dirty Sandstone 6244.0 12.0 0.500 12.0 2906 Shale 6259.0 2.0 0.200 10.0 2912 Clean Sandstone 6264.0 30.0 2.000 15.0 2920 Dirty Sandstone 6294.0 4.0 0.500 12.0 2906 SHALE 6299.0 1.0 0.001 1.0 2951 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States schlctorgcr Propped Fracture Schedule (Stage 8) Pumping Schedule Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 1302 bbl of YF125ST 215 bbl of WF125 Proppant Totals 239100 lb of CarboLite 16/20 Pad Percentages % PAD Clean 24.6 Job Description 20.5 Job Execution Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 8 40.0 YF125ST 320 25.0 Cum. Time (min) 0.00 1 PPA 40.0 YF125ST 144 25.0 CarboLite 16/20 1.00 2 PPA 40.0 YF125ST 151 25.0 CarboLite 16/20 2.00 4 PPA 40.0 YF125ST 161 25.0 CarboLite 16/20 4.00 6 PPA 40.0 YF125ST 149 25.0 CarboLite 16/20 6.00 8 PPA 40.0 YF125ST 139 25.0 CarboLite 16/20 8.00 10 PPA 40.0 YF125ST 131 25.0 CarboLite 16/20 10.00 12 PPA 40.0 YF125ST 107 25.0 CarboLite 16/20 12.00 1 FLUSH 40.0 WF125 215 30.2 46862 0.00 Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 1302 bbl of YF125ST 215 bbl of WF125 Proppant Totals 239100 lb of CarboLite 16/20 Pad Percentages % PAD Clean 24.6 % PAD Dirty 20.5 Job Execution Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop 0b) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 8 320 320 320.0 320.0 0 0 4928 8.0 8.0 1 PPA 144 464 150.0 470.0 6027 6027 4942 3.8 11.8 2 PPA 151 615 165.0 635.0 12709 18736 4999 4.1 15.9 4 PPA 161 776 190.0 825.0 27025 45761 5437 4.8 20.6 6 PPA 149 925 190.0 1015.0 37650 83411 6190 4.8 25.4 8 PPA 139 1065 190.0 1205.0 46862 130273 6869 4.8 30.1 10 PPA 131 1195 190.0 1395.0 54926 185199 7268 4.8 34.9 12 PPA 107 1302 165.0 1560.0 1 53880 1 239079 7469 4.1 39.0 FLUSH 215 1517 215.1 1775.1 1 D 1 239079 5821 5.4 44.4 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 8) scbluburocr The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 8 MD------------------------------------------ 14445.0 ft Initial Fracture Top TVD_______________________ 214.0 ft Initial Fracture Bottom TVD ------------------ 6244.0 ft Propped Fracture Half -Length--------------- 363.9 ft Average Propped Width---------------- ------ 0.371 in Max Surface Pressure---------------- -------- 7576 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 91.0 11.9 0.456 98.5 4.07 233.9 14274 91.0 181.9 10.5 0.440 98.5 3.90 248.6 1 13240 181.9 272.9 8.2 0.399 94.4 3.55 272.7 11485 272.9 363.9 3.1 0.210 82.9 1.86 628.7 5119 Attachtnent G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 9) schlumborgor Formation Mechanical Properties Zone Name Top TVD Iftl Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.ino.5) SHALE 6175.0 50.0 0.800 4960 5.000E+5 0.33 1000 Dirty Sandstone 6225.0 5.0 0.670 4172 2.000E+6 0.33 700 Clean Sandstone 6230.0 30.0 0.650 4059 1.600E+6 0.25 1200 Dirty Sandstone 6260.0 15.0 0.670 4199 2.000E+6 0.33 1000 Shale 6275.0 5.0 0.700 4394 2.000E+6 0.29 1000 Clean Sandstone 6280.0 30.0 0.650 4092 1.600E+6 0.22 1000 Dirty Sandstone 6310.0 5.0 0.670 4229 2.000E+6 0.33 1000 SHALE 6315.0 15.0 0.800 5058 1 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TVD (ft) Net Height (ft) Perm (md) Porosity 1%1 Res. Pressure (psi) SHALE 6175.0 1.0 0.001 1.0 2902 Dirty Sandstone 6225.0 4.0 0.500 12.0 2877 Clean Sandstone 6230.0 30.0 2.000 16.0 2923 Dirty Sandstone 6260.0 12.0 0.500 12.0 2906 Shale 6275.0 2.0 0.200 10.0 2912 Clean Sandstone 6280.0 30.0 2.000 15.0 2920 Dirty Sandstone 6310.0 4.0 0.500 12.0 2906 SHALE 6315.0 1.0 0.001 1.0 2959 Propped Fracture Schedule (Stage 9) Pumping Schedule Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 9 40.0 YF125ST 420 25.0 0.00 1 PPA 40.0 YF125ST 172 25.0 Carbo Lite 16/20 1.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States SGhlum6urgur Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 1628 bbl of YF125ST Proppant Totals 2385001b of CarboLite 16/20 Pad Percentages % PAD Clean 29.5 Job Description 25.0 Job Execution Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 3 PPA 40.0 YF125ST 158 25.0 CarboLite 16/20 3.00 5 PPA 40.0 YF125ST 204 25.0 CarboLite 16/20 5.00 7 PPA 40.0 YF125ST 171 25.0 CarboLite 16/20 7.00 9 PPA 40.0 YF125ST 160 25.0 CarboLite 16/20 9.00 10 PPA 40.0 1 YF125ST 138 25.0 CarboLite 16/20 10.00 FLUSH 40.0 1 YF125ST 1 205 25.0 250.0 0.00 Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 1628 bbl of YF125ST Proppant Totals 2385001b of CarboLite 16/20 Pad Percentages % PAD Clean 29.5 % PAD Dirty 25.0 Job Execution Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 9 420 420 420.0 420.0 0 0 4990 10.5 10.5 1 PPA 172 592 180.0 600.0 7232 7232 5014 4.5 15.0 3 PPA 158 751 180.0 780.0 19967 27200 5174 4.5 1 19.5 5 PPA 204 955 250.0 1030.0 42807 70007 5906 6.3 25.8 7 PPA 171 1125 225.0 1255.0 50228 120235 6546 5.6 31.4 9 PPA 160 1285 225.0 1480.0 60423 180658 6970 5.6 37.0 10 PPA 138 1423 200.0 1680.0 57817 238475 7179 5.0 42.0 FLUSH 205 1628 205.1 1 1885.1 0 238475 6688 5.1 47.1 Attachment G Client Caelus Energy Alaska Well ODSN-la Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 9) schludcrgcr The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 9 MD 13786.0 ft Initial Fracture Top TO 6230.0 ft Initial Fracture Bottom TVD ------------------ 6260.0 ft Propped Fracture Half -Length --------------- 410.5 ft Average Propped Width----------------------- 0.324 in Max Surface Pressure_________________________ 7231 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 102.6 10.7 0.353 72.3 3.16 279.9 9794 102.6 205.3 10.0 0.361 98.9 3.23 284.8 9960 205.3 307.9 8.1 0.337 88.8 2.93 300.7 9288 307.9 410.5 1 3.3 0.255 74.6 2.23 384.1 7162 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 10) SchhIbepgcp Formation Mechanical Properties Zone Name Top TO (ft) Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.ino.5) SHALE 6195.0 50.0 0.800 4976 5.000E+5 0.33 1000 Dirty Sandstone 6245.0 5.0 0.670 4186 2.000E+6 0.33 700 Clean Sandstone 6250.0 30.0 0.650 4072 1.600E+6 0.25 1200 Dirty Sandstone 6280.0 15.0 0.670 4213 2.000E+6 0.33 1000 Shale 6295.0 5.0 0.700 4408 2.000E+6 0.29 1000 Clean Sandstone 6300.0 30.0 0.650 4105 1.600E+6 0.22 1000 Dirty Sandstone 6330.0 5.0 0.670 4243 2.000E+6 0.33 1000 SHALE 6335.0 15.0 0.800 5074 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TVD Net (ft) Height (ft) Perm (m d) Porosity 1%► Res. Pressure (psi) SHALE 6195.0 1.0 0.001 1.0 2911 Dirty Sandstone 6245.0 4.0 0.500 12.0 2877 Clean Sandstone 6250.0 30.0 2.000 16.0 2932 Dirty Sandstone 6280.0 12.0 0.500 12.0 2906 Shale 6295.0 2.0 0.200 10.0 2912 Clean Sandstone 6300.0 30.0 2.000 15.0 2920 Dirty Sandstone 6330.0 4.0 0.500 12.0 2906 SHALE 6335.0 1.0 0.001 1.0 2968 Propped Fracture Schedule (Stage 10) Pumping Schedule Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (lb/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 10 40.0 YF125ST 420 25.0 0.00 1 PPA 40.0 YF125ST 172 25.0 CarboLite 16/20 1.00 3 PPA 40.0 YF125ST 158 25.0 CarboLite 16/20 3.00 5 PPA 40.0 YF125ST 204 25.0 CarboLite 16/20 5.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States scicmhcrgcr Job Description Step Name Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 7 PPA 40.0 YF125ST 171 25.0 CarboLite 16/20 7.00 9 PPA 40.0 YF125ST 160 25.0 CarboLite 16/20 9.00 10 PPA 40.0 YF125ST 138 25.0 CarboLite 16/20 10.00 FLUSH 40.0 YF125ST 195 25.0 25.8 0.00 Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 1618 bbl of YF125ST Proppant Totals 2385001b of CarboLite 16/20 Pad Percentages % PAD Clean 29.5 % PAD Dirty 25.0 Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Cum. Step Slurry Slurry Prop Volume Volume (lb) (bbl) (bbl) Cum. Prop. (Ib) Avg. Step Surface Time Pressure (min) (psi) Cum. Time (min) PAD 10 420 420 420.0 420.0 0 0 4862 10.5 10.5 1 PPA 172 592 180.0 600.0 7232 7232 4885 4.5 15.0 3 PPA 158 751 180.0 780.0 19967 1 27200 5019 4.5 1 19.5 5 PPA 204 955 250.0 1030.0 42807 70007 5699 6.3 25.8 7 PPA 171 1125 225.0 1255.0 50228 120235 6297 5.6 31.4 9 PPA 160 1285 225.0 1480.0 60423 180658 6694 5.6 37.0 10 PPA 138 1423 200.0 1680.0 57817 238475 6888 5.0 42.0 FLUSH 195 1618 195.1 1875.1 0 238475 6454 4.9 46.9 Attachment G Client Caelus Energy Alaska s�jhINmII'orgor Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 10) The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 10 MD Initial Fracture Top TVD_________________ Initial Fracture Bottom TVD ------------ Propped Fracture Half -Length -------__ Average Propped Width ----------------- Max Surface Pressure 13127.0 ft 6250.0 ft 6280.0 ft 410.8 ft 0.324 in 6935 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Cone. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Cone. (Ib/ft2) Frac. Gel Cone. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 102.7 10.7 0.352 72.2 3.15 280.8 9705 102.7 205.4 10.0 0.360 98.8 3.22 285.5 9885 205.4 308.1 8.1 0.337 88.7 1 2.93 1 300.7 1 9258 308.1 410.8 3.3 1 0.258 74.5 1 2.26 1 371.2 1 7311 Atlachniew G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 11) schI MIOPOOP Formation Mechanical Properties Zone Name Top TO (ft) ZoneFrac Height (ft) Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.inO.5) SHALE 6205.0 50.0 0.800 4984 5.000E+5 0.33 1000 Dirty Sandstone 6255.0 5.0 0.670 4193 2.000E+6 0.33 700 Clean Sandstone 6260.0 30.0 0.650 4079 1.600E+6 0.25 1200 Dirty Sandstone 6290.0 15.0 0.670 4219 2.000E+6 0.33 1000 Shale 6305.0 5.0 0.700 4415 2.000E+6 0.29 1000 Clean Sandstone 6310.0 30.0 0.650 4111 1.600E+6 0.22 1000 Dirty Sandstone 6340.0 5.0 0.670 4249 2.000E+6 0.33 1000 SHALE 6345.0 15.0 0.800 5080 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TVD (ft) Net Height (ft) Perm (md) Porosity I%1 Res. Pressure (psi) SHALE 6205.0 1.0 0.001 1.0 2916 Dirty Sandstone 6255.0 4.0 0.500 12.0 2877 Clean Sandstone 6260.0 30.0 2.000 16.0 2937 Dirty Sandstone 6290.0 12.0 0.500 12.0 2906 Shale 6305.0 2.0 0.200 10.0 2912 Clean Sandstone 6310.0 30.0 2.000 15.0 2920 Dirty Sandstone 6340.0 4.0 0.500 12.0 2906 SHALE 6345.0 1.0 0.001 1.0 2972 Propped Fracture Schedule (Stage 11) Pumping Schedule Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (lb/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 11 40.0 YF125ST 320 25.0 0.00 1 PPA 40.0 YF125ST 144 25.0 CarboLite 16/20 1.00 2 PPA 40.0 YF125ST 151 25.0 CarboLite 16/20 2.00 4 PPA 40.0 YF125ST 1 16 1 25.0 CarboLite 16/20 4.00 6 PPA 40.0 YF125ST 1 149 25.0 CarboLite 16/20 6.00 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States schilmhPlep Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 8 PPA 40.0 YF125ST 139 25.0 CarboLite 16/20 8.00 10 PPA 40.0 YF125ST 131 25.0 CarboLite 16/20 10.00 12 PPA 40.0 YF125ST 107 25.0 CarboLite 16/20 12.00 FLUSH 40.0 YF125ST 185 25.0 i 0.00 Please note that this pumping schedule is under -displaced by 5.0 bbl. Fluid Totals 1487 bbl of YF125ST Proppant Totals 239100 Ib of CarboLite 16/20 Pad Percentages % PAD Clean 24.6 PAD Dirty 20.5 Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (Ib) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 11 320 320 320.0 320.0 0 0 4513 8.0 8.0 1 PPA 144 464 150.0 470.0 6027 6027 4532 3.8 1 11.8 2 PPA 151 615 165.0 635.0 12709 18736 4580 4.1 15.9 4 PPA 161 776 190.0 825.0 27025 45761 4922 4.8 20.6 6 PPA 149 925 190.0 1015.0 37650 83411 5484 4.8 25.4 8 PPA 139 1065 190.0 1205.0 46862 130273 6052 4.8 30.1 10 PPA 131 1195 190.0 1395.0 54926 185199 6392 1 4.8 34.9 12 PPA 107 1302 165.0 1560.0 53880 239079 6563 4.1 39.0 FLUSH 185 1487 185.0 1745.0 0 239079 6105 4.6 43.6 Attachment G Client Caelus Energy Alaska �cIMY�r��r Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 11) The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 11 MD. ---------------------------------------- 12469.0 ft Initial Fracture Top TVD_______________________ 6260.0 ft Initial Fracture Bottom TVD 6290.0 ft Propped Fracture Half -Length --------------- 357.4 ft Average Propped Width ----------------------- ------ ---- 0.378 in Max Surface Pressure_________________________ 6671 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 89.4 11.9 0.466 95.1 4.17 233.2 14665 89.4 178.7 10.4 0.450 95.1 4.00 247.9 1 13529 178.7 268.1 8.2 0.406 93.1 3.62 272.9 11636 268.1 357.4 3.3 0.214 82.6 1.90 653.9 1 5166 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Zone Data (Stage 12) Schlumhcrgcr Formation Mechanical Properties Zone Name Top TO (ft) Zone Height (ft) Frac Grad. (psi/ft) Insitu Stress (psi) Young's Modulus (psi) Poisson's Ratio Toughness (psi.in0.5) SHALE 6205.0 50.0 0.800 4984 5.000E+5 0.33 1000 Dirty Sandstone 6255.0 5.0 0.670 4193 2.000E+6 0.33 700 Clean Sandstone 6260.0 30.0 0.650 4079 1.600E+6 0.25 1200 Dirty Sandstone 6290.0 15.0 0.670 4219 2.000E+6 0.33 1000 Shale 6305.0 5.0 0.700 4415 2.000E+6 0.29 1000 Clean Sandstone 6310.0 30.0 0.650 4111 1.600E+6 0.22 1000 Dirty Sandstone 6340.0 5.0 0.670 4249 2.000E+6 0.33 1000 SHALE 6345.0 15.0 0.800 5082 5.000E+5 0.35 1000 Formation Transmissibility Properties Zone Name Top TVD Net (ft) Height (ft) Perm (md) Porosity 1%I Res. Pressure (psi) SHALE 6205.0 1.0 0.001 1.0 2916 Dirty Sandstone 6255.0 4.0 0.500 12.0 2877 Clean Sandstone 6260.0 30.0 2.000 16.0 2937 Dirty Sandstone 6290.0 12.0 0.500 12.0 2906 Shale 6305.0 2.0 0.200 10.0 2912 Clean Sandstone 6310.0 30.0 2.000 15.0 2920 Dirty Sandstone 6340.0 4.0 0.500 12.0 2906 SHALE 6345.0 1.0 0.001 1.0 2973 Propped Fracture Schedule (Stage 12) Pumping Schedule Job Description Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) PAD 12 40.0 YF125ST 320 25.0 0.00 1.0 PPA 40.0 YF125ST 144 25.0 Carbol-ite 16/20 1.00 Attachment G Client Caelus Energy Alaska Well ODSN-ta Formation Nuigsut District Prudhoe Bay, AK Country United States cichorgcr Fluid Totals 1302 bbl of YF125ST 180 bbl of WF125 Proppant Totals 2391001b of CarboLite 16/20 Pad Percentages % PAD Clean 24.6 % PAD Dirty 20.5 Job Description Job Execution Step Name Pump Rate (bbl/min) Fluid Name Step Fluid Volume (bbl) Gel Conc. (Ib/mgal) Prop. Type and Mesh Prop. Conc. (PPA) 2.0 PPA 40.0 YF125ST 151 25.0 CarboLite 16/20 2.00 4.0 PPA 40.0 YF125ST 161 25.0 CarboLite 16/20 4.00 6.0 PPA 40.0 YF125ST 149 25.0 CarboLite 16/20 6.00 8.0 PPA 40.0 YF125ST 139 25.0 CarboLite 16/20 8.00 10.0 PPA 40.0 YF125ST 131 25.0 CarboLite 16/20 10.00 12.0 PPA 40.0 YF125ST 107 25.0 CarboLite 16/20 12.00 FLUSH 40.0 WF125 180 1 30.2 149 1 0.00 Fluid Totals 1302 bbl of YF125ST 180 bbl of WF125 Proppant Totals 2391001b of CarboLite 16/20 Pad Percentages % PAD Clean 24.6 % PAD Dirty 20.5 Attachment G Job Execution Step Name Step Fluid Volume (bbl) Cum. Fluid Volume (bbl) Step Slurry Volume (bbl) Cum. Slurry Volume (bbl) Step Prop (lb) Cum. Prop. (Ib) Avg. Surface Pressure (psi) Step Time (min) Cum. Time (min) PAD 12 320 320 320.0 320.0 0 0 4359 8.0 8.0 1.0 PPA 144 464 150.0 470.0 6027 6027 4378 3.8 11.8 2.0 PPA 151 615 165.0 635.0 12709 18736 4423 4.1 15.9 4.0 PPA 161 776 190.0 825.0 27025 45761 4767 4.8 20.6 6.0 PPA 149 925 190.0 1015.0 37650 83411 5336 4.8 25.4 8.0 PPA 139 1065 190.0 1205.0 46862 130273 5837 4.8 30.1 10.0 PPA 131 1195 190.0 1395.0 54926 185199 6117 4.8 34.9 12.0 PPA 107 1302 165.0 1560.0 53880 239079 6251 4.1 39.0 FLUSH 180 1482 180.0 1740.0 0 239079 4976 4.5 43.5 Attachment G Client Caelus Energy Alaska Well ODSN-1a Formation Nuigsut District Prudhoe Bay, AK Country United States Propped Fracture Simulation (Stage 12) Scl lobager The following are the results of the computer simulation of this Fracturing Proposal using a Pseudo 3-D Vertical model. Effective Conductivity and Effective Fcd are calculated based on perforated intervals with positive net heights. Stage 12 MD.________________________________________11810.0 ft Initial Fracture Top TVD----------------------- 6260.0 ft Initial Fracture Bottom TVD ------------------ 6290.0 ft Propped Fracture Half -Length--------------- 357.5 ft Average Propped Width----------------------- 0.381 in Max Surface Pressure --------------- -- ------ 6341 psi Simulation Results by Fracture Segment From (ft) To (ft) Prop. Conc. at End of Pumping (PPA) Propped Width (in) Propped Height (ft) Frac. Prop. Conc. (Ib/ft2) Frac. Gel Conc. (Ib/mgal) Fracture Conductivity (md.ft) 0.0 89.4 11.8 0.470 98.2 4.20 232.3 14808- 89.4 178.7 10.4 0.454 98.2 4.03 247.0 13656 178.7 268.1 8.2 0.410 94.3 3.65 271.9 11768 268.1 357.5 3.3 0.213 82.8 1.90 668.1 5131 Attachment G Schlmherger Client: Caelus Energy Alaska Well: ODSN-Ola Basin/Field: Oooguruk State: Alaska County/Parish: North Slope Borough Case: J580 Gelling Agent 24.7 Lb / 1000 Gal Disclosure Type: Pre -Job Well Completed: 4/16/2016 Date Prepared: 12/18/2015 1:48 PM Report ID: RPT -40666 VolumeFluid Name & YF125ST:WF125 745,416 Gal dditive F103 Additive Description Surfactant 1 Gal / 1000 Gal 743.0 Gal J218 Breaker 0.5 Lb / 1000 Gal 368.0 Lb J475 Breaker 5.9 Lb / 1000 Gal 4,407.0 Lb J532 Crosslinker 5.5 Gal / 1000 Gal 4,101.0 Gal J580 Gelling Agent 24.7 Lb / 1000 Gal 18,378.0 Lb L065 Scale Inhibitor 2 Gal / 1000 Gal 1,469.0 Gal M002 Additive 0.7 Lb / 1000 Gal 513.0 Lb M275 Bactericide 0.3 Lb / 1000 Gal 252.0 Lb 5522-1620 Propping Agent varied concentrations 2,359,207.0 Lb Misc. Proppant DIS- 16JAN2015- Propping Agent varied concentrations CC 124,169.0 Lb The total volume listed in the tables above represents the summation of water and additives. water is supplied by client. CAS •- Water(Includin Mix Water Supplied bClient)* 1 -71 % 56-81-5 1, 2, 3 - Pro anetriol < 0.1 % 64-19-7 Acetic acid(impurity) < 0.0001 % 67-63-0 Pro an-2-ol < 0.1 % 107-21-1 Ethylene glycol < 0.1 % 111-46-6 2,2"-o diethanol (impurity) < 0.001 % 111-76-2 2-butox ethanol <0.1 % 112-42-5 1-undecanol <0.01 % 127-08-2 Acetic acid, otassium salt < 0.0001 % 1303-96-4 Sodium tetraborate decah drate <0.1 % 1310-58-3 Potassium hydroxide <0.1 % 1310-73-2 Sodium hydroxide (impurity) <0.01 % 2682-20-4 2 -meth I-2h-isothiazol-3-one <0.0001 % 7447-40-7 Potassium chloride (impurity) <0.001 % 7631-86-9 Non -crystalline silica (impurity) <0.001 % 7647-14-5 Sodium chloride <0.01 % 7727-54-0 Diammonium peroxidisulphate <0.1 % 7786-30-3 Magnesium chloride <0.001 % 9000-30-0 Guar um < 1 % 9002-84-0 of tetrafluoroeth lene) <0.001 % 9003-35-4 Phenolic resin <0.1 % 10043-52-4 Calcium Chloride <0.01 % 10377-60-3 Magnesium nitrate <0.001 % 14464-46-1 Cristobalite <0.0001 % 14807-96-6 Magnesium silicate hydrate (talc) <0.001 % 14808-60-7 Quartz, Crystalline silica <0.0001 % 25038-72-6 Vinylidene chloride/meth lac late copolymer < 0.01 26172-55-4 5 -chloro -2 -meth I-2h-isothiazolol-3-one <0.001 % 34398-01-1 Alcohol, C11 linear, ethoxylated < 0.1 % 66402-68-4 Ceramic materials and wares, chemicals -28 % 68131-39-5 C12-15 alcohol eth ox fated <0.01 % 68715-83-3 2-Butenedioic acid (2Z)-, polymer with sodium 2- ro ene-l-sulfonate < 0.1 91053-39-3 Diatomaceous earth, calcined < 0.01 % 129898-01-7 2 -Pro enoicacid, of mer with sodium hos hinate • <0.1 % 11'. ;ix water a suppuea by the client. Scmumoerger has performed no analysis of the water and cannot provide o O Schlumberger 2015. Used by Caelus Energy Alaska by permission. of components that may have been added to the water by third -parties. Page: 1 / i ATTACHMENT H ODSN- 01a Flowback Procedure Date -213//16 Prepared: Date: Jack Kralick Wells Superintendent Page 1 of 4 ATTACHMENT I Flowback Objectives — Post Frac 1) Conduct PJSM w/Wells Group Supervisor, Expro, Operations team, ACS, and all personnel relevant to thejob scope. No Injuries. No Spills. No HSE Incidents. 2) Establish fluid production types and rates (Oil, Gas, Water). 3) Uninterrupted flow for first 96 hours, i.e. no shutdowns, or significant slowdowns. 4) Conduct a seamless switch between Expro testing and Caelus Energy LLC operations. 5) Meet CPAI requirements for sales as directed by Caelus Energy LLC Production Supervisor. 6) The well was fracture stimulated using a Halliburton RapidStage Ball Actuated system. The balls are dissolvable in brine, but ball fragments may return and should be caught in the ball catcher. A list of ball sizes can be found at the end of the program. NOTE: Any DMXT balls that were left in the well between frac stages have been recorded in WellView as well as the vendor reports. Pre-Flowback Ooerations 1) Confirm HAZOP actions and P&ID walk through of flowback equipment spread. 2) P/T ESD valve & chart per AOGCC guidelines. 3) Ensure data acquisition systems are functional and recording. 4) Record initial pressures and temperatures (BHP, OA, IA, tubing). 5) Review flowback operations and expected duration during morning SimOps meeting. 6) Verify wind direction and speed prior to and during flowback. Minimum 5 mph wind required for all unloading and transfer operations. Wind break effect of surrounding structures need to be considered in order to prevent lay down of heavy hydrocarbon vapors in low lying spots and wind protected areas. Wind needs to be carrying any gas vapors to a safe location away from operating equipment and ignition sources. Well Clean -Up and Diagnostic Flow Test Using Lift Gas: 1) Collect and send samples periodically to KRU lab for API gravity validation. 2) Verify Lift Gas Header pressure is greater than Fluid Column Hydrostatic Pressure above. 3) If WHP is greater than production header pressure bleed WH P down until they're equal. 4) Initial choke setting should be 30/64ths. This choke setting should be sufficient to generate an increase in surface temperature on the wellhead flowline. 5) Start methanol injection into IA; just upstream of the LG choke if possible. Page 2 of 4 ATTACHMENT I 6) Slowly start lift gas injection into the IA at 300 Mscf/day (as low as possible). Keep the rate slow enough such that IA pressure increases no more than 50 psi every 60 minutes after the initial lift gas injection rate. Increase should be slow and steady to avoid fluid -cutting the valves. No more than 1 bpm of liquid should pass thru a gas lift or orifice valve. There should be a slow, steady increase in both IA and BH pressures. Monitor these pressures using DCS trends and/or the Trend Tool. 7) Maintain this low LG rate and IA pressure increase until fluid level is pushed down to the top valve and gas is injected into the tubing. This will be indicated in the following ways: a. Both IA and BH pressures will decrease suddenly b. Well will start producing aerated fluids 8) Each time a new GLV is uncovered there should be a corresponding decrease in IA pressure; although it will not be as great as that seen when uncovering the first valve. 9) Continue at the current LG rate until fluid level is at the OV. If necessary, shoot fluid level to confirm. 10) With fluid level at the OV, begin opening choke in 2/64ths increments and monitor BHP and returns for 2X tubing volumes. If BHP is fairly stable and solids content is <1 % repeat this procedure. 11) If BHP stays stable and solids content is low after a total of 20/64ths choke increase from the initial setting, then more aggressive choke changes can be made by 4/64ths increments. Monitor BHP and returns 2X tubing volumes. The goal is to work the choke open as quickly as possible following the above guidelines. Slugging should be first be mitigated by adjusting the lift gas rate, not the choke. Once the choke is open it should remain open. Note: It is imperative that the well is allowed to flow uninterrupted for a minimum of 96 hours. Any shut-ins tend to cause plugging when the proppant falls out of the fluid stream. 12) LG rates can be increased at the discretion of the Production Supervisor. 13) As a check, IA pressure is an indicator as to whether LG valves above the OV are closed. IA pressure must be less than the closing pressures listed in the gas lift design tables in the post frac slickline procedures above for them to be closed. 14) Once PPSA criteria are met with sufficient sampling approved by the KRU lab, production can be turned over to sales. A pre -job meeting with the Well Work Supervisor, Production Operations and Expro should be held to ensure everyone is aware of the process and that shutting in the well may create a problem leading to limited flow potential. Page 3 of 4 AJ TACI1MFN'1 Post Frac Slickline: 1) Record Tubing, IA, and OA pressures. Record BHP and Temp. Note on Wellview Report. 2) Complete well handover form from Operations to Wells Group. 3) Conduct a pre -job safety meeting with HES, Wells Group Supervisor, and all personnel involved in the job scope. 4) MIRU HES Combo Unit w/.125 wire. Hang load cell, and necessary sheaves. 5) Pick up lubricator, toolstring, and 3.83" gauge ring. 6) Make up lubricator to wellhead and pressure test as per HES policy & procedure. (1.5 times expected WH pressure) 7) RIH w/ 3.83" gauge ring to "XXO" SVLN @ 2186' MD. 8) Pull Frac Sleeve at 2186' 9) Run catcher to `X' nipple at 10320' 10) Pull DV at 10204'- GLM# 1 11) Run 5/16" OV to 10204' 12) Pull catcher from X nipple at 10132' 13) Run 10K Frac Sleeve to 2186'- 3.12" ID 14) Begin Post Frac Flowback through Expro using flowback procedures a. 14 Days until a tested ScSSV is required by the AOGCC b. 5 days after that a AOGCC witnessed closure testis required Page 4 of 4 ATTACHMENT I Stagefrac Rigup ODSN-01A Nuiqsut Production Well Completion I I • Landed Upper Packer Fluid mix: Inhibited Kill weight Brine with 2000' TVD diesel cao I I Completion with 40,000 lbs I Slack -Off I I I I I I 11-3/4" 60# L-80 BTC Surface ... I 3 i Casing @ 4,308' MD / 16" I 3,334' TVD Conductor I ::::.cemented to surface GLM# 3 5 MD(ft) GL DGLV Tubing Hanger 34 SOV 7" Stage 2 TOC I Estimated I ' ` @ 7,459 ft. MD x Baker 5"X7" ZXP Uner Top Packer with Flex Lock Hanger/20ft4.25" Seal Bore Recepticle Below x Installed 7 7,000 psiI Max rated 4%" Halliburton'XXO' SVLN w/3.813" "X" profile with singlel/4" x 0.049" s/scontrol line. Cannon Cross -coupling clamps on everyjoint w/15ft Pup BxPTop & Bottom I I Whipstock Window: 4,077'- 4,099' MD 4 17 anc 7" Stage 1 TOC 1 9-5/8" Permanent Bridge Estimated 2,531 6 I I Plug @ 4,194 MD I 9 GL(Vi# 20�0 7 HES "X"Nipple 3.813"w/15ft Pup BxPTop & Bottom I 2,608 GL 4%"12.6#/ft C-110 Hydril 521Tubing Volant Centralizer Pin End and Eft Pup 41/2" 126#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant DGLV >> Installed 9 X 5,689 7,000 psi 10 4-%"12.6#/ft C-110 Hydril 521 Tubing (2 Joints) Max rated 11 I TOC Estimated 5,808 4,028 12 @ 500 ft above Centralizer on Top of Swell Packer 13 9-5/8" Shoe 10,013 5,958 14 9-5/8" 40# L-80 HLB41/2" RapidStage gall Actuated Sleeve (3.009ball /2.95Seat) w/15ft41/2"P-110Pup41/2" 15 Hydril 521 10,132 6,013 16 Intermediate 1 4-'/:" 12.6#/ft Hydril 521 C-110 Liner 17 I Casing 10 AM 6,045 18 I @ 7,940' MD / Volant Centralizer Pin Endand 6ft Pup41/2"126#/ftP-110 Hydril 521 Boxx Pinw/Slide On Volant 11,891 19 1 5,003' TVD GLM# 1GL4.1 MD(ft) TVD(ft) DGLV Tubing Hanger 34 Installed 15 7,000 psi Max rated 7" Stage 2 TOC I Estimated I ' ` @ 7,459 ft. MD x Baker 5"X7" ZXP Uner Top Packer with Flex Lock Hanger/20ft4.25" Seal Bore Recepticle Below ES -II Cementer 3 4%" Halliburton'XXO' SVLN w/3.813" "X" profile with singlel/4" x 0.049" s/scontrol line. Cannon Cross -coupling clamps on everyjoint w/15ft Pup BxPTop & Bottom @ 8,632 ft. MD _ 4 17 anc 7" Stage 1 TOC 5 4-h" x 1" GLM #3, KBG-45 Hydril 521 w/ 15ft Pup BxP Top & Bottom Estimated 2,531 6 @ 9,850 ft. MD RHC Plug Installed 1s 3-12-2016 FINAL No. UpperCompledon MD(ft) TVD(ft) 1 Tubing Hanger 34 34 2 4-W' 12.6#/ft C-110 Hydril 521 Tubing Baker 5"X7" ZXP Uner Top Packer with Flex Lock Hanger/20ft4.25" Seal Bore Recepticle Below 3 4%" Halliburton'XXO' SVLN w/3.813" "X" profile with singlel/4" x 0.049" s/scontrol line. Cannon Cross -coupling clamps on everyjoint w/15ft Pup BxPTop & Bottom 2'186 2,048 4 4Y"12.6#/ftC-110 Hydril521Tubing 4-YV'12.6#/ft Hydril 521C-110 Liner 5 4-h" x 1" GLM #3, KBG-45 Hydril 521 w/ 15ft Pup BxP Top & Bottom 2,833 2,531 6 4X"12.64/ft C-110 Hydril 521Tubing(2Joints) 4-'/:"12.6#/ft Hydril 521C-110 Liner 7 HES "X"Nipple 3.813"w/15ft Pup BxPTop & Bottom 2,952 2,608 8 4%"12.6#/ft C-110 Hydril 521Tubing Volant Centralizer Pin End and Eft Pup 41/2" 126#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 11,404 9 4%"xl"GLM #2,KBG-45 Hydril 521w/ 15ft Pup BxPTop & Bottom 5,689 3,974 10 4-%"12.6#/ft C-110 Hydril 521 Tubing (2 Joints) Halliburton well Packer # 12 (4-%" Hydril 521) OD 5.95'- 9 meter long oil activated with Slide on Sralizer 11 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 5,808 4,028 12 4-W'12.6#/ft C-110 Hydril 521 Tubing Centralizer on Top of Swell Packer 13 4-%" x 1" GLM # 1, KBG-4-5 Hydril 521 w/ 15ft Pup BxP Top & Bottom 10,013 5,958 14 4-W'12.6#/ft C-110 Hydril 521 Tubing (2 Joints) HLB41/2" RapidStage gall Actuated Sleeve (3.009ball /2.95Seat) w/15ft41/2"P-110Pup41/2" 15 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 10,132 6,013 16 4-%"12.6#/ft C-110 Hydril S21 Tubing 4-'/:" 12.6#/ft Hydril 521 C-110 Liner 17 4-1/2" Halliburton'ROC' Gauge Carrier w/ Encapsulated a -line to Surface w/ 15ft Pup BxP Top& Bottom 10 AM 6,045 18 4-Y/-12.6#/ft C-110 Hydril 521 Tubing (2 jt) Volant Centralizer Pin Endand 6ft Pup41/2"126#/ftP-110 Hydril 521 Boxx Pinw/Slide On Volant 11,891 19 HES XN 3.813" (3.725" NoGo) - w/ 15ft Pup BxP Top & Bottom 10,320 6,092 20 4-%"12.6#/ft C-110 Hydri 1521 Tubing 4-N"12.6#/ft Hydril 521 C-110 Liner 21 41/2"x4" Crossover P-110 Locator with a 5.66' long 41/2" handling pup on top, 4" Spacer Pup w/ Bullet Seal Assembly + Solid Mule Shoe 11,118 6,251 Bottom of Shoe 11,152 6,254 No. Lower Com letion - MD(ft) TVD(ft) 22 20 ft 5.25" Tie Back extension 11,098 6,249 Baker 5"X7" ZXP Uner Top Packer with Flex Lock Hanger/20ft4.25" Seal Bore Recepticle Below 23 Hanger 11,119 6,251 24 4-YV'12.6#/ft Hydril 521C-110 Liner 25 Resman Internally Vented Carrier # 4 ROS -1525-1 / RWS-1531-1 w/ 15ft Pup BxP Top & Bottom 11,205 6,259 26 4-'/:"12.6#/ft Hydril 521C-110 Liner Halliburton Swell Packer # 13 (4-%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 27 Volant Centralizer Pin End and Eft Pup 41/2" 126#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 11,404 6,276 Centralizer on Top of Swell Packer Halliburton well Packer # 12 (4-%" Hydril 521) OD 5.95'- 9 meter long oil activated with Slide on Sralizer 28 Volant CentPin End and 6ft Pup 41/2' 126#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 11,444 6,280 Centralizer on Top of Swell Packer 29 4-W' 12.6#/ft Hydril 521 C-110 Liner HLB41/2" RapidStage gall Actuated Sleeve (3.009ball /2.95Seat) w/15ft41/2"P-110Pup41/2" 30 126#/ft P-110 Hydril 521 Box x Pin 11,618 6,288 31 4-'/:" 12.6#/ft Hydril 521 C-110 Liner Hal liburton Swell Packer # 11(4%" Hydril 521) OD 5.85- 9 meter long oil activated with Slide on 32 Volant Centralizer Pin Endand 6ft Pup41/2"126#/ftP-110 Hydril 521 Boxx Pinw/Slide On Volant 11,891 6,286 Centralizer on Top of Swell Packer 33 4-N"12.6#/ft Hydril 521 C-110 Liner HL134-1/2" RapidStage Ball Actuated Sleeve (2.925 ball/ 2.867 Seat) w/15ft 41/2"P-110Pup41/2" 34 1L6#/ft P-110 Hydril 521 Box x Pin 12.271 6,282 35 4-%" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 30 (4%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 36 Volant Centralizer Pin End and 6ft Pup 41/2"12.6#/ftP-110 Hydril 521 Box x Pin w/ Slide On Volant 12,422 6,280 Centralizer on Top of Swell Packer 37 4-'/:"12.6#/ft Hyd ri1521 C-110 Li ner HLB4-1/2" RapidStage Ball Actuated Sleeve (2.842 ball/ 2786 Seat) w/ 15ft 41/2"P-110 Pup 41/2" 38 12.6#/ft P-110 Hydril 521 Box x Pin 12,841 6,272 39 4-X"12.6#/ft Hyd ri1521 C-110 Li n e r Halliburton Swell Packer # 9 (4'/:" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 40 Volant Centralizer Pin End and 6ft Pup 41/2' 12.6#/ft P-110 Hydril 521 Box x Pin w/Slide On Volant 13,199 6,266 Centralizer on Top of Swell Packer 41 4-%" 12.6#/ft Hydril 521 C-110 Liner 7" 26# Hydril 56328 Intermediate 2 32 @ 11,354 MD/ \ z7 `� _ - -- - O� so -O 7a 36 42 as -50sa 7s - 38 .. - 56 70 - 81 83 6,272' TVD 6-1/8" Hole TD 4-%" Hydril 521 / C-110 Liner with Halliburton Ball Actuated @ 18,811' MD / Sleeves, & Swell Packers 6 338' TVD ATTACHMENT K ' ODSN-01A Nuiqsut Production Well Completion - I I ' Landed Upper Packer Fluid mix: Inhibited Kill weight Brine with 2000' TVD diesel cap I I Completion with 40,000 lbs i Slack -Off 16" Conductor GLM# 3 Sov Installed 7,000 psi Max rated GLU19 2 DGLV Installed 7,000 psi Max rated GLM# 1 DGLV Installed 7,000 psi Max rated Iol I 11-3/4" 60# L-80 BTC Surface 3 Casing @ 4,308' MD / 3,334' TVD emented to surface J I I I Whipstock Window: 4,077' - 4,099' MD 9-5/8" Permanent Bridge Plug @ 4,194 MD I F1. " .. _... _ .. I TOC Estimated @ 500 ft above 9-5/8" Shoe 9-5/8" 40# L-80 Hydril 521 Intermediate 1 I Casing I @ 7,940' MD / 5,003' TVD 7" Stage 2 TOC Estimated I @ 7,459 ft MD ES -II Cementer ' @ 8,632 ft. MD _ n Roy 7" Stage 1 TOC Estimated @ 9,850 ft. MD RHC Pluc Installed 7" 26# Hydril 563�V Intermediate 2 \ Casing @ 11,354' MD / 6,272' TVD 3-12-2016 FINAL No. Lower Com letion MD(ft) TVD(ft) 1-11.641/2" RapidStage Ball Actuated Sleeve(2.761 ball/ 2.706 Seat) w/15ft 41/2"P-110 Pup 41/2" 42 12.6#/ft P-110 Hydril 521 Box x Pin 13495 6,262 43 4-W' 12.6#/ft Hydril S21 C-110 Liner 44 Resman Internally Vented Carrier # 3 ROS -1524-I / RWS-1530-1 w/ 15ft Pup BxP Top & Bottom 13,689 6,258 45 4-X"12.6#/ft Hydri1521 C-110 Li ner Halliburton Swell Packer # 8 (4'/:" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 46 Volant Centralizer Pin End and 6ft Pup 41/2"12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 13,850 6,253 Centralizer on Top of Swell Packer 47 4-%"12.6#/ft Hydri1521 C-110 Li ner 1-11_641/2" RapidStage Ball Actuated Sleeve (2.661 ball / 2.628 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 48 12.6#/ft P-110 Hydril 521 Box x Pin 14,144 6,247 49 4-%"12.6#/ft Hyd ri1521 C-110 Li ner Halliburton Swell Packer # 7 (4-%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 50 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 14,378 6,240 Centralizer on Top of Swel I Packer 51 4-K" 12.64/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.603 ball / 2.552 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 52 12.6#/ft P-110 Hydril 521 Box x Pin 14,711 6,230 53 4-%" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 6 (4-%" Hydril 521) OD 5.85- 9 meter long oil activated with Slide on 54 Volant Centralizer Pin End and 6ft Pup 41/2"12.6#/ftP-110 Hydril 521Boxx Pin w/Slide On Volant 14,945 6,229 Centralizer on Top of Swell Packer 55 4-%" 12.6#/ft Hydril 521 C-110 Liner 1-11.64-1/2" RapidStage Ball Actuated Sleeve (2.527 ball/ 2.477 Seat) w/ 15ft 4-1/2" P-ilo Pup 41/2" 56 12.6#/ft P-110 Hydril 521 Box x Pin 15,321 6,224 57 4-Y,"12.6#/ft Hyd ri1521 C-110 Li ner 58 Re sman Internally Vented Carrier # 2 ROS -1523-1 / RWS-1529-1 w/ 15ft Pup BxP Top & Bottom 15,512 6,221 59 4-%" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer #5 (4-W' Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 60 Volant Centralizer Pin Endand 6ft Pup41/2"12.6#/ftP-110 Hydril 521Boxx Pinw/Slide On Volant 15,631 6,219 Centralizer on Top of Swell Packer 61 4-%"12.6#/ftHydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.452 ball/ 2.404 Seat) w/ 15ft41/2" P-110 Pup 41/2" 62 12.6#/ft P-110 Hydril 521 Box x Pin 15,967 6,216 63 4-W'12.6#/ft Hyd ri1521 C-110 Li ner Halliburton Swell Packer # 4 (4%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 64 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 16,367 6,221 Centralizer on Top of Swell Packer 65 4-%" 12.64/ft Hydril S21 C-110 Liner HLB41/2" RapidStage Ball Actuated Sleeve (2.379 ball / 2.332 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 66 12.6#/ft P-110 Hydril 521 Box x Pin ]b,786 6,218 67 4-'/:" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 3 (4-W' Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 68 Volant Centralizer Pin Endand 6ft Pup41/2"12.6#/ftP-110 Hydril 521Boxx Pinw/Slide On Volant 17,102 6,216 Centralizer on Top of Swell Packer 69 4-%" 12.6#/ft Hydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.307 ball/ 2.261 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 70 12.6#/ft P-110 Hydril 521 Box x Pin 17,399 6,214 71 4-'/:" 12.6#/ft Hydril 521 C-110 Liner 72 Resman Internally Vented Carrier # 1 ROS -1522-1 / RWS-1528-1 w/ 15ft Pup BxP Top & Bottom 17,553 6,212 73 4-W' 126#/ft Hydril 521 C-110 Liner Halliburton Swell Packer# 2 (4-Y," Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 74 Volant Centralizer Pin End and 6ft Pup 41/2"12.6#/ftP-110 Hydril 521Boxx Pin w/Slide On Volant 17,672 6,211 Central izer on Top of Swell Packer 75 4-W' 12.6#/ft Hydril 521 C-110 Liner 1-11.134-1/2" RapidStage Ball Actuated Sleeve (2.236 ball /2.192 Seat) w/ 15ft4-1/2" P-110 Pup 41/2" 76 12.6#/ft P-110 Hydril 521 Box x Pin 18,755 6,223 77 4-%" 12.6#/ft Hydril S21 C-110 Liner Halliburton Swell Packer # 1(4%" Hydril S21) OD 5.85'- 9 meter long oil activated with Slide on 78 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 18,366 6,231 Centralizer on Top of Swell Packer 79 4-K" 12.6#/ft Hydril 521 C-110 Liner Pre -perforated Pup w/ 4-Y." 12.6#/ft Hydril 521 w/ 15ft 41/2" P-110 Pup BxP Top & Bottom 18,420 6,237 N.2 Pre -perforated Pup w/4-%" 12.6#/ft Hydril 521 w/ 15ft 1/2" P-110 Pup BxP Top & Bottom 4 18,424 6,238 4-%" 12.6#/ft Hydril S21 C-110 Liner 4'/," Hydril 521 Eccentric Shoe with Double Float Sub 18,436 1 6,239 Bottom of Assembly 18,440 6,240 36 O 60 O 68 sa(70 74 _ 78 81 83 ya- 34 72 76 80 - - 6-1/8" Hole TD 4-'/z" Hydril 521 / C-110 Liner with Halliburton Ball Actuated @ 18,811' MD / Sleeves, & Swell Packers ATTACHMENT K 6,338' TVD ,SIJ 3A13k_ CE CAELU S EnerQly Alaska ODSN-01A (PTD 216-008) Fracture Stimulation Sundry Application Response to Requests (1) Please provide a discussion of anticipated fracture pressures for the overlying confining zones (Miluveach and Upper Kingak shales), Nuiqsut sand, and underlying confining zone(s) (Lower Kingak shale). The modeled fracture bottomhole pressures at the ODSN-01A wellbore are: Top Miluveach/LCU Shale: 4,950 psi (6,138' TVD, -6,082' TVDss) Top Kingak Shale/BCU Shale: 4,990 psi (6,233' TVD, -6,177' TVDss) Nuiqsut sand: 4,070 psi (6,263' TVD, -6,207' TVDss) Lower Kingak Shale: 5,060 psi (6,326' TVD, -6,270' TVDss) The Nuiqsut fracturing model was constructed using log and core data from area wells and matched to treating histories from numerous wells. To -date there is no evidence that hydraulic fracturing or sustained injection pressures above parting pressure in the Nuiqsut wells have developed pathways through the confining layers. The average bottomhole fracturing extension pressure of 4,070 psi is well below the sustained average injection well bottomhole pressure of 5,500 psi; additionally, the fracture treatment is of very short duration compared to the years of injection at 5,500 psi. These data are consistent with presence of the known thick, ubiquitous shale confining layers providing large seal capacities despite numerous mapped faults. (2) From Attachments B and E, there appears to be 4 faults within % mile radius of ODSN- 01A planned frac zone. Please provide a list of fault -cuts (MD, TVDSS and vertical displacement) that have been observed within wells and well branches within the AOR of ODSN-01A. No faults directly intersect the ODSN-01 or ODSN-01A wellbores. Fault F -A (Attachment 1) was seen on seismic and while drilling the ODSN-19 lateral. The fault (or a pair of faults — A and D) is interpreted between 14,300' MD and 14,400' and (- 6,264' tvdss). There was no fluid loss associated with this fault zone when it was drilled in ODSN-19. The total offset in the ODSN-19 is estimated at 40 ft. down -to -the -west, but dies out before reaching the ODSN-01A well. There was no evidence the F -A fault was cut in either ODSN-01 or ODSN-01A. The mapped F -C fault near the toe of the ODSN-34 well is from the seismic interpretation with throw of 5 ft. to 10 ft. and has not been identified in any wells; it may not exist. The F -C fault has been used to explain some of the dips seen in the ODSN-34 plug back branches — although the variance in dips could result from survey error between the well branches and offset wells. ODSN-01A 10-403 Sundry App. For Fracture Stimulation Response to Requests March 23, 2016 Page 1 of 3 The F -B fault is another seismic interpreted fault of about 5 ft. to 10 ft. throw down -to -the - west that was also not identified in any wells. These small faults, F -B and F -C, are kept in the geologic and simulation models to use as reservoir baffles to restrict fluid flow between wells in the model to assist in history matching. (3) Please provide estimates of the horizontal distances from the ends of the projected fracture wings to any nearby faults. If any of these fracture wings are likely to intersect or even closely approach a fault, please discuss why that fault will not provide a pathway for injected fluids to migrate out of the pool. Attachment 1 depicts the 2,640 ft. (1/2 mile) AOR lateral and a 350 ft. fracture half-length polygon (the average modeled half-length is 382 ft.) around the ODSN-01A Nuiqsut lateral. The well is oriented perpendicular to the minimum stress thus the fracture wings will be longitudinal or parallel to the wellbore, not propagating too far from the wellbore; however, if the fractures were perpendicular to the wellbore the table below details the estimated distance from the fracture wing to the interpreted faults on the map in Attachment 1. Stage MD Perf Depth (feet) ND Perf Depth (feet) Max Propped Height (feet) Frac 1/2 Length (feet) Fault F -B Distance from 1/2 Length if Frac is perpendicular to wellpath (feet) Fault F -A Distance from 1/2 Length if Frac is perpendicular to wellpath (feet) Fault F -C Distance from 1/2 Length if Frac is perpendicular to wellpath (feet) 1 18778 6330 84 150 Not Mapped Not Mapped 2 18401 6238 93 335 Not Mapped -17 Not Mapped 3 17740 6209 98 468 Not Mapped 232 Not Mapped 4 17081 6212 98 467 Not Mapped 488 Not Mapped 5 16422 6216 99 409 Not Mapped 736 Not Mapped 6 15763 6217 101 441 Not Mapped 959 Not Mapped 7 15104 6223 99 409 Not Mapped 1246 Not Mapped 8 14445 6229 99 364 Not Mapped 1609 Not Mapped 9 13786 6245 99 411 289 Beyond N19 Not Mapped 10 13127 6265 99 411 734 Beyond N19 Not Mapped 11 12469 6275 95 357 725 Beyond N19 Not Mapped 12 11810 1 6275 98 358 469 Beyond N19 1042 These faults are not considered possible pool containment leak points because: • The fracs are longitudinal and since the N01 well does not intersect any faults, the fracs should not either. The resulting fracs would have to be strongly transverse to connect to any of the faults in the area. • To -date there is no evidence that hydraulic fracturing or sustained injection pressures above parting pressure in the Nuiqsut wells have developed pathways through the ODSN-01A 10-403 Sundry App. For Fracture Stimulation Response to Requests March 23, 2016 Page 2 of 3 confining layers. The average bottomhole fracturing pressure of 4,070 psi is well below the sustained average injection well bottomhole pressure of 5,500 psi; additionally, the fracture treatment is of very short duration compared to the years of injection at 5,500 psi. These data are consistent with presence of the known thick, ubiquitous shale confining layers providing large seal capacities despite numerous mapped faults. In the process of drilling 35 development wells (Kuparuk and Nuiqsut) and conducting 253 Nuiqsut hydraulic fracturing treatments, no anomalous reservoir pressure or fracture performance data have been observed that would indicate vertical communication between the Nuiqsut and adjacent stratigraphic intervals outside the pool. The data are consistent with three-dimensional modeling conducted by Barree & Associates in support of AIO 34 in 2007, their Nuiqsut fracturing program modeling from 2009 thru 2012, and consistent with the Schlumberger modeling submitted with the Application for Sundry Approval for this work. During fracturing operations should the fracture half wing intersect a conductive fault the fluid leak -off, likely into the porous Nuiqsut sands along the fault, will be so rapid that the fractures will quickly close, i.e. the treatment will screen -out, thus limiting any further propagation; additionally, if a fault is encountered and proppant is placed in the confining zone, conductivity will be very limited or non-existent due to rapid embedment of the proppant into the confining shales, thus effectively closing off any potential pathways. • There is no overlying Kuparuk over most of the the ODSN-01A lateral. The Kuparuk is interpreted from seismic amplitude to exist only in about the first 3000' of lateral, however, there is 70-150' of Kingak and Milluveach top seal shales restricting any vertical movement. To -date, if losses are incurred while drilling a Nuiqsut lateral, and they are believed to be associated with a fault in the well path, the interval will be either isolated with blank pipe and swell packers, opened to production but not fracture stimulated, or treated with a conservative fracture treatment; these mitigation measures are focused on reservoir management of the Nuiqsut pool between wells not because of concerns the faults will provide vertical pathways through the confining zones. ODSN-01A 10-403 Sundry App. For Fracture Stimulation Response to Requests March 23, 2016 Page 3 of 3 Stage MD Perf ND Perf Depth Depth (feet) (feet) Max Propped Height (feet) Frac 1/2 Length (feet) 1 18778 6330 84 150; 2 18401 6238 93 335' 3 17740 6209 98 4681 4 17081 6212 98 467; 5 16422 6216 99 409! 6 15763 6217 101 441 7 15104 6223 99 4091 8 14445 6229 99 364; 9 13786 6245 99 411' 10 13127 6265 99 4110 11 12469 6275 95 3571 12 11810 6275 _98 358': t� 1 � 4 ;LN25 NO1A frac 9 N, I f xi,N341 r J err Nuiqsut Str Estimated half length for N01A fracs are 150-470' (average is 382'). The minimum stress field is perpendicular to the well bore orientation and the fracs are assumed to be primarily longitudinal along the well -bore. There is a fault (F-A)intersected in the N19 well that appears to die out about 450' from the NOTA Stage 1. There is also a seismic fault (F -B) that parallels the N01 lateral near the heel. These faults are not considered to be a leak point for the Nuiqsut pool because: 1) there were no losses when fault F -A was drilled in the N19i and N19PB2 wells where there is about 40' of offset. 'IV. 411.11 2) Fault F -B did not seem to effect the 1 drilling or fracturing of N01 In 2012 -� 3) in the process of drilling 35 _ development wells (Kuparuk and Nuiqsut) and conducting 253 Nuiqsut '+. hydraulic fracturing treatments, no anomalous reservoir pressure or fracture performance data have been observed that would indicate vertical communication between the Nuiqsut and overlying stratigraphic intervals Ak outside the pool, even in areas with A faulting. The N01A lateral is about 500' from the N01 lateral. Any frac leakage from N01A into N01 would still be confined within the Nuiqsut pool because the N01 has been lure �---� effectively abandoned and isolated. ATTACHMENT 1 20 AAC 25.283 Hydraulic Fracturing Application — Checklist ODSN No. 1A (PTD No. 216-008; Sundry No. 316-194) Paragraph Sub -Paragraph Section Complete? AOGCC Page 1 March 23, 2016 -11 Dated 3/14/2016. Provided with application. On (a) Application for (a)(1) Affidavit 3/14/2016, operator sent Notice of Operations (Notice) to Sundry Approval all owners, landowners, surface owners, and operators PKB within one-half mile radius of proposed well trajectory. (a)(2) Plat Attachment B of application. PKB Clearly displayed on Attachment B of application. Legal description not included with packet, but the well lies within T13N, R7E, UM and T14N, R7E. The proposed fracturing interval lies within Section 3, T13N, R7E, UM (a)(2)(A) Well location (State lease ADL 355036) and Sections 33 and 34, T14N, PKB R7E, UM (State lease ADL 389959). Only Caelus, Eni, and DNR are potentially affected parties. The well lies more than 1 mile from the nearest external boundary of the Oooguruk Unit and within the Affected Areas of CO 597 and AlO 34. (a)(2)(B) Each water well within 'z mile None: Per AK DNR's Water Estate Map (3/21/2016). PKB (a)(2)(C) Identify all well types within % ODSN-19, 26, and 34 (service wells) and ODSN-01 and 37 PKB mile (development wells). (a)(3) Freshwater aquifers: geological name None per Conclusion 3 of AIO 34. PKB (a)(3) Freshwater aquifers: measured and true vertical depth NA PKB (a)(4) Baseline water sampling plan Not required. PKB (a)(5) Casing and cementing information (a)(6) Casing and cementing operation assessment (a)(6)(A) Casing cemented below lowermost freshwater aquifer and Not required; no freshwater aquifers present per PKB conforms to 20 AAC 25.030 Conclusion 3 of AIO 34. AOGCC Page 1 March 23, 2016 -11 20 AAC 25.283 Hydraulic Fracturing Application — Checklist ODSN No. 1A (PTD No. 216-008; Sundry No. 316-194) - -- -- -- --- - - Paragraph Sub -Paragraph Section Complete? (a)(6)(8) Each hydrocarbon zone is isolated BATTSonic log run. TOC in 7" 1st stage at 13,560 ft. (a)(7) Pressure test: information and pressure -test plans for casing and tubing MITT 6050 psi, IA 4000 psi, Variance granted for testing installed in well Itubing down to XN nipple above packer. (a)(8) Pressure ratings and schematics: wellbore, wellhead, ROPE, treating head provided, 10K spool See Attachment E of application. Fracturing zone will be the Nuiqsut 1 sand, approximately 30' to 40' true vertical thickness. (a)(9)(A) Fracturing and confining zones: 1 Upper confining zones are the Upper Kingak shale, which lithologic description for each zone totals approximately 38' true vertical thickness in this area; and the Miluveach shale, approximately 90' thick. (a)(9)(8) Geological name of each zone Lower confining zone is 7-15' of Nuiqsut shale that overlies the Nechelik non -reservoir sand, silt and shale. Below the (a)(9)(C) and (a)(9)(D) Measured and true Nechelik are thick Lower Kingak shales. vertical depths (a)(9)(E) Fracture pressure for each zone (a)(10) Location, orientation, report on mechanical condition of each well Top Nuiqsut is at 11,258' MD (6,207' TVDss). Top Miluveach shale is at 10,453' MD (6,082' TVDss). Lower Kingak shale not penetrated by well. Nuiqsut sand estimated fracture gradient is 4,070 psi. Overlying Upper Kingak shale estimated fracture gradient is 4,990 psi. Overlying Miluveach shale estimated fracture gradient is 4,950 psi. Underlying Kingak shale estimated fracture gradient is 5,060 psi. provided GLS GLS CDW PKB PKB CDW AOGCC Page 2 March 23, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist ODSN No. 1A (PTD No. 216-008; Sundry No. 316-194) Paragraph Sub -Paragraph Section Complete? AOGCC Page 3 March 23, 2016 (a)(11) Sufficient information to determine wells will not interfere with containment provided CDW within % mile Map of faults within AOR provided in application, Attachments B and E. There are four faults in the vicinity of the ODSN-1A: one fault "F -A" with 40 throw dies out before reaching ODSN-01A. There was no fluid loss associated with this fault when ODSN-19 drilled through it. (a)(11) Faults and fractures, Location, The remaining faults, interpreted by seismic, have orientation estimated throws of 5 to 10' and where not crossed by the ODSN-01A well. (a)(11) Faults and fractures, Sufficient PKB information to determine no interference No anomalous reservoir pressure or fracture performance with containment within % mile data has been observed that would indicate vertical communication between the Nuiqsut and overlying stratigraphic intervals outside the pool. The hydrocarbon accumulation within the Nuiqsut Oil Pool confirms the integrity of the top seal in this area. It is highly unlikely that these faults will provide a conduit for migration of fracture fluids out of zone. (a)(12) Proposed program for fracturing operation _ provided CDW (a)(12)(A) Estimated volume 745 thousand gal provided CDW (a)(12)(B) Additives: names, purposes, concentrations provided CDW (o)(12)(C) Chemical name and CAS number of each provided CDW AOGCC Page 3 March 23, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist ODSN No. 1A (PTD No. 216-008; Sundry No. 316-194) Paragraph Sub -Paragraph = Section Complete? (a)(12)(D) Inert substances, weight or 32 59 million pounds volume of each (a)(12)(E) Maximum treating pressure with CDW supporting info to determine Provided 8667 psi stage 3 appropriateness for program Provided in Model Results and on Attachment 1. The faults CDW are not considered possible pool containment leak points because: The fracs are longitudinal and since the ODSN-1A does not intersect any faults, the fracs should not either; and, today there is no evidence that hydraulic fracturing or sustained injection pressures above parting pressure in the j (a)(12)(F) Fractures - height, length, MD; Nuigsut wells have developed pathways through the and TVD to top, description of fracturing confining layers. PKB model Mitigation: If losses are incurred while drilling a Nuiqsut lateral, and they are believed to be associated with a fault in the wellpath, the interval will be either isolated with blank pipe and well packers, opened to production but not fracture stimulated, or treated with a conservative fracture treatment. (a)(13) Proposed program for post - fracturing well cleanup and fluid recovery Well testing -disposal well ODSN available. CDW (b)Testing of casing or intermediate Tested >110% of max anticipated pressure casina (c) Fracturing string (c)(1) Packer >100' below TOC of - - I production or intermediate casin (c)(2) Tested >110% of max anticipated pressure differential AOGCC — _._ - --- ---- -- ---------- - -- IA to test to 4000 psi, backpressure of 3500 psi. PRV will be set at 3700 psi during pumping. Verified Max frac pressure stage 3 of 8667 psi. Pump trip set at 8600psi. Testing of surface line is 9000 psi. Working line pressure of 10,000 psi. Tubing test to 6050 psi (3500 IA holdpressure Page 4 CDW GLS GLS March 23, 2016 20 AAC 25.283 Hydraulic Fracturing Application — Checklist ODSN No. 1A (PTD No. 216-008; Sundry No. 316-194) Paragraph Sub -Paragraph Section Complete? (d) Pressure relief Line pressure <= test pressure, remotely Expected line pressure max of 8667 psi is <= 9000 psi test CDW valve controlled shut-in device pressure. GORV of 9000 psi. Pump trip set at 8600 psi. CDW (e) Confinement Frac fluids confined to approved provided formations (f) Surface casing Monitored with gauge and pressure relief provided CDW pressures device (g) Annulus pressure 500 psi criteria monitoring & notification (g)(1) Notify AOGCC within 24 hours (g)(2) Corrective action or surveillance (g)(3) Sundry to AOGCC (h) Sundry Report (i) Reporting (i)(1) FracFocus Reporting (i)(2) AOGCC Reporting: printed & electronic (j) Post frac water sampling plan (k) Confidential Clearly marked and specific facts information supporting nondisclosure (I) Variances Modifications of deadlines, requests for requested variances or waivers AOGCC Page 5 March 23, 2016 Bettis, Patricia K (DOA) From: Jack Kralick <Jack.Kralick@caelusenergy.com> Sent: Wednesday, March 23, 2016 10:46 AM To: Bettis, Patricia K (DOA) Subject: ODSN-Ola (PTD 216-008) Attachments: ODSN-01A (PTD 216-008) Application to Hydraulically Fracture Stimulate Response to Requests.pdf Hello Patricia, Please see additional responses from our Subsurface guys that may help clarify some areas. Regards, Jack Kralick Wells Superintendent Caelus Energy Alaska, LLC Office 907.343.2185 1 Cell 907.830.7233 4ack.kralickCcDcaelusenergy.com Please note the new company and email address Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. CE CAI: LU S arsAlaska ODSN-01A (PTD 216-008) Fracture Stimulation Sundry Application Response to Requests (1) Please provide a discussion of anticipated fracture pressures for the overlying confining zones (Miluveach and Upper Kingak shales), Nuiqsut sand, and underlying confining zone(s) (Lower Kingak shale). The modeled fracture bottomhole pressures at the ODSN-01A wellbore are: Top Miluveach/LCU Shale: 4,950 psi (6,138' TVD, -6,082' TVDss) Top Kingak Shale/BCU Shale: 4,990 psi (6,233' TVD, -6,177' TVDss) Nuiqsut sand: 4,070 psi (6,263' TVD, -6,207' TVDss) Lower Kingak Shale: 5,060 psi (6,326' TVD, -6,270' TVDss) The Nuiqsut fracturing model was constructed using log and core data from area wells and matched to treating histories from numerous wells. To -date there is no evidence that hydraulic fracturing or sustained injection pressures above parting pressure in the Nuiqsut wells have developed pathways through the confining layers. The average bottomhole fracturing extension pressure of 4,070 psi is well below the sustained average injection well bottomhole pressure of 5,500 psi; additionally, the fracture treatment is of very short duration compared to the years of injection at 5,500 psi. These data are consistent with presence of the known thick, ubiquitous shale confining layers providing large seal capacities despite numerous mapped faults. (2) From Attachments B and E, there appears to be 4 faults within % mile radius of ODSN- 01A planned frac zone. Please provide a list of fault -cuts (MD, TVDSS and vertical displacement) that have been observed within wells and well branches within the AOR of ODSN-01A. No faults directly intersect the ODSN-01 or ODSN-01A wellbores. Fault F -A (Attachment 1) was seen on seismic and while drilling the ODSN-19 lateral. The fault (or a pair of faults — A and D) is interpreted between 14,300' MD and 14,400' and (- 6,264' tvdss). There was no fluid loss associated with this fault zone when it was drilled in ODSN-19. The total offset in the ODSN-19 is estimated at 40 ft. down -to -the -west, but dies out before reaching the ODSN-01A well. There was no evidence the F -A fault was cut in either ODSN-01 or ODSN-01A. The mapped F -C fault near the toe of the ODSN-34 well is from the seismic interpretation with throw of 5 ft. to 10 ft. and has not been identified in any wells; it may not exist. The F -C fault has been used to explain some of the dips seen in the ODSN-34 plug back branches — although the variance in dips could result from survey error between the well branches and offset wells. ODSN-01A 10-403 Sundry App. For Fracture Stimulation Response to Requests March 23, 2016 Page 1 of 3 The F -B fault is another seismic interpreted fault of about 5 ft. to 10 ft. throw down -to -the - west that was also not identified in any wells. These small faults, F -B and F -C, are kept in the geologic and simulation models to use as reservoir baffles to restrict fluid flow between wells in the model to assist in history matching. (3) Please provide estimates of the horizontal distances from the ends of the projected fracture wings to any nearby faults. If any of these fracture wings are likely to intersect or even closely approach a fault, please discuss why that fault will not provide a pathway for injected fluids to migrate out of the pool. Attachment 1 depicts the 2,640 ft. (1/2 mile) AOR lateral and a 350 ft. fracture half-length polygon (the average modeled half-length is 382 ft.) around the ODSN-01A Nuiqsut lateral. The well is oriented perpendicular to the minimum stress thus the fracture wings will be longitudinal or parallel to the wellbore, not propagating too far from the wellbore; however, if the fractures were perpendicular to the wellbore the table below details the estimated distance from the fracture wing to the interpreted faults on the map in Attachment 1. Stage MD Perf Depth (feet) ND Perf Depth (feet) Max Propped Height (feet) Frac 1/2 Length (feet) Fault F -B Distance from 1/2 Length if Frac is perpendicular to wellpath (feet) Fault F -A Distance from 1/2 Length if Frac is perpendicular to wellpath (feet) Fault F -C Distance from 1/2 Length if Frac is perpendicular to wellpath (feet) 1 18778 6330 84 150 Not Mapped Not Mapped 2 18401 6238 93 335 Not Mapped -17 Not Mapped 3 17740 6209 98 468 Not Mapped 232 Not Mapped 4 17081 6212 98 467 Not Mapped 488 Not Mapped 5 16422 6216 99 409 Not Mapped 736 Not Mapped 6 15763 6217 101 441 Not Mapped 959 Not Mapped 7 15104 6223 99 409 Not Mapped 1246 Not Mapped 8 14445 6229 99 364 Not Mapped 1609 Not Mapped 9 13786 6245 99 411 289 Beyond N19 Not Mapped 10 13127 6265 99 411 734 Beyond N19 Not Mapped 11 12469 6275 95 357 725 Beyond N19 Not Mapped 12 11810 1 6275 1 98 358 469 Beyond N19 1042 These faults are not considered possible pool containment leak points because: • The fracs are longitudinal and since the N01 well does not intersect any faults, the fracs should not either. The resulting fracs would have to be strongly transverse to connect to any of the faults in the area. • To -date there is no evidence that hydraulic fracturing or sustained injection pressures above parting pressure in the Nuiqsut wells have developed pathways through the ODSN-01A 10-403 Sundry App. For Fracture Stimulation Response to Requests March 23, 2016 Page 2 of 3 confining layers. The average bottomhole fracturing pressure of 4,070 psi is well below the sustained average injection well bottomhole pressure of 5,500 psi; additionally, the fracture treatment is of very short duration compared to the years of injection at 5,500 psi. These data are consistent with presence of the known thick, ubiquitous shale confining layers providing large seal capacities despite numerous mapped faults. In the process of drilling 35 development wells (Kuparuk and Nuiqsut) and conducting 253 Nuiqsut hydraulic fracturing treatments, no anomalous reservoir pressure or fracture performance data have been observed that would indicate vertical communication between the Nuiqsut and adjacent stratigraphic intervals outside the pool. The data are consistent with three-dimensional modeling conducted by Barree & Associates in support of AIO 34 in 2007, their Nuiqsut fracturing program modeling from 2009 thru 2012, and consistent with the Schlumberger modeling submitted with the Application for Sundry Approval for this work. During fracturing operations should the fracture half wing intersect a conductive fault the fluid leak -off, likely into the porous Nuiqsut sands along the fault, will be so rapid that the fractures will quickly close, i.e. the treatment will screen -out, thus limiting any further propagation; additionally, if a fault is encountered and proppant is placed in the confining zone, conductivity will be very limited or non-existent due to rapid embedment of the proppant into the confining shales, thus effectively closing off any potential pathways. • There is no overlying Kuparuk over most of the the ODSN-01A lateral. The Kuparuk is interpreted from seismic amplitude to exist only in about the first 3000' of lateral, however, there is 70-150' of Kingak and Milluveach top seal shales restricting any vertical movement. To -date, if losses are incurred while drilling a Nuiqsut lateral, and they are believed to be associated with a fault in the well path, the interval will be either isolated with blank pipe and swell packers, opened to production but not fracture stimulated, or treated with a conservative fracture treatment; these mitigation measures are focused on reservoir management of the Nuiqsut pool between wells not because of concerns the faults will provide vertical pathways through the confining zones. ODSN-01A 10-403 Sundry App. For Fracture Stimulation Response to Requests March 23, 2016 Page 3 of 3 101A frac Estimated half length for N01A fracs are 150-470' (average is 382'). The minimum stress field is perpendicular to the well bore orientation and the fracs are assumed to be primarily longitudinal along the well -bore. There is a fault (F-A)intersected in the N19 well that appears to die out about 450' from the N01A Stage 1. There is also a seismic fault (F -B) that parallels the N01 lateral near the heel. These faults are not considered to be a leak point for the Nuiqsut pool because: 1) there were no losses when fault F -A was drilled in the N19i and N19PB2 wells where there is about 40' of offset. 2) Fault F -B did not seem to effect the drilling or fracturing of N01 in 2012 3) in the process of drilling 35 development wells (Kuparuk and Nuiqsut) and conducting 253 Nuiqsut hydraulic fracturing treatments, no anomalous reservoir pressure or fracture performance data have been observed that would indicate vertical communication between the Nuiqsut and overlying stratigraphic intervals outside the pool, even in areas with faulting. The N01A lateral is about 500' from the N01 lateral. Any frac leakage from NOTA into N01 would still be confined within the Nuiqsut pool because the N01 has been effectively abandoned and isolated. ATTACHMENT 1 Bettis, Patricia K (DOA) From: Jack Kralick <Jack.Kral ick@caelusenergy.com> Sent: Tuesday, March 22, 2016 1:45 PM To: Bettis, Patricia K (DOA) Subject: RE: ODSN No. 1A (PTD 216-008): Fracture Stimulation Sundry Application Good afternoon Patricia, The Subsurface team is working to get answers to your questions. We will get the data to you hopefully later today or tomorrow morning. Is there anything else you can think of you may need? Due to scheduling problems we need the approved Sundry sooner rather than later. Thanks much, Jack From: Bettis, Patricia K (DOA)[mailto:patricia.bettis@alaska.gov] Sent: Monday, March 21, 2016 4:54 PM To: Jack Kralick Subject: ODSN No. 1A (PTD 216-008): Fracture Stimulation Sundry Application Good afternoon Jack, From Attachments B and E, there appears to be 4 faults within % mile radius of ODSN-1A planned frac zone. Please provide a list of fault -cuts (MD, TVDSS and vertical displacement) that have been observed within wells and well branches within the AOR of ODSN 1A. Please provide estimates of the horizontal distances from the ends of the projected fracture wings to any nearby faults. If any of these fracture wings are likely to intersect or even closely approach a fault, please discuss why that fault will provide a pathway for injected fluids to migrate out of the pool. 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 pi tricia.bettisPaiaska.Qov. Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. Bettis, Patricia K (DOA) From: Bettis, Patricia K (DOA) Sent: Monday, March 21, 2016 4:11 PM To: 'Jack Kralick' Subject: ODSN-01A (PTD 216-008): Fracture Stimulate Sundry Application Good afternoon Jack, For ODSN-01A, please provide a discussion of anticipated fracture pressures for the overlying confining zones (Miluveach and Upper Kingak shales), Nuiqsut sand, and underlying confining zone(s) (Lower Kingak shale). 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. ov. RE"'EIVED b MAR 0 9 20 ib 21 6008 26903 CA'rr-tS LETTER OF TRANSMITTAL C nery Alaska DATA LOGGED 3 h0 1201!, M.K.BENDER DATE: March 7, 2016 ❑ Maps FROM2 TOM Shannon Koh AOGCC Caelus Energy AlaskaAttn: 3700 Centerpoint Dr., Suite 500 Anchorage, AK 99503 Makana Bender 333 W. 7th Avenue, Suite 100 Anchorage, AK 99501 INFORMATION TRANSMITTED ❑ Letter ❑ Maps ❑ CD -R ❑ Agreement Other — CD, Logs nFTA11 QTY DESCRIPTION Well Name: ODSN-01A (50-703-20648-01-00) 1 CD -Rom Digital Graphic Logs 2 Well Logs PACE LWD PEAK ANALYSIS OF LWD XBAT WAVEFORMS RADIAL SHELLS; DGR XBAT 1:1200/1:240 Received by: ��.4-A' Date: Please sign and return one copy to: Caelus Energy Alaska ATTN: Shannon Koh 3700 Centerpoint Dr., Suite 500, Anchorage, AK 99503 907-343-2193 fax 907-343-2128 phone shannon.kohCcDcaelusenergy.com THE STATE ATE 01ALASKA GOVERNOR BILL WALKER Alex Vaughan Senior Drilling Engineer Caelus Natural Resources Alaska, LLC 3700 Centerpoint Drive, Suite 500 Anchorage, AK 99503 Alaska Oil and G siolConservation Commis 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Re: Oooguruk Field, Nuiqsut Oil Pool, ODSN-OIA Caelus Natural Resources Alaska, LLC Permit to Drill Number: 216-008 Surface Location: 3035' FSL, 1077' FEL, SEC. 11, TI 3N, R7E, UM Bottomhole Location: 4314' FSL, 1332' FEL, SEC. 33, T14N, R7E, UM Dear Mr. Vaughan: Enclosed is the approved application for permit to re -drill the above referenced development well. 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. 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, Cathy P Fo`erster Chair DATED this Z2 day of January, 2016. STATE OF ALASKA AL ;A OIL AND GAS CONSERVATION COMM ' DN PERMIT TO DRILL 20 AAC 25.005 �,C�tivGv JAN 12 2016 ()cr 1a. Type of Work: 1 h. Proposed Well Class: Exploratory - Gas ❑ervice - WAG ❑ Service - Disp ❑ 1c. Specify if well is proposed for: Drill ❑ Lateral ❑ Stratigraphic Test ❑ Development - Oil 4 Service - Winj ❑ Single Zone Coalbed Gas ❑ Gas Hydrates ❑ Redrill 2] . Reentry ❑ Exploratory - Oil ❑ Development - Gas ❑ Service - Supply ❑ Multiple Zone ❑ Geothermal ❑ Shale Gas ❑ 2. Operator Name: 5. Bond: Blanket ❑ , Single Well ❑ 11. Well Name and Number: Caelus Natural Resources Alaska, LLC Bond No. SUR002517 • ODSN-01A - 3. Address: 6. Proposed Depth: 12. Field/Pool(s): 3700 Centerpoint Drive, Suite 500, Anchorage, AK 99503 MD: 18,833' - TVD: 6,174' Oooguruk Nuiqsut Oil . 4a. Location of Well (Governmental Section): 7. Property Designation (Lease Number): Surface: 3035' FSL, 1077' FEL, Sec. 11, T13N, R7E, UM ADL 355036 / ADL 389959 - Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 3793' FSL, 1908' FEL, Sec. 3, T13N, R7E, UM 417497 2/4/2016 9. Acres in Property: 14. Distance to Nearest Property: Total Depth: 4314' FSL, 1332' FEL, Sec. 33, T14N, R7E, UM 5,760 / 2,560 • 2,416' 4b. Location of Well (State Base Plane Coordinates - NAD 27): 10. KB Elevation above MSL (ft): 56.2 feet 15. Distance to Nearest Well Open Surface: x- 469921 y- 6031151 Zone- ASP4 ' GL Elevation above MSL (ft): - 13.5 feet to Same Pool: 1,033' 16. Deviated wells: Kickoff depth: 8' O feet 4M 17. Maximum Potential Pressures in psig (see 20 AAC 25.035) Maximum Hole Angle: 95 • degrees Downhole: 3,196 , Surface: 2,506 18. Casing Program: Specifications Top - Setting Depth - Bottom Cement Quantity, c.f. or sacks Hole Casing Weight Grade Coupling Length MD TVD MD TVD (including stage data) 24" 16" 109# H-40 Welded 115' Surface Surface 158'_rt 158' Driven 14-1/2" 11-3/4" 60# L-80 BTC 4,045' Surface Surface 4,088,,/ 3,233' N/A G:"' t2 11-3/4" 9-5/8" 40# L-80 Hydril 521 4,015' 3938' 3162' 7,953' 5,013' 191 sks (1.17 ft/sk) Surface Surface 11,333' 6,271' 41Zv — 1.17 ft/sk) Stage 1 /5GL 8-1/2" 7" 26# L-80 Hydril 563 11,290' 263 sks (1.17 ft/sk) Stage 2 6-1/8" 4-1/2" 12.6# 1 L-80 I Hydril 521 7,700' 11133' 6271' 18,833' 6,174' JUncemented 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): 18,011' 6,183' 6,743'MD / 11,088'MD 17,900' 6,188' N/A Casing Length Size Cement Volume MD TVD Conductor/Structural 110' 16" Driven 158' 158' Surface 4,269' 11-3/4" 499 sx PF'L'; 563 sx Class'G' 4,308' 3,334' Intermediate 1 4,408' 9-5/8" 398 sx Class'G' 8,526' 5,446' Intermediate 2 11,345' 7" 1083 sx Class'G' 11,380' 6,262' Liner 6,759' 4-1/2" Uncemented 17,900' 6,188' Perforation Depth MD (ft): See attachment pg. 2 Perforation Depth TVD (ft): See attachment pg. 2 20. Attachments: Property Plat ❑ BOP Sketch ❑ Drilling Program Time v. Depth Plot ❑ Shallow Hazard Analysis❑ Diverter Sketch ❑ Seabed Report ❑ Drilling Fluid Program ❑✓ 20 AAC 25.050 requirements ❑ 21. Verbal Approval: Commission Representative: Date 22. 1 hereby certify that the foregoing is true and the procedure approved herein will not Alex Vaughan be deviated from without prior written approval. Contact alex.vaughan(Lbcaelusenercly.co Email Printed Name Alex Vaughan Title Senior Drilling Engineer Si natur Phone 907-343-2186 Date liz GCS R_k Uvi- S Commission Use Only Permit to Drill API Number: Permit Approval See cover letter for other Number: — (70� 50- 03— �8 �� — I^� Date: O� ' ^ lL requirements. Conditions of approval : If box is checked, well may not be used to explore for, test, or produce coalbed methane, gas hydrates, or gas contained in shales: Other: k 44 S~00 lost S or -71 Tv_ y � Samples req'd: Yes ❑ No � Mud log req'd: Yes ❑ No [./( "Z_' _ � 1 - HzS measures: Yes ❑ No V, Directional svy req'd: Yes YNo❑ V Spacing exception req'd: Yes E]No [Inclination -only svy req'd: Yes ❑ No _ ' �Zd_r�sY' ,_ r� •a,�2.—!i� ddt i Vis` ��y� ;ci FostinitialinjectionMITreq'd:Yes❑ No E] � - Approved by: APPROVED BY COMMISSIONER THE COMMISSION Date: Submit corm and Form 10-401 (R sgd 1�� 5) OiRrri�''`� `�I'Lfor j� `�onths from the date of approval (20 AAC 25.005(g)) Attachments in Duplicate 5 jo V I i V H L RECEIVED CAELUS JAN 12 2016 Energy Alaska AOGCD Caelus Natural Resources Alaska, LLC 3700 Centerpoint Drive, Anchorage, AK 99503 Tel: (907) 277-2700 Fax: (907) 343-2190 January 4, 2016 State of Alaska Alaska Oil and Gas Conservation Commission 333 West 7th Avenue, Suite #100 Anchorage, AK 99501 RE: Application for Permit to Drill 0DSN-01Af Surface Location: 3035' FSL, 1077' FEL, Sec. 11, T1 3N, R7E, UM X = 469920.45, Y = 6031151.32, ASP4 Caelus Natural Resources Alaska, LLC. (CNRA) hereby applies for a Permit to Drill a development well from the Oooguruk Drill Site (ODS) located within the Oooguruk Unit. The well is designed to be a production well in the Oooguruk-Nuiqsut formation. CNRA requests the Permit to Drill based on appr eov d Pool Rules. ODSN-01A will be drilled off a whipstock out of the ODSN-01 surface casing. Please reference the following well documentation drilled from the Oooguruk Drill Site slot 01. • ODSN-01 Approved PTD# 211-166 o Workscope: Drill original well into the Nuiqsut formation. • ODSN-01 Approved Sundry# 315-504 o Workscope: Plug and abandon lateral section. • ODSN-01 Well Completion or Recompletion Report and Log in reference to Sundry# 315-343 submitted 9/17/2015 o Workscope: Results of abandonment plug The abandonment of ODSN-01(PTD# 211-166) above previously approved (Sundry #) lateral abandonment plug has been applied for in a separate sundry As indicated in the attachments, the drilling and well construction program includes the following: Suspend ODSN-01 o Application for sundry permit to abandon ODSN-01 will be made separately. ODSN-01 Intermediate Hole: 131(V 6.2--f o Drill 10-5/8" and under -ream while drilling (UWD) to 11-3/4" to 7,953' MD / 5,013' TVD. Run and set a 9-5/8" drilling liner. Intermediate Hole 2: o Drill 8-1/2" and under -ream while drilling (UWD) to 9-1/2" to 11,333' MD / 6,271' TVD and set 7" Intermediate casing into the top of the Oooguruk-Nuiqsut formation. Alaska Oil & Gas Conservation Commission January 4, 2016 Page 2 of 3 • Lateral Hole: o Drill 6-1/8" horizontally to 18,833' MD / 6,174' TVD and set a 4-1/2" liner with a Halliburton mechanical diversion frac system. • Fracture Stimulation Completion: rzs���e_.C, o 4-1/2" fracture stimulation string with SS V & S4iding Sleeves. • Fracture Stimulation: o 2,000,000 lbs of Carboceramics Carbolite proppant pumped in 600,000 gallons of Schlumberger's YF125ST. • ESP Completion: o ESP completion string with ScSSV & GLM. CNRA will implement Managed Pressure Drilling technology (MPD) while drilling the Intermediate 2 section and the lateral hole section as outlined below. • Intermediate 2 shoe to TD o Use -10.0-10.4 ppg WBM while using MPD to control pressure from the surface to —13.0 ppg EMW at the bottom of the hole during connections and while tripping. ■ Open formations: • Nuigsut Sands, --9.8 ppg Pore Pressure • Kuparuk Sands, —9.8 ppg Pore Pressure • Lateral shoe to TD j o Use—7.6-8.4 ppg fluid while using MPD to control pressure from the surface to —9.8-10.2 ppg EMW at the bottom of the hole during connections and while tripping. Please find attached information as required by 20 AAC 25.005 (a) and (c) for your review. Pertinent information attached to this application includes the following: 1) Form 10-401 Application for Permit to Drill per 20 AAC 25.005 (a). 2) A copy of the proposed drilling program per 20 AAC 25.005 (c) (13) including: a. The drilling fluid program as required by 20 AAC 25.033 b. Complete logging and mud logging operations are planned and descriptions are attached. c. A complete proposed casing and cementing program is attached as per 20 AAC 25.030. d. A summary of the drilling operations. e. A summary of drilling hazards per 20 AAC 25.005 (c) (4). f. A wellbore schematic is attached visually depicting the proposed well. g. One-half mile plot of ODSN-01 Torok intersection relative proximity to the ODSDW1-44 Torok disposal well. 3) A copy of the Planned Directional Well Path - including traveling cylinder and development layout plots. Alaska Oil & Gas Conservation Commission January 4, 2016 Page 3of3 The following items are on file with the AOGCC: 1) A plat showing the surface location proposed for the well per 20 AAC 25.005 (c) (2). 2) Diagrams and descriptions of the BOP and diverter equipment to be used on Nabors (Alaska Rig 19 -AC as required by 20 AAC 25.035 (b) and (c). 3) A description of the procedure for conducting formation integrity tests per 20 AAC 25.035 (c) (5). 4) CNRA does not anticipate the presence of H2S in the formations to be encountered in this well. However, H2S monitoring equipment as specified in 20 AAC 25.065(1) will be functioning on the rig as standard operating procedure for all wells drilled by that rig. Products for treating H2S contamination in the drilling mud system will be maintained on the ODS. The following are PNRA's designated contacts for reporting responsibilities to the Commission: 1) Completion Report (20 AAC 25.070) 2) Geologic Data and Logs (20 AAC 25.071) Alex Vaughan, Senior Drilling Engineer 907.343.2186 Alex.vaughan@caelusenergy.com Greg Griffin, Operations Geologist 907.343.2141 greg.griffin@caelusenergy.com The anticipated spud date for this well is February 4th, 2016. If you have any questions or require further information, please contact Alex Vaughan at 907.343.2186 Sincerely, Alex Vaughan Senior Drilling Engineer Attachments: Form 10-401 Supporting permit information cc: ODSN-01 Well File Permit to Drill Well Plan Summary ODSN-01A (ODSN-01 Re -Drill) Oooguruk — Nuigsut Single Lateral Production Well Surface Casing Whipstock @ 4,088 MD / 3,233' TVD Drilling Liner TD @ 7,953' MD / 5,013' TVD Intermediate TD @ 11,333' MD / 6,271' TVD Lateral TD @ 18,833' MD / 6,174' TVD Surface Location: 2947' FSL, 1 5' FEL, Sec. 11, T1 3N, R7E, Umiat ASP 4 NAD27projection X = 469,883.13 1 Y = 6,031,113.73 54 days to Drill and Complete Target: Ooo uruk-Nuiqsut 3793' FSL, 1908' FEL, Sec. 3, T1 3N, WE, Umiat (ADL355036) Well Design: Modified Slimhole (11-3/4" x 9-5/8" liner x 7" x 4-1/2" liner) Single -Lateral X = 463,830.95 Y = 6,037,215.03 I 6271' TVDrkb EtomHole Location 4314' FSL, 1332' FEL, Sec. 33, T14N, R7E, Umiat (ADL389959) X = 459,148.48 1 Y = 6,043,039.96 6174' TVDrkb AFE Number: TBA Est. Start Date: February 4, 2016 Ri : Nabors 19AC Operating days: 54 days to Drill and Complete Objective & Well Type Nuiqsut Development Well Well Design: Modified Slimhole (11-3/4" x 9-5/8" liner x 7" x 4-1/2" liner) Single -Lateral Current Mechanical Condition: Well Bay Footing / ODS Ground Level: Elevation above MSL: 13.5' RKB to Ground Level: 42.66' Rig Elevation: RKB + MSL = 56.16' Conductor: 158' MDrkb Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 1 of 15 Well Control: Well Section Pressure Depth psi TVD Basis 10-5/8" x 11-3/4" Intermediate 1 Casing Hole Section Maximum anticipated BHP 1446 3233 Based on seawater gradient of 0.4472 psi/ft Maximum surface pressure 1090 Surface (Based on BHP and a full column of gas from TD @ 0.11 psi/ft) 8-1/2" x 9-1/2" Intermediate 2 Casing Hole Section Maximum anticipated BHP 2242 5013 Based on 9.8 ppg Oooguruk-Kuparuk pore pressure) Maximum surface pressure 1690 Surface Based on BHP and a full column of gas from TD @ 0.11 psi/ft) 6-1/8" Production Hole Section Maximum anticipated BHP 3196 6271 Based on 9.8 ppg Oooguruk-Nuiqsut pore pressure) Maximum surface pressure 2506 ° Surface Based on BHP and a full column of gas -" from TD @ 0.11 psi/ft) Maximum casing pressure: 3500 psi @ surface Planned BOP test pressure: 4500 psi (annular to 2500 psi) Due to required 4500 psi casing pressure test. Planned completion fluid: 10.2 ppg Brine /6.8 ppg Diesel E)r schematic on file with AOGCC — Note: Requesting Diverter Exemption on a Well by Well Basis): Hydril 21-1/4° 2M annular BOP 1 y� 1 16" full opening knife gate valve, hydraulically actuated 16" diverter line 50.0.0 psi BOP stack (schematic on file with AOGCC): Hydril GK 11" 5M annular BOP Hydril 11" 5M single ram BOP w/ studded connections Hydril 11" 5M single ram BOP w/ studded connections Drilling cross 11" 5M x 11" 5M with 2 ea. 3-1/8" 5M side outlets w/flanged connections 2 ea. 3-1/8" 5M full opening inner manual gate valves mounted on drilling cross 2 ea. 3-1/8" 5M full opening outer remote hydraulic controlled gate valves mounted on inner gate valves. Hydril 11" 5M single ram BOP w/ studded connections Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 2 of 15 Formation Integrity Testing Requirements: Test Point Depth Test Type Minimum EMW 11-3/4" Surface Shoe Rathole + 20' to 50' from shoe LOT 12.5 ppg I 9-5/8" Drilling Liner Shoe Rathole + 20' from shoe FIT 13.5 ppg 7" Intermediate Shoe I Rathole + 20' from shoe FIT 12.5 ppg Drilling Fluids Program: Intermediate 1 Hole Mud Properties: 10-5/8" x 11-3/4" hole MOBM Interval Density Viscosity secs YP PV HTHP@ 200 OWR Intermediate 1 10.0-10.4 ppg 55-80 12-25 20-35 <6 80/20 Intermediate 2 Hole Mud Properties: 8-1/2" x 9-1/2" hole LSND Interval Density p Viscosity secs YP PV MBT API ml Intermediate 2 10.2 ppg (13 ppg via MPD 50-70 25-30 10-25 < 15 <6 Production Hole Mud Properties: 6-1/8" hole MOBM Interval Density pp Viscosity secs YP PV HTHP OWR Lateral 7.4 - 8.4 ppg 55-80 8-12 15-20 <4 70/30 (-9.8 ppg via MPD Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 3 of 15 Formation Markers: Name TVD MD Estimated Pore Pressure HUE 2 3248 4121 Top of Whipstock 3233 4088 ✓ IA,' 'CD `4s Hue Res C tied 3979 5708 Hue Res B tied 4236 6268 Hue Res A tied 4272 6346 BROOK 26 5013 7953 ICP1 15' TVD above the Torok `�'$ --� 5013 7953 8.8 TOROK TOP 5028 7985 TOROK BASE 5273 8516 ' TOROK SH1 MKR 5437 8872 <— 9-y 115 TOP HRZ 5843 9753 129 BASE HRZ 5972 10032 130 KALUBIK MKR 6048 10198 KUP C 6113 10365 134 LCU 6132 10418 145 BCU 6230 10870 NUIQSUT 6260 11214 NUIQ 1 6267 11287 9.8 ICP2 - 4' TVD below Nui sut 1 - see Nui 1 marker on los 6271 11333 Permit TD 7.5K 6174 18833 Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 4 of 15 Logging Program: 10-5/8" x 11-3/4" Section: Drilling: Mud Logging — 50' samples Dir / GR /Res / At -bit GR Open Hole: N/A Cased Hole: N/A 8-1/2" Section: Drilling: Mud Logging — 50ft samples, 3 isotube samples Dir / GR / Res / AzDen / Neu / At -bit GR Open Hole: N/A Cased Hole: Bat Sonic Bond log of 7" Stage 1 Cement 6-1/8" Section: Drilling: Mud logging — 100ft samples, 200ft isotube gas samples Dir / GR / Res / AzDens / Neut / At -bit Inc Open Hole: N/A Cased Hole: N/A Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 5 of 15 Casing Program: Hole Size Casing / Tubing Weight Grade Conn. Casing Length Csg/Tbg Top MDrkb Hole Btm MDrkb/TVDrkb 24" 16" 109# H-40 Welded 115 Surface 158 158 14-1/2" 11-3/4" 60# L-80 BTC 4045 Surface 4088 3233 11-3/4" 9-5/8" 40# L-80 Hydril521 4015 3938 7953 5013 8-1/2" 7" 26# L-80 Hydril563 11290 Surface 11333 6271 6-1/8" 4-1/2" 12.6# L-80 Hydril 521 7700 11133 18833 6174 Tubing 12.6# C-110 3.958" Hydril521 11040 Surface 11083 6249 Casing Properties Size Weight Grade ID Drift ID Conn. Internal Yield (psi) Collapse (psi) Tensile Strength Joint Body 16" 100.2# X-65 14.67" 14.5" Welded Conductor casing 11-3/4" 60# L-80 10.772" 1 10.62" BTC 5830 3170 1384M 1384M 9-5/8" 40# L-80 8.835' 8.75" H dril 521 5750 3090 641 M 916 M 7" 26# L-80 6.276" 6.151 H dril 563 7240 5410 604 M 604 M 4-1/2" 12.6# C-110 3.958" 3.833" H dril 521 11590 9200 263 M 396 M Annular Infection: Currently not requested, but may be requested in the future. ,f Cuttings Handling_ All Class 2 solids will be processed on the Oooguruk Drill Site by the Grind and Inject facility in the Rig Support Complex and injected down the approved Class 1 / Class 2 disposal well, ODSDW1-44. Fluid Handlinq: All Class 1 and Class 2 fluids will be processed on the Oooguruk Drill Site by the Grind and Inject facility in the Rig Support Complex and injected down the approved Class 1 / Class 2 disposal well, ODSDW1-44. 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ODSN-01 drilled and recorded on file with the AOGCC. The following work scope has been applied for via a separate sundry. It has been included here for information purposes only: Abandon ODSN-01 11-3/4" Surface Casing Zonal isolation: r et a) Torok Formation is cemented off behind ODSN-01 11 9-5/8" Casing and Cement job a. Reference ODSN-01 Nuiqsut Production Well Completion Schematic. b) Kuparuk Formation is cemented off behind ODSN-01 12 7" Casing and Cement job. a. Reference ODSN-01 Nuiqsut Production Well Completion Schematic. c) The Nuiqsut Formation has been abandoned via cement plug by displacement. a. Reference ODSN-01 Nuiqsut Production Well Completion Schematic. b. Reference: Well Completion or Recompletion Report and Log in reference to Sundry# 315-343 submitted 9/17/2015 1. MIRU Nabors 19AC over ODSN-01. 2. ND production tree with the following well control barriers in place a) 7" casing retrievable bridge plug installed @ 6,743' MD. 3. Install test plug, NU BOPE & Test 250 psi low / 4500 psi high as required per AOGCC regulations. a) Notify the AOGCC Field Representative 48 hours prior to the BOPE Test. 4. Circulate out diesel freeze protection. 5. BOLDS and unseat 4-1/2" tubing hanger with the use of a 4" drillpipe landing joint. 6. Pull and lay down freeze protection string. 7. Install 7" BOPE rams in lower ram body and & test 250 psi low / 4500 psi high as required per AOGCC regulations. a) Notify the AOGCC Field Representative 48 hours prior to the BOPE Test. 8. RIH with mechanical casing cutter and cut 7" 26# Hydril 511 & BTC -M 20' below 9-5/8" of LHP at 4138' MD. 9. Establish communication between 7" casing and OA to confirm 7" casing cut. 10. Circ surface to surface volume of kill weight brine down 7" and up OA. a) Circ OA fluid through OA wellhead valve via hardline to portable choke skid into flowback tank. b) Fluid will contain significantly contaminated freeze protection fluid. A considerable volume of solids are expected. Ensure contingency plan is available should pack -off in surface equipment occur. 11. BOLDS and unseat 7" hanger and pull hanger to floor. 12. Break 7" hanger and POOH with 7" casing. a) Inspect casing for scale or corrosion and report on WellView. b) Clean all casing equipment at the rig floor with water. c) Equipment retrieved will be sent to vendors for inspection. Label equipment accordingly during POOH. d) If junk is left in hole contact Rig Superintendent and discuss fishing options. e) Test casing for NORM. 13. Install 2-7/8" x 5" VBR's" in lower ram body and & test 250 psi low / 4500 psi high as required per AOGCC regulations. Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 10 of 15 14. Notify the AOGCC Field Repi .sentative 48 hours prior to the BOPE Test. 15. RIH with 10-5/8" bit and scraper to 9-5/8" LHP top at 4,118' MD. 16. Circulate 2 BU and POOH. 17. RIH with 11-3/4" permanent bridge plug to 4,110' MD and set. a) This plug is intended to limit fluid swapping between kill weight ODSN-01A OBM Intermediate 1 drilling fluid with Kill weight ODSN-01 7" ID abandonment brine. 18. Pressure test permanent bridge plug to 3500 psi for 5 min. �+ J 19. Swap to 10.2 ppg MOBM ODSN-01A 11 Drilling fluid and POOH with running tool. 20. RIH with Baker 11-3/4" whipstock and set to put window between 4,088'— 4,098' MD. a) Orient whipstock as per HAL WP # 10 21. Shear off whipstock and drill off to cut window in 11-3/4" surface casing as per Baker Rep until upper watermelon mill exits window. 22. Pull into 11-3/4" casing and circ and cond fluid. 23. Perform a FIT to 12.5ppg EMW. �! b) If a 12.5ppg FIT is not achieved contact Drilling Superintendent. 24. POOH with milling assembly. 25. RIH with 10-5/8" mill tooth bit and 1.83° motor and drill ahead 300'-400' until magnetic interference with ODSN-01 cleans up. 26. Confirm separation from ODSN-01 via inclination difference and POOH. t The following work scope is for this ODSN-01A PTD Application: Drill and Complete ODSN-01A 1. MU 10-5/8" x 11-3/4" RSS, including Under -reamer and,MWD/LWD and RIH. 2. Drill 10-5/8" x 11-3/4" Intermediate 1 to casing point. • Intermediate 1 hole section will be drilled to roughly 15' TVD above the Top of Torok. 3. Change one set of pipe rams to 9-5/8" and test BOPE as required. 4. Run 9-5/8" drilling liner on 5" DP and cement. • Planned cement top is 500ft above 9'5/8" shoe depth. 5. Bump the plug, increase pressure to 3500 psi and hold pressure for 5 minutes • This will provide a quick integrity test of the 9-5/8" liner. • Note the pressure test in the morning report 6. Release pressure and ensure floats are holding • This will check the integrity of the floats to ensure there isn't a flow path through the liner shoe 7. Set liner hanger and packer and test the liner top to 3500 psi for 5 minutes • This will check the integrity of the liner top packer to ensure isolation between the liner and the surface casing • Note the pressure test of the liner top in the morning report 8. POOH w/ 5-1/2" DP. 9. ND BOPE, ND Drillin_ spool, NU Multi -bowl Wellhead, & NU BOPE and install Halliburton managed pressure V" q/ drilling (MPD) equipment. Test BOPE to 250/4500 p_si - No AOGCC48 hours_in advance Qf_te t._ Ensure integrity of the liner and the liner top has been verified by a pressure test prior to performing this step p� 10. MU 8-1/2" bit and clean out assembly and RIH to top of landing collar. `( Wr 11. Close pipe rams and combo pressure test the Drilling Liner and the Surface Casing to 3500 psi 30 minutes -- chart and send to ODE. -'--- 12. Drill through liner shoetrack and rathole. Displace Intermediate 1 drilling fluid to Intermediate 2 drilling fluid while drilling the shoetrack. Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 11 of 15 Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 12 of 15 13. MU 8-1/2" x 9-1/2" RSS, MWl„LWD on 5" DP and RIH. RU MPD seal bearing package in the rotary control 14. Drill 20' MD of new formation. Pull the bit back into the casing and perform FIT to 13.5ppg EMW. POOH. 15. Drill 8-1/2" Intermediate 2 to Torok 1 Shale Marker holding 12.5 ppg EMW via MPD. 16. Spot LCM pill across the Torok 1 Shale Marker and Torok Sand Package. 17. Pull into 9-5/8" shoe and perform bore hole strengthening squeeze. 18. Wash and ream in hole to Torok 1 Shale Marker. 19. Drill 8-1/2" Intermediate 2 to casing point holding 12.5 ppg EMW via MPD. 20. Circulate and condition the well to run 7" intermediate casing. Displace the well over to -12.0 ppg mud for shale stability. RD the MPD bearing assembly and RU MPD trip nipple. POOH. 21. Change one set of pipe rams to T' and test BOPE as_reguired._ 22. Run 7" 26# L-80 Hydril 563 Intermediate 2 casing to TD. • Position stage cementer at Base of Torok Sand Package. 23. Pump stage 1 _cement-jqb ___ #'( TOC of cement job designed to cover 500' MD above Top of Kuparuk. Minimal Kuparuk formation is expected in ODSN-07i. 24. Precede second stage of cement job with MOBM spacer intended to act as a freeze protection fluid for the 11-3/4" x 9-5/8" x 7" annulus 25. Pump stage 2 cement job. �J' a. TOC is designed to cover 500' MD above Top of Torok Sand Package. The second stage cement job will fill the 9-5/8" x 7" annulus with cement thereby sealing off annular pressure communication between the 11-3/4" x 9-5/8" x 7" annulus and formations below the 9-5/8" shoe. 26. Bump the plug and bring the pressure up to 3500 psi -hold for 5 minute pressure test. Release pressure and ensure floats are holding. 27. LD 5" DP 28. RU MPD trip nipple & PU 4" DP as needed to TD the lateral hole section. 29. RIH to landing collar and w/ 4" DP & mill tooth cleanout bit. 30. Change pipe rams to 4" and test BOPE to 250/4500 psi - Notify AOGCC 48 hours in advance of test. 31. Pressure test casi_ng to_4000_p§ _- chart and hold for 30 minute pressure test. Send chart to ODE. 32. Drill through Intermediate 2 shoe and POOH w/ cleanout assembly. 33. MU 6-1/8" Motor, agitator, MWD/LWD drilling assembly on 4" DP and RIH. 34. RD MPD trip nipple and RU bearing assembly. 35. Displace to drill -in -fluid for lateral hole. f 36. i� Drill rathole 20' of new hole and perform FIT to 1_2.5 ppg. l' 37. Drill 6-1/8" lateral lateral hole to TD. 38. Circulate and condition hole to run liner. 39. POOH to intermediate shoe and set heavy weight balance brine pill. 40. RD MPD bearing assembly and RU MPD trip nipple. Continue POOH to surface. 41. Change one set of pipe rams to 4-1/2" and test BOPE as required. RIH _w/4_-_1/2_"production liner w/ Halliburton frac sleeves and swellpackers from 150' inside the intermediate shoe to TD. 43. Release from the liner and set the liner top packer. Displace the well over to completion brine and POOH. 44. Run 4-1/2" fracture stimulation string to top of 4-1/2" liner seal bore. 45. Reverse circulate corrosion inhibited brine or diesel to freeze protect the well to -2000' TVD. 46. Sting 4-1/2" fracture stimulation string into the 4-1/2" liner seal bore. 47. Pressure test 7" x 4-1/2" annulus to 3500 psi - chart and hold for 30 minute pressure. Send chart to ODE. Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 12 of 15 CNRA wily oubmit a sundry prior to executing the following program Post Ria Operation: Fracture Stimulation 1 1. Fracture stimulate well 2,000,000 lbs of 20/40 Carboceramics Carbolite proppant pumped in 600,000 gallons of Schlumberger's YF125ST. The fluid volume includes a pad stage yet to be determined. The stimulation will target the Nuiqsut reservoir in a 11 stage treatment using the Halliburton frac sleeve mechanical diversion system. The expected surface treating pressure at a planned pump rate of 50 barrels per minute is 7000 psi. Maximum proppant concentration is 10 ppa per gallon. The Schlumberger YF125ST is a water based guar gel system with borate crosslinker. The chemical make-up of the YF125ST includes: Seawater base — 983.75 gpt Clay Stabilizer — 2 gpt Polymer — 6.25 gpt Surfactant — 2 gpt Crosslinker — 6 gpt Oxidative Breaker — 0.05 ppt 2. Remove SSSV sleeve and install wireline retrievable SSV 3. Install live gaslift valves 4. Flowback well with gaslift. 5. RDMO well. Ria Activity: ESP Completion 1. Rig up over well. 2. Install BPV and nipple down tree. 3. Pull 4 %2" fracture stimulation string. 4. RIH w/ ESP completion w/ Packer & Tubing Retrievable ScSSSV. 5. Space out and land tubing hanger. 6. RILDS and test both the upper and lower tubing hanger body seals to 5000psi. 7. Set BPV, ND BOPE, NU Production Tree 8. Replace BPV w/ TWC & Test Production Tree void to 5000psi & recover TWC 9. Reverse circulate corrosion inhibited brine or diesel to freeze protect the well to —2000' TVD 10. Set packer and test annulus to 3500 psi for 30 min. Post Ria Operations: 1. Rig up slickline 2. Retrieve ball/rod assembly from the RHC -M plug body 3. Pull dummy valve from lower GLM, set'/" OV in same. 4. Retrieve RHCM plug body 5. Rig down slickline Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 13 of 15 Casing Shoe Leak Off Test r rocedure: 1. After testing BOPE, pick up the drilling assembly and RIH to the float collar. Circulate to consistent mud weight and rheology. 2. Shut in with the pipe rams and test the casing to the required test pressure. Record the volume of mud required and the corresponding pressures in'/ bbl increments. When the design pressure is reached shut in the well and record the shut in pressure for 30 minutes. 3. Bleed off pressure while taking returns to a calibrated tank and record volume recovered. 4. Drill out the shoe track. Drill 20 ft of new hole and circulate the hole clean with consistent mud weight in/out. Pull up into the casing shoe. 5. Perform a Leak Off Test (or Formation Integrity Test): • Calculate the required test pressure to reach leak off (or formation integrity test limit) with the actual mud weight and the estimated fracture EMW. • Plot the casing test data and the calculated leak off on appropriate scale coordinate paper. As a guide, use the data from the casing test to determine the approximate volume of mud required to reach the calculated LOT/FIT. • Shut the well in. R/U the test pump. • Bring the pump on line at 0.25 — 0.50 bpm. Maintain a constant rate. • Record the pressure for every'/ of a bbl pumped. • Continue pumping until the pressure vs. volume curve breaks over indicating leak off. Note: For FIT, do not take to leak off • Discontinue pumping and shut in the well. Record the shut in pressure in 1 minute increments for 10 minutes or until pressure shows stabilization. • Bleed off the pressure and record the volume of mud recovered. • Plot the data to determine the LOT/FIT pressure at the shoe as EMW. • Submit the test results to the Pioneer drilling engineer for distribution as required. Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 14 of 15 Drilling Hazards and Contingencies POST THIS NOTICE IN THE DOGHOUSE Well Control • Prior to drilling into the Torok, hold a pre -reservoir meeting to outline heightened awareness for kick detection and lost circulation. o Following the Torok penetration, pick up off bottom, shut off the pumps and perform a flow check to verify there isn't any overpressure. Hydrates and Shallow gas • No hydrates are expected in this area. Lost Circulation/Breathing/Formation Stability/Stuck Pipe Events • Breathing may be seen while drilling the Hue shale. Minimizing swab and surge on the formation is critical to reducing the impact of breathing in the wellbore. Breathing was seen in the ODSN-40 well, but only after substantial time in trying to solve the lost circulation problems in the fault seen in and below the Torok Sands. • Lost Circulation was seen in drilling the ODSN-36 across this same interval. Review the DOB2C pill procedure prior to penetrating the Kuparuk. Follow the Lost Circulation Decision Tree and combat losses accordingly • During the attempt to retrieve a fish from the ODSK-33 well, an un -centralized BHA got stuck from differential sticking across the Torok due to the increase in mud weight needed to hold back the shales below. Differential sticking indications were not noted with the drilling BHA and drill pipe. • There is a small section of formation above the Top of the HRZ that is volcanic in nature (TUFFS) and can either have "glassy" material, swelling clays or both while drilling, which produced a pack off on ODSK-33 and ODSN-45. Kick Tolerance/Integrity Testing Kick Tolerance / Integrity Testing Summary Table Casing set / Maximum Mud Weight Exp Pore Min LOT / FIT Interval Influx Volume Press ress11-3/ 11 -3/Whipstock / 10-5//8" x 11-3/4" Infinite 10.0-10.4 ppg - 2242 12.5 ppg (LOT) 9-5/8" Drilling Liner/ Infinite 10.2-10.5 ppg 3196 13.5 ppg (FIT) 8-1/2" x 9-1/2" 13.0 EMW w/MPD 7" Intermediate / 6-1/8" ` w`Infinite `� 7.4-8.4 ppg 9.8-10.2 EMW w/MPD 3147 12.5 ppg (FIT) NOTE: All LOT / FIT will be taken with a minimum of 20 -ft and a maximum of 50 -ft of new hole drilled outside of the previous casing string Hydrogen Sulfide • The Oooguruk Drill Site is not designated as an H2S site, however Standard Operating Procedures for H2S precautions should be followed at all times. Caelus Natural Resources Alaska LLC Last Revised: January 4, 2016 ODSN-01 Permit To Drill Page 15 of 15 ODSN-1 Nuiqsut Production Well Completion 16" Conductor to 158' FINAL Suspension 9/3/2015 Upper Completion MD (ft) TVD (ft) A Tubing Hanger 34' 34' B 4-1/2" 12.6 # L-80 Hydril 521 Tubing C 4-1/2" 12.6 # L-80 Hydril 521 Full Muleshoe it 2550' 2333' 11-3/4" 60 ppf L-80 Hydril 521 Surface Casing c @ 4308' MD / 3334' TVD cemented to surface Baker Retrievable Plug # 2 @ 6,743 ft MD RCT Damage 7" @6,935' MD RCT Damage 7" @8,221' MD RCT Damage 7" @8,242' MD =.' 9-5/8" 40 ppf L-80 Hydril 521 Intermediate 1 Casing @8526'MD/ 5446' TVD RCT Damage 7" @8,745' MD RCT Damage 7" @8,785' MD Cement Top 8,665' MD 7" Damaged 9635'-9638' MD 5-%'W" Solid Expandable Liner - 6,790 ft to 11,147 ft MD ID varies from 5.57" to 5.43" minimum ID 22 potential connection leaks detected in expandable liner but still under investigation. Major leaks @ -- 7,700 ft MD & -9,200 ft MD BAT Sonic TOC @9,650" MD 7" Damaged 9,727-9,733' MD Baker Cement Retainer # 1 @ 11,088 ft MD Expandable Liner Hanger Joints w/ 5 Seals per Hanger @: 6,790 - 6,811 ft MD 9,201 - 9,221 ft MD 11,118-11,139ft MD End of Assembly 2564' 2343' Pre -Perforated Pups Staged -200 ft apart (Dynamic Diversion) w/ Resman Tracer Carries (Qty 8) • • • o 0 0 0 0 0 0 a7 I --------------- 170� [, 6-1/8" Hole TD at 7" 26 ppf L-80 4-/2" Hydril 521 Liner with Baker Hughes EX -C Sliding Hydril 521 Sleeves (8 total) with oil activated Swell Packers (10 at 180MD / Intermediate 2 total / 2 placed below 7" shoe). 6183'' T TVD Casing Resman Tracers will he nla _ -d above and below @ 11380' MD / each Fra _ Sleeve _v 6262' TVD ODSN-1 Nuiqsut Production Well Completion FINAL Suspension 9/3/2015 16" Conductor to 158' 11-3/4" 60 ppf L-80 Hydril 521 Surface Casing @ 4308' MD / 3334' TVD cemented to surface Baker Retrievable Plug # 2 @ 6,743 ft MD RCT Damage 7" @6,935' MD RCT Damage 7" @8,221' MD RCT Damage 7" @8,242' MD 9-5/8" 40 ppf L-80 Hydril 521 Intermediate 1 Casing @ 8526' MD / 5446' TVD RCT Damage 7" @8,745' MD RCT Damage 7" @8,785' MD Cement Top 8,665' MD 7" Damaged 9635'-9638' MD 5-t/2"x7" Solid Expandable Liner -- 6,790 ft to 11,147 ft MD ID varies from 5.57" to 5.43" minimum ID 22 potential connection leaks detected in expandable liner but still under investigation. Major leaks @ - 7,700 ft MD 8r -9,200 ft MD No. Lower Completion MD (ft) TVD(ft) 15 Baker 5-W' X 7" ZXP Liner Top Packer with Tie Back extension and Flex Lock Hanger 11,141' 6,251' 16 4-'h"12.6#/ft Hydril 521 Liner 17 Halliburton 5we11 Packer(4%" Hydril 521) OD 5.85 11,431' 6,264' 18 4Y"12.6#/ft Hydril 521 Liner(2 joints) 19 Halliburton Swell Packer(4-/,," Hydril 521) OD SSS ' 11,460' 6,265' 20 4G"12.6#/ft Hydril 521 Liner 21 4'/," SLHTBall Actuated Sleeve (2.635' Seat ID) (2.688" Ball) w/4%" Resman Tracer Carriers above and below Frac Sleeve 11,705' 6,274' 2214-Y,"12.6#/ft Hydri 1521 Liner 23 f!alliburton Swell Pa<kcr(4%" HVdrH 521) 0D 5.85r 11,881' 6,272' 24 4Y" 12.6#/ft Hydril 521 Liner 25 4'/," SLHTBall Actuated Sleeve (2.573" Seat ID) (2-625" Ball) w/4'/," Resman Tracer Carriers above and below Frac Sleeve 12,129' 6,268' 26 4-%"12.6#/ft Hydril 521 Liner 21 Halliburton Swell Packer (4 Hydnl 521) OD 5.85' 12,306' 6,270' 28 4-W' 12.6#/ft Hydril 521 Liner 29 4Y," $LHT Ball Actuated Sleeve (2.510" Seat 113) (2.563" Ball) w/4%" Resman Tracer Carriers above and below Frac Sleeve 12,672 6,263' 30 4-%" 12.6#/ft Hydril 521 Liner 31 Halliburron Swell Packer(4 Y,' Hydril 531) OD 5-85` 12 8,0, 6,259' 32 4Y" 12.6#/ft Hydril 521 Liner 33 4'/,"SLHT Ball Actuated Sleeve (2.448"SeatlD)(2.S00"Ball)w/4'/," Resman Tracer Carriers above and below Frac Sleeve 13057' 6,252' 34 4-Y," 12.6#/ft Hydril 521 Liner 35 Halliburton Swell Packer(4-Y" Hydril 521) OD 5.85 13,231' 6,247 36 4-'/," 12.64/ft Hydril 521 Liner 37 4'/:" SLHTBall Actuated Sleeve (2.385"Seat ID) (2.438"Ball) w/4%" Resman Tracer Carriers above and below Fac Sleeve 13,476' 6,241' 38 4-Y,," 12.6#/ft Hydril 521 Liner 39 Halliburton Swell Packer(4Y," Hydril 521) OD 5.85 13,769' 6,237' 40 4-%" 12.6#/ft Hydril 521 Liner 41 4%" SLHT Ball Actuated Sleeve (2.323" Seat ID) (2.375" Ball) w/ 4'/," Resman Tracer Carriers above and below Frac Sleeve 14,092' 6,229' 42 4%"12.6#/ft Hydril S21 Liner 43 11a1liburt-S-11Packer(4-%'Hydril521)0D5.85' 14,267' 6,225' 44 4-%" 12.6#/ft Hydril 521 Liner 4S 4'/," SLHT Ball Actuated Sleeve (2.260"Seat ID) (2.313"Ball) w/4%'Resman Tracer Carriers above and below Frac Sleeve 14,554' 6,218' 46 4-Y," 12.6#/ft Hydril 521 Liner 47 Halliburton Swell Packer(4-%" Hydril 521) OD S.85 14,688' 6,231' 48 4-'/,"12.6#/ft Hydril 521 Liner 49 4%" SLHTBall Actuated Sleeve (2.198"SeatlD)(2.250"Ball) w/4'W'Resman Tracer Carriers above and below Frac Sleeve 14,931' 6,209' 504'/,"12.6#/ft Hydril 521 Liner 51 Halliburton Swell Packer(4'/," Hydril 521) OD5.85' 1S 106, 6,206 52 4Y"12.6#/ft Hydril 521Liner 53 4-W,12.6#/ft Hydni 521 Liner with Pre- Perforated Pups spaced -200 ft apart w/4T'Resman Tracer Carr i ers (Qty 8 spaced out evenly across between pre -perforated pups) 54 4-R" Hydril 521 Eccentric Shoe 17,900' 6,188' BAT Sonic TOC @9,650" MD 7" Damaged 9,727-9,733' MD Baker Cement Retainer # 1 @ 11,088 ft MD Expandable Liner Hanger Joints w/ 5 Seals per Hanger @: 6,790 - 6,811 ft MD 9,201 - 9,221 ft MD 11,118 - 11,139 ft MD Pre -Perforated Pups Staged -200 ft apart (Dynamic Diversion) w/ Resman Tracer Carries (Qty 8) 6-1/8" Hole TD at 7" 26 ppf L-80 4-'/" Hydril 521 Liner with Baker Hughes EX -C Sliding at 18011' MD / Hydril 521 Sleeves (8 total) with oil activated Swell Packers (10 6183' TVD Intermediate 2 total / 2 placed below 7" shoe). Casing Resman Trarers will be plared ahovp and helow @ 11380' MD / each Frac Sleeve 6262' TVD Proposed ODSN-01 Abandonment and ODSN-01A Kick-off 16" Conductor to 158' oa drip /V,07 q \whp °Ck 11-3/4" 60 ppf L-80 Hydril 521 Surface Casing @ 4308' MD / 3334' TVD cemented to surface Baker Retrievable Plug # 2 @ 6,743 ft MD RCT Damage 7" @6,935' MD RCT Damage 7" @8,221' MD RCT Damage 7" @8,242' MD 9-5/8" 40 ppf L-80 Hydril 521 Intermediate 1 Casing @ 8526' MD / 5446' TVD RCT Damage 7" @8,745' MD RCT Damage 7" @8,785' MD Cement Top 8,665' MD 7" Damaged 9635'-9638' MD BAT Sonic TOC @9,650" MD 7" Damaged 9,727-9,733' MD Baker Cement Retainer # 1 @ 11,088 ft MD i f 7" 26 ppf L-80 Hydril 521 Intermediate 2 Casing @ 11380' MD / 6262' TVD Whipstock window: 4,088'— 4,098' MD 11-3/4" Permanent Bridge Plug: 4,110' MD Top of 9-5/8" LHP: 4,118' MD 11-3/" Casing Shoe:4,308' MD Expandable Liner Hanger Joints w/ 5 Seals per Hanger @: 6,790 — 6,811 ft MD 9,201 — 9,221 ft MD 11,118 —11,139 ft MD Pre -Perforated Pups Staged -200 ft apart (Dynamic Diversion) w/ Resman Tracer Carries (Qty 8) 6-1/8" Hole TD at at 18011' MD / 6183' TVD ODSN-01A Nuiqsut Production Well Completion Land Upper Packer Fluid mix: Completion Inhibited Kill with 40,000 lbs weight Brine Slack -Off with 2000' TVD I diesel cap I I ( 11-3/4" 60# L-80 '_Sst I 3 BTC Surface Casing 16" @ 4,308' MD / Conductor I 3,334' TVD Cemented to surface GLM# 3 5 GL SOV er Com letion MD ft Installed 7 x Tuhin Han er 7,000 psi Whipstock Window: 2 Max rated Hanger I 4,088' - 4,098' MD 3 4-%" Halliburton'XXO' SVLN w/3.813" "Y' profile with singlei/4"x0.049"s/s control line. Cannon Cross -coupling clamps on everyjoint w/ 15ft Pup BxP Top &Bottom 11-3/4" Permanent 2,052 4 Bridge Plug @ 4,110 MD 25 w 15ft Pu BxP To & Bottom 5 GL GLM# 2 9 2,482 6 DGLV 11 k Installed I 2,861 7,000 psi 8 Max rated Halliburton Swell Packer # 12 (4%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on TOC Estimated 9 4X" x 1" GLM #2, KBG-45 Hydril 521w/ 15ft Pup BxP Top& Bottom I @ 500 ft above 3,975 10 9-5/8" Shoe I 29 4-X"12.6#/ftHydril 521 C-130 Liner 9-5/8" 40# L-80 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 5,800 Hydril 521 12 4-X"126#/ft C-110Hydril 521 Tubing I Intermediate 1 31 13 Casing 10,000 5,957 @ 7,953' MD / 4-%"12.6#/ft C-110Hydril 521 Tubing (2 Joints) Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 5,013' TVD GLM# 1 13 ? GL 6,003 DGLV Installed 15 4-%"126#/ft C -110H dnI 521 Tubing x I` 7,000 psi 10,200 6,048 Max rated 4%"12.6#ft C-110 Hydril 521 Tubing 2't ROC 7" TOC Estimated @ 500 ft above Kuparuk RHC Plug 19 xN Installed 7" 26# Hydril 563 Intermediate 2 Casing @ 11,333' MD / 6,271' TVD 1-4-2016 DRAFT No.U er Com letion MD ft ND ft 1 Tuhin Han er 34 34 2 4'/."12.6#/ft C-110Hydril 521Tubin Hanger 11,083 6,249 3 4-%" Halliburton'XXO' SVLN w/3.813" "Y' profile with singlei/4"x0.049"s/s control line. Cannon Cross -coupling clamps on everyjoint w/ 15ft Pup BxP Top &Bottom 2,191 2,052 4 4-'h"12.6#/ft C-110Hydril 521Tubin 25 w 15ft Pu BxP To & Bottom 5 4.%" x 1" GLM #3, KBG-45 Hydril 521 w 15ft Pup BxP Top & Bottom 2,761 2,482 6 4-X"12.6#/ft C -110H dril 521Tubin 2Joints 27 7 HES "X" Ni le 3.813" w ." Pu BxP To & Bottom 2,861 2,549 8 4X"12.6#/ft C-110Hydril 521 Tubing Halliburton Swell Packer # 12 (4%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 9 4X" x 1" GLM #2, KBG-45 Hydril 521w/ 15ft Pup BxP Top& Bottom 5,700 3,975 10 4-Y,,"12.6#/ft C-110Hydril 521 Tubing (2 Joints) 29 4-X"12.6#/ftHydril 521 C-130 Liner 11 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 5,800 4,021 12 4-X"126#/ft C-110Hydril 521 Tubing 11,807 6,290 31 13 4-W' x 1" GLNI # 1, KBG-45 Hydril 521 w/ 15ft Pup BxP Top & Bottom 10,000 5,957 14 4-%"12.6#/ft C-110Hydril 521 Tubing (2 Joints) Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 12,136 6,290 15 HES "X" Nipple 3.813" w/ 15ft Pup BxP Top & Bottom 10,100 6,003 16 4-%"126#/ft C -110H dnI 521 Tubing HLB 41/2" RapidStage Ball Actuated Sleeve (2.925 ball/ 2.867 Seat) w/ 15ft 41/2"P-110 Pup 41/2" 17 41/2" Halliburton 'ROC' Gauge Carrier w/ Encapsulated a -line to Surface w/ 15ft Pup BxP Top & Bottom 10,200 6,048 18 4%"12.6#ft C-110 Hydril 521 Tubing 2't 19 HES XN 3.813" 3.725" NoGo - w/ 15ft Pup BxP Top & Bottom 10,300 6,090 20 4-%"126#/ft C-110Hydril 521 Tubing Centralizeron Top of Swell Packer 21 41/2"x4" Crossover P-110 Locator with a 5.66' long 4.V2" handling pup on top, 4" Spacer Pup w/ Bullet Seal Assembl +Auto Ent Guide Shoe 11,083 6,249 nottom or 5noe 11,119 b,252 No. Lower Completion MD k TVD ft 22 20ft5.25" Tie Backextension 11,063 6,247 Bakers"XT' ZXP Liner Top Packer with Flex Lock Hanger/20ft4.25" Seal Bore Recepticle Below 23 Hanger 11,083 6,249 24 4-%"126#/ftH Hydril 521C-110 Liner Resman Internally Vented Carrier#4JN#24552-2-1 /ROS -1372-11 / RWS-1399-11 25 w 15ft Pu BxP To & Bottom 11,337 6,271 26 4X"12.6#/ftHydril 521 C-110 Liner Halliburton Swell Packer# 13 (4X" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 27 Volant Centralizer Pin End and 6ft Pup 41/2"12.6#/ftP-110 Hydril S21 Box x Pin w/Slide On Volant 11,437 6,280 Centralizeron Top of Swell Packer Halliburton Swell Packer # 12 (4%" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 28 Volant Centralizer Pin End and 6ft Pup 41/2'12.6#/ftP-110 Hydril 521 Box x Pin w/ Slide On Volant 11,477 6,284 Centralizer on Top of Swell Packer 29 4-X"12.6#/ftHydril 521 C-130 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (3.009 ball / 2.95 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 30 12.6# ft P-110 Hydril 521 Box x Pin 11,807 6,290 31 4X" 126# ft Hydril 521 C-110 Liner Halliburton Swell Packer # 11(4-Y." Hydril 521) OD 5.85- 9 meter long oil activated with Slide on 32 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 12,136 6,290 Centralizer on Top of Smell Packer 33 4-W'12.6#/ftHydril 521 C-110 Liner HLB 41/2" RapidStage Ball Actuated Sleeve (2.925 ball/ 2.867 Seat) w/ 15ft 41/2"P-110 Pup 41/2" 34 12.6#/ft P-110 Hydril 521 Box x Pin 12,466 6,287 35 4-X"126#/ftHydril 521 C-110 Liner Halliburton Swell Packer # 10 (4X" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 36 Volant Centralizer Pin End and 6ft Pup 41/2"12.69/ftP-110 Hydril 521 Box x Pin w/ Slide On Volant 12,795 6,281 Centralizeron Top of Swell Packer 37 4-%"12.6#/ftHydril 521 C-110 Liner HLB 4112' RapidStage Ball Actuated Sleeve (2.842 ball / 2.786 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 38 12.6# ft P-110 H dril 521 Box x Pin 13,124 6,273 39 4-%"126#/ftHydril 521 C-110 Liner Resman Internally Vented Carrier # 3 JN#24552-2-1 /ROS -1371-11/ RWS-1398.11 40 w 15ft Pu BxP Top& Bottom 6,267 13 354 41 4'h"12.6#/ftHydril 521 C-110 Liner Halliburton Swell Packer # 9 (4h" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 42 Volant Centralizer Pin End and 6ft Pup 41/2"12.6#/ftP-110 Hydril 521 Box x Pin w/ Slide On Volant 13,454 6,265 Centralizer on Top of Swell Packer 43 4%" 12.6#/ft Hydril 521 C-110 Liner ______2________ 4�_________; �__(�y1�„r6__________ 60_____O�8� 70________74 __ 38 40 �� 48 52 H 58) ILY 62 i]I_ 66 ---i]I72 4-1/2" Hydril 521 / C-110 Liner with Halliburton Ball Actuated Sleeves, & Swell Packers �J_______ _82 80 __-___: 6-1/8" Hole TD @ 18,833' MD / 6,174' TVD ODSN-01 A Nuiqsut Production Well Completion Land Upper Packer Fluid mix: Completion Inhibited Kill with 40,000 lbs weight Brine Slack -Off with 2000' TVD I diesel cap I I 11-3/4" 60# L-80 GLM# 2 GL MD ftND ft DGLV 11 3 BTC Surface Casing 16" Ell 13,783 6,257 @ 4,308' MD / Conductor Max rated Halliburton Swell Packer # 8 (4-%" Hydril S21) OD 5.85' - 9 meter long oil activate d with Slide on 3,334' TVD 46 Vol ant Ce ntral ize r Pi n End and 6ft Pup 4-1/2"12.6#/ft P-110 Hydri 1521 Box x Pi n w/Slide On Vol an: @ 500 ft above demented to surface Ce ntralize r on Top of Swe 11 Packer GLM# 3 SOV Installed 7,000 psi Max rates! 5 7 GL I is Whipstock Window: 4,088' - 4,098' MD x I Hydril 521 48 12.6#/ft P-110 H dri15218ox x Pin I Intermediate 1 494-W'12.6#/ftHydril 11-3/4" Permanent Casing Halliburton Swell Packer # 7 (4h" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on @ 7,953' MD / Brldge Plug @4,110 MD Volant Centralizer Pin End and6ft Pup4-1/2"12.6#/ftP-110 Hydri1521BoxxPinw/Slide On Volant 5,013' TVD iI GLM# 1 ` 13 DGLV C t� GNI �i eL P GLM# 2 GL MD ftND ft DGLV 11 HLB 41/2" Rapid5tage Ball Actuated Sleeve (2.761 ball / 2.706 Seat) w/ 15ft 41/2" P-110 Pup 41/2" Installed Ell 13,783 6,257 7,000 psi 4'/:"12.6#/ftH dri1521 C-110 Li mer Max rated Halliburton Swell Packer # 8 (4-%" Hydril S21) OD 5.85' - 9 meter long oil activate d with Slide on I TOC Estimated 46 Vol ant Ce ntral ize r Pi n End and 6ft Pup 4-1/2"12.6#/ft P-110 Hydri 1521 Box x Pi n w/Slide On Vol an: @ 500 ft above Ce ntralize r on Top of Swe 11 Packer 9-5/8" Shoe ��p✓v 4-W'12.6#/ftH driI S 2 1 C-110 Li ner I 9-5/8" 40# L-80 HLB 4-1/2" Rapid5tage Ball Actuated Sleeve (2.681 ball / 2.628 Seat) w/ 15ft 41/2" P-110 Pup 41/2" I Hydril 521 48 12.6#/ft P-110 H dri15218ox x Pin I Intermediate 1 494-W'12.6#/ftHydril 521 C-110 Li ner Casing Halliburton Swell Packer # 7 (4h" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on @ 7,953' MD / 50 Volant Centralizer Pin End and6ft Pup4-1/2"12.6#/ftP-110 Hydri1521BoxxPinw/Slide On Volant 5,013' TVD iI GLM# 1 ` 13 DGLV C t� GNI �i eL GL 51 15 Installed x I 5vL 7,000 psi Max rated I a be." 52 12.6#/ft P-110 Hydril 521 Boz x Pin 15,101 6,228 53 17 I I `-S I N k Rosman Internally Vented Carrier # 2 JN# 24552-2-1/ ROS -1370-11 / RWS-1397.11 aoc 1 7" TOC Estimated @ 500 ft above Kuparuk RHC Plug Installed 7" 26# Hydril 563 Intermediate 2 32 Casing 3s @ 11,333' MD / 27 6,271' TVD 30 ` 1-4-2016 DRAFT No. Lower Com letlon MD ftND ft HLB 41/2" Rapid5tage Ball Actuated Sleeve (2.761 ball / 2.706 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 44 12.6#/ft P-110HdriI S21 Boz x Pin 13,783 6,257 45 4'/:"12.6#/ftH dri1521 C-110 Li mer Halliburton Swell Packer # 8 (4-%" Hydril S21) OD 5.85' - 9 meter long oil activate d with Slide on 46 Vol ant Ce ntral ize r Pi n End and 6ft Pup 4-1/2"12.6#/ft P-110 Hydri 1521 Box x Pi n w/Slide On Vol an: 11,113 6,21' Ce ntralize r on Top of Swe 11 Packer 47 4-W'12.6#/ftH driI S 2 1 C-110 Li ner HLB 4-1/2" Rapid5tage Ball Actuated Sleeve (2.681 ball / 2.628 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 48 12.6#/ft P-110 H dri15218ox x Pin 14,442 6,241 494-W'12.6#/ftHydril 521 C-110 Li ner Halliburton Swell Packer # 7 (4h" Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 50 Volant Centralizer Pin End and6ft Pup4-1/2"12.6#/ftP-110 Hydri1521BoxxPinw/Slide On Volant 14,772 6,234 Centralize r on Top of Swe11 Packer 51 4-A"12.6#/ftHydril 521 C-110 Liner HLB 41/2" Rapid5tage Ball Actuated Sleeve (2.603 ball /2.552 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 52 12.6#/ft P-110 Hydril 521 Boz x Pin 15,101 6,228 53 4W'12.6#/ft Hydril 521 C-110 Liner Rosman Internally Vented Carrier # 2 JN# 24552-2-1/ ROS -1370-11 / RWS-1397.11 54 w 15ft Pu BxP To &Bottom 15,331 6,224 55 4-%"12.6#/ftHydril 521 C-110 Liner Halliburton Swell Packer# 6(4-%" Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 56 Volant Centralizer Pin End and 6ft Pup 4-1/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Vola , 1 i 11 Central -on Top of Swell Packer 57 4 %" 12.6#/ft H dril 521 C-110 Liner HLB 41/2" Rapid5tage Ball Actuated Sleeve (2.527 ball/ 2.477 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 12.6# ft P-110 Hydril 521 Box x Pin 15,760 6,218 59 4'/:" 12.6#/ft Hydril 521 C-110 Liner Halliburton Swell Packer # 5 (4'/:" Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 60 Volant Centralizer Pin End and Eft Pup 41/2"12.6#/ft P-110 Hydril 521 Box x Pin w/Slide On Volant 16,089 6,21x, Ce ntralizeron To of '_ 11 Packer 61 4-%"12.6#/ftH dril521 C-110 Li ner HLB 41/2" Rap id5tage Bal 1 Actuated Sleeve (2.452 ball / 2.404 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 62 12.69ft P-110Hydril 521 Box x Pin 16,419 6,215 63 4-%"12.6ftftHydril 521 C-110 Li ner Halliburton Swell Packer # 4 (43/." Hydril 521) OD 5.85'- 9 meter long oil activated with Slide on 64 Volant Centralizer Pin End and 6ft Pup 41/2" 12.6#/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 16,748 6,213 Centralizer on Top of Swell Packer 65 4-h"12.6#/ftHydril 521 C-110 Li ner HLB 41/2" Rapid5tage Ball Actuated Sleeve (2.379 ball / 2.332 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 66 12.6# ft P-110 Hydril 521 Box Pin 17,078 6,211 67 4-h"126#/ftH driI S21 C-110 Liner Resman Internally Ve nted Card er If 1 JN# 24552-2-1 / ROS -1369-11 / RW S-1396-11 68 w/1Sft Pup BxP Top &Bottom 17,307 6,210 69 4-W' 12.6#/ft H driI S21 C-110 Liner Halliburton Swell Packer # 3 (4-W' Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 70 Volant Centralizer Pin End and 6ft Pup 41/2"12.64/ft P-110 Hydril 521 Box x Pin w/ Slide On Volant 17,407 6,210 Centralizer on Topof Swell Packer 71 4-'/."12.6#/ftHydril 521 C-110 Liner HLB 41/2" Rapid5tage Ball Actuated Sleeve (2.307 ball/ 2.261 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 72 12.6#/ft P-110 ff dn1521 Box Pin 17,737 6,209 73 4-%"12.6#ftHydril 521 C-110 Li ner Halliburton Swell Packer # 2 (4-X" Hydril 521) OD 5.85' - 9 meter long oil activated with Slide on 74 Volant Centralizer Pin End and 6ft Pup 4-1/2" 12.6#/ft P-110 Hydril 521 Bax x Pin w/ Slide On Volant 18,066 6, toe lCentralizeron'Top of Swell Packer 75 4-h"12.6#/ftH dri1521C-1101-iner HLB 41/2" Rapid5tage Ball Actuated Sleeve (2.236 ball/ 2.192 Seat) w/ 15ft 41/2" P-110 Pup 41/2" 76 12.6# ft P-110 H dn1521 Boxx Pin 18,396 6,206 77 4X"12.6#/ftHydril 521C-110 Liner Halliburton Swell Packer # 1(4Y" Hydril S21) OD 5.85' - 9 meter long oil activated with Slide on 78 Volant Centralizer Pin End and Eft Pup 41/2"12.6#/ft P-110 Hydri1521Boxx Pinw/Slide On Volant 18,725 6,18-1 Centralizer on Top of Swell Packer 79 4-X"12.6#/ft Hydril 5210-110 Liner 80Pre- erforated Pu w 4h" 12.6# ftH dril 521 w 15ft 41 2" P-110 Pu BZP To & Bottom 18,775 fi 180 814-W' 12.6#/ft Hydril 521 C-110 Liner 82 4-t" Fi dril 521 Eccsntic Slme with Double Finat Suh 19,825 6,175 Bottom of Assembly 18,830 6,175 60 64 68 70 74 78 82 -� ---- f-- 05a------- 9 ------ In--_ --40N-019-0-190-W-8 44 48 -1 52 -W 58 --271- 62 1r71- 66 -_--271 72 3671 76 80 ------ 6-1/8" Hole TD 4-1/2" Hydril 521 / C-110 Liner with Halliburton Ball Actuated @ 18,833- MD / Sleeves, & Swell Packers 6,174' TVD Caelus Energy Alaska Oooguruk Development Oooguruk Drill Site ODSN-01 - Slot ODS 1 ODSN-01A Plan: ODSN-01 A wpl 0 Standard Proposal Report 31 December, 2015 Sperry Drilling Services HALLIBURTON CE CAELUS Fns tqy Alaska Sperry Drilling Project: Oooguruk Development Site: Oooguruk Drill Site Well: ODSN-01 Wellbore: ODSN-01A Plan: ODSN-01A wp10 REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well ODSN-01 - Slot ODS 1, True North Vertical (TVD) Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Measured Depth Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Calculation Method: Minimum Curvature 600 DDI = 6.974 1200 1800 2400 C 3000 7 O 0 3600 to r 4200 io U 4800 a� 2 5400 6000 6600 COMPANY DETAILS: Caelus Enerbry Alaska Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Trav, Cylinder North Error Surface. Elliptical Conic Warning Method. Rules Based FORMATION TOP DETAILS TVDPath TVDssPath MDPath Formation 3248.26 3192.06 4121.36 Top Hue2 tied 3489.07 3432.87 4646.46 Hue Res C tied 3978.78 3922.58 5708.49 Hue Res B tied 4236.62 4180.42 6267.84 Hue Res A tied 4272.46 4216.26 6345.60 Brook 2B 5028.20 4972.00 7985.10 TEEC nuna top 5272.85 5216.65 8515.83 TEEC nuns base 5437.19 5380.99 8872.35 TorokShale-I tied 5843.28 5787.08 9753.32 TOP HRZ 5971.88 5915.68 10032.30 BASE HRZ 6047.74 5991.54 10198.27 KALUHIK_MKR 6113.97 6057.77 10365.16 KUPC 6132.11 6075.91 10417.89 LCU 6230.43 6174.23 10870.31 BCU 6260.62 6204.42 11214.40 NUIQSUT 6266.96 6210.76 11287.19 NUIQ 1 KOP TOW: 9.46°/100' : 4088' MD, 3233.09'TVD : 65° LT TF End Dir : 4108.08' MD, 3242.27' TVD Start Dir 3°/100' : 4158.08' MD, 3264.82'TVD End Dir : 4347.21' MD, 3351.13' TVD 0-- _"_ Start Dir 31/100' : 4847.21' MD, 3581.62'TVD ---____ To Hu e2 tied - - - - - End Dir : 5092.2' MD, 3694.7' TVD Sec MD Inc Azi TVD TVDSS +N/ -S +E/ -W 1 4088.00 62.39 315.27 3233.09 3176.89 1498.89 -1432.95 2 4108.08 63.20 313.33 3242.27 3186.07 1511.36 -1445.73 3 4158.08 63.20 313.33 3264.82 3208.62 1541.99 -1478.19 4 4347.21 62.55 307.00 3351.13 3294.93 1650.51 -1606.71 5 4847.21 62.55 307.00 3581.62 3525.42 1917.54 -1961.07 6 5092.20 62.55 315.28 3694.70 3638.50 2060.39 -2124.59 7 10145.63 62.55 315.28 6024.11 5967.91 5247.08 -5279.89 8 10898.13 85.00 312.78 6233.05 6176.85 5745.39 -5796.63 9 11198.13 85.00 312.78 6259.20 6203.00 5948.37 -6015.98 10 11473.13 85.00 312.78 6283.17 6226.97 6134.43 -6217.06 11 11643.13 90.10 312.78 6290.43 6234.23 6249.75 -6341.67 12 12193.13 90.10 312.78 6289.47 6233.27 6623.30 -0745.36 13 12209.80 90.60 312.78 6289.37 6233.17 6634.62 -6757.59 14 12609.80 90.60 312.78 6285.18 6228.98 6906.28 -7051.16 15 12636.47 91.40 312.78 6284.72 6228.52 6924.39 -7070.73 16 12936.47 91.40 312.78 6277.39 6221.19 7128.08 -7290.85 17 13294.36 91.40 323.52 6268.62 6212.42 7394.20 -7529.21 18 14594.36 91.40 323.52 6236.86 6180.66 8439.18 -8301.89 19 14607.69 91.00 323.52 6236.58 6180.38 8449.89 -8309.81 20 15607.69 91.00 323.52 6219.12 6162.92 9253.84 -8904.26 21 15631.02 90.30 323.52 6218.86 6162.66 9272.60 -8918.13 22 17231.02 90.30 323.52 6210.48 6154.28 10559.08 -9869.39 23 17234.36 90.20 323.52 6210.47 6154.27 10561.76 -9871.37 24 18389.36 90.20 323.52 6206.44 6150.24 11490.45 -10558.06 25 18549.36 95.00 323.52 6199.18 6142.98 11618.93 -10653.06 26 18833.00 95.00 323.52 6174.46 6118.26 11846.13 -10821.06 P I Hue Res C tied Start Dir 3°/100' : 10145.63' MD, 6024.117VD Hue Res B tied 1, 1 End Dir : 10898.13' MD, 6233.05' TVD Hue Res A tied Brook 2B 9 5/8" TEEC_nuna_top - - - - TEEC_nuna_base - - - - , Begin Geo -steering Tarok Shale 1 tied TOP HRZ --- --- - _ �� or BASE-HRZ " 7200 CASING DETAILS TVD TVDSS MD Size Name Version: 5013.20 4957.00 7952.55 9-5/8 9 5/8" Tool 6270.95 6214.75 11333.00 7 7" SRG-SS 6174.46 6118.26 18833.00 4-1/2 41/2" 7800 4088.00 4460.00 ODSN-01A wp10 KALUBIK MKR n o t.t✓�-4'' at of KUPC LCU BCU NUIQSUT DLeg TFace VSec Target 0.00 0.00 2073.11 9.46 -65.00 2090.94 0.00 0.00 2135.44 3.00 -97.97 2302.24 0.00 0.00 2738.39 3.00 91.90 2954.15 0.00 0.00 7435.05 3.00 -6.51 8151.46 0.00 0.00 8449.27 ODSN-01 HEEL v2 0.00 0.00 8722.26 3.00 0.00 8891.45 0.00 0.00 9439.51 3.00 0.00 9456.12 0.00 0.00 9854.69 3.00 0.00 9881.26 0.00 0.00 10180.11 3.00 89.87 10537.36 0.00 0.00 11830.01 3.00 180.00 11843.27 0.00 0.00 12837.77 3.00 180.00 12860.98 0.00 0.00 14452.39 3.00 180.00 14455.71 0.00 0.00 15604.52 3.00 0.00 15763.45 0.00 0.00 16044.50 WELL DETAILS: ODSN-01 Ground Level. 13.50 +N/ -S +E/ -W Northing Easung Latittude Longitude 0.00 0.00 6031151,32 469920.45 70.4961782222 -150.2459624120 Total Depth : 18833' MD, 6174.46' TVD 0 0 4 1/2" o) a) m i i i ODSN-01 KE3 PB1 r ODSN-01A wp10 i r ODSN-01 KE3 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 Vertical Section at 317.59° (1500 usft/in) SURVEY PROGRAM Date: 2015-12-31700:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 100.00 832.00 ODSN-1 KE3 Gyro SRG-SS 909.73 4088.00 ODSN-1 KE3 MWD MWD+IFR2+MS+sag 4088.00 4460.00 ODSN-01A wp10 MWD_Interp Azi+sag 4460.00 7952.00 ODSN-01A wp10 MWD+IFR2+MS+sag 7952.00 11333.00 ODSN-01A wp10 MWD+IFR2+MS+sag 11333.00 18833.00 ODSN-01A wp10 MWD+IFR2+MS+sag WELL DETAILS: ODSN-01 Ground Level. 13.50 +N/ -S +E/ -W Northing Easung Latittude Longitude 0.00 0.00 6031151,32 469920.45 70.4961782222 -150.2459624120 Total Depth : 18833' MD, 6174.46' TVD 0 0 4 1/2" o) a) m i i i ODSN-01 KE3 PB1 r ODSN-01A wp10 i r ODSN-01 KE3 1800 2400 3000 3600 4200 4800 5400 6000 6600 7200 7800 8400 9000 9600 10200 10800 11400 12000 12600 13200 13800 14400 15000 15600 16200 Vertical Section at 317.59° (1500 usft/in) r [� KE3 PBI _ 1 8800 SECTION DETAILS /� CE, LI M' \ ��C✓✓✓/ ��.V..JJ Sec MD Inc Azi TVD TVDSS +N/ -S +E/ -W DLeg TFace VSec Target �.LLL��� V 1 4088.00 62.39 315.27 3233.09 3176.89 1498.89 -1432.95 0.00 0.00 2073.11 EtlaJ."Alaska 2 4108.08 63.20 313.33 3242.27 3186.07 1511.36 -1445.73 9.46 -65.00 2090.94 w 3 4158.08 63.20 313.33 3264.82 3208.62 1541.99 -1478.19 0.00 0.00 2135.44 4 4347.21 62.55 307.00 3351.13 3294.93 1650.51 -1606.71 3.00 -97.97 2302.24 ��� 5 4847.21 62.55 307.00 3581.62 3525.42 1917.54 -1961.07 0.00 0.00 2738.39 6 5092.20 62.55 315.28 3694.70 3638.50 2060.39 -2124.59 3.00 91.90 2954.15 _. 7 10145.63 62.55 315.28 6024.11 5967.91 5247.08 -5279.89 0.00 0.00 7435.05 Sperry O.r;¢i;nq 8 10898.13 85.00 312.78 6233.05 6176.85 5745.39 -5796.63 3.00 -6.51 8151.46 9 11198.13 85.00 312.78 6259.20 6203.00 5948.37 -6015.98 0.00 0.00 8449.27 ODSN-01 HEEL v2 0 10 11473.13 85.00 312.78 6283.17 6226.97 6134.43 -6217.06 0.00 0.00 8722.26 11 11643.13 90.10 312.78 6290.43 6234.23 6249.75 -6341.67 3.00 0.00 8891.45 Project., Oooguruk Development 12 12193.13 90.10 312.78 6289.47 6233.27 6623.30 -6745.36 0.00 0.00 9439.51 Site: 13 12209.80 90.60 312.78 6289.37 6233.17 6634.62 -6757.59 3.00 0.00 9456.12 Oooguruk Drill Site 14 12609.80 90.60 312.78 6285.18 6228.98 6906.28 -7051.16 0.00 0.00 9854.69 Well: ODSN-01 15 12636.47 91.40 312.78 6284.72 6228.52 6924.39 -7070.73 3.00 0.00 9881.26 1 1 2936.47 9 .40 3 1 2.78 627739 6221.19 7128.08 -7290.85 0.0010180.11 Wellbore: ODSN-01A 17 13294 36 91.40 323.52 6268.62 6212.42 7394.20 -7529.21 3.00 89 807 10537.36 Plan: ODSN-01A wp10 18 19 14594.36 91.40 323.52 6236.86 6180.66 14607.69 91.00 323.52 6236.58 6180.38 8439.18 8449.89 -8301.89 -8309.81 0.00 3.00 0.00 180.00 11830.01 11843.27 20 15607.69 91.00 323.52 6219.12 6162.92 9253.84 -8904.26 0.00 0.00 12837.77 13600 21 15631.02 90.30 323.52 6218.86 6162.66 9272.60 -8918.13 3.00 180.00 12860.98 2400 22 17231.02 90.30 323.52 6210.48 6154.28 10559.08 -9869.39 0.00 0.00 14452.39 23 17234.36 90.20 323.52 6210.47 6154.27 10561.76 -9871.37 3.00 180.00 14455.71 Vertical (TVD) Reference: 42.7'+ 13.5'@ 56.20us@ (Nabors 19AC) 24 18389.36 90.20 323.52 6206.44 6150.24 11490.45 -10558.06 0.00 0.00 15604.52 25 18549.36 95.00 323.52 6199.18 6142.98 11618.93 -10653.06 3.00 0.00 15763.45 12800 26 18833.00 95.00 323.52 6174.46 6118.26 11846.13 -10821.06 0.00 0.00 16044.50 0DSN-01A vvp I0 6174 800 Ground Level: 13.50 ,ti°°° 800 +N/ -S +F/ -W Northing Easting Latittude Longitude COMPANY DETAILS: Caelus Enerbry Alaska 12000 ODSN-01 KE3 0.00 0.00 6031151.32 469920.45 70.4961782222 -150.2459624120 Calculation Method:. Minimum Curvature 4 1/2" 0 SURVEY PROGRAM Error System: Scan Method: ISCWSA Tray. Cylinder North 11200- Date: 2015-12-31TD0:00:00 Validated: Yes Version: Surface Elliptical -800 Depth From Depth To Survey/Plan Tool CASING DETAILS -800 Warning Method: RuleError ased 10400- \ \ X10400 9600 8800ODSN-01 KE3 PBI _ 8800 c rn 8000 8000 ti p s 0 0 7200 7200 + r 6400 6400 c 70 C 7- 0 s � 5600 -ho° 0 0 5600 � ODSN-Ol HEEL v2 o° 4800 5 4800 o° 50 4000 4000 o° 0.5 3200 9 5/8" � 3200 o° 0.O 2400 REFERENCE INFORMATION 2400 o0 Co-ordinate (N/E) Reference: Well ODSN-01 - Slot ODS 1, True North Vertical (TVD) Reference: 42.7'+ 13.5'@ 56.20us@ (Nabors 19AC) Measured Depth Reference: 42.7'+ 13.5'@ 56.20usH (Nabors 19AC) 1600 Calculation Method: Minimum Curvature 1600 WELL DETAILS: ODSN-01 800 Ground Level: 13.50 ,ti°°° 800 +N/ -S +F/ -W Northing Easting Latittude Longitude 0.00 0.00 6031151.32 469920.45 70.4961782222 -150.2459624120 0 0 SURVEY PROGRAM Date: 2015-12-31TD0:00:00 Validated: Yes Version: -800 Depth From Depth To Survey/Plan Tool CASING DETAILS -800 100.00 832.00 ODSN-1 KE3 Gyro SRG-SS 909.73 4088.00 ODSN-1 KE3 MWD MWD+IFR2+MS+sag TVD TVDSS MD Size Name 4088.00 4460.00 ODSN-01A wp10 MWD Interp Azi+sag 5013.20 4957.00 7952.55 9-5/8 9 5/8" -1600 4460.00 7952.00 ODSN-01A wp10 MWD+IFR2+MS+sag 6270.95 6214.75 11333.00 7 7° -1600 7952.00 11333.00 ODSN-01A wp10 MWD+IFR2+MS+sag 6174.46 6118.26 18833.00 4-1/2 4 1/2" 11333.00 18833.00 ODSN-01Awp10 MWD+IFR2+MS+sag -12000 -11200 -10400 -9600 -8800 -8000 -7200 -6400 -5600 -4800 11000 -3200 -2400 -1600 -800 0 800 West( -)/East(+) (2000 usft/in) Database: EDMPrd Company: Caelus Energy Alaska Project: Oooguruk Development Site: Oooguruk Drill Site Well: ODSN-01 Wellbore: O DS N-01 A Design: ODSN-01A wp10 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well ODSN-01 - Slot ODS 1 42.7' + 13.5'@ 56.20usft (Nabors 19AC) 42.7'+ 13.5' @ 56.20usft (Nabors 19AC) True Minimum Curvature Project Oooguruk Development Map System: US State Plane 1927 (Exact solution) System Datum: Mean Sea Level Geo Datum: NAD 1927 (NADCON CONUS) Using Well Reference Point Map Zone: Alaska Zone 04 Using geodetic scale factor Site Oooguruk Drill Site Site Position: Northing: 6,031,151.32 usft Latitude: 70.4961782222 From: Map Easting: 469,920.45 usft Longitude: -150.2459624120 j Position Uncertainty: 0.00 usft Slot Radius: 13-3/16" Grid Convergence: -0.23 ° Well [Well 0DSN-01 - Slot ODS 1 Position +Nl-S 0.00 usft Northing: 6,031,151.32 usft Latitude. 70.4961782222 Position Uncertainty +E/ -W 0.00 usft 0.00 usft Easting: Wellhead Elevation: 469,920.45 usft Longitude: usft Ground Level: -150.2459624120 13.50 usft Wellbore ODSN-01A - -- ---- I Magnetics Model Name Sample Date Declination Dip Angle I Field Strength (°1 (°1 (nT) IGRF2010 7/17/2015 19.27 81.01 57,702 Design ODSN-01Awp10 Audit Notes: Version: Phase: PLAN Tie On Depth I Vertical Section: Depth From (TVD) +N/ -S +E/ -W (usft) (usft) (usft) 42.70 0.00 0.00 4,088.00 Direction (°) 317.59 12/31/2015 12:29:55PM Page 2 COMPASS 5000.1 Build 58 14,11AU,J St PJ PTEl, FN' Halliburton Standard Proposal Report Database: EDMPrd Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Company: Caelus Energy Alaska TVD Reference: 42.7' + 13.5' @ 56.20usft (Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-01 Survey Calculation Method: Minimum Curvature Wellbore: ODSN-01A Design: ODSN-01A wp10 Plan Sections - -- -- - ---- --- - ---- -- - ---- .. - - -- - - - - -- Measured Vertical TVD Dogleg Build Turn Depth Inclination Azimuth Depth System +N/ -S +E/ -W Rate Rate Rate Tool Face (usft) (°) (°) (usft) usft (usft) (usft) (°/100usft) (°/100usft) (°/100usft) 4,088.00 62.39 315.27 3,233.09 3,176.89 1,498.89 -1,432.95 0.00 0.00 0.00 0.00 4,108.08 63.20 313.33 3,242.27 3,186.07 1,511.36 -1,445.73 9.46 4.00 -9.61 -65.00 4,158.08 63.20 313.33 3,264.82 3,208.62 1,541.99 -1,478.19 0.00 0.00 0.00 0.00 4,347.21 62.55 307.00 3,351.13 3,294.93 1,650.51 -1,606.71 3.00 -0.34 -3.35 -97.97 4,847.21 62.55 307.00 3,581.62 3,525.42 1,917.54 -1,961.07 0.00 0.00 0.00 0.00 5,092.20 62.55 315.28 3,694.70 3,638.50 2,060.39 -2,124.59 3.00 0.00 3.38 91.90 10,145.63 62.55 315.28 6,024.11 5,967.91 5,247.08 -5,279.89 0.00 0.00 0.00 0.00 10,898.13 85.00 312.78 6,233.05 6,176.85 5,745.39 -5,796.63 3.00 2.98 -0.33 -6.51 11,198.13 85.00 312.78 6,259.20 6,203.00 5,948.37 -6,015.98 0.00 0.00 0.00 0.00 11,473.13 85.00 312.78 6,283.17 6,226.97 6,134.43 -6,217.06 0.00 0.00 0.00 0.00 11,643.13 90.10 312.78 6,290.43 6,234.23 6,249.75 -6,341.67 3.00 3.00 0.00 0.00 12,193.13 90.10 312.78 6,289.47 6,233.27 6,623.30 -6,745.36 0.00 0.00 0.00 0.00 12,209.80 90.60 312.78 6,289.37 6,233.17 6,634.62 -6,757.59 3.00 3.00 0.00 0.00 12,609.80 90.60 312.78 6,285.18 6.22898 6,906.28 -7,051.16 0.00 0.00 0,00 0.00 12,636.47 91.40 312.78 6,284.72 6.228.52 6,924.39 -7,070.73 3.00 3.00 0.00 0.00 12,936.47 91.40 312.78 6,277.39 6,221.19 7,128.08 -7,290.85 0.00 0.00 0.00 0.00 13,294.36 91.40 323.52 6,268.62 6212.42 7,394.20 -7,529.21 3.00 0.00 3.00 89.87 14,594.36 91.40 323.52 6,236.86 6,180.66 8,439.18 -8,301.89 0.00 0.00 0.00 0.00 14,607.69 91.00 323.52 6,236.58 6,180.38 8,449.89 -8,309.81 3.00 -3.00 0.00 180.00 15,607.69 91.00 323.52 6,219.12 6,162.82 9,253.84 -8,904.26 0.00 0.00 0.00 0.00 15,631.02 90.30 323.52 6,218.86 6,162.66 9,272.60 -8,918.13 3.00 -3.00 0.00 180.00 17,231.02 90.30 323.52 6,210.48 6,154.28 10,559.08 -9,869.39 0.00 0.00 0.00 0.00 17,234.36 90.20 323.52 6,210.47 6,154.27 10,561.76 -9,871.37 3.00 -3.00 0.00 180.00 18,389.36 90.20 323.52 6,206.44 6,150.24 11,490.45 -10,558.06 0.00 0.00 0.00 0.00 18,549.36 95.00 323.52 6,199.18 6,142.98 11,618.93 -10,653.06 3.00 3.00 0.00 0.00 18,833.00 95.00 323.52 6,174.46 6,118.26 11,846.13 -10,821.06 0.00 0.00 0.00 0.00 12/31/2015 12.29:55PM Page 3 COMPASS 5000.1 Build 58 Halliburton 1,, „ F 11 F71,T(1,3 Standard Proposal Report Planned Survey Measured Vertical Database: EDMPrd Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Company: Caelus Energy Alaska TVD Reference: 42.7'+ 13.5' @ 56.20usft (Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+ 13.5' @ 56.20usft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-01 Survey Calculation Method: Minimum Curvature Wellbore: ODS N-01 A (usft) (usft) Design: ODSN-01A wp10 4,088.00 Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS Vert Section (usft) (1) (1) (usft) usft (usft) (usft) (usft) (usft) 3.176.89 4,088.00 62.39 315.27 3,233.09 3,176.89 1,498.89 -1,432.95 6,032,655.85 468,493.72 0.00 2,073.11 KOP TOW: 9.46°1100' : 4088' MD, 3233.09'TVD : 65° LT TF 4,100.00 62.87 314.11 3,238.61 3,182.41 1,506.39 -1,440.52 6,032,663.37 468,486.18 9.46 2,083.75 4,108.08 63.20 313.33 3,242.27 3,186.07 1,511.36 -1,445.73 6,032,668.37 468,480.99 9.46 2,090.94 End Dir : 4108.08' MD, 3242.27' TVD 4,121.36 63.20 313.33 3,248.26 3,192.06 1,519.50 -1,454.35 6,032,676.54 468,472.41 0.00 2,102.76 Top Hue2 tied 4,158.08 63.20 313.33 3,264.82 3,208.62 1,541.99 -1,478.19 6,032,699.12 468,448.66 0.00 2,135.44 Start Dir 3°/100' : 4158.08' MD, 3264.82'TVD 4,200.00 63.03 311.94 3,283.78 3,227.58 1,567.31 -1,505.69 6,032,724.56 468,421.26 3.00 2,172.69 4,300.00 62.68 308.59 3,329.41 3,273.21 1,624.82 -1,573.58 6,032,782.33 468,353.61 3.00 2,260.93 4,347.21 62.55 307.00 3,351.13 3,294.93 1,650.50 -1,606.70 6,032,808.15 468,320.60 3.00 2,302.24 End Dir : 4347.21' MD, 3351.13' TVD 4,400.00 62.55 307.00 3,375.46 3,319.26 1,678.70 -1,644.12 6,032,836.49 468,283.30 0.00 2,348.29 4,500.00 62.55 307.00 3,421.56 3,365.36 1,732.10 -1,714.99 6,032,890.18 468,212.65 0.00 2,435.52 4,600.00 62.55 307.00 3,467.66 3,411.46 1,785.51 -1,785.86 6,032,943.86 468,142.00 0.00 2,522.75 4,646.46 62.55 307.00 3,489.07. 3,432.87 1,810.32 -1,818.79 6,032,968.81 468,109.18 0.00 2,563.28 Hue Res C tied 4,700.00 62.55 307.00 3,513.75 3,457.55 1,838.91 -1,856.73 6,032,997.55 468,071.36 0.00 2,609.98 4,800.00 62.55 307.00 3,559.85 3,503.65 1,892.32 -1,927.61 6,033,051.24 468,000.71 0.00 2,697.21 4,847.21 62.55 307.00 3,581.61 3,525.41 1,917.53 -1,961.06 6,033,076.58 467,967.36 0.00 2,738.39 Start Dir 31/100': 4847.21' MD, 3581.62'TVD 4,900.00 62.51 308.78 3,605.97 3,549.77 1,946.30 -1,998.02 6,033,105.49 467,930.51 3.00 2,784.56 5,000.00 62.49 312.17 3,652.15 3,595.95 2,003.86 -2,065.48 6,033,163.33 467,863.29 3.00 2,872.56 5,092.20 62.55 315.28 3,694.70 3,638.50 2,060.39 -2,124.59 6,033,220.09 467,804.43 3.00 2,954.15 End Dir : 5092.2' MD, 3694.7' TVD 5,100.00 62.55 315.28 3,698.30 3,642.10 2,065.31 -2,129.46 6,033,225.03 467,799.58 0.00 2,961.07 5,200.00 62.55 315.28 3,744.39 3,688.19 2,128.37 -2,191.90 6,033,288.33 467,737.40 0.00 3,049.74 5,300.00 62.55 315.28 3,790.49 3,734.29 2,191.43 -2,254.34 6,033,351.64 467,675.22 0.00 3,138.41 5,400.00 62.55 315.28 3,836.58 3,780.38 2,254.49 -2,316.77 6,033,414.95 467,613.05 0.00 3,227.08 5,500.00 62.55 315.28 3,882.68 3,826.48 2,317.55 -2,379.21 6,033,478.25 467,550.87 0.00 3,315.75 5,600.00 62.55 315.28 3,928.78 3,872.58 2,380.61 -2,441.65 6,033,541.56 467,488.69 0.00 3,404.42 5,700.00 62.55 315.28 3,974.87 3,918.67 2,443.67 -2,504.09 6,033,604.86 467,426.51 0.00 3,493.09 5,708.49 62.55 315.28 3,978.78 3,922.58 2,449.03 -2,509.39 6,033,610.24 467,421.24 0.00 3,500.62 Hue Res B tied 5,800.00 62.55 315.28 4,020.97 3,964.77 2,506.73 -2,566.53 6,033,668.17 467,364.34 0.00 3,581.76 5,900.00 62.55 315.28 4,067.06 4,010.86 2,569.79 -2,628.97 6,033,731.47 467,302.16 0.00 3,670.43 6,000.00 62.55 315.28 4,113.16 4,056.96 2,632.85 -2,691.41 6,033,794.78 467,239.98 0.00 3,759.10 6,100.00 62.55 315.28 4,159.25 4,103.05 2,695.91 -2,753.85 6,033,858.09 467,177.81 0.00 3,847.77 6,200.00 62.55 315.28 4,205.35 4,149.15 2,758.97 -2,816.29 6,033,921.39 467,115.63 0.00 3,936.44 6,267.84 62.55 315.28 4,236.62 4,180.42 2,801.75 -2,858.64 6,033,964.34 467,073.45 0.00 3,996.60 Hue Res A tied 6,300.00 62.55 315.28 4,251.45 4,195.25 2,822.03 -2,878.73 6,033,984.70 467,053.45 0.00 4,025.12 6,345.60 62.55 315.28 4,272.46 4,216.26 2,850.79 -2,907.20 6,034,013.57 467,025.10 0.00 4,065.55 Brook 2B 12/31/2015 12:29:55PM Page 4 COMPASS 5000.1 Build 58 .."I , ..a Database: Company: Project: Site: Well: Wellbore: Design: Planned Survey Measured Depth Inclination (usft) (°) 6,400.00 62.5 6,500.00 62.5 6,600.00 62.5 6,700.00 62.5 6,800.00 62.5 6,900.00 62.5 7,000.00 62.55 7,100.00 62.55 7,200.00 62.55 7,300.00 62.55 7,400.00 62.55 7,500.00 62.55 7,600.00 62.55 7,700.00 62.55 7,800.00 62.55 7,900.00 62.55 7,952.55 62.55 9 518" 7,985.10 62.55 TEEC_nuna_top 8,000.00 62.55 8,100.00 62.55 8,200.00 62.55 8,300.00 62.55 8,400.00 62.55 8,500.00 62.55 8,515.83 62.55 TEEC_nuna base 8,600.00 62.55 8,700.00 62.55 8,800.00 62.55 8,872.35 62.55 Torok Shale 1 tied 8,900.00 62.55 9,000.00 62.55 9,100.00 62.55 9,200.00 62.55 9,300.00 62.55 9,400.00 62.55 9,500.00 62.55 9,600.00 62.55 9,700.00 62.55 9,753.32 62.55 TOP_HRZ 9,800.00 62.55 EDMPrd Caelus Energy Alaska Oooguruk Development Oooguruk Drill Site ODSN-01 ODSN-01A ODSN-01 A wp10 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well ODSN-01 - Slot ODS 1 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) 42.7' + 13.5' @ 56.20usft (Nabors 19AC) True Minimum Curvature 5 5 5 5 5 5 Vertical 4,972.00 3,884.66 -3,930.88 Map Map 0.00 Azimuth Depth TVDss +N/ -S +E/ -W Northing Easting DLS C) (usft) usft (usft) (usft) (usft) (usft) 4,241.34 315.28 4,297.54 4,241.34 2,885.09 -2,941.16 6,034,048.00 466,991.27 0.00 315.28 4,343.64 4,287.44 2,948.15 -3,003.60 6,034,111.31 466,929.10 0.00 315.28 4,389.73 4,333.53 3,011.21 -3,066.04 6,034,174.62 466,866.92 0.00 315.28 4,435.83 4,379.63 3,074.27 -3,128.48 6,034,237.92 466,804.74 0.00 315.28 4,481.92 4,425.72 3,137.33 -3,190.92 6,034,301.23 466,742.57 0.00 315.28 4,528.02 4,471.82 3,200.39 -3,253.36 6,034,364.53 466,680.39 0.00 315.28 4,574.12 4,517.92 3,263.45 -3,315.80 6,034,427.84 466,618.21 0.00 315.28 4,620.21 4,564.01 3,326.51 -3,378.24 6,034,491.15 466,556.04 0.00 315.28 4,666.31 4,610.11 3,389.57 -3,440.68 6,034,554.45 466,493.86 0.00 315.28 4,712.40 4,656.20 3,452.63 -3,503.11 6,034,617.76 466,431.68 0.00 315.28 4,758.50 4,702.30 3,515.69 -3,565.55 6,034,681.06 466,369.50 0.00 315.28 4,804.59 4,748.39 3,578.75 -3,627.99 6,034,744.37 466,307.33 0.00 315.28 4,850.69 4,794.49 3,641.81 -3,690.43 6,034,807.67 466,245.15 0.00 315.28 4,896.79 4,840.59 3,704.87 -3,752.87 6,034,870.98 466,182.97 0.00 315.28 4,942.88 4,886.68 3,767.93 -3,815.31 6,034,934.29 466,120.80 0.00 315.28 4,988.98 4,932.78 3,830.99 -3,877.75 6,034,997.59 466,058.62 0.00 315.28 5,013.20 4,957.00 3,864.13 -3,910.56 6,035,030.86 466,025.94 0.00 Vert Section 4,113.79 4,202.46 4,291.13 4,379.80 4,468.47 4,557.14 4,645.81 4,734.48 4,823.15 4,911.82 5,000.49 5,089.16 5,177.83 5,266.50 5,355.17 5,443.84 5,490.44 315.28 5,028.20 4,972.00 3,884.66 -3,930.88 6,035,051.47 466,005.71 0.00 5,519.30 315.28 5,035.07 4,978.87 3,894.05 -3,940.19 6,035,060.90 465,996.44 0.00 5,532.51 315.28 5,081.17 5,024.97 3,957.11 -4,002.63 6,035,124.20 465,934.26 0.00 5,621.18 315.28 5,127.26 5,071.06 4,020.17 -4,065.07 6,035,187.51 465,872.09 0.00 5,709.85 315.28 5,173.36 5,117.16 4,083.23 -4,127.50 6,035,250.82 465,809.91 0.00 5,798.52 315.28 5,219.46 5,163.26 4,146.29 -4,189.94 6,035,314.12 465,747.73 0.00 5,887.19 315.28 5,265.55 5,209.35 4,209.35 -4,252.38 6,035,377.43 465,685.56 0.00 5,975.86 315.28 5,272.85 5,216.65 4,219.33 -4,262.27 6,035,387.45 465,675.71 0.00 5,989.90 315.28 5,311.65 5,255.45 4,272.41 -4,314.82 6,035,440.73 465,623.38 0.00 6,064.53 315.28 5,357.74 5,301.54 4,335.47 -4,377.26 6,035,504.04 465,561.20 0.00 6,153.20 315.28 5,403.84 5,347.64 4,398.53 -4,439.70 6,035,567.34 465,499.02 0.00 6,241.87 315.28 5,437.19 5,380.99 4,444.16 -4,484.87 6,035,613.15 465,454.04 0.00 6,306.03 315.28 5,449.93 5,393.73 4,461.59 -4,502.14 6,035,630.65 465,436.85 0.00 6,330.54 315.28 5,496.03 5,439.83 4,524.65 -4,564.58 6,035,693.96 465,374.67 0.00 6,419.21 315.28 5,542.13 5,485.93 4,587.71 -4,627.02 6,035,757.26 465,312.49 0.00 6,507.88 315.28 5,588.22 5,532.02 4,650.77 -4,689.45 6,035,820.57 465,250.32 0.00 6,596.56 315.28 5,634.32 5,578.12 4,713.83 -4,751.89 6,035,883.87 465,188.14 0.00 6,685.23 315.28 5,680.41 5,624.21 4,776.89 -4,814.33 6,035,947.18 465,125.96 0.00 6,773.90 315.28 5,726.51 5,670.31 4,839.95 -4,876.77 6,036,010.49 465,063.78 0.00 6,862.57 315.28 5,772.60 5,716.40 4,903.01 -4,939.21 6,036,073.79 465,001.61 0.00 6,951.24 315.28 5,818.70 5,762.50 4,966.07 -5,001.65 6,036,137.10 464,939.43 0.00 7,039.91 315.28 5,843.28 5,787.08 4,999.70 -5,034.94 6,036,170.85 464,906.28 0.00 7,087.19 315.28 5,864.80 5,808.60 5,029.13 -5,064.09 6,036,200.40 464,877.25 0.00 7,128.58 12/31/2015 12:29:55PM Page 5 COMPASS 5000.1 Build 58 Halliburton Standard Proposal Report Database: EDMPrd Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Company: Caelus Energy Alaska TVD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-01 Survey Calculation Method: Minimum Curvature Wellbore: ODSN-01A Northing Easting DLS Design: ODSN-01A wp10 (usft) 5,854.69 6,036,263.71 Planned Survey 0.00 7,217.25 6,036,327.02 464,752.90 0.00 7,305.92 Measured 464,732.82 0.00 Vertical 6,036,390.32 464,690.72 0.00 Depth Inclination Azimuth Depth TVDss +N/ -S +E/ -W (usft) (1) (1) (usft) usft (usft) (usft) 9,900.00 62.55 315.28 5,910.89 5,854.69 5,092.19 -5,126.53 10,000.00 62.55 315.28 5,956.99 5,900.79 5,155.25 -5,188.97 10,032.30 62.55 315.28 5,971.88 5,915.68 5,175.62 -5,209.13 BASE_HRZ 7,858.52 6,036,785.01 464,290.38 3.00 7,955.93 10,100.00 62.55 315.28 6,003.08 5,946.88 5,218.31 -5,251.41 10,145.63 62.55 315.28 6,024.12 5,967.92 5,247.09 -5,279.90 Start Dir 311100': 10145.63' MD, 6024.11'TVD 8,153.32 6,036,988.76 464,073.49 10,198.27 64.12 315.08 6,047.74 5,991.54 5,280.46 -5,313.05 KALUBIK MKR 0.00 8,449.27 6,037,124.66 463,927.82 0.00 10,200.00 64.17 315.08 6,048.49 5,992.29 5,281.56 -5,314.15 10,300.00 67.15 314.71 6,089.70 6,033.50 5,345.86 -5,378.69 10,365.16 69.10 314.49 6,113.97 6,057.77 5,388.31 -5,421.74 KUPC 463,728.88 0.00 8,722.26 6,037,328.52 463,709.30 3.00 10,400.00 70.14 314.37 6,126.11 6,069.91 5,411.17 -5,445.07 10,417.89 70.67 314.31 6,132.11 6,075.91 5,422.95 -5,457.12 LCU 0.00 9,047.76 6,037,601.26 463,416.94 0.00 9,147.41 10,500.00 73.12 314.03 6,157.62 6,101.42 5,477.33 -5,513.10 10,600.00 76.10 313.71 6,184.16 6,127.96 5,544.13 -5,582.60 10,700.00 79.09 313.39 6,205.64 6,149.44 5,611.41 -5,653.38 10,800.00 82.07 313.08 6,222.01 6,165.81 5,678.98 -5,725.24 10,870.31 84.17 312.86 6,230.43 6,174.23 5,726.56 -5,776.32 BCU 10,898.13 85.00 312.78 6,233.05 6,176.85 5,745.38 -5,796.63 End Dir : 10898.13' MD, 6233.05' TVD 10,900.00 85.00 312.78 6,233.22 6,177.02 5,746.65 -5,798.00 11,000.00 85.00 312.78 6,241.93 6,185.73 5,814.31 -5,871.11 11,100.00 85.00 312.78 6,250.65 6,194.45 5,881.97 -5,944.23 11,198.13 85.00 312.78 6,259.20 6,203.00 5,948.37 -6,015.98 11,200.00 85.00 312.78 6,259.36 6,203.16 5,949.63 -6,017.35 11,214.40 85.00 312.78 6,260.62 6,204.42 5,959.37 -6,027.88 NUIQSUT 11,287.19 85.00 312.78 6,266.96 6,210.76 6,008.62 -6,081.10 NUIQ_i 11,300.00 85.00 312.78 6,268.08 6,211.88 6,017.29 -6,090.47 11,333.00 85.00 312.78 6,270.95 6,214.75 6,039.62 -6,114.59 Begin Geo -steering .7" 11,400.00 85.00 312.78 6,276.79 6,220.59 6,084.95 -6,163.58 11,473.13 85.00 312.78 6,283.17 6,226.97 6,134.43 -6,217.06 11,500.00 85.81 312.78 6,285.32 6,229.12 6,152.62 -6,236.71 11,600.00 88.81 312.78 6,290.02 6,233.82 6,220.46 -6,310.02 11,643.13 90.10 312.78 6,290.43 6,234.23 6,249.75 -6,341.67 11,700.00 90.10 312.78 6,290.33 6,234.13 6,288.37 -6,383.41 11,800.00 90.10 312.78 6,290.16 6,233.96 6,356.29 -6,456.81 11,900.00 90.10 312.78 6,289.98 6,233.78 6,424.21 -6,530.21 12,000.00 90.10 312.78 6,289.81 6,233.61 6,492.13 -6,603.60 Map Map Northing Easting DLS Vert Section (usft) (usft) 5,854.69 6,036,263.71 464,815.08 0.00 7,217.25 6,036,327.02 464,752.90 0.00 7,305.92 6,036,347.46 464,732.82 0.00 7,334.56 6,036,390.32 464,690.72 0.00 7,394.59 6,036,419.21 464,662.35 0.00 7,435.05 6,036,452.71 464,629.33 3.00 7,482.05 6,036,453.81 464,628.24 3.00 7,483.60 6,036,518.37 464,563.97 3.00 7,574.60 6,036,560.99 464,521.09 3.00 7,634.99 6,036,583.95 464,497.86 3.00 7,667.60 6,036,595.77 464,485.86 3.00 7,684.42 6,036,650.37 464,430.11 3.00 7,762.32 6,036,717.45 464,360.88 3.00 7,858.52 6,036,785.01 464,290.38 3.00 7,955.93 6,036,852.86 464,218.80 3.00 8,054.29 6,036,900.64 464,167.92 3.00 8,123.86 6,036,919.54 464,147.69 3.00 8,151.46 6,036,920.81 464,146.33 0.00 8,153.32 6,036,988.76 464,073.49 0.00 8,252.59 6,037,056.71 464,000.66 0.00 8,351.85 6,037,123.39 463,929.18 0.00 8,449.27 6,037,124.66 463,927.82 0.00 8,451.12 6,037,134.44 463,917.33 0.00 8,465.42 6,037,183.90 463,864.31 0.00 8,537.68 6,037,192.61 463,854.98 0.00 8,550.39 6,037,215.03 463,830.95 0.00 8,583.15 6,037,260.56 463,782.15 0.00 8,649.66 6,037,310.25 463,728.88 0.00 8,722.26 6,037,328.52 463,709.30 3.00 8,748.94 6,037,396.64 463,636.28 3.00 8,848.47 6,037,426.06 463,604.74 3.00 8,891.45 6,037,464.85 463,563.16 0.00 8,948.12 6,037,533.06 463,490.05 0.00 9,047.76 6,037,601.26 463,416.94 0.00 9,147.41 6,037,669.47 463,343.82 0.00 9,247.06 12131/2015 12:29:55PM Page 6 COMPASS 5000.1 Build 58 ALI IFE., k. J R T Halliburton Standard Proposal Report Database: EDMPrd Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Company: Caelus Energy Alaska TVD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Project: Oooguruk Development MD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Site: Oooguruk Drill Site North Reference: True Well: ODSN-01 Survey Calculation Method: Minimum Curvature Wellbore: ODSN-01A Design: ODSN-01Awp10 [Planned Survey Measured Vertical Map Map Depth Inclination Azimuth Depth TVDss +N/ -S +El -W Northing Easting DLS Vert Section (usft) (usft) usft (usft) (usft) (usft) (usft) 6,233.44 12,100.00 90.10 312.78 6,289.64 6,233.44 6,560.05 -6,677.00 6,037,737.68 463,270.71 0.00 9,346.71 12,193.13 90.10 312.78 6,289.47 6,233.27 6,623.30 -6,745.36 6,037,801.20 463,202.62 0.00 9,439.51 12,200.00 90.31 312.78 6,289.45 6,233.25 6,627.96 -6,750.40 6,037,805.89 463,197.59 3.00 9,446.35 12,209.80 90.60 312.78 6,289.37 6,233.17 6,634.62 -6,757.59 6,037,812.57 463,190.43 3.00 9,456.12 12,300.00 90.60 312.78 6,288.43 6,232.23 6,695.88 -6,823.79 6,037,874.09 463,124.48 0.00 9,546.00 12,400.00 90.60 312.78 6,287.38 6,231.18 6,763.79 -6,897.18 6,037,942.30 463,051.37 0.00 9,645.64 12,500.00 90.60 312.78 6,286.33 6,230.13 6,831.71 -6,970.58 6,038,010.50 462,978.26 0.00 9,745.28 12,600.00 90.60 312.78 6,285.28 6,229.08 6,899.62 -7,043.97 6,038,078.71 462,905.15 0.00 9,844.92 12,609.80 90.60 312.78 6,285.18 6,228.98 6,906.28 -7,051.16 6,038,085.39 462,897.99 0.00 9,854.69 12,636.47 91.40 312.78 6,284.72 6,228.52 6,924.39 -7,070.73 6,038,103.57 462,878.50 3.00 9,881.26 12,700.00 91.40 312.78 6,283.16 6,226.96 6,967.53 -7,117.35 6,038,146.90 462,832.06 0.00 9,944.55 12,800.00 91.40 312.78 6,280.72 6,224.52 7,035.42 -7,190.72 6,038,215.09 462,758.97 0.00 10,044.17 12,900.00 91.40 312.78 6,278.28 6,222.08 7,103.32 -7,264.10 6,038,283.27 462,685.87 0.00 10,143.78 12,936.47 91.40 312.78 6,277.39 6,221.19 7,128.08 -7,290.85 6,038,308.14 462,659.22 0.00 10,180.11 13,000.00 91.40 314.69 6,275.83 6,219.63 7,171.99 -7,336.75 6,038,352.23 462,613.51 3.00 10,243.48 13,100.00 91.41 317.69 6.273.38 6,217.18 7,244.12 -7,405.95 6,038,424.63 462,544.61 3.00 10,343.41 13,200.00 91.40 320.69 6,270.93 6,214.73 7,319.77 -7,471.28 6,038,500.54 462,479.59 3.00 10,443.33 13,294.36 91.40 323.52 6,268.62 6,212.42 7,394.20 -7,529.21 6,038,575.20 462,421.96 3.00 10,537.36 13,300.00 91.40 323.52 6,268.48 6,212.28 7,398.74 -7,532.57 6,038,579.74 462,418.63 0.00 10,542.97 13,400.00 91.40 323.52 6,266.04 6,209.84 7,479.12 -7,592.00 6,038,660.36 462,359.52 0.00 10,642.40 13,500.00 91.40 32152 6,263.59 6,207.39 7,559.50 -7,651.44 6,038,740.97 462,300.42 0.00 10,741.84 13,600.00 91.40 323.52 6,261.15 6,204.95 7,639.89 -7,710.87 6,038,821.59 462,241.31 0.00 10,841.27 13,700.00 91.40 323.52 6,258.71 6,202.51 7,720.27 -7,770.31 6,038,902.20 462,182.21 0.00 10,940.71 13,800.00 91.40 323.52 6,256.26 6,200.06 7,800.65 -7,829.75 6,038,982.82 462,123.10 0.00 11,040.14 13,900.00 91.40 323.52 6,253.82 6,197.62 7,881.03 -7,889.18 6,039,063.43 462,064.00 0.00 11,139.58 14,000.00 91.40 323.52 6,251.38 6,195.18 7,961.42 -7,948.62 6,039,144.04 462,004.89 0.00 11,239.01 14,100.00 91.40 323.52 6,248.93 6,192.73 8,041.80 -8,008.06 6,039,224.66 461,945.79 0.00 11,338.45 14,200.00 91.40 323.52 6,246.49 6,190.29 8,122.18 -8,067.49 6,039,305.27 461.886.68 0.00 11,437.88 14,300.00 91.40 323.52 6,244.05 6,187.85 8,202.56 -8,126.93 6,039,385.89 461,827.58 0.00 11,537.32 14,400.00 91.40 323.52 6,241.60 6,185.40 8,282.95 -8,186.37 6,039,466.50 461,768.48 0.00 11,636.75 14,500.00 91.40 323.52 6,239.16 6,182.96 8,363.33 -8,245.80 6,039,547.12 461,709.37 0.00 11,736.19 14,594.36 91.40 323.52 6,236.86 6,180.66 8,439.18 -8,301.89 6,039,623.18 461,653.60 0.00 11,830.01 14,600.00 91.23 323.52 6,236,73 6,180.53 8,443.71 -8,305.24 6,039,627.73 461,650.27 3.00 11,835.62 14,607.69 91.00 323.52 6,236.58 6,180.38 8,449.89 -8,309.81 6,039,633.93 461,645.72 3.00 11,843.27 14,700.00 91.00 323.52 6,234,97 6,178.77 8,524.11 -8,364.68 6,039,708.36 461,591.15 0.00 11,935.07 14,800.00 91.00 323.52 6,233.22 6,177.02 8,604.50 -8,424.13 6,039,788.98 461,532.04 0.00 12,034.52 14,900.00 91.00 323.52 6,231.47 6,175.27 8,684.89 -8,483.57 6,039,869.61 461,472.93 0.00 12,133.97 15,000.00 91.00 323.52 6,229.73 6,173.53 8,765.29 -8,543.02 6,039,950.24 461,413.81 0.00 12,233.42 15,100.00 91.00 323.52 6,227.98 6,171.78 8,845.68 -8,602.47 6,040,030.86 461,354.70 0.00 12,332.87 15,200.00 91.00 323.52 6,226.24 6,170.04 8,926.08 -8,661.91 6,040,111.49 461,295.58 0.00 12,432.32 15,300.00 91.00 323.52 6,224.49 6,168.29 9,006.47 -8,721.36 6,040,192.11 461,236.47 0.00 12,531.77 15,400.00 91.00 323.52 6,222.75 6,166.55 9,086.86 -8,780.80 6,040,272.74 461,177.36 0.00 12,631.22 15,500.00 91.00 323.52 6,221.00 6,164.80 9,167.26 -8,840.25 6,040,353.37 461,118.24 0.00 12,730.67 15,600.00 91.00 323.52 6,219.26 6,163.06 9,247.65 -8,899.69 6,040,433.99 461,059.13 0.00 12,830.12 1 15,607.69 91.00 323.52 6,21912 6,162.92 9,253.84 -8,904.26 6,040,440.19 461,054.58 0.00 12,837.77 1213112015 12:29:55PM Page 7 COMPASS 5000.1 Build 58 Database: EDMPrd Map Map Company: Caelus Energy Alaska +Nl-S +E/ -W Project: Oooguruk Development Vert Section Site: Oooguruk Drill Site (usft) (usft) Well: ODSN-01 6,162.66 9,272.60 -8,918.13 Wellbore: ODSN-01A 3.00 12,860.98 6,162.30 Design: ODSN-01A wp10 461,000.01 0.00 Planned Survey 6,161.77 9,408.46 -9,018.60 6,040,595.26 460,940.89 Measured 13,029.04 6,161.25 9,488.87 -9,078.05 Vertical Depth Inclination Azimuth Depth (usft) (°) 6,040,756.54 {) 0.00 (usft) 15,631.02 90.30 -9,196.96 323.52 460,763.52 6,218.86 15,700.00 90.30 9,730.08 323.52 6,040,917.81 6,218.50 15,800.00 90.30 6,159.16 323.52 -9,315.86 6,217.97 15,900.00 90.30 13,526.36 323.52 9,890.89 6,217.45 16,000.00 90.30 0.00 323.52 6,158.11 6,216.93 16,100.00 90.30 460,527.04 323.52 13,725.29 6,216.40 16,200.00 90.30 6,041,240.36 323.52 0.00 6,215.88 16,300.00 90.30 -9,553.68 323.52 460,408.79 6,215.36 16,400.00 90.30 10,212.52 323.52 6,041,401.64 6,214.83 16,500.00 90.30 6,156.01 323.52 -9,672.58 6,214.31 16,600.00 90.30 14,123.14 323.52 10,373.33 6,213.79 16,700.00 90.30 0.00 323.52 6,154.97 6,213.26 16,800.00 90.30 460,172.31 323.52 14,322.07 6,212.74 16,900.00 90.30 6,041,724.19 323.52 0.00 6,212.21 17,000.00 90.30 -9,869.39 323.52 460,094.84 6,211.69 17,100.00 90.30 10,561.76 323.52 6,041,751.89 6,211.17 17,200.00 90.30 6,154.04 323.52 -9,910.40 6,210.64 17,231.02 90.30 14,521.00 323.52 10,694.95 6,210.48 17,234.36 90.20 0.00 323.52 6,153.34 6,210.47 17,300.00 90.20 459,935.82 323.52 14,719.93 6,210.24 17,400.00 90.20 6,042,046.74 323.52 0.00 6,209.89 17,500.00 90.20 -10,148.21 323.52 459,817.57 6,209.54 17,600.00 90.20 11,016.57 323.52 6,042,208.01 6,209.19 17,700.00 90.20 6,151.94 323.52 -10,267.12 6,208.84 17,800.00 90.20 15,117.78 323.52 11,177.38 6,208.49 17,900.00 90.20 0.00 323.52 6,151.25 6,208.14 18,000.00 90.20 459,581.09 323.52 15,316.71 6,207.79 18,100.00 90.20 6,042,530.57 323.52 0.00 6,207.45 18,200.00 90.20 -10,504.94 323.52 459,462.84 6,207.10 18,300.00 90.20 11,490.45 323.52 6,042,683.26 6,206.75 18,389.36 90.20 6,150.17 323.52 -10,564.39 6,206.44 18,400.00 90.52 15,615.10 323.52 11,579.35 6,206.37 18,500.00 93.52 3.00 323.52 6,142.98 6,202.85 18,549.36 95.00 459,315.54 323.52 15,763.45 6,199.18 18,600.00 95.00 6,042,852.79 323.52 0.00 6,194.77 18,700.00 95.00 -10,742.29 323.52 459,226.82 6,186.05 18,800.00 95.00 11,819.70 323.52 6,043,013.45 6,177.33 18,833.00 95.00 6,118.26 323.52 -10,821.06 6,174.46 Total Depth: 18833' MD, 6174.46' TVD - 4112" Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well ODSN-01 - Slot ODS 1 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) True Minimum Curvature 12131/2015 12:29:55PM Page 6 COMPASS 5000.1 Build 58 Map Map TVDss +Nl-S +E/ -W Northing Easting DLS Vert Section usft (usft) (usft) (usft) (usft) 6,162.66 6,162.66 9,272.60 -8,918.13 6,040,459.01 461,040.79 3.00 12,860.98 6,162.30 9,328.06 -8,959.14 6,040,514.63 461,000.01 0.00 12,929.58 6,161.77 9,408.46 -9,018.60 6,040,595.26 460,940.89 0.00 13,029.04 6,161.25 9,488.87 -9,078.05 6,040,675.90 460,881.77 0,00 13,128.51 6,160.73 9,569.27 -9,137.50 6,040,756.54 460,822.65 0.00 13,227.97 6,160.20 9,649.68 -9,196.96 6,040,837.18 460,763.52 0.00 13,327.44 6,159.68 9,730.08 -9,256.41 6,040,917.81 460,704.40 0.00 13,426.90 6,159.16 9,810.49 -9,315.86 6,040,998.45 460,645.28 0.00 13,526.36 6,158.63 9,890.89 -9,375.32 6,041,079.09 460,586.16 0.00 13,625.83 6,158.11 9,971.30 -9,434.77 6,041,159.73 460,527.04 0.00 13,725.29 6,157.59 10,051.70 -9,494.22 6,041,240.36 460,467.92 0.00 13,824.75 6,157.06 10,132.11 -9,553.68 6,041,321.00 460,408.79 0.00 13,924.22 6,156.54 10,212.52 -9,613.13 6,041,401.64 460,349.67 0.00 14,023.68 6,156.01 10,292.92 -9,672.58 6,041,482.27 460,290.55 0.00 14,123.14 6,155.49 10,373.33 -9,732.04 6,041,562.91 460,231.43 0.00 14,222.61 6,154.97 10,453.73 -9,791.49 6,041,643.55 460,172.31 0.00 14,322.07 6,154.44 10,534.14 -9,850.94 6,041,724.19 460,113.18 0.00 14,421.53 6,154.28 10,559.08 -9,869.39 6,041,749.20 460,094.84 0.00 14,452.39 6,154.27 10,561.76 -9,871.37 6,041,751.89 460,092.87 3.00 14,455.71 6,154.04 10,614.54 -9,910.40 6,041,804.82 460,054.06 0.00 14,521.00 6,153.69 10,694.95 -9,969.85 6,041,885.46 459,994.94 0.00 14,620.46 6,153.34 10,775.35 -10,029.31 6,041,966.10 459,935.82 0.00 14,719.93 6,152.99 10,855.76 -10,088.76 6,042,046.74 459,876.70 0.00 14,819.39 6,152.64 10,936.17 -10,148.21 6,042,127.38 459,817.57 0.00 14,918.86 6,152.29 11,016.57 -10,207.67 6,042,208.01 459,758.45 0.00 15,018.32 6,151.94 11,096.98 -10,267.12 6,042,288.65 459,699.33 0.00 15,117.78 6,151.59 11,177.38 -10,326.57 6,042,369.29 459,640.21 0.00 15,217.25 6,151.25 11,257.79 -10,386.03 6,042,449.93 459,581.09 0.00 15,316.71 6,150.90 11,338.20 -10,445.48 6,042,530.57 459,521.96 0.00 15,416.18 6,150.55 11,418.60 -10,504.94 6,042,611.20 459,462.84 0.00 15,515.64 6,150.24 11,490.45 -10,558.06 6,042,683.26 459,410.01 0.00 15,604.52 6,150.17 11,499.01 -10,564.39 6,042,691.84 459,403.72 3.00 15,615.10 6,146.65 11,579.35 -10,623.80 6,042,772.42 459,344.64 3.00 15,714.50 6,142.98 11,618.93 -10,653.06 6,042,812.11 459,315.54 3.00 15,763.45 6,138.57 11,659.50 -10,683.06 6,042,852.79 459,285.71 0.00 15,813.63 6,129.85 11,739.60 -10,742.29 6,042,933.12 459,226.82 0.00 15,912.72 6,121.13 11,819.70 -10,801.51 6,043,013.45 459,167.92 0.00 16,011.81 6,118.26 11,846.13 -10,821.06 6,043,039.96 459,148.48 0.00 16,044.50 12131/2015 12:29:55PM Page 6 COMPASS 5000.1 Build 58 HALLIBURTPIV Database: EDMPrd Company: Caelus Energy Alaska Project: Oooguruk Development Site: Oooguruk Drill Site Well: ODSN-01 Wellbore: O DS N-01 A Design: ODSN-01 A wp10 Local Co-ordinate Reference: TVD Reference: MD Reference: North Reference: Survey Calculation Method: Halliburton Standard Proposal Report Well ODSN-01 - Slot ODS 1 42.7'+ 13.5' @ 56.20usft (Nabors 19AC) 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) True Minimum Curvature Targets ---- ----- ---------- -- Target Name hit/miss target Dip Angle Dip Dir. TVD +N/ -S +E/ -W Northing Easting Shape (°) (°) (usft) (usft) (usft) (usft) (usft) ODSN-01HEELv2 0.00 0.00 6.259.20 5,948.37 -6,015.98 6,037,123.39 463,929.18 plan hits target center _Point - Casing Points ---- --- - - -------------_.— - Measured Vertical Casing Hole Depth Depth Diameter Diameter (usft) (usft) Name 18,833.00 6,174.46 41/2" 4-1/2 6-1/8 11,333.00 6,270.95 7" 7 9-1/2 7,952.55 5,013.20 9 5/8" 9-5/8 11-3/4 Formations Measured Vertical Vertical Dip Depth Depth Depth SS Dip Direction (usft) (usft) Name Lithology 11,287.19 6,266.96 NUIQ_l 6,345.60 4,272.46 Brook 2B 4,646.46 3,489.07 Hue Res C tied 10,365.16 6,113.97 KUPC 10,417.89 6,132.11 LCU 4,121.36 3,248.26 Top Hue2 tied 11,214.40 6.260.62 NUIQSUT 5,708.49 3,978.78 Hue Res B tied 6,267.84 4,236.62 Hue Res Atied 7,985.10 5,028.20 TEEC_nuna_top 9,753.32 5,843.28 TOP_HRZ 8,515.83 5,272.85 TEEC_nuna_base 8,872.35 5,437.19 Torok Shale 1 tied 10,198.27 6,047.74 KALUBIK_MKR 10,870.31 6,230.43 BCU 10,032.30 5,971.88 BASE HRZ Plan Annotations Measured Vertical Local Coordinates Depth Depth +N/ -S +E/ -W (usft) (usft) (usft) (usft) Comment 4,088.00 3,233.09 1,498.89 -1,432.95 KOP TOW: 9.46°/100' : 4088' MD, 3233.09'TVD : 65° LT TF 4,108.08 3,242.27 1,511.36 -1,445.73 End Dir : 4108.08' MD, 3242.27' TVD 4,158.08 3,264.82 1,541.99 -1,478.19 Start Dir 31/100' : 4158.08' MD, 3264.82'TVD 4,347.21 3,351.13 1,650.50 -1,606.70 End Dir : 4347.21' MD, 3351.13' TVD 4,847.21 3,581.61 1,917.53 -1,961.06 Start Dir 31/100' : 4847.21' MD, 3581.62'TVD 5,092.20 3,694.70 2,060.39 -2,124.59 End Dir : 5092.2' MD, 3694.7' TVD 10,145.63 6,024.12 5,247.09 -5,279.90 StartDir 3°/100' : 10145.63' MD, 6024.1l'TVD 10,898.13 6,233.05 5,745.38 -5,796.63 End Dir : 10898.13' MD, 6233.05TVD 11,333.00 6,270.95 6,039.62 -6,114.59 Begin Geo -steering 18,833 00 6,174.46 11,846.13 -10,821.06 Total Depth : 18833' MD, 6174.46' TVD 12/31/2015 12.29:55PM Page 9 COMPASS 5000.1 Build 58 Caelus Energy Alaska Oooguruk Development Oooguruk Drill Site ODSN-01 ODSN-01A ODSN-01A wp10 Anticollision Summary Report 31 December, 2015 270 0 180 Azimuth from North 'I vs Centre to Centre Separation [100 usft/ink REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well ODSN-01 - Slot ODS 1, True North Vertical (TVD) Reference: 42.7' + 13.5' @� 56.20usft (Nabors 19AC) Section (VS) Reference: Slot - ODS 1(O.00N, O.00E) Measured Depth Reference: 42.7' + 13.5' @ 56.20usft (Nabors 19AC) Calculation Method: Minimum Curvature NAD 27 ASP Zone 4: WELL DETAILS: ODSN-01 g Grougnd Level: 13.50 Latittude Long +0.00 00 603 151.32 469920.45 70.4961782222 -150.245It d 9 24120 Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Tray. Cylinder North Error Surface: Elliptical Conic Warning Method: Rules Based 4088' MD to 18833' MD OO5N-Ot KE3 aDSN-01 KE3 Pei From Color To MD 4000 Date: 2015-12-31T00:00:00 Validated: Yes Version: Depth From Depth To Survey/Plan Tool 100.00 832.00 ODSN-1 KE3 Gyro SRG-SS 909.73 4088.00 ODSN-1 KE3 MWD MWD+IFR2+MS+sag 4088.00 4460.00 4460.00 7952.00 ODSN-01A wp10 ODSN-01A MWD Interp Azi+sag MWD+IFR2+MS+sag 7952.00 11333.00 wp10 ODSN-01A wp10 MWD+IFR2+MS+sag 11333.00 18833.00 ODSN-01A wp10 MWD+IFR2+MS+sag 270 0 180 Azimuth from North 'I vs Centre to Centre Separation [100 usft/ink REFERENCE INFORMATION Co-ordinate (N/E) Reference: Well ODSN-01 - Slot ODS 1, True North Vertical (TVD) Reference: 42.7' + 13.5' @� 56.20usft (Nabors 19AC) Section (VS) Reference: Slot - ODS 1(O.00N, O.00E) Measured Depth Reference: 42.7' + 13.5' @ 56.20usft (Nabors 19AC) Calculation Method: Minimum Curvature NAD 27 ASP Zone 4: WELL DETAILS: ODSN-01 g Grougnd Level: 13.50 Latittude Long +0.00 00 603 151.32 469920.45 70.4961782222 -150.245It d 9 24120 Calculation Method: Minimum Curvature Error System: ISCWSA Scan Method: Tray. Cylinder North Error Surface: Elliptical Conic Warning Method: Rules Based 4088' MD to 18833' MD OO5N-Ot KE3 aDSN-01 KE3 Pei From Color To MD 4000 4250 4250 4500 4500 --------- 4750 4750 5000 5000 6000 6000 7000 7000 8000 8000 9000 9000 ----- - 10000 10000 11000 11000 12000 12000 13000 13000 14000 14000 15000 15000 ------------ 16000 16000 17000 17000 18000 18000 19000 19000 20000 20000 21000 21000 22000 22000 23000 23000 24000 300 240 ANTI -COLLISION SETTINGS Interpolation Method: MD, interval: 25.00 Depth Range From: 4088.00 To 18833.00 Centre Distance: 2079.03 Plan: ODSN-01A wp10 0 ODSN-Oi KE3 330,---- _ - 30 40 ODSN-011 KE3 P131 i 60 \QW, % 90 i � I 2� Ai 210 ` 150 180 Azimuth from North (°( vs Centre to Centre Separation iusfti SECTION DETAILS Sec MD Inc Azi TVD TVDSS +N/ -S +E/ -W DLeg TFace VSec Target 1 4088.00 62.39 315.27 3233.09 3176.89 1498.89 -1432.95 0.00 0.00 2073.11 2 4108.08 63.20 313.33 3242.27 3186.07 1511.36 -1445.73 9.46 -65.00 2090.94 3 4158.08 63.20 313.33 3264.82 3208.62 1541.99 -1478.19 0.00 0.00 2135.44 4 4347.2162.55 307.00 3351.13 3294.93 1650.51 -1606.71 3.00 -97.97 2302.24 5 4847.21 62.55 307.00 3581.62 3525.42 1917.54 -1961.07 0.00 0.00 2738.39 65092.20 62.55 315.28 3694.70 3638.50 2060.39 -2124.59 3.00 91.90 2954.15 7 10145.63 62.55 315.28 6024.11 5967.91 5247.08 -5279.89 0.00 0.00 7435.05 8 10898.13 85.00 312.78 6233.05 6176.85 5745.39 -5796.63 3.00 -6.51 8151.46 9 11198.13 85.00 312.78 6259.20 6203.00 5948.37 -6015.98 0.00 O.OD 8449.27 ODSN-01 HEEL Q 10 11473.13 85.00 312.78 6283.17 6226.97 6134.43 -6217.06 0.00 0.00 8722.26 11 11643.13 90.10 312.78 6290.43 6234.23 6249.75 -6341.67 3.00 0.00 8891.45 12 12193.13 90.10 312.78 6289.47 6233.27 6623.30 -6745.36 0.00 0.00 9439.51 13 12209.80 90.60 312.78 6289.37 6233.17 6634.62 -6757.59 3.00 0.00 9456.12 14 1 2609 .80 90.60 312.78 6285.18 6228.98 6906.28 -7051.16 0,00 0.00 9854.69 15 12636.47 91.40 312.78 6284.72 6228.52 6924.39 -7070.73 3.00 0.00 9881.26 16 12936.47 91.40 312.78 6277.39 6221.19 7128.08 -7290.85 0.00 0.00 10180.11 17 13294.36 91.40 323.52 6268.62 6212.42 7394.20 -7529.21 3.00 89.87 10537.36 18 14594.36 91.40 323.52 6236.86 6180.66 8439.18 -8301.89 0.00 0.00 11830.01 19 14607.69 91.00 323.52 6236.58 6180.38 8449.89 -8309.81 3.00 180.00 11843.27 20 15607.69 91OD 323.52 6219.12 6162.92 9253.84 -8904.26 0.00 0.00 12837.77 21 15631.02 90.30 323.52 6218.86 6162.66 9272.60 -8918.13 3.00 180.00 12860.98 22 17231 02 90.30 323.52 6210.48 6154.28 10559 08 -9869.39 0.00 0.00 14452.39 23 17234.36 90.20 323.52 6210.47 6154.27 10561.76 -9871.37 3.00 180.00 14455.71 24 18389.36 90.20 323.52 6206.44 6150.24 11490.45 -10558.06 0.00 0.00 15604.52 25 1 8549. 36 95.00 323.52 6199.18 6142.98 11618.93 -10653.06 3.00 0.00 15763.45 26 18833.00 95.00 323.52 6174.46 6118.26 11846.13 -10821.06 0.00 0.00 16044.50 Halliburton Anticollision Report Company: Caelus Energy Alaska Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Project: Oooguruk Development TVD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Reference Site: Oooguruk Drill Site MD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Site Error: 0.00usft North Reference: True Reference Well: ODSN-01 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 2.00 sigma Reference Wellbore ODSN-01A Database: EDMPrd Reference Design: ODSN-01A wp10 Offset TVD Reference: Offset Datum Reference ODSN-01Awp10 Filter type: GLOBAL FILTER APPLIED: All wellpaths within 200'+ 100/1000 of reference Interpolation Method: MD Interval 25.00usft Error Model: ISCWSA Depth Range: 4,088.00 to 18,833.00usft Scan Method: Tray. Cylinder North Results Limited by: Maximum center -center distance of 2,079.03usft Error Surface: Elliptical Conic Survey Tool Program Date 12/31/2015 From To (usft) (usft) Survey (Wellbore) Tool Name 100.00 832.00 ODSN-1 KE3 Gyro (ODSN-01 KE3 PB1) SRG-SS 909.73 4,088.00 ODSN-1 KE3 MWD (ODSN-01 KE3 PB1) MWD+IFR2+MS+sag 4,088.00 4,460.00 ODSN-O1Awp10 (ODSN-01A) MWD_InterpAzi+sag 4,460.00 7,952.00 ODSN-01Awp10 (ODSN-01A) MWD+IFR2+MS+sag 7,952.00 11,333.00 ODSN-01Awp10 (ODSN-01A) MWD+IFR2+MS+sag 11,333.00 18,833.00 ODSN-01Awp10 (ODSN-01A) MWD+IFR2+MS+sag Description Surface readout gyro single shot Fixed:v2:IIFR dec & 3 -axis correction + sag Fixed:v2:std dec with interpolated azimuth + sag Fixed:v2:IIFR dec & 3 -axis correction + sag Fixed:v2:IIFR dec & 3 -axis correction + sag Fixed:v2:IIFR dec & 3 -axis correction + sag 12/31/2015 12.31:09PM Page 2 of 5 COMPASS 5000.1 Build 58 Halliburton Anticollision Report Company: Caelus Energy Alaska Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Project: Oooguruk Development TVD Reference: 423'+ 13.5'@ 56.20usft (Nabors 19AC) Reference Site: Oooguruk Drill Site MD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Site Error 0.00usft North Reference: True Reference Well: ODSN-01 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 2.00 sigma Reference Wellbore ODSN-01A Database: EDMPrd Reference Design: ODSN-01Awp10 Offset TVD Reference: Offset Datum Summary Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (usft) from Plan Offset Well - Wellbore - Design (usft) (usft) (usft) (usft) Oooguruk Drill Site ODSK-13 - ODSK-13 - ODSK-13 4,088.00 4,675.00 1,224.49 119.15 1,105.92 Pass - Major Risk ODSK-13 - ODSK-13PB1 - ODSK-13PB1 Out of range ODSK-13 - ODSK-13PB2 - ODSK-13PB2 4,088.00 4,675.00 1,224.49 119.14 1,105.94 Pass - Major Risk ODSK-13 - ODSN-13A- ODSN-13A wp06 4,088.00 4,675.00 1,224.49 119.07 1,106.01 Pass - Major Risk ODSK-14 - ODSK-14 - ODSK-14 KupB 4,118.83 4,500.00 1,467.80 139.35 1,328.42 Pass - Major Risk ODSK-14 - ODSK-14 P81 - ODSK-14 PB1 KupB 4,118.56 4,500.00 1,468.23 128.80 1,339.36 Pass - Major Risk ODSK-14 - ODSK-14 PB2 - ODSK-14 PB2 KupB 4,118.83 4,500.00 1,467.80 128.18 1,339.55 Pass - Major Risk ODSK-33 - ODSK-33 KupA- ODSK-33 KupA 4,112.44 4,925.00 1,688.78 126.53 1,581.29 Pass - Major Risk ODSK-33 - ODSK-33 P81 KupA- ODSK-33 PB1 K 4,112.44 4,925.00 1,688.78 126.55 1,581.27 Pass - Major Risk ODSK-35Ai - ODSK-35Ai - ODSK-35Ai KupH Sury 10,112.39 11,425.00 376.14 305.92 83.84 Pass - Major Risk ODSK-38i - ODSK-38i KupD - ODSK-38i KupD Su Out of range ODSN-01 - ODSN-01 KE3 - ODSN-01 KE3 4,100.00 4,100.00 0.11 1.87 -1.65 FAIL- Minor Risk 1/200 ODSN-01 - ODSN-01 KE3 PB1 - ODSN-01 KE3 P 4,100.00 4,100.00 0.11 1.87 -1.65 FAIL- Minor Risk 1/200 ODSN-02 - ODSN-02 PN3 ext - ODSN-02 PN3 ex Out of range ODSN-02 - ODSN-02 PN3 ext PB1 - ODSN-02 PN Out of range ODSN-03i - ODSN-03i IN4 ext- ODSN-03i IN4 ext 4,088.00 4,550.00 2,025.00 126.09 1,902.03 Pass - Major Risk ODSN-04 - ODSN-04 PN5 ext - ODSN-04 PN5 ex 4,088.00 4,250.00 1,297.13 131.98 1,172.64 Pass - Major Risk ODSN-04 - ODSN-04 PN5 ext PB1 - ODSN-04 PN 4,088.00 4,250.00 1,297.13 132.39 1,172.30 Pass - Major Risk ODSN-07i - ODSN-07 IN1 - ODSN-07 IN1 Out of range ODSN-07i - ODSN-07 IN1 - ODSN-07i IN1 wp16 Out of range ODSN-09i - N-09 18 EXT - N-09 18EXT wp02 4,132.11 4,025.00 1,414.12 161.10 1,290.98 Pass - Major Risk ODSN-10i - ODSN-10i 15EXT - ODSN-10i 15EXT 4,125.78 4,225.00 1,390.38 150.04 1,257.49 Pass - Major Risk ODSN-10i - ODSN-10i 15EXT PB2 - ODSN-10i 15 4,125.78 4,225.00 1,390.38 149.95 1,257.58 Pass - Major Risk ODSN-10i - ODSN-10i 15EXT PB3 - ODSN-10i 15 4,125.78 4,225.00 1,390.38 150.04 1,257.49 Pass - Major Risk ODSN-11 i - ODSN-11 i 16EXT - N-11 wp06 Out of range ODSN-12 - ODSN-12 ERD-0 - N-12 wp06 Out of range ODSN-15i - ODSN-15i - ODSN-15i IN 12 Out of range ODSNA6 - ODSN-16 - ODSN-16 PN13 Surveys Out of range ODSN-16 - ODSN-16 ST - ODSN-16a wp02 (shor Out of range ODSN-16 - ODSN-16L1 - ODSN-161_1 PN13 Out of range ODSN-17 - ODSN-17 - ODSN-17 PN13 Mid Surve Out of range ODSN-17 - ODSN-17 L1 - ODSN-17 L1 PN13 Out of range ODSN-17 - ODSN-17L1 A - ODSN-17L1 A wp01 Out of range ODSN-18 - ODSN-18 - ODSN-18 PN11 Out of range ODSNA8 - ODSN-18 PB5 - ODSNA8 PN 11 PB5 Out of range ODSN-18 - ODSN-18 P81 - ODSN-18 PN11 PB1 Out of range ODSNA8 - ODSN-18 PB2 - ODSNA8 PN 11 PB2 Out of range ODSNA 8 - ODSN-18 P132 - ODSNA 8_ PB2 Out of range ODSN-18 - ODSN-18 PB3 - ODSN-18 PN11 P133 Out of range ODSN-18 - ODSN-18 P84 - ODSN-18 PN11 P134 Out of range ODSN-18 - ODSN-IBA- ODSNA 8Awp01 Out of range ODSN-19i - ODSN-19i 34 ext - ODSN-19i 34 ext 4,982.32 4,675.00 940.85 189.20 801.52 Pass - Major Risk ODSN-19i - ODSN-19i 34 ext PB1 - ODSN-19i 34e 4,982.32 4,675.00 940.85 188.20 802.14 Pass - Major Risk ODSN-19i - ODSN-19i 34 ext P132 - ODSN-19i 34 4,982.32 4,675.00 940.85 189.20 801.52 Pass - Major Risk ODSN-19i - ODSN-19i 34 ext PB3 - ODSN-19i 34 4,982.32 4,675.00 940.85 189.20 801.52 Pass - Major Risk ODSN-20 - ODSN-20i ERD-1 - N -20i ERD1 wp06 Out of range ODSN-21 - ODSN-21i ERD-5 - N -21i ERD-5 wp05 Out of range ODSN-22 - ODSN-22 PSW2 - ODSN-22 PSW2 Out of range ODSN-23i - ODSN-23i - ODSN-23i IN 14 Out of range ODSN-23i - ODSN-23i P132 - ODSN-23i IN14 P62 Out of range ODSN-24 - ODSN-24 KE5 - ODSN-24 KE5 4,140.18 4,250.00 1,463.97 140.89 1,329.34 Pass - Major Risk ODSN-24 - ODSN-24 KE5 P82 - ODSN-24 KE5 P 4,140.18 4,250.00 1,463.97 140.89 1,329.34 Pass - Major Risk ODSN-25 - ODSN-25 - ODSN-25 KE1 4,100.00 4,200.00 1,265.13 140.83 1,136.90 Pass - Major Risk 12/31/2015 12:31:09PM Page 3 of 5 COMPASS 5000.1 Build 58 Summary Site Name Offset Well - Wellbore - Design Oooguruk Drill Site ODSN-25 - ODSN-25 PB1 - ODSN-25 PB1 ODSN-25 - ODSN-25 PB2 - ODSN-25 KE1 PB2 ODSN-25 - ODSN-25 PB3 - ODSN-25 KE1 P133 ODSN-25 - ODSN-25 PB4 - ODSN-25 KE1 PB4 ODSN-26i - ODSN-26i KE2 - ODSN-26i KE2 ODSN-26i - ODSN-26i KE2 PB1 - ODSN-26i KE2 ODSN-26i - ODSN-26i KE2 PB2 - ODSN-26 KE2 ODSN-27i - ODSN-27i IN4 - ODSN-27i IN4 ODSN-28 - ODSN-28 PN3 - ODSN-28 PN3 ODSN-29 - ODSN-29 PN5 - ODSN-29 PN5 ODSN-29 - ODSN-29 PN5 P61 - ODSN-29 PN5 P ODSN-29 - ODSN-29 PN5 PB2 - ODSN-29 PN5 P ODSN-29 - ODSN-29A - ODSN-29A wp02 ODSN-30 - ODSN-30 ERD-6 - N-30 ERD-6 WP04 ODSN-31 - ODSN-31 - ODSN-31 PN6 Surveys ODSN-31 - ODSN-31 PB1 - ODSN-31 PB1 PN6 Su ODSN-31 - ODSN-31 ST - ODSN-31 ST wp02 ODSN-32i - ODSN-32i IN7 - ODSN-32i IN7 Survey ODSN-32i - ODSN-32iPB1 IN7 - ODSN-32iPB1 IN ODSN-34i - ODSN-34 IN9 - ODSN-34i IN9 Survey ODSN-34i - ODSN-34i P132 - ODSN-34iPB2 IN9 ODSN-34i - ODSN-34i PB3 - ODSN-34iPB3 IN9 ODSN-34i - ODSN-34iPB1 - ODSN-34iPB1 IN9 ODSN-36 - ODSN-36 L1 - ODSN-36a wp08 ODSN-36 - ODSN-36 PN10 - ODSN-36 PN10 Sur ODSN-37 - ODSN-37 - ODSN-37 PN8 ODSN-37 - ODSN-371_1 - ODSN-371_1 wp10a ODSN-40 - ODSN-40 PN12 - ODSN-40 PN12 Sur ODSN-40 - ODSN-40PB2 PN12 - ODSN-40PB2 P ODSN-43 - ODSN-43 Western ERD - ODSN43 W ODSN-43 - ODSN-43 Western ERD P132 - ODSN- ODSN-48 - ODSN-48 Western ERD - ODSN-48 S ODST-39 - ODST-39 Torok D - ODST-39 Torok D ODST-39 - ODST-39 Torok D PB1 - ODST-39 Toro ODST-45 - ODSN-45i P131 IN13 - ODSN-45i PB1 ODST-45 - ODST-45A - ODST-45A Surveys ODST-46i - ODST-46i - ODST-46i Torok C ODST-46i - ODST-46i PB1 - ODST-46i Torok C PB ODST-46i - ODST-46i PB2 - ODST46i Torok C PB ODST-46i - ODST-46i Torok C P133 - ODST-46i PB ODST-47 - ODST-47A - N -47A PS16 wp01 1213112015 12: 31: 09 PM Reference Offset Halliburton No -Go Allowable Measured Measured Anticollision Report Distance Deviation Warning Company: Caelus Energy Alaska Local Co-ordinate Reference: Well ODSN-01 - Slot ODS 1 Project: Oooguruk Development TVD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Reference Site: Oooguruk Drill Site MD Reference: 42.7'+ 13.5'@ 56.20usft (Nabors 19AC) Site Error: 0.00usft North Reference: True Reference Well: ODSN-01 Survey Calculation Method: Minimum Curvature Well Error: 0.00usft Output errors are at 2.00 sigma Reference Wellbore ODSN-01A Database: EDMPrd Reference Design: ODSN-01A wp10 Offset TVD Reference: Offset Datum Summary Site Name Offset Well - Wellbore - Design Oooguruk Drill Site ODSN-25 - ODSN-25 PB1 - ODSN-25 PB1 ODSN-25 - ODSN-25 PB2 - ODSN-25 KE1 PB2 ODSN-25 - ODSN-25 PB3 - ODSN-25 KE1 P133 ODSN-25 - ODSN-25 PB4 - ODSN-25 KE1 PB4 ODSN-26i - ODSN-26i KE2 - ODSN-26i KE2 ODSN-26i - ODSN-26i KE2 PB1 - ODSN-26i KE2 ODSN-26i - ODSN-26i KE2 PB2 - ODSN-26 KE2 ODSN-27i - ODSN-27i IN4 - ODSN-27i IN4 ODSN-28 - ODSN-28 PN3 - ODSN-28 PN3 ODSN-29 - ODSN-29 PN5 - ODSN-29 PN5 ODSN-29 - ODSN-29 PN5 P61 - ODSN-29 PN5 P ODSN-29 - ODSN-29 PN5 PB2 - ODSN-29 PN5 P ODSN-29 - ODSN-29A - ODSN-29A wp02 ODSN-30 - ODSN-30 ERD-6 - N-30 ERD-6 WP04 ODSN-31 - ODSN-31 - ODSN-31 PN6 Surveys ODSN-31 - ODSN-31 PB1 - ODSN-31 PB1 PN6 Su ODSN-31 - ODSN-31 ST - ODSN-31 ST wp02 ODSN-32i - ODSN-32i IN7 - ODSN-32i IN7 Survey ODSN-32i - ODSN-32iPB1 IN7 - ODSN-32iPB1 IN ODSN-34i - ODSN-34 IN9 - ODSN-34i IN9 Survey ODSN-34i - ODSN-34i P132 - ODSN-34iPB2 IN9 ODSN-34i - ODSN-34i PB3 - ODSN-34iPB3 IN9 ODSN-34i - ODSN-34iPB1 - ODSN-34iPB1 IN9 ODSN-36 - ODSN-36 L1 - ODSN-36a wp08 ODSN-36 - ODSN-36 PN10 - ODSN-36 PN10 Sur ODSN-37 - ODSN-37 - ODSN-37 PN8 ODSN-37 - ODSN-371_1 - ODSN-371_1 wp10a ODSN-40 - ODSN-40 PN12 - ODSN-40 PN12 Sur ODSN-40 - ODSN-40PB2 PN12 - ODSN-40PB2 P ODSN-43 - ODSN-43 Western ERD - ODSN43 W ODSN-43 - ODSN-43 Western ERD P132 - ODSN- ODSN-48 - ODSN-48 Western ERD - ODSN-48 S ODST-39 - ODST-39 Torok D - ODST-39 Torok D ODST-39 - ODST-39 Torok D PB1 - ODST-39 Toro ODST-45 - ODSN-45i P131 IN13 - ODSN-45i PB1 ODST-45 - ODST-45A - ODST-45A Surveys ODST-46i - ODST-46i - ODST-46i Torok C ODST-46i - ODST-46i PB1 - ODST-46i Torok C PB ODST-46i - ODST-46i PB2 - ODST46i Torok C PB ODST-46i - ODST-46i Torok C P133 - ODST-46i PB ODST-47 - ODST-47A - N -47A PS16 wp01 1213112015 12: 31: 09 PM Reference Offset Centre to No -Go Allowable Measured Measured Centre Distance Deviation Warning Depth Depth Distance (usft) from Plan (usft) (usft) (usft) (usft) 4,100.00 4,200.00 1,265.13 140.83 1,136.90 Pass - Major Risk 4,100.00 4,200.00 1,265.13 140.83 1,136.90 Pass - Major Risk 4,100.00 4,200.00 1,265.13 140.83 1,136.90 Pass - Major Risk 4,100.00 4,200.00 1,265.13 140.83 1,136.90 Pass - Major Risk 4,100.00 4,200.00 725.73 133.96 594.61 Pass - Major Risk 4,100.00 4,200.00 725.73 133.96 594.61 Pass - Major Risk 4,100.00 4,200.00 725.73 133.96 594.61 Pass - Major Risk Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range 9,229.32 13,343.97 1,970.44 325.71 1,663.06 Pass - Major Risk 8,865.22 12,897.97 2,021.16 349.51 1,707.60 Pass - Major Risk 10,965.35 16,714.97 965.77 369.93 595.95 Pass - Major Risk 10,416.96 16,006.97 1,607.90 386.01 1,224.71 Pass - Major Risk Out of range Out of range Out of range Out of range 9,756.32 14,294.97 501.85 399.86 383.53 Pass - Major Risk 10,142.01 14,754.00 458.91 382.42 156.40 Pass - Major Risk Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Out of range Page 4 of 5 COMPASS 5000.1 Build 58 i Legend $ ODSN-01A wpIO $ ODSDWI-44, ODSDWl44 Disposal, ODSDWI-44 Disposal VO $ ODSK-13, ODSK-13, ODSK-13 VO AODSK-13, ODSK-13PB1, ODSK-13PB1 VO ODSK-13, ODSK-13PB2, ODSK-13P62 VO 44 ODSK-14, ODSK-14 PBI, ODSK-14 PBI KupB VO # ODSK-14, ODSK-14 PB2, ODSK-14 PB2 KupB VO 09ODSK-14, ODSK-14, ODSK-14 KupB VO 4+ODSK-33, ODSK-33 KupA, ODSK-33 KupA VO ODSK-33, ODSK-33 P61 KupA, ODSK-33 PBS KupA VO # ODSK-35Ai, ODSK-35 KupB, ODSK-35 KupB Survevs VO E -j ODSK-38i, ODSK-38i KupD, ODSK-38i KupD Surveys VO $ ODSK-41, ODSK-41 KupF, ODSK-41 KupF Surveys VD ODSK-41, ODSK-41 PB1 KupF, ODSK-41 PBl KupF VO $ODSK-42i, ODSK-42Ai, ODSK-42AiVO # ODSK-42i, ODSK42i KupG, ODSK-42i KupG VO ODSK42i, ODSN-42B PBI, ODSN-42B PBI VO ODSK-42i, ODSN-42B PB2, ODSN-42B PB2 VO ODSK42i, ODSN-42B, ODSN-42BVO ODSN-01, ODSN-01 KE3 PB1, ODSN-01 KE3 PBI VO ODSN-Ol, ODSN-01 KE3, ODSN-01 KE3 VO 49 ODSN-02, ODSN-02 PN3 ext PB1, ODSN-02 PN3 ext PBI VO AODSN-02, ODSN-02 PN3 ext, ODSN-02 PN3 ext VO # ODSN-03i, ODSN-03i IM ext, ODSN-03i IN4 ext VO ODSN-04, ODSN44 PN5 ext PB1, ODSN-04 PNS ext PB1 VO $ ODSN-04, ODSN-04 PN5 e#, ODSN-04 PN5 ext VO 49 ODSN-06i, ODSN-06i IS3, ODSN-06i IS3 VO fA ODSN-07i, ODSN-07IN1, ODSN-07IN1 VO X ODSN-07i, ODSN-07i IM PBI, ODSN-07i INl PBI VO A ODSN-10y ODSN-10i 15EXT PB1, ODSN-10i 15EXT PBI VO # ODSN-10j ODSN-10i 15EXT PB2, ODSN-10i 15EXT PB2 VO ODSN-104 ODSN-10i 15EXT PB3, ODSN-10i 15EXT PB3 VO �j ODSN-10i, ODSN-10i 15EXT, ODSN-10i 15EXT VO $ ODSN-15i, ODSN-15i, ODSN-15i IN12 VO ODSN-16, ODSN-16, ODSN-16 PN13 Surveys VO ODSN-16, ODSN-16L1, ODSN-16LI PN13 VO # ODSN-17, ODSN-17 Ll, ODSN-17 LI PN23 VO ODSN-17, ODSN-17, ODSN-17 PN13 Mid Surveys VO fjODSN-18, ODSN-18 PBS, ODSN-18 PN11 PB5 VO {� ODSN-18, ODSN-18 PB1, ODSN-18 PN11 PB1 VO ODSN-18, ODSN-18 PB2, ODSN-18 PMI PB2 VO ODSN-18, ODSN-18 PB2, ODSN-18 PB2 VO ODSN-18, ODSN-18 P93, ODSN-18 PN11 PB3 VO # ODSN-18, ODSN-18 PB4, ODSN-18 PM1 PB4 VO 49ODSN-18, ODSN-18, ODSN-18 PN21 VO {9 ODSN-19i, ODSN-19i 34 ext PBI, ODSN-19i 34ext PBI VO ODSN-19i, ODSN-19i 34 ext PB2, ODSN-19i 34 ext PB2 VO $ ODSN-19i, ODSN-19i 34 ext PB3, ODSN-19i 34 ext PB3 VO ODSN-19i, ODSN-19i 34 ed, ODSN-19i 34 ext VO ODSN-22, ODSN-22 PSW2, ODSN-22 PSW2 VO # ODSN-23i, ODSN-23i PBI, ODSN-Z3i IN14 PBI VO .�ODSN-23i, ODSN-23i PB2, ODSN-23iIN14 PB2 VO 44 ODSN-23i. ODSN-23L ODSN-23i MAI VO ODSN-01A vs K-35Ai 1/4 mile Heel 3D Vie,,,-, - Plan: ODSN-UIQ wp10 {ODSN-011ODSN-01A1 ODSN-01A vs K-35Ai 114 mile Heel Legend S��, ('t��® Pian L'ew-PbwOCSN C1r aplfi (ODSN-01JODIPT f1Ar $ODSN-01A wpIO I')ED o° is El 'J It iN % °o°x A ODSDW144, ODSDWI44 Disposal, ODSDWI-44 Disposal VO x-�IWO ODSK-13, ODSK-13, ODSK-13 VO ND' L_J NIS. .._.-..� EM7--- _J �.._ --- ODSK-13, ODSK-13P61, ODSK-13P61W 49ODSK-13, ODSK-13P82, ODSK-13F82 VO- ODSK-14, ODSK-14 PBS, ODSK-14 PBI Kup6 VO '; -- ODSK-14, ODSK-14 P82, ODSK-14 P82 KupB VO, �( ODSK-14, ODSK-14, ODSK-14 KupB VO ODSK-33, ODSK-33 KupA, ODSK-33 KupA VO ' "- �\ ------- DSK-33, _ DSK 33, ODSK-33 PBI KupA, ODSK-33 PBI KupA V0 ODSK 35Ai, ODSK 35 KupB, ODSK-35 KupB Surveys VO -)E ODSK-384 ODSK-38c KupD, ODSK-38, KupD Surveys VO A ODSK 41, ODSK 41 KupF, ODSK-41 KupF Surveys VO ODSK-41, ODSK-41 PBI KupF, ODSK-41 PBI KupF VO i<>ODSK-424 ODSK-42A4 ODSK-42Ai VO`""`+.,, \, i \ I ODSK-424 ODSK-42i Kup6, ODSK42i KupG VO-- 'i� ODSK-426 ODSN-42B PBI, ODSN-426 PBI VD .. `• �� * ! I $ODSK425 ODSN-42B PB2, ODSN-428 PB2 VO ODSK-42- ODSN-42B, ODSN-426 VO I i 4 � AODSN-01, ODSN-Dl K€3 P61, ODSN-OF KE3 PB! W 1 $ODSN-01, ODSN-01 KE3, ODSN-01 KE3 VO `< �E ODSN-02, ODSN-02 PN3 ext PBI, ODSN-02 PN3 ext PBI VO "s° .�. ..+_ -- ' ' 'v ! • �� - �� ,, _ ! ODSN-02, ODSN-02 PW at ODSN-02 PN3 ext VO- ODSN-03i, ODSN-03i IM ex . ODSN-03i IN4 ed VO ODSN-04, ODSN-04 PN5 ext FBI, ODSN-04 PN5 ext PBI VO e ODSN-04, OOSN-04 PNS ext, ODSN-04 PN5 ext VO �E ODSN-066 ODSN-W, 1S3, ODSN-06i 1S3 VD- $ODSN-075 ODSN-071M, ODSN-071M VD {} ODSNdO' ODSNdO� fSEXT PBI, ODSN-10i 1SEXT PBI VO ODSN-07 ODSN-07i IM PBI, ODSN-07i IM P91 VO _ r I(J( � 4 _ ODSN-106 ODSN-10i ISEXT PB2, ODSN l0i 15EXT PB2 VO - - • � � - - - - I �EODSN-101 ODSN 10i15EXT PB3, ODSN-10i15EXT P93 W TAODSN 101, ODSN-10i 15EXT, ODSN-10i 15EXT W ((�ODSN 155 ODSN-15i, ODSN-15i IM2 VO - �ODSN-16, ODSN-16, ODSN-16 PNB Surveys VD $ ODSN-16, ODSN-16t1, ODSN-I L PN13 V i ^� ODSN-17, ODSN-17 LI, ODSN-17 Lt PNI3 VD ''>''_-:""f $ODSN-17, ODSN-17, ODSN-17 PM3 Mid Survey; VO •`»� - { _! ODSN-18, ODSN-18 P65, ODSN-18 PMI P85 VO 46ODSN-18, ODSN-18 PBI, ODSN-18 PMS PB1 VO -- - e0DSN-18, ODSN-18 P62, ODSN-18 PMI PB2 Vp e ODSN-18, ODSN-18 PB2, ODSN-18 PB2 VOEl ' ``� I I. _ � ��V' �� `•. % i ODSN-18, ODSN-18 P83, ODSN-18 PMI PB3 VO use --1-- 1._._.__.____ �:'�..1 __{.._ =ODSN-18, ODSN-18 PB4, ODSN-18 PNU PO4 VO # ODSN-18, ODSN-18, ODSN 18 PM1 VO r .... � ODSN-194 ODSN-14i 34 ext PBI, ODSN-19i 34ert PB1 VO AODSN-194 ODSN-19i 34 ext PB2, ODSN-19i 34 ext P82 VD .................. \ A ODSN 196 ODSN 19i 34 od P83, ODSN-19, 34 ext PB3 V0 ODSN-195 ODSN-19i 34 ext, ODSN-24, 34 ext VO ODSN-22, ODSN-22 PSN2, ODSN 22 PSW2 VO } , +ODSN-234 ODSN-23i P61, ODSN-73i IM4 PB1 W BODSN-23i, ODSN-23i PB2, ODSN 23iIM4 PB2 VO,.3 +A ODSN-21, ODSN-23i, ODSN-2311N14V0,:_?i"� • -�., ,._ .s.4 -ttODSDWI-44, ODSDWI-44 Disposal, ODSDWI-44 Disposal VO iaODSK-13, ODSK-13, ODSK-13 VO 49 ODSK-13, ODSK-13PB1, ODSK-13PB1 VO ODSK-13, ODSK-13PB2, ODSK-13PB2 VO �ODSK-14, ODSK-14 PBI, ODSK-14 PBl KupB VO ODSK-14, ODSK-14 PBZ, ODSK-14 PB2 KupB VO 49 ODSK-14, ODSK-14, ODSK-14 KupB VO #ODSK-33, ODSK-33 KupA, ODSK-33 KupA VO ODSK-33, ODSK-33 PBI KupA, ODSK-33 PBI KupA VO # ODSK-35Ai, ODSK-35 KupB, ODSK-35 KupB Surveys VO 14 ODSK-35Ay ODSK-35Ai, ODSK-35Ai KupH Surveys VO ODSK-38i, ODSK-38i KupD, ODSK-38i KupD Surveys VO $ ODSK-41, ODSK41 KupF, ODSK-41 KupF Surveys VO ODSK41, ODSK41 P81 KupF, ODSK-41 PBl KupF VO ODSK-42i, ODSI( 42Ai, ODSK42Ai VO dE ODSK-42i, ODSK42i KupG, ODSK-42i KupG VO ODSK-424 ODSN42B PBI, ODSN-42B PBI VO ODSK-42i, ODSN-42B PB2, ODSN-42B PB2 VO ODSK42i, ODSN-42B, ODSN-42B VO ODSN-01. ODSN-M KE3 PBI, ODSN-01 KE3 PBI VO h ODSN-02, ODSN-02 PW ext PBI, ODSWO2 PN3 ext PBI VO ODSN-02, ODSN-02 PW ext, ODSN-02 PN3 ext VO # ODSN-03i, ODSN-03i IN4 ext, ODSN-03i IN4 ext VO ODSN-04, ODSN-04 PN5 ext PBI, ODSN-04 PN5 ext PBI VO $ ODSN-04, ODSN-04 PW ext, ODSN-04 PN5 ext VO (4 ODSN-06i, ODSN-06i IS3, ODSN-06i IS3 VO i'A ODSN-074 ODSN-07IN1, ODSN-07IN1 VO X ODSN-07i, ODSN-07i IM PBI, ODSN-07i 1N3 PBI VO L ODSN-10i, ODSN-10i 15EXT PBl, ODSN-10i 15E)CT PBI v0 # ODSN-10i, ODSN-10i 15EXT PB2, ODSN-10i ISEXT PB2 W 0ODSN-10i, ODSN-10i 15EXT PB3, ODSN-10i 15EXT PB3 VO <j ODSN-10i, ODSN-10i 15EXT, ODSN-10i 15EXT VO 3 ODSN-15i, ODSN-15i, ODSN-15i IN12 VO 1+ODSN-16, ODSN-16, ODSN-16 PN13 Surveys VO 14,ODSN-16, ODSN-16L1, ODSN-16L1 PN13 VO # ODSN-17, ODSN-17 Lt, ODSN-17 Ll PN13 VO 460DSN-17, ODSN-17, ODSN-17 PN13 Mrd Surveys VO 4ODSN-18, ODSN-18 PB5, ODSN-18 PNll P85 VO ODSN-18, ODSN-18 PB1, ODSN-18 PMI PBI VO -E�ODSN-18, ODSN-18 PB2, ODSN-18 PWI PB2 VO ODSN-18, ODSN-18 PB2, ODSN-18_ PB2 VO ODSN-18, ODSN-18 PB3, ODSN-18 PNll PB3 VO # ODSN-18, ODSN-18 PB4, ODSN-18 PNll PB4 VO A ODSN-18, ODSN-18, ODSN-18 PN11 VO 49ODSN-19i, ODSN-19i 34 ext PBI, ODSN-19i 34ext PBI VO ODSN-19i, ODSN-19i 34 ext PB2, ODSN-19i 34 ext PB2 VO D ODSN-19L ODSN-19i 34 ed P83, ODSN-19i 34 ext PB3 VO ODSN-19i, ODSN-19i 34 ext, ODSN-19i 34 ext v0 ODSN-22, ODSN-22 PSW2, ODSW22 PSW2 VO # ODSN-21, ODSN-23i Pill, ODSN-23i IN14 P61 VO ODSN-23i, ODSN-23i PB2, ODSN-23i IN14 PB2 VO {� ODSN-23i, ODSN-23i, ODSN-23i IN14 VO 4;+ ODSN-24.ODSN-24 KE5 PBI.ODSN-24 PBI VO ODSN-01A vs N-01 1/4 mile � 3DVrevr Pian: ODSWGIAwp10(ODSN-O1/ODSN-OIA;,- ODSN-01A vs N-01 1/4 mile � i� Pian iiewr - r'!en �D3`i-:kl,� � CSIt �,T:ODSPd-'Ji::, 19 ® 0° 's El ILl ARS 'ic _ (�ODSDWI-44, ODSDWI-44 Disposal, ODSDWI-44 Disposal VO <->ODSK-13,ODSK-13, ODSK-13 VO �L---�_--_-' 14FGDSK-13, ODSK-13PB1, ODSK-13PBI VO Y L= TVtr 14/8: EW: ODSK-13, ODSK-13PB2, ODSK-13PB2 VO +�ODSK-14, ODSK-14 PBI, ODSK-14 P8I KupB VD - -� ^i T T (^ iODSK-14, ODSK-14 PBZ ODSK-14 P82 KupB VO 'Ta0° - --- - - - r _ �---.- }- - -. , - -.- _ . <. aE ODSK-14, ODSK-14, ODSK-14 KupB V0 ODSK-33, QOSK-33 KupA, QDSK-33 KupG VD -}----- ODSK-33, ODSK-33 PB1 Kupq ODSK-33 PBI KupA VO I- , j" ODSK-35Ai, ODSK-35 KupB, ODSK-35 KupB Surveys VO ,rsse .._ . i _:__. j . y $ODSK-35Ai ODSK-35Ay ODSK-35Ai KupH Surveys VO ;.f ! J �• �" - I L _ - �-)4.ODSK-38t ODSK-38, KupD, QDSK-38i KupD Surveys VO a _ _ �� _, •. _ _. A ODSK-41, ODSK-41 KupF, ODSK-41 KupF Surveys V0- ODSK-41, ODSK41 PBl KupF, ODSK-41 PBI KupF VO ( i. ._.. - " - 1 ;moi (.. ' :.. ODSK-421 ODSK-42Ai, ODSK-42Ai VD = ODSK-424 ODSK-42i KupG, ODSK-42i KupG VO ! L4ODSK-42i, ODSN-42B PBI, ODSN-428 PBI VO ,ms ' -�T-?a-- B ODSK-42i, ODSN-42B PBZ, ODSN-42B PB2 VO _ ODSK-42i, ODSN-428, ODSN-42B V0 ," _ '.: , . _ .-.. _ _ ---.� _ _ j.. ___--t AODSN-01, ODSN-01 KB PIU, ODSN-01 KF3 PBI VO �E ODSN-02, ODSN-02 PN3 ext PBI, ODSN-02 PN3 ext PB1 VO QDSN-01,O DSN-03i IN est PBD, N -03i 14 PNS ez[ PBI W _ r^a -!- _ t -� �,�-� -i ! �� �• �` - - -- - � - - -� _ - - a- .�7 1 ert, ODSN-03i 1N4 ext VO � ODSN-04, ODSN-04 PNS cs •�. _ �.. _ �. _. -- _. y _.� DSN A exK ODSN-04 PNS ad VO ODSN-06i, ODSN-06iLS3, ODSN-06i tS3 V0 $ ODSN-07i, ODSN-071N3, ODSN-07IM VO o 1 I - - -• ` �V ( . ODSN-07i, ODSN 07i IM PBI, ODSN 07i IM PBI VO ( • �E 02 ODSN-10i ODSN-10i 15EXT PB3, QDSN-10i 15FXT PV0 - E'$ ODSN-10i, ODSN-30, 15FX7 PBI, ODSN-10i 15FXT PBI VD VD �} ODSN-10i, ODSN-10i 15IXT, ODSN-10i 15IXTW f i 44ODSN-15y ODSN-15� ODSN-15i IN12 VD !� ODSN-16, ODSN-16, ODSN-16 PN13 Surveys VO �$ODSN-16, ODSN-16L1, ODSN-16L1 PN13 VO r , +ODSN-17, ODSN-17 LI, ODSN-17 LI PN13 VO- $ ODSN-17, ODSN-17, ODSN-17 PN13 Mid Surveys VO ( ODSN-18, ODSN-18 PB5, ODSN-18 PMI PB5 VD `.; - 4 f ( `�_ ,• , `• ,46 ODSN-18, ODSN 1B PBI, ODSN 18 PNli P61 VD i j�ODSN-18, ODSN-18PBZ, ODSN-18 PN11 P82 VO L •-" _ /� ODSN-18, ODSN-18 P82, ODSN-18_ PB2 VO T� �. - --- - -+- -., _ ..� .-- : ` . ...____, 1- _.._ _ . _..� . _ _ _. �•� -[I ODSN-18, ODSN-18 PB3, ODSN-18 PN11 PB3 VO ODSN-18, ODSN-18 PO4, QDSN-18 PNll PB4 VO .no ......... __. __ �--f ODSN-SS, ODSNdB, ODSN-18 PN11 V4 � '-- ':,-➢EODSN-19' ODSN-19i34 ext PBI, ODSN-1%34ext PBI VO cn { �} ODSN-194 ODSN-19i 34 ext PBZ, ODSN-19i 34 ext PB2 V0 iODSN-19i, ODSN-19i 34 e. P83, ODSN 19i 34 ext P83 VO- $ ODSN-19i ODSN-19i 34 eA ODSN-19, 34 ext V0 �+ODSN-22, ODSN-22 PSWZ, ODSN-22 PM VO ODSN-23i, ODSN 23i PEI, ODSN-23, IN14 PRI VO { ODSN-23i, ODSN-23i PB2, ODSN-23i IN14 P62 VO �. _.. 1.: I ;--:..._`:•. .�s:s w �cas-,s,5o r '� T �' T Tf'T^T' $ODSN-23i, ODSN-23% ODSN-23i VO -+xss -,� -,-, ,s;n -,sroo ,.�s .a:w u-rrs gram -.:aa _.,a� � s -s -+,.m --ssrrs via sv^s 3. - •._; ...... jAODSN-24, ODSN-24 M PBI, ODSN-24 PBI VO N Legend �44ODSDW-44, ODSDW1-44 Disposal, ODSNV1-44 Disposal VO <>ODSK-13, ODSK-13, ODSK-13 VO 44ODSK-13, ODSK-13P61, ODSK-13PBI VO AODSK-13, ODSK-13PBZ ODSK-13P62 VO 41 ODSK-14, ODSK-14 PBI, ODSK-14 PBI KupB VO -1-ODSK-14, ODSK-14 P82, ODSK-14 PB2 KupB VD 44ODSK-14, ODSK-14, ODSK-14 KupB VO ODSK-33, ODSK-33 KupA, ODSK-33 KupA VO +aODSK-33, ODSK-33 RBI KupG ODSK-33 PBI KupA VO ODSK35AL ODSK-35 KupB, ODSK-35 KupB Surveys VO $ ODSK-35Ai, ODSK-35A6 ODSK-35Ai KupH Surveys VO --)4 ODSK-386 ODSK-38i KupD, ODSK-38i KupD Surveys VO A ODSK-41, ODSK-41 KuPF, ODSK-41 KupF Surveys VO ` ODSK-41, ODSKAI PBI KupF, ODSK41 PBI KupF VO ODSK-42-4 ODSK-42A6 ODSK-42Ai VO ODSK-42i, ODSK-42i KupG, ODSK-42i KupG VO A ODSK-42i, ODSN-42B PBI, ODSN428 PB1 VO $ ODSK-426 ODSN42B PB2, ODSN42B PB2 VO ODSK-42i, ODSN-42B, ODSN-42B VO $ ODSN-01, ODSN-01 KE3, ODSN-01 KE3 VO -4-ODSN-04 ODSN-02 PN3 ext PBI, ODSN-02 PN3 nd PBI VO $ ODSN-02, ODSN-02 PNB ext, ODSN-02 PN3 ext VO ODSN-03i, ODSN-03i FRN ext, ODSN-03i 114 ext VO j ODSN-04, ODSN-04 PN5 amt DBI, ODSN-04 PN5 ext PBI VO A ODSN-04, DDSN-04 PN5 ext, ODSN-04 PN5 ext VO �4 ODSN-06i, ODSN-06i 153, ODSN-06i IS3 VO ODSN-076 ODSN-07IM, ODSN-07111 VO ODSN-07i, ODSN-07i 1M PB1, ODS14-07i M PBI VO '$ ODSN-10i, ODSN-10i 15EXT P61, ODSN-10i 15EXT PB1 VO +ODSN-106 ODSN-1Oi l5EXT PB2, ODSN-10i l5EXT PB2 VO -4ODSN-1Di, ODSN-10i 15EXT PB3, ODSN-10i 15EXT PB3 VO +4� ODSN-10i, ODSN-10i 15EXT, ODSN-10i 15EXT VO A ODSN-156 ODSN-156 ODSN-15i BV12 VO A ODSN-I6, ODSN-16, ODSN-16 PN13 Surveys VO $ ODSN-16, ODSN-161.1, ODSN-161.1 PM3 VO 4 ODSN-17, ODSN-171.3, ODSN-17 Ll PM3 VO $ ODSN-17, ODSN-17, ODSN-17 PN13 Mid Surveys VO A ODSN-18, ODSN-18 P85, ODSN-18 PNn PBS VO -"ODSN-18, ODSN-18 PBl, ODSN-18 PRU PB1 VO A ODSN-18, ODSN-18 PB2, ODSN-18 PNII PB2 VO A ODSN-18, ODSN-18 PB2, ODSN-18- PB2 VO 0ODSN-18, ODSN-18 PB3, ODSN-18 PN21 PB3 v0 -$ ODSN-IB, ODSN-18 P114, ODSN-18 PM1 PB4 VO -4 ODSN-18, ODSN-18, ODSN-18 PMI VO -4 ODSN-196 ODSN-19i 34 ext PBI, ODSN-19i 34ad PBI VO A ODSN-19i, ODSN-19i 34 ext PB2, ODSN-19i 34 ext PB2 VO A ODSN-19i, ODSN-19i 34 ext P83, ODSN-19i 34 ext PB3 VO ODSN-196 ODSN-19i 34 exk ODSN-19i 34 ad VO ODSN-22, ODSN-22 PSW2, ODSN-22 PSW2 VO ODSN-23i, ODSN-23i PBI, ODSN-23i 6314 Pill VO {3 ODSN-236 ODSN-23i PB2, ODSN-23i IM4 P82 VO A ODSN-23i, ODSN-236 ODSN-Z3i IM4 VO AODSN-24, ODSN-24 KE5 PBI, ODSN-24 P61 VO IODSN-01A vs N-01 PB1 1/4 mile PPIaDVic.,,-��Pl-CDSN-£lis..,,pIO(ODSN-01ODSN-41A') --. ........ ..__ n'g+r%�.i[sal 4f ODSN-18, ODSN-18 PB4, ODSN-18 PNIl PB4 VO ,4ODSN-18, ODSN-18, ODSN-18 PMI VO ODSN-194 ODSN-19i 34 ext PBI, ODSN-19i 34eA PB1 VO ODSN-19i, ODSN-19i 34 ext PB2, ODSN-19i 34 ext PB2 VO $ ODSN-19i, ODSN-19i 34 ext PB3, ODSN-19i 34 ext PR3 VO ODSN-19i, ODSN-19i 34 eA ODSN-19i 34 ext VO ODSN-22, ODSN-22 PSW2, ODSN-22 PSW2 VO 44ODSN-23i, ODSN-23i PBI, ODSN-23i IN14 PBI VO ODSN-23i, ODSN-23i PB2, ODSN-23i IN24 PB2 VO A ODSN-23i, ODSN-23i, ODSN-23i IN14 VO $ ODSN-24, ODSN-24 KE5 PBI, ODSN-24 PBI VO ODSN-24, ODSN-24 KE5 PB2, ODSN-24 KE5 PB2 VO ODSN-24, ODSN-24 KE5, ODSN-24 KE5 VO ODSN-25, ODSN-25 PB1, ODSN-25 PB1 VO $ ODSN 25, ODSN-25 PB2, ODSN-25 KEI PB2 VO 44ODSN-25, ODSN-25 PB3, ODSN-25 KE1 PB3 VO ODSN-25, ODSN-25 PB4, ODSN-25 KEI PB4 VO ODSN-25, ODSN-25, ODSN-25 KEI VD E+ODSN-264 ODSN-26r KEZ PBI, ODSN-26i KE2 PB1 VO A ODSN-26i, ODSN-26i KEZ PBZ, ODSN-26 KEZ PB2 VO ODSN-26i, ODSN-26t KE2, ODSN-25i KE2 VO A ODSN-27i, ODSN-27i INA, ODSN-27i IM VO iF ODSN-28, ODSN-26 PN3, ODSN-28 PN3 VO ODSN-29, ODSN-29 PN5 PB1, ODSN-29 PN5 PBl VO 34ODSN-29, ODSN-29 PN5 PB2„ ODSN-29 PNS PB2 VO L ODSN-29, ODSN-29 PNS, ODSN-29 PN5 VO 4ODSN-31, ODSN-31 PBI, ODSN-31PB1 PM Surveys VO A ODSN-31, ODSN-31, ODSN-31 PW Surveys VO �ODSN-32t, ODSN-32i IN7, ODSN-32i IN7 Surveys VO ODSN-32i, ODSN-32iPBI IN7, ODSN-32iP81 IN7 VO r r +ODSN•34i, ODSN-34i P82, OpSN-34iP62IM VO $ODSN-34i, ODSN-34i PB3, ODSN-34iP63 M VO 04ODSN-34L ODSN-34iPB1, ODSN-34iPB1IN9V0 A ODSN-36, ODSN-36 PB1, ODSN-36 PBI PMO VO A ODSN-36, ODSN-36 PB2, ODSN-36 PB2 PNIO VO -4 ODSN-36, ODSN-36 PN1D, ODSN-36 PMO Surveys VO ODSN-37, ODSN-37, ODSN-37 PM VO • ODSNAO, ODSN-40 PN12, ODSN-4O PN12 Surveys VO +� ODSNAO, ODSN-40PB1 PN12, ODSN-40PBI PN12 VO $ ODSN-40, ODSN-40PB2 PN12, ODSN-40P62 PNI2 VO AODSN-43, ODSN-43 Western ERD PBI, ODSN-43 Western ERD PB1 VO 4f ODSN-43, ODSN-43 Westem ERD PB2, ODSN-43 Western ERD PB2 VO �ODSN-43, ODSN-43 Western ERD, ODSN-43 Westem ERD VO �ODSN-48, ODSN-48 Western ERD, ODSN48 Surveys VO ODST-39, ODSN-39i IN11, ODSN-39i IN11 VO +� ODST-39, ODST-39 Torok D PB1, ODST-39 Torok D PBI VO $ ODST-39, ODST-39 Torok D, ODSE-39 Torok D VO r ODST-45, ODSN-45i PBI IM3, ODSN45i PB1 IN13 VO ODST-45, ODST45A, ODST-45A Surveys VO �ODST-46i, ODST-46i P61, ODST-46i Torok C PB1 VO $ ODST-461 ODST-46i PBZ, ODST-46i Torok C PB2 VO ODST-46i, ODST-46 Torok C PB3, ODST-46i PB3 VO ODST-46i, ODST-46i, ODST46i Torok C VO ODST-47. ODST-47. ODST-47 VO ODSN-01A vs N -34i 1/4 mile Heel ,Z� 3D View - Plan ODSN-OSAwpIO (ODSN-0IiODSN-0lA) L 0'1LL A + +R FT Q VAC' �ir sF1 4 Q {Jr{ � ll G3 tiC1AME£_M1C91�i Npe as.ousm: �E ODSN-06i, ODSN-06i IS3, ODSN-06i IS3 VO $ ODSN-076 ODSN-07IN1, ODSN-071N1 VO ° ODSN-07i, ODSN-07i INF PBI, ODSN-07i INl PBI VO } ODSN10i, ODSN-10i 15EXT PBI, ODSN-10i 15EXT PBI VO ODSN-10i, ODSN-10i 15EXT PBZ, ODSN-10i 15EXT PB2 VO �E ODSN-104 ODSN-10i 15EXT PB3, ODSN-l0i 15EXT PB3 VO A ODSN-104 ODSN-10i 15EXT, ODSN-10i 15EXT VO A ODSN-154 ODSN-156 ODSN-15i IN12 VO ')ODSN-16, ODSN-16, ODSN-16 PPIF3 Surveys VO $ ODSN-16, ODSN-16LI, ODSN-16LI PN13 VO ODSN-17, ODSN-17 LI, OMN-17 LI PPII.3 VO $ ODSN-17, ODSN-17, ODSN-17 PN13 Mid Surveys VO +� ODSN-I8, ODSN-18 PB5, ODSN-18 PN11 PB5 VD $ ODSN-18, ODSN-18 PB1, ODSN-18 PNU PBS VO A ODSN-18, ODSN-18 PB2, ODSN-18 PN11 PB2 VO 49 ODSN-18, ODSN-18 P82, ODSN-18- PB2 VO El ODSN-18, ODSN-18 PB3, ODSN-18 PRU P93 VO ODSN-18, ODSN-18 PB4, ODSN-18 PNI1 PB4 VO i>F ODSN-18, ODSN-18, ODSN-18 PNll VO -4- ODSN-19't, ODSN-19i 34 ad PBI, ODSN-19i 34ad PBI VO A ODSN-194 ODSN-19i 34 ext PB2, ODSN-19i 34 ext PB2 VO 44ODSN-194 ODSN-19i 34 ext P83, ODSN-19i 34 ext PB3 VO A ODSN-196 ODSN-19i 34 eA ODSN-19i 34 ext VO ODSN-22, ODSN-22 PSW2, ODSN-22 PW VO ODSN-234 ODSN-23i P81, ODSN-23i INF4 PBI VO �} ODSN-23L ODSN-23i PB2, ODSN-23i 1NF4 PB2 VO ODSN-236 ODSN-234 ODSN-23i IN14 VO A ODSN-24, ODSN-24 KES PBI, ODSN-24 P01 VO -)<- ODSN-24, ODSN-24 KES PB2, ODSN-24 KE5 PB2 VO AODSN-24, ODSN-24 KES, ODSN-24 KE5 VO # ODSN-25, ODSN-25 PBI, ODSN-25 P81 VO B ODSN-25, ODSN-25 PB2, ODSN-25 KEl PB2 VO ODSN-25, ODSN-25 PB3, ODSN-25 KEI P03 VO ODSN-25, ODSN-25 PB4, ODSN-25 KEl PB4 VO 49 ODSN-25, ODSN-25, ODSN-25 KEl VO AODSN-266 ODSN-26i KE2 PBI, ODSN-26i KE2 PBI VO AODSN-264 ODSN-26i KE2 PB2, ODSN-26 KE2 PB2 VO ODSN-26i, ODSN-26i KE2, ODSN-267. KE2 NO ODSN-27i, ODSN-27i IN4, ODSN-27i IN4 VO ODSN-28, ODSN-28 PM, ODSN-28 PN3 VO (� ODSN-29, ODSN-29 PN5 PB3, ODSN-29 PN5 PBF VO +ODSN-29, ODSN-29 PN5 PBZ, ODSN-29 PN5 PB2 VO $ODSN-29, ODSN-29 PN5, ODSN-29 PN5 VO +ODSN-31, ODSN-31 PBI, ODSN-31POl PPG Surveys VO $ ODSN-31, ODSN-31, ODSN-31 PPG Surveys VO �E ODSN-324 ODSN-32i IN7, ODSN-32i IN7 Surveys VO AODSN-324 ODSN-32iPB1 IN7, ODSN-32iPB1 IND VO i ODSN-346 ODSN-34i PB2, ODSN-34iP621N9 VO A ODSN-34i, ODSN-34i P03, ODSN-34iP63 !P9 VO .A ODSN-34i, ODSN-34iPB1, ODSN-34iPB1 IN9 VO A ODSN-36, ODSN-36 PBI, ODSN-36 PBI PN10 VO -'�4ODSN-36, ODSN-36 PB2, ODSN-36 P82 PN10 VO ODSN-36, ODSN-36 PMO, ODSN-36 PN3O Surveys VO $ODSN-37, ODSN-37, ODSN-37 PM VO ODSN-01A vs N -34i 1/4 mile Heel -LI Pill, Vi- - Plan: ODSN-OSAwplO (m?SN-OIIODSN-OIA) MIEN ::`o'Jit�°x _.e...b_-___.__.,_..,..-._..___ ..,.__....._ ...._......._ -.%- � MD.� . ••. Inc'"` �` Ax' Nam¢. . Legend �B ODSDWl-44, ODSDWI-44 Disposal, ODSDW3-44 Disposal VO $ ODSK-13, ODSK-13, ODSK-13 VO igODSK-13, ODSK-13PB1, ODSK-13POl VO ODSK-13, ODSK-13P82, ODSK-13PB2 VO <->ODSK-14, ODSK-14 PBI, ODSK-14 RBI KupB VO -)EODSK-14, ODSK-14 PBZ, ODSK-14 PBZ KupB VO ODSK-14, ODSK-14, ODSK-14 KupB VO -4+ ODSK-33, ODSK-33 KupA, ODSK-33 KupA VO (� ODSK-33, ODSK-33 PB1 KupA, ODSK-33 PBI KupA VO ODSK-35A6 ODSK-35 KupB, ODSK-35 KupB Surveys VO ODSK-35Ai, ODSK-35A6 ODSK-35Ai KupH Surveys VO ODSK-38i, ODSK-38i KuPD, ODSK-38i KupD Surveys VO $ ODSK-41, ODSK41 KupF, ODSK-41 KupF Surveys VO ODSK-41, ODSK-41 P81 KupF, ODSK-41 PBI KupF VO $ ODSK-42i, ODSK42Ai, ODSK-42Ai VO -14 ODSK426 ODSK42i KupG, ODSK-42i KupG VO A ODSK426 ODSN-42B PBI, ODSN-429 PBI VO '> ODSK42i, ODSN-42B PB2, ODSN428 PB2 VO ODSK-42% ODSN-42B, ODSN-42B VO ODSN-01, ODSN-01 KE3 PW, ODSN-01 KE3 PBI VO 41, ODSN-01, ODSN-01 KE3, ODSN-01 KE3 VO A ODSN-02, ODSN-02 PN3 ext PBI, ODSN-02 PN3 ext P61 VO A ODSN-02, ODSN-02 PN3 ext ODSN-02 PN3 ext VO 44 ODSN-03i, ODSN-03i 1N4 ext, ODSN-03i It44 ext VO ODSN-04, ODSN-04 PNS ext PBI, ODSN-04 PNS ext PBI VO $ ODSN-04, ODSN-04 PNS ext ODSN-04 PN5 ext VO A ODSN-066 ODSN-06i 1S3, ODSN-06i 1S3 VO ODSN-076 ODSN-07 641, ODSN-071N1 VO 49 ODSN-076 ODSN-07i IM PB1, ODSN-07i 1NI PBI VO +09iODSN-106 ODSN-10i 15M PBI, ODSN-10i 15EXT PBI VO # ODSN-106 ODSN40i 15EXT PB2, ODSN-10i 15EXT PB2 VO AODSN-106 ODSN-10i 15EXT PB3, ODSN-10i 15EXT PB3 VO AODSN-10i, ODSN-10i 15EXT, ODSN-10i 15EXT VO $ ODSN-156 ODSN-156 ODSN-15i IN12 VO ODSN-16, ODSN-16, ODSN-16 PKI13 Surveys VO ODSN-16, ODSN-1611, ODSN-16L1 PNI3 VO �E ODSN-17, ODSN47 Ll, ODSN-17 LI PN13 VO 4, ODSN-17, ODSN-17, ODSN-17 PN13 Mid Surveys VO ODSN-18, ODSN-18 PB5, ODSN-18 PNU PB5 Vo �4 ODSN-18, ODSN-18 PBI, ODSN-18 PN11 PB1 VO $ ODSN-18, ODSN-18 PB2, ODSN-18 PN11 PB2 VO $- ODSN48, ODSN-18 PB2, ODSN-18- P82 VO ODSN-18, ODSN-18 P83, ODSN-18 PNII PB3 VO }E ODSN-18, ODSN-18 P64, ODSN-18 PNII PB4 V0 �ODSN-18, ODSN-18, ODSN-18 PNU VO A ODSN-196 ODSN-19i 34 ext PBS, ODSN-19i 34e d P81 VO ODSN-196 ODSN-19i 34 ext PBZ, ODSN-19i 34 ext PB2 VO $ ODSN496 ODSN-19i 34 ext PB3, ODSN-19i 34 ext PB3 Vo A ODSN-19i, ODSN-19i 34 ext, ODSN-19i 34 ext VO A ODSN-22, ODSN-22 PSW2, ODSN-22 PSW2 VO ODSN-236 ODSN-Z3i PB1, ODSN-23i IN14 PBI VO ODSN-23i, ODSN-23i PBZ, ODSN-23i IN14 PB2 VO AODSN-23i, ODSN-23i, ODSN-23i IN14 VO ODSN-01A 1/4 mile Torok 13D Vimv - Flan: ODSN-OlA wp10 40DSN-01I0DSN-0IA7 i ra e.!-1 11 ll _Y K ,�. •�• , •�a _ I•r, � � .,,iw .i. e. .-.. n _.. _ ... .. _. _ .. _... .... � ._.. _. ._ 1, ODSN-01A vs DW44 1/2 mile Torok ODSN-01A vs DW44 1/2 mile Torok tF ODSN-0lA wp10 4eOODSDWI-44, ODSDWI-44 Disposal, ODSDM-44 Disposal VO <>ODSK-13, ODSK-13, ODSK-13 VO # ODSK-13, ODSK-13P61, ODSK-13PB1 VO ODSK-13, ODSK-13PB2, OD5K-13PB2 VO ODSK-14, ODSK-14 PBI, ODSK-14 P61 KupB VO ODSK-14, ODSK-14 P92, ODSK-14 PBZ KupB VO �EODSK-14, ODSK-14, ODSK-14 KupB VO ODSK-33, ODSK-33 KupA, ODSK-33 KupA VO s�ODSK-33, ODSK-33 PBI KupA, ODSK-33 P61 KupA VO ODSK-35Ai, ODSK-35 KupB, ODSK-35 KupB Surveys VO $ ODSK-35Ay ODSK-35Ai, ODSK-35Ai KupH Surveys VO -*ODSK-38i, ODSK-38i KupD, ODSK-38i KupD Surveys VO 44ODSK-41, ODSK-41 KupF, ODSK-41 KupF Surveys VO ODSK-41, ODSK-41 PBI KupF, ODSK-41 PBI KupF VO ODSK-42i, ODSK-42A, ODSK-42Ai VO ODSK-42k ODSK42i KupG, ODSK42i KupG VO ODSK42i, ODSN-42B PBI, ODSN-42B PBI VO $ ODSK-42i, ODSN-428 PBZ, ODSN-42B PB2 VO 0 ODSK-42i, ODSN-42B, ODSN-42B VO AODSN-01, ODSN-01 KE3 PBI, ODSN-01 KE3 PBI V0 a sa -)FODSN-02, ODSN-02 PN3 ext PBI, ODSN-02 PNB ext PBI VO ODSN-02, ODSN-02 PN3 ext, ODSN-02 PN3 ext VO ODSN-03i, ODSN-03i IN4 ext, ODSN-03i IM ext VO ODSN-04, ODSN-04 PN5 ext PBI, ODSN-04 PN5 ed PBS VO A ODSN-04, ODSN-04 PN5 ext, ODSN-04 PN5 ext VO -'0E ODSN-06i, ODSN-06i IS3, ODSN-06i IS3 VO $ODSN-07i, ODSN-07IN1, ODSN-07641 VO ODSN-07i, ODSN-07i IM PB1, ODSN-07i INI PBl VO ODSN-10i, ODSN-10i 15EXT PB1, ODSN-10i 15EX7 PBJ VO ODSN-10i, ODSN-10i 15EXT PB2, ODSN-10i 15EXT PB2 VO -X- ODSN-10i, ODSN-10i 15EXT PB3, ODSN-10i 15EXT P03 VO A ODSN-10i, ODSN-10i 15EXT, ODSN-10i 15EXT VO 1\4ODSN-15i, ODSN-15i, ODSN-15i IN12 VO A ODSN-16, ODSN-16, ODSN-16 PN33 Surveys VO $ODSN-16, ODSN-161-1, ODSN-16LI PN13 VO +ODSN-17, ODSN-17 LI, ODSN-17 LI PN13 VO $ ODSN-17, ODSN-17, ODSN-17 PN13 Mid Surveys VO L ODSN-18, ODSN-18 P65, ODSN-18 PN11 P65 VO ODSN-18, ODSN-18 PBI, ODSN-18 PMI PBI VO 44ODSN-18, ODSN-18 PB2, ODSN-18 PM1 PB2 VO 49ODSN-18, ODSN-18 PB2, ODSN-18_ PB2 VO {] ODSN-18, ODSN-18 PB3, ODSN-18 PN31 PB3 VO -ODSN-18, ODSN-18 P134, ODSN-18 PNSI PB4 VO aE ODSN-18, ODSN-18, ODSN-18 PN11 VO ODSN-19i, ODSN-19i 34 ext PBI, ODSN-19i 34ext PB1 VO AODSN-19i, ODSN-19i 34 ext PB2. ODSN-19i 34 ext PB2 VO (� ODSN-19i, ODSN-19i 34 ext PB3, ODSN-19i 34 ext PB3 VO ODSN-19i, ODSN-19i 34 mdt ODSN-19i 34 ext VO ODSN-22, ODSN-22 PSW2, ODSN-22 PSW2 VO ODSN-23i, ODSN-23i PBI, ODSN-23i IM4 PBl VO ¢3 ODSN-23i, ODSN-23i 11112, ODSN-23i IN14 PB2 VO ODSN-23i, ODSN-23i, ODSN-21 IN14 VO x ODSN-01A vs N-01 1/4 mile Torok 3D View - P€m ODSN-01A v:p1O (ODSN O1fODSN-OIA) . E..t gefls4 {� LD ODSK-33, ODSK-33 PBI Kup& ODSK-33 WKupA VO � ODSK-35Ai, ODSK-35 KupB, ODSK-35 KupB Surveys VO ODSK-35Ai, ODSK-35Ai, ODSK-35Ai KupH Surveys VO ODSK-38(, ODSK-38i KupD, ODSK-38i KupD Surveys VO ODSK-41, ODSK-41 KupF, ODSK-41 KupF Surveys VO ODSK-41, ODSK-41 PB1 KupF, ODSK-41 PB1 KupF VO ODSK-42i, ODSK-42Ai, ODSK-42Ai VO ODSK-42i, ODSK-42i KupD, ODSK-42i KupG VO ODSK-42i, ODSN-42B PBI, ODSN-42B PBI VO ODSK-42i, ODSN-428 PB2, ODSN-42B PB2 VO ODSK-421, ODSN-426, ODSN-42B VO ODSN-01- ODSN-01 KE3 RBI. ODSN-01 KE3 PBI VO (q ODSN-O2, ODSN-02 PN3 est PB1, ODSN-02 PN3 ext PB1 VO A ODSN-02, ODSN-02 PN3 ext, ODSN-02 PNB ext VO -,,<- ODSN-03k ODSN-03i IM ext, ODSN-03i IN4 ext VO ODSN-04, ODSN-04 PN5 at PBI, ODSN-04 PN5 ext PB1 VO $ ODSN-04, ODSN-04 PN5 eat, ODSN-04 PN5 ext VO [9ODSN-06i, ODSN-06i W. ODSN-06i IS3 VO A ODSN-07i, ODSN-071N3, ODSN-071N1 V0 ()ODSN-07i, ODSN-07iRd PBI, ODSN-07i1N1 PBI VO A ODSN-10i, ODSN-10i 15EXT PBI, ODSN-10i 15EXT P81 VO 3F ODSN-10i, ODSN-10i 15EXT PB2, ODSN-10i 15EXT PB2 VO ODSN-10i, ODSN-10i 15EXT P83, ODSN-10i 15EXT P83 VO AODSN-10i, ODSN-10i15E)CT, ODSN-10i15EXTV0 $ ODSN-15i, ODSN-15i, ODSN-15i IM2 VO ODSN-16, ODSN-16, ODSN-16 PN13 Surveys VO ODSN-16, ODSN-161-1, ODSN-161-1 PN13 VO -�0qE ODSN-17, ODSN-171-I, ODSN-17 U PN13 VD ODSN-17, ODSN-17, ODSN-17 PNI3 Mid Surveys VO (� ODSN-18, ODSN-18 PBS, ODSN-18 PMI PBS VO (� ODSN-18, ODSN-18 PB1, ODSN-18 PN11 PB1 VO $ ODSN-18, ODSN-18 P82, ODSN-18 PNU PB2 VO $_ ODSN-18, ODSN-18 PB2, ODSN-18_ PB2 VO A ODSN-18, ODSN-18 PB3, ODSN-16 PPi11 PB3 VO 4 ODSN-18, ODSN-18 PB4, ODSN-18 PN11 PB4 VO ODSN-18, ODSN-18, ODSN-18 PN11 VO ODSN-19i, ODSN-19i 34 ext PBI, ODSN-19i 34ext PBI VO ODSN-19i, ODSN-19i 34 ext PB2, ODSN-19i 34 ext PB2 VO $ ODSN-19i, ODSN-19i 34 act PB3, ODSN-19i 34 est P03 VO (�O ODSN-19i, ODSN-19134 ext, ODSN-19134 ext VO 4�O ODSN-22, ODSN-22 PSW2, ODSN-22 PSW2 VO ODSN-23i, ODSN-23i PBI, ODSN-23i IN14 PBI VO +9e ODSN-23i, ODSN-231 P02, ODSN-23i IN14 PB2 VO A ODSN-23i, ODSN-231, ODSN-23i IN14 VO $ ODSN-24, ODSN-24 KE5 PB1, ODSN-24 PBI VO A ODSN-24, ODSN-24 KES PB2, ODSN-24 KE5 PB2 VO ODSN-24, ODSN-24 KES, ODSN-24 KE5 VO AODSN-25, ODSN-25 PBI, ODSN-25 PB1 VO $ ODSN-25, ODSN-25 PB2, ODSN-25 KES PB2 VO -)<- ODSN-25, ODSN-25 P03, ODSN-25 KE1 P83 VO A ODSN-25, ODSN-25 PBA, ODSN-25 KEl P84 VO ODSN-25, ODSN-25, ODSN-25 KEI VO ❑ ODSN-26i, ODSN-26i KE2 PBI, ODSN-26i KE2 PBS VO 4ODSN-26i, ODSN-26i KE2 PB2, ODSN-26 KE2 PB214 ODSN-01A vs N-01 1/4 mile Torok 3D Vieev - Plan: ODSN-OiA avp1O ,ODSN-OVODSN-OlA?. Well No. Alaska State fare - Y l=atitude (M _ __ _Q�ti-- Longitude (VV) 4n LInBSSL FEL@ Rad t lev, 1 2 _ 6,031,151.32 6, 031,146.35 469,920,46 469, 915.52 _ 70 2046,24160 70 29 46,19252 _ _ 15014 45,46468 1$V14-45,-6--Q--9-22--T0-30 3036 7-01T--737-50 10$2 13.50 3 6,031,141.39 469,910,59 70 29 46,14354 101447 l;a 3026 108 13,50 4 6,031,136.46 469,905,67 70 294 6.M85 15014 45,89799 3020 109 13.50 6,031,131,454%,M.7-47-02-9 466.04536 15014 46,04252 301 -1007T-- 09 6 6 6, 031,126, 51 +469, 895, 00 70 29 45, 99660 15014 46,16735 3010 1102 13.50 7 6,031,113.73 459,003,13 70 294-6.07039 16014 46,6 29$7 11 S 13.x0 8 6,031,108,73 469, 87$.21 70 29 45,$2102 13014 -46,700-$ 2992 1120 13,50 9 6,031,103.7-5 469, 873,26 70 2.9 46.771$4 15014 46, 14 29$ 112 13.50 'I0 601,098,79 469,868,36 70 29 45,72266 15014 46,99179 298 1130 13,50 11 6,031,093,84 469,663,39 70 28 45,6730$ 1$014 47,13760 2977 11:5 13,5p 12 6,031,068,$7 4%,-8-%,-4-7-- 70 29 45,62490 150 14 4718174 2972 1140 13,50 13 6, 031, 076,06 469, 845,61 70 29 46,4084 15014 47, 65288 2960 1152 13,50 14 15 6, 031, 071,09 6, 031, 066.15 469, 840, $7 469,8.5, 96 70 29 45, 44932 70-2W 45,40053 150 14 47.79770 150 1447,94165 2955 -200--116 1157 13,50 13.50 16 6,031,061,15 469,831,04 70 29 45.35145 15014 46,0 2946 116 -717-2-13,50 13,50 17 6,031, 056, 25 469, 826.11 70 29 45, 30277 150 14 48, 23042 2940 16 -6,031,051,27 469, 821,16 70 29 45, 25359 15014 4$, 37495 2935 1177 13,50 19 6, 031, 038, 52 459,505,W-- 70 29.45.12768 15014 48, 74668 1189 13,50 20 ?1 6, 031, 033,50 6,031,02 ,53 469, 603, 5a 469;796.62 70 29 45, 07811 70 2 45,02903 15014 48,09051 15014 4-9 03632 _2922 2917 291 1194 1199 13.$ 13,50 22 6,031,0 23, S$ 469, 793, 67 70 29 444, 98014 15014 49,1$144 2 1204 13.5 23 1-6,031,018'.57 --469,788,76 70-29 44, 93067 TWO 49, 325372902 1209 13,50 24 5,031,013,60 469,783,5-4 702944-M159 15014 49,46950 2 1214 13,50 V\t� R��ssicW�- �P�i Nous: 1, Elevatigns or@ based on 9P Mean $ea Level, 2, Cogrdinotes are Ogsed on Alosko Rote Plone Nod 27, Zane 4. 3, All conductors ore within Protrocted Section 11. .Pioneer Natural Resouaes JOB NAME: 000quruk gill Site Conductors DRAWN BY: Bl. CHECKED BY: miD LOCATION., Protrocted section 11 SCALE: NIA Township 13 North Ronge 7 Sost DATE: 7-12-07 Umiot Meridign -- NANUC JOB N4, EhiEE'� ESCRIPTIQN: As -wilt CQordinatos 05204 1 3 of 4 Well No. Alaska State Plane Y X Latitude (N) Longitude (W) Section FSL Line Offset FEL Pad Elev. 25 6,031,128.32 469,943.64 70 29 46.01630 150 14 44.77930 3013 1055 13.50 26 6,031,123.35 469, 938.69 70 29 45.96722 150 14 44.92442 3008 1060 13.50 27 6,031,118.33 469, 933.76 70 29 45.91765 150 14 45.06895 300 1065 13.50 28 6,031,113.39 469, 928.86 70 29 45.86887 150 14 45.21260 2997 1070 13.50 29 6,031,108.44 469, 923.95 70 29 45.81999 150 14 45.35655 2992 1075 13.50 30 6,031,103.45 469,919.01 70 29 45.77071 150 14 45.50137 2988 1079 13.50 31 6, 031, 090.65 469, 906.38 70 29 45.64431 15014 45.87163 2975 1092 13.50 32 6, 031, 085.68 469, 901.39 70 29 45.59523 150 14 46.01793 2970 1097 13.50 33 6,031,080.67 469,896.50 70 29 45.54576 150 14 46.16128 2965 1102 13.50 34 6,031,075.73 469,891.57 70 29 45.49698 150 14 46.30581 2960 1106 13.50 35 6, 031, 070.76 469, 886.60 70 29 45.44789 150 14 46.45152 2955 1111 13.50 36 6, 031, 065.83 469, 881.69 70 29 45.39921 150 14 46.59547 2950 1116 13.50 37 6, 031, 053.00 469, 869.00 70 29 45.27251 150 14 46.96749 2937 1129 13.50 38 6, 031, 047.99 469, 864.14 70 29 45.22304 150 14 47.10995 2932 1134 13.50 39 6, 031, 043.03 469, 859.20 70 29 45.17406 150 14 47.25478 2927 1139 13.50 40 6, 031, 038.10 469, 854.21 70 29 45.12537 150 14 47.40108 2922 1144 13.50 41 6,031,033.05 469,849.29 70 29 45.07551 150 14 47.54530 2917 1149 13.50 42 6,031,028.13 469,844.38 70 29 45.02692 150 14 47.68925 2912 1154 13.50 43 6,031,015.46 469,831.70 70 29 44.90180 150 14 48.06099 2899 1166 13.50 44 6, 031, 010.49 469, 826.79 70 29 44.85272 150 14 48.20493 2894 1171 13.50 45 6, 031, 005.53 469, 821.86 70 29 44.80373 150 14 48.34946 2889 1176 13.50 46 6, 031, 000.54 469, 816.94 70 29 44.75446 150 14 48.49369 2884 1181 13.50 47 6, 030, 995.50 469, 811.98 70 29 44.70469 150 14 48.63910 2879 1186 13.50 48 6, 030, 990.58 1 469, 807.07 70 29 44.65610 1 150 14 48.78304 2874 1191 13.50 . nF A f - U 11111%1OFESS10Nm-, I HEREBY CERTIFY THAT I AM PROPERLY REGISTERED AND LICENSED TO PRACTICE LAND SURVEYING IN THE STATE OF ALASKA AND THAT THIS PLAT REPRESENTS A SURVEY DONE BY ME OR UNDER MY SUPERVISION AND THAT I BELIEVE THAT ALL DIMENSIONS AND OTHER DETAILS ARE CORRECT AS SUBMITTED TO ME BY NANUQ, INC. AS OF JULY 12TH, 2007. Pioneer Natural Resouces JOB NAME: Oooguruk Drill Site Conductors DRAWN BY: BL CHECKED BY: MJD, LOCATION: Protracted Section 11 SCALE: N/A Township 13 North Range 7 East DATE: 7-12-07 Umiat Meridian NANUQ JOB NO. SHEET DESCRIPTION: As -built Coordinates 05204 4of4 ODSN-01 PTD# 211-166 Report of Operations Addendum to the 404 Sundry ODSN-01 9/17/2014 Bettis, Patricia K (DOA) From: Alex Vaughan <Alex.Vaughan@caelusenergy.com> Sent: Friday, January 1S, 2016 11:32 AM To: Bettis, Patricia K (DOA) Cc: Oooguruk DrillingTechAdmin Subject: Re: ODSN-01A Permit to Drill Application (PTD 216-008) Yes, ODSN-01A is a proposed development oil well. Alex Sent from my iPhone On Jan 15, 2016, at 11:17 AM, Bettis, Patricia K (DOA) <patricia.bettis@alaska.gov> wrote: Good morning Alex, Please verify that ODSN-01A is a proposed development oil well. This was left off the Form 10-403, Box 1b. 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. Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. Schwartz, Guy L (DOA) From: Alex Vaughan <Alex.Vaughan@caelusenergy.com> Sent: Thursday, January 21, 2016 5:33 PM To: Schwartz, Guy L (DOA) Cc: Oooguruk DrillingTechAdmin; Robert Tirpack; Rami Jasser Subject: RE: ODSN-01 P & A and sidetrack (PTD 216-008) Guy, As discussed today via telephone: • We will perform a pressure test against the IBP at 6,743' MD to 1,000 psi for 30 min charted. o I have already sent the request to our Wells Group. I am expecting results over the weekend. • Caelus intends to pump the Second Stage of the 12 Cement Job. We will include the cement job information on future schematic submissions to the AOGCC to avoid confusion. • The ODSN-01A 12 hole section will be drilled with a 8.5" bit and 9.5" under -reamer BHA. We will indicate this on future AOGCC coversheets under Table 18 Hole Size Column. • The ODSN-01A Intermediate 2 Stage 1 cement job volume of 117 bbls was incorrect. Please replace this with the following corrected 12 Stage 1 cement volume information: o 88 bbls, 420 sks I will be in touch again beginning of next week with pressure test results. Alex Vaughan Senior Drilling Engineer Caelus Energy Alaska, LLC 3700 Centerpoint Dr. I Anchorage, AK 99503 Direct 907.343.2186 1 Cell 907.748.5478 alex.vaughan@caelusenergy.com From: Schwartz, Guy L (DOA)(mailto:guy.schwartzCalalaska.gov] Sent: Thursday, January 21, 2016 12:35 PM To: Alex Vaughan Subject: RE: ODSN-01 P & A and sidetrack (PTD 216-008) Also the proposed well schematic doesn't show the 2 stage anywhere. Assume you will pump 2 Ind stage no matter what. 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.aov). From: Schwartz, Guy L (DOA) Sent: Thursday, January 21, 2016 12:22 PM To: 'Alex Vaughan' Subject: ODSN-01 P & A and sidetrack (PTD 216-008) Alex, I am still going to require a retest of the IBP once you get on location to verify it is still a barrier. A test 6 months ago is may not be valid today on an IBP. Cement on top of it would make it permanent. (SL dump bail? ) Also, in reviewing the PTD application the int 1 casing cement volume is off by a bit. Looks like a OH size is 9 %" instead of 8.5" OH. Look at both stages for the 7" casing as it carried over to both. Regards, 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). Statement of Confidentiality: This message may contain information that is privileged or confidential. If you receive this transmission in error, please notify the sender by reply e-mail and delete the message and any attachments. TRANSMITTAL LETTER CHECKLIST WELL NAME: p UobsQ_014 PTD: ( OO /Development _ Service Exploratory Stratigraphic Test _ Non -Conventional FIELD: t POOL: nn Ck I A k L_1*'6_'C, (A� Check Box for Appropriate Letter / Paragraphs to be Included in 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 on permit). 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 sam les 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 OOOGURUK, NUIQSUT OIL - 576150_ Well Name: OOOGURUK NUQ ODSN-01A Program DEV _ Well bore seg ❑ PTD#:2160080 Company CAELUS NATURAL RESOURCES ALASKA LLC Initial Class/Type DEV/PEND GeoArea 890 Unit 11550 On/Off Shore Off Annular Disposal ❑ Administration 17 Nonconven. gas conforms -to AS31.05,030(i.1.A),(j.2.A-D) - - - - - - - - - -- - - - - - - - - NA_ - -- - - -- - - - - - -- . - - - - - - - _ _ _ _ _ - - - - _ . . 1 Permit- fee attached- - - - - - - - - - - - - --- - - - - - - - - -- - - NA- -- - -- - - - --- -- - - - - - ----- - - - -- -- 2 Lease number appropriate- - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - - - -- - Yes - - - - - - - ADL0355036, Surf Loc & Top _ Prod Interv; ADL0389959,-TD- 3 Unique well,n_ameandnumber- - _ - - _ - - - _ _ _ _ .. _ Yes - - _ - - _ _OoogurukODSN-01A- - - - - - - - - - - - - - - - - - - - - - - - 4 Well -located in.a-defined pool- - - - - - - - - - - - - - - - - _ _ _ _ _ _ . _ ------------- Yes - - - - _ - - OOOGURUK,_NUIQSUT OIL- 576150,_govemed_by Conservation -Order No, 597- - - - _ . . ------ 5 Well located proper distance from drilling unit boundary_ Yes _ _ _ _ _ _ _ CO 597 - -tains no spacing restrictions with respect -to drilling unit boundaries. - 6 Well located proper distance from other wells_ - - - - - . - - - - - - - Yes - - - - - - - CO 597 has no interwell-spacing_restrictions- - - - _ _ - - - - _ . _ 7 Sufficient acreage -available in_dril_ling unit - - - - Yes - - 8 If-deviated,is_wellbore plat_ included - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - . - - - - _ - _ _ - - -- - - - - - - - - - _ _ _ - - - _ - _ _ . _ _ - - - -- - - - - - - - - - - - 9 Operator only affected party- - - - - - - - - - - - - Yes - . - - - - - Wellbore -will be -more than 500' from an external property line where ownership or landownership_ changes._ - 10 Operator has -appropriate- bond in force - - - - - - - - - - - - - - -- - - --------- - - -- Yes - - - - _ _ _ . _ - - - - - - - - - - - - - - - - _ _ _ _ _ _ _ ---------------------------- Appr Date 11 Permit_ can beissued __without conservation order __-------- - - -- -- Yes________________________________________________ ______________ 12 P e r m i i c a n b beissued _w_ i t h o u t ad m i n i s t r a t i v_ e - ap p r o v a I - - - - - - - - - - - - - - - - .. _ Yes - - - - - _ _ _ _ _ _ _ _ - - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - _ . _ . _ . _ _ . _ _ _ _ _ _ _ _ PKB 1/20/2016 13 Can permit be approved before 15 -day wait- - - - - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 14 Well located within area and strata authorized by_ Injection Order # (put -10# in -comments)- (For NA- - - - - - - - - - - - - - - - - - - - - - - - _ .. _ - - - - _ .. _ _ . _ _ _ _ _ - - _ - - - - - - _ - 15 _A_ll wells -within -1/4 mile -area -of review identified (For service well only)- - - - - - - - - - - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 16 Pre -produced injector: duration of pre -production less than 3 months -(For -service well only) - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 18 Conductor string- provided - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - ----- NA_ - - - - - - _ Conductor set_in ODSN-01 - - - - - - - - - - - - - _ _ _ . - - - -- - - - -- - - - - - - -- - - ----- Engineering 19 Surface casing protects all -known USDWs - - - - - - - - - - - - - - - - NA- - - - - - _ - Surface casing set in ODSN-01 - - - - - - - _ _ _ . 20 CMT_vol_ adequate to circulate -on conductor & surf-csg - - - - - - - - NA- . - - - - - - Surface casing cement to surface ,., window to be cut at 4088ft md._ 21 CMT_v_ol_ adequate to tie -in -long string to surf csg---------------------- -- - - N_o_ - - - - _ _ _ 7"-x-9.5/8" will -have cement_in Liner lap -- - - - - - _ _ - - - - - - - - - - - - - - - - - - 22 CMT -will co -ver -a-11 known -productive horizons_ - - - - _ - - - - - - Yes - - - - _ - lateral will haveported_non-cemented_liner for frac treatment. - - - - 23 _Casing designs adequate for CJ, B &_ permafr_ost_ - _ - _ - - - - - - - Yes - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 24 Adequate -tankage -or reserve pit - _ - - - - _ _ - - - - - - _ - - - -- Yes .. _ _ _ - _ Rig has steel pits, All waste to -approved -disposal well onsite, 25 If_a_re-drill,has _a10-403 for abandonment been approved - - - - ------- - - - - - -- -- Yes -----__Sundry316-021_---------------------------- ----- --------- 26 Adequate wellbore separation proposed- - - - - - - - - - - - - - _ _ - - - - - - - _Yes - - - _ _ _ _ anti,collision_report furnished_ No issues. 27 If_diverter required, does it meet_ regulations- - - - - - - - - - - - - - - .. - - - - - _ _ _ - - - - - N_A_ - - - _ _ _ _ Wellhead in place.. BOP will be used, _ - - - - - - - - - - - - - . - - _ - - - _ _ _ _ _ _ _ - - _ - - - - - - - - - - Appr Date 28 Drilling fluid program schematic-&- equip list_adequat_e- - - - - - - - - - - - - - - - - - - - - - - Yes - - - - _ - _ Max form pressure =_3.196 psi (9,8 ppg EMW) will_ used 8 ppg-MOBM and used MPD for BHP control. - - - - - - GLS 1/21/2016 29 _B_OPEs,_do they meet_ regulation - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - Yes - - - _ _ _ - Using MPD on Int 1_ and -lateral -drilling, -_ - - - - - - _ _ _ _ _ _ - - - - _ - - _ _ - - - - - - - - - - - - _ _ 30 BOPE_press rating appropriate; test to -(put psig in comments)- - - - - - - - - - - - - - - - - - - - Yes - - - - _ _ _ MASP = 2506_psi_will test BOP -to 4500-psi(casingrams to -3500 psi) _ - - - - _ - _ - - - - - _ - _ _ 31 Choke_manifold complies w/API_ RP -53 (May 84)_ - - - - - - - - - - - - - - - Yes - - - - - _ _ _ _ _ _ _ _ _ _ _ _ _ - - - - - _ _ - - - _ _ _ _ _ - - - - _ _ _ _ _ _ _ _ _ - _ _ - _ - - 32 Work will occur without operation shutdown- - - - - - - - - - - - - - - - - - - -Yes - - - - - - _ Sundry_approval for hydraulic_frac operations is required. ----------------------- 33 Is presence of 1-12S gas probable - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -- - - - No- - _ _ - _ - - 1-12S not expected. _Rig has_sensors_and alarms. _ - - - - - - - - - - - - - - - - - - - _ - _ - _ - - _ _ _ _ _ . 34 Mechanical condition of wells within AOR verified (For service well only_) _ _ _ _ _ _ _ _ _ _ _ _ _ NA_ - - - - - _ _ _ _ _ _ _ _ _ - _ _ - - - - - _ _ _ _ _ - - - _ _ _ - - - - - - - _ _ _ _ _ . _ _ _ _ _ _ _ _ _ . _ _ - _ _ - - _ - - - _ 35 Permit can be issued w/o hydrogen_ sulfide measures _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Yes - - - - - _ - H2S not expected. _Rig equipped with -sensors & alarms._ H2$ sequestering agents -will be_ available - - - - - - - - Geology 36 Data_presented on potential overpressure zones - - - - _ - - - - - ------------ -- - - - Yes - - - - - _ - Expected reservoir -pressure is 9,8_ppg EMW; intermediate hole will be drilled using-10.0-10,4-0.mud._ Appr Date 37 Seismic_analysis_ of shallow gas -zones -------------------- _ _ _ _ _ _ _ _ _ _ _ _ _ _ _NA_ - - - _ _ Production- hole -will be_drilled_using 7:4 to 8.4 ppg mud and MPD -technique. _ _ _ - _ _ - - - - - _ - - - - - - PKB 1/20/2016 38 Seabed condition survey -(if off_ -shore) - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - NA- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - 39 Contact name/phone for weekly_ progress reports_ [exploratory only] N _ A - Development well to be drilled from man-made island. _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - - - opment Geologic Engineering Public Sidetrack of ODSN-01 ... window cut out of surface casing at 4088 ft. and . GIs Commissioner: Date: Commissioner: Date Commissioner Date ''s 11 2 4 V4 -e-,4 /ZZ -��
