The URL can be used to link to this page

Home My WebLink About212-0827. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU S-32A Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 212-082 50-029-22099-01-00 11848 Conductor Surface Intermediate Liner Liner 8987 80 2657 10071 253 1990 9007 20" 13-3/8" 9-5/8" 7" 3-1/2" x 3-1/4" x 2-7/8" 7941 34 - 114 33- 2685 31- 10099 9860 - 10113 9855 - 11845 34 - 114 28 - 2685 28 - 8810 8264 - 8821 8621 - 8987 None 2260 4760 5410 10530 9007, 9389 5020 6870 7240 10160 7524 - 7590 4-1/2" 12.6# 13Cr80 28 - 7445, 9314 - 9913 6741 - 6795 Structural 4-1/2" HES TNT Packer 9832, 8603 7388, 9832 6632, 8603 Torin Roschinger Operations Manager Hunter Gates hunter.gates@hilcorp.com (907) 777-8326 PRUDHOE BAY, Aurora Oil Pool Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028257 28 - 6678, 8189 - 8666 See Attached Report See Attached Report Well Test Not Available 98 193 1422 1400 900 240 300 325-275 13b. Pools active after work:Aurora Oil Pool 4-1/2" TIW Packer 7388, 6632 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations No SSSV Installed By Gavin Gluyas at 8:03 am, Jul 16, 2025 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.07.15 20:39:43 - 08'00' Torin Roschinger (4662) RBDMS JSB 072525 CDW 07/16/2025 JJL 8/12/25 ACTIVITY DATE SUMMARY 6/7/2025 SLB Frac Job Scope: Perform hydraulic fracture stimulation to Kuparuk C formation. MIRU Frac fleet, spot POD, iron missile, five frac pumps, PCM, LAS, Frac Cat. Rig up high pressure iron and suction hoses. Double tap frac tanks and start loading fresh water. 6/9/2025 Assist Frac (FRACTURING) Heated/Loaded 71 BBLS 90* Diesel from Worley tanker to SLB Tanker (100 BBLS Total). Pumped 7 bbls into IA maintaining IA pressure during frac. Pumped 10 bbls diesel for TBG FP per WSS SCARPELLA. FWHP's 3643/498/0 DSO notified of well status per LRS departure. Tang hung on Master. SSV/SV/WV= Closed IA/OA= OTG JOB CONTINUED ON 6-10-25 6/9/2025 SLB Frac Job Scope: Perform hydraulic fracture stimulation to Kuparuk C Sands. Flood pump and function test equipment.Pressure test frac equipment to 5500 psi. Pump the following fluids and sand concentration. 70 bbls Fresh water w/adds Hard Shut Down ISIP- 2100 psi Mix up YF128ST X-Link Gel Pump OE approved frac schedule at 25 bpm. 100 bbls Pad of YF128ST 100 bbls 0.5 PPA Scour 100 bbls Pad of YF128ST 100 bbls 1 PPA 75 bbls 2 PPA 75 bbls 3 PPA 75 bbls 4 PPA 75 bbls 5 PPA 75 bbls 6 PPA 75 bbls 7 PPA 85 bbls 8 PPA Saw pressure spike increasing at end of 8 PPA sand stage. Elected to stay at 8 PPA and screened out 2 bbls later. Sand in formation 58051 lbs Sand in wellbore 38640 lbs (7-8 PPA) Total sand pumped 96691 lbs of 16/20 CarboBond Hand well over to LRS to freeze protect. (See LRS for details) ***Job complete*** 6/10/2025 Assist Frac **JOB CONTINUED FROM 6-9-25** 6/11/2025 SLB CTU #8 1.75" .156" WT. Job Scope: Post Frac FCO Mobilize (Service road to S-pad flooding over down to one lane) & MIRU CTU #8. NU BOP & Fnc Test. MU 1.75" slim BHA Tag @ 705'. Begin FCO - no frac sand & clean Linar fluid returns. RIH dry tag @ 4237' CTM. POOH to remove dfcv/prep for reverse FCO. Begin reverse FCO from 4200' ***Job in Progress*** 6/12/2025 SLB CTU #8 1.75" .156" WT. Job Scope: Post Frac FCO Continue FCO, the long way from 7521' to 7800'. Chase OOH 80%. FP well 2500' w/ diesel. RDMO CTU 8. ***Job Complete*** Daily Report of Well Operations PBU S-32A Daily Report of Well Operations PBU S-32A 6/13/2025 ***WELL S/I ON ARRIVAL*** BEGIN RIGGING UP SLICKLINE. DELAYED DUE TO MECHANICAL ISSUES. ***CONTINUED ON 6-14-25*** 6/13/2025 LRS WTU #6 Begin WSR 6/13/25. Post frac flowback Continue WSR on 6/14/25 6/14/2025 LRS WTU #6 continue WSR from 6/13/25. Post frac flowback Continue WSR on 6/15/25 6/14/2025 ***CONTINUED FROM 6-13-25*** RAN 4 1/2" BRUSH AND 3.79" GAUGE RING. BRUSHED GLM's AND NIPPLE @ 7421' MD. SET 3.81" X CATCHER @ 7421' MD. PULLED RK-DGLV FROM ST# 1 @ 7280' MD PULLED RK-DGLV FROM ST# 2 @ 6617' MD PULLED RK-DGLV FROM ST# 3 @ 5705' MD PULLED RK-DGLV FROM ST# 4 @ 4582' MD PULLED RK-DGLV FROM ST# 5 @ 3329' MD SET RK-LGLV IN ST#5 @ 3329' MD SET RK-LGLV IN ST#4 @ 4582' MD SET RK-LGLV IN ST#3 @ 5705' MD SET RK-LGLV IN ST#2 @ 6617' MD SET RK-OGLV IN ST#1 @ 7280' MD PULLED CATCHER FROM 7421' MD. ***WELL S/I ON DEPARTURE*** 6/15/2025 LRS WTU #6 continue WSR from 6/14/25. Post frac flowback Continue WSR on 6/16/25 6/16/2025 LRS WTU #6 continue WSR from 6/15/25. Post frac flowback Continue WSR on 6/17/25 6/17/2025 LRS WTU#6. Continue WSR from 6/16/25. Post Frac Flowback. Continue WSR to 6/18/25 6/18/2025 LRS WTU #6. Continue WSR from 6/17/25. Post Perf Flowback. Continue End WSR on 6/18/25 6/25/2025 LRS Test Unit 6, Begin WSR on 6/25/25, S-32 IL, S-38 OL, Rig Down Job, End WSR on 6/25/25 FracCAT Treatment Report Well : S-32A Field : Aurora Formation : Kuparuk Well Location : Greater Prudhoe Bay State : Alaska Country : United States Prepared for Client : Hilcorp North Slope, LLC Client Rep : Hunter Gates Date Prepared : June 9, 2025 Prepared by Name : Michael Hyatt Division : Schlumberger Phone : 907-227-9897 Pressure (All Zones) Initial Wellhead Pressure (psi) 780 Surface Shut in Pressure(psi) 2,347 Maximum Treating Pressure (psi) 4,367 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbl) 1,128.7 Total Proppant Pumped per FracCat (lb) 96,691 Total YF128ST Past Wellhead (bbl) 939 Total Proppant in Formation per FracCat (lb) 65,922 Total WF128 Past Wellhead (bbl) 0 Total Freeze Protect Past Wellhead (bbl) 0 Chemical Additives Mixed / Used Past WH Chemical Additives Mixed / Used Past WH F103 (gal) 41 41 M275 (lb) 30 14 L065 (gal) 41 41 J475 (lb) 137 136 J580 (lb) 1,551 1,259 J134 (lb) 11 0 J532 (gal) 97 96 S123 (gal) 56 55 L071 (gal) 82 81 Disclaimer Notice This information is presented in good faith, but no warranty is given by and Schlumberger assumes no liability for advice or recommendations made concerning results to be obtained from the use of any product or service. The results given are estimates based on calculations produced by a computer model including various assumptions on the well, reservoir and treatment. The results depend on input data provided by the Operator and estimates as to unknown data and can be no more accurate than the model, the assumptions and such input data. The information presented is Schlumberger's best estimate of the actual results that may be achieved and should be used for comparison purposes rather than absolute values. The quality of input data, and hence results, may be improved through the use of certain tests and procedures which Schlumberger can assist in selecting. The Operator has superior knowledge of the well, the reservoir, the field and conditions affecting them. If the Operator is aware of any conditions whereby a neighboring well or wells might be affected by the treatment proposed herein it is the Operator's responsibility to notify the owner or owners of the well or wells accordingly. Prices quoted are estimates only and are good for 30 days from the date of issue. Actual charges may vary depending upon time, equipment, and material ultimately required to perform these services. Freedom from infringement of patents of Schlumberger or others is not to be inferred. Client : Hilcorp North Slope, LLC Well : S-32A Formation : Kuparuk District : AKA Country : United States 09:56:20 10:25:30 10:54:40 11:23:50 11:53:00 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 Tr. Press - psi0 5 10 15 20 25 30 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 18 20 Prop Con - PPATreating Pressure Annulus Pressure Slurry Rate Prop Con BH Prop Con PRC Plot © Schlumberger 1994-2017 Hilcorp S-32A 6/9/2025 Client : Hilcorp North Slope, LLC Well : S-32A Formation : Kuparuk District : AKA Country : United States As Measured Pump Schedule As Measured Pump Schedule Step # Step Name Slurry Volume (bbl) Slurry Rate (bbl/min) Pump Time (min) Fluid Name Fluid Volume (gal) Proppant Name Max Prop Conc (PPA) Prop Conc (PPA) Prop Mass (lb) 1 Injection 85.8 17.8 6.4 Water 3605 0.0 0.0 0 2 Pad 150.0 24.2 6.3 YF128ST 6300 0.0 0.0 0 3 Scour 100.0 24.9 4.0 YF128ST 4113 16/20 CarboBOND Lite 0.5 0.5 2029 4 Pad 150.0 25.1 6.0 YF128ST 6297 0.0 0.0 0 5 1.0 PPA 100.0 25.0 4.0 YF128ST 4033 16/20 CarboBOND Lite 1.1 0.9 3768 6 2.0 PPA 75.1 25.0 3.0 YF128ST 2904 16/20 CarboBOND Lite 2.1 1.9 5551 7 3.0 PPA 75.1 24.9 3.0 YF128ST 2794 16/20 CarboBOND Lite 3.0 1.9 8029 8 4.0 PPA 75.1 25.0 3.0 YF128ST 2682 16/20 CarboBOND Lite 4.1 3.9 10546 9 5.0 PPA 75.1 25.1 3.0 YF128ST 2585 16/20 CarboBOND Lite 5.2 4.9 12743 10 6.0 PPA 75.2 25.0 3.0 YF128ST 2495 16/20 CarboBOND Lite 6.2 5.9 14785 11 7.0 PPA 75.2 25.0 3.0 YF128ST 2410 16/20 CarboBOND Lite 7.2 6.9 16707 12 8.0 PPA 91.1 24.7 3.9 YF128ST 2823 16/20 CarboBOND Lite 9.5 8.0 22533 13 Freeze Protect 0.9 1.0 0.9 Freeze Protect 39 0.0 0.0 0 Stage Pressures & Rates Step # Step Name Average Slurry Rate (bbl/min) Maximum Slurry Rate (bbl/min) Average Treating Pressure (psi) Maximum Treating Pressure (psi) Minimum Treating Pressure (psi) 1 Injection 17.8 25.3 3293 3956 1084 2 Pad 24.2 25.3 3291 3510 2764 3 Scour 24.9 25.1 3549 3572 3510 4 Pad 25.1 25.3 3529 3565 3486 5 1.0 PPA 25.0 25.2 3490 3569 3403 6 2.0 PPA 25.0 25.2 3338 3402 3282 7 3.0 PPA 24.9 24.9 3187 3195 3178 8 4.0 PPA 25.0 25.1 3123 3179 3072 9 5.0 PPA 25.1 25.2 3024 3075 2983 10 6.0 PPA 25.0 25.2 2945 2993 2902 11 7.0 PPA 25.0 25.3 2940 2965 2911 12 8.0 PPA 24.7 25.2 3052 3633 1468 13 Freeze Protect 1.0 1.2 3326 3922 30 As Measured Totals Slurry (bbl) Pump Time (min) Clean Fluid (gal) Proppant (lb) 1128.7 49.5 43081 96691 Client : Hilcorp North Slope, LLC Well : S-32A Formation : Kuparuk District : AKA Country : United States Job Messages Message Log # Time Message Treating Pressure (psi) Annulus Pressure (psi) Total Slurry (bbl) Slurry Rate (bbl/min) Prop. Conc. (PPA) 1 8:03:58 Priming Pumps 0 0 0.0 0.0 0.0 2 8:25:06 Starting PT 54 -1250 0.0 0.0 0.0 3 8:32:54 Good Check Valve 3810 -1250 0.0 0.0 0.0 4 9:46:15 Issues with POD 67 2003 0.0 0.0 0.0 5 10:12:20 Well Open 23 turns 788 2156 0.0 0.0 0.0 6 10:13:34 Start Injection Automatically 1093 2515 0.0 1.9 0.0 7 10:13:34 Start No name Automatically 1093 2515 0.0 1.9 0.0 8 10:13:34 Start Stage 2 Automatically 1093 2515 0.0 1.9 0.0 9 10:13:40 Started Pumping 1389 2524 0.0 2.8 0.0 10 10:17:53 Activated Extend Stage 3958 2821 51.2 25.2 0.0 11 10:23:51 Mixing Gel 1640 2963 70.6 0.0 0.0 12 10:47:25 Deactivated Extend Stage 2786 2652 85.8 14.7 0.0 13 10:47:25 Start Pad Manually 2786 2652 85.8 14.7 0.0 14 10:49:26 Stage at Perfs: Injection 3315 2829 129.5 24.8 0.0 15 10:52:51 Stage at Perfs: Pad 3413 3103 215.3 25.0 0.0 16 10:53:41 Start Scour Automatically 3529 3138 236.2 25.0 0.0 17 10:53:41 Started Pumping Prop 3529 3138 236.2 25.0 0.0 18 10:57:42 Start Pad Automatically 3512 3264 336.1 25.1 0.5 19 10:57:54 Stopped Pumping Prop 3502 3269 341.1 25.0 0.0 20 10:58:53 Stage at Perfs: Scour 3488 3291 365.8 25.1 0.0 21 11:02:52 Stage at Perfs: Pad 3552 3269 465.9 25.0 0.0 22 11:03:40 Start 1.0 PPA Automatically 3545 3280 485.9 25.0 0.0 23 11:03:41 Started Pumping Prop 3553 3279 486.3 25.1 0.0 24 11:07:41 Start 2.0 PPA Automatically 3399 3271 586.3 25.0 1.0 25 11:08:51 Stage at Perfs: 1.0 PPA 3345 3278 615.5 25.1 2.1 26 11:10:41 Start 3.0 PPA Automatically 3284 3287 661.3 25.0 1.9 27 11:12:52 Stage at Perfs: 2.0 PPA 3194 3294 715.9 25.0 2.9 28 11:13:41 Start 4.0 PPA Automatically 3173 3297 736.2 24.9 2.9 29 11:15:53 Stage at Perfs: 3.0 PPA 3081 3300 791.2 24.9 4.1 30 11:16:42 Start 5.0 PPA Automatically 3085 3265 811.6 25.0 4.0 31 11:18:52 Stage at Perfs: 4.0 PPA 2977 3266 865.8 25.1 5.0 32 11:19:41 Start 6.0 PPA Automatically 2994 3268 886.4 25.0 5.1 33 11:21:53 Stage at Perfs: 5.0 PPA 2902 3032 941.4 24.9 5.9 34 11:22:42 Start 7.0 PPA Automatically 2909 2810 961.8 25.0 6.0 35 11:24:52 Stage at Perfs: 6.0 PPA 2926 2825 1015.9 25.1 7.2 36 11:25:42 Start 8.0 PPA Automatically 2946 2831 1036.8 25.0 7.0 37 11:27:53 Stage at Perfs: 7.0 PPA 2933 2847 1091.4 25.3 8.2 38 11:29:05 Activated Extend Stage 3609 2881 1121.5 24.9 8.0 39 11:43:07 Stopped Pumping Prop 1532 2757 1127.7 0.0 0.9 40 11:46:34 Closed Well 23 Turns 1369 2730 1127.7 0.0 0.0 41 12:04:41 Open Well 797 2527 1127.7 0.0 0.0 42 12:05:47 Started Pumping 2740 2554 1127.7 1.4 0.0 43 12:05:53 Deactivated Extend Stage 2834 2554 1127.8 1.3 0.0 44 12:05:53 Start Freeze Protect Manually 2834 2554 1127.8 1.3 0.0 45 12:08:37 Well Closed 23 turns 2369 2496 1128.7 0.0 0.0 46 12:47:45 Well Open 23 Turns 390 1909 1128.7 0.0 0.0 47 12:47:55 LRS FP Well 383 1908 1128.7 0.0 0.0 Hydraulic Fracturing Fluid Product Component Information Disclosure Job Start Date: 06/09/2025 Job End Date: 06/09/2025 State: Alaska County: Beechey Point API Number: 50-029-22099-01-00 Operator Name: Hilcorp Alaska, LLC Well Name and Number: PRUDHOE BAY UNIT S-32A Latitude: 70.353296 Longitude: -149.029755 Datum: WGS84 Federal Well: NO Indian Well: NO True Vertical Depth: 7941 Total Base Water Volume (gal)*: 39083 Total Base Non Water Volume: 0 Water Source Percent Surface Water, < 1000TDS 100.00% Hydraulic Fracturing Fluid Composition: Trade Name Supplier Purpose Ingredients Chemical Abstract Service Number (CAS #) Maximum Ingredient Concentration in Additive (% by mass)** Maximum Ingredient Concentration in HF Fluid (% by mass)** Comments F103 Schlumberger Surfactant J475 Schlumberger Breaker J532 Schlumberger Crosslinker J580 Schlumberger Gel J580 L065 Schlumberger Scale Inhibitor L071 Schlumberger Clay Control Agent M275 Schlumberger Bactericide S123 Schlumberger Activator S526- 1620 Schlumberger Propping Agent Items above are Trade Names. Items below are the individual ingredients. Water (Including Mix Water Supplied by Client)*7732-18-5 0.00000 82.54581 None Ceramic materials and wares,66402-68-4 95.58447 16.68349 None chemicals Guar gum 9000-30-0 1.82094 0.31783 None 2-hydroxy-N,N,N- trimethylethanaminium chloride 67-48-1 0.73674 0.12859 None Propan-2-ol 67-63-0 0.36403 0.06354 None 1, 2, 3 - Propanetriol 56-81-5 0.28214 0.04925 None Alcohols, c11-15-secondary, ethoxylated 68131-40-8 0.27105 0.04731 None Sodium tetraborate decahydrate 1303-96-4 0.23039 0.04021 None Diammonium peroxodisulphate 7727-54-0 0.15892 0.02774 None Ethylene Glycol 107-21-1 0.11611 0.02027 None 2-Propenoic acid, polymer with sodium phosphinate 129898-01-7 0.10849 0.01894 None 2-butoxyethanol 111-76-2 0.09297 0.01623 None Ethoxylated C11 Alcohol 34398-01-1 0.08540 0.01491 None Ethoxylated Alcohol 68131-39-5 0.04635 0.00809 None Vinylidene chloride/methylacrylate copolymer 25038-72-6 0.03774 0.00659 None Sodium chloride 7647-14-5 0.02170 0.00379 None Calcium chloride 10043-52-4 0.01114 0.00194 None Diatomaceous earth, calcined 91053-39-3 0.01015 0.00177 None 1-undecanol (impurity) 112-42-5 0.00744 0.00130 None Silicon Dioxide (Impurity) 7631-86-9 0.00456 0.00080 None Magnesium nitrate 10377-60-3 0.00203 0.00035 None 5-chloro-2-methyl-4- isothiazolin-3-one and 2- methyl-4-isothiazolin-3-one 55965-84-9 0.00122 0.00021 None 2,2''-oxydiethanol (impurity) 111-46-6 0.00117 0.00020 None Magnesium chloride 7786-30-3 0.00101 0.00018 None Magnesium silicate hydrate (talc)14807-96-6 0.00099 0.00017 None poly(tetrafluoroethylene) 9002-84-0 0.00099 0.00017 None Sodium hydroxide (impurity) 1310-73-2 0.00059 0.00010 None Potassium chloride (impurity) 7447-40-7 0.00059 0.00010 None Acetic acid, potassium salt (impurity)127-08-2 0.00028 0.00005 None Cristobalite 14464-46-1 0.00020 0.00004 None Quartz, Crystalline silica 14808-60-7 0.00020 0.00004 None Acetic acid (impurity) 64-19-7 0.00005 0.00001 None * Total Water Volume sources may include various types of water including fresh water, produced water, and recycled water ** Information is based on the maximum potential for concentration and thus the total may be over 100% Note: For Field Development Products (products that begin with FDP), MSDS level only information has been provided. Ingredient information for chemicals subject to 29 CFR 1910.1200(i) and Appendix D are obtained from suppliers Material Safety Data Sheets (MSDS) Chemical disclosure available on www.fracfocus.org 07/16/2025 CDW. 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in this pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU S-32A Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 212-082 50-029-22099-01-00 ADL 0028257 11848 Conductor Surface Intermediate Production Liner 8987 80 2657 10071 253 1990 9007 20" 13-3/8" 9-5/8" 7" 3-1/2" x 3-1/4" x 2-7/8" 7941 34 - 114 33- 2685 31- 10099 9860 - 10113 9855 - 11845 4500 34 - 114 28 - 2685 28 - 8810 8264 - 8821 8621 - 8987 None 2260 4760 5410 10530 9007, 9389 5020 6870 7240 10160 7524 - 7590 4-1/2" 12.6# 13Cr80 28 - 7445, 9314 - 99136741 - 6795 Structural 4-1/2" HES TNT Packer 4-1/2" TIW Packer 7388, 6632 9832, 8603 Date: Torin Roschinger Operations Manager Hunter Gates hunter.gates@hilcorp.com (907) 777-8326 PRUDHOE BAY 5/31/2025 Current Pools: Aurora Oil Proposed Pools: Aurora Oil Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662) Date: 2025.05.02 11:17:04 - 08'00' Torin Roschinger (4662) 325-275 By Grace Christianson at 11:24 am, May 02, 2025 CDW 05/13/2025 A.Dewhurst 22MAY25 JJL 5/14/25 5/31/2025 Variance requested to 20 AAC 25.283(a)(6)(B) is approved. DSR-5/6/25 S-43 tubing and annuli to be monitored while S-32A frac pumping. Include a PRV on OA or hold an open bleed on OA during fracture treatment. 10-404 *&: 5/28/2025 Jessie L. Chmielowski Digitally signed by Jessie L. Chmielowski Date: 2025.05.28 08:30:42 -08'00' RBDMS JSB 052925 Kuparuk Frac Well: S-32A PTD: 212-082 Well Name:S-32A Permit to Drill:212-082 Current Status:Operable, Producer API Number:50-029-22099-01 Estimated Start Date:May 31, 2025 Estimated Duration:5days Regulatory Contact:Abbie Barker Sundry Number: First Call Engineer:Hunter Gates (907) 777-8326 (O)(215) 498-7274 (M) Second Call Engineer:Tyson Shriver (907) 564-4542 (O)(406) 690-6385 (M) Current Bottom Hole Pressure:4,096 psi @ 6,700’ TVDss Max Anticipated Treating Pressure:4,500 psi Last SI WHP: 227 psi on 3/18/2025 Min ID:3.813” @ 2,170’ MD X-Nipple Max Angle:39 deg @ 5,300’ MD Brief Well Summary: S-32A is a Kuparuk producer that is Operable but currently shut-in due to its inability to flow. This was a CTD sidetrack completed in early September 2012. A rig workover in May 2023 was performed as we performed an UHRC to the Kuparuk reservoir. The Ivishak was adequately P&A’d and 66’ of Kuparuk perforations were shot. Testers began flowback, but the well had issues with inflow and was just cycling gas lift gas. Well has been shut in since. Reservoir P&A was completed with CT in April 2024. Objective: Set dummy GLV’s. Pressure test. Install tree-saver. Perform hydraulic fracture stimulation to stimulate the Kuparuk C formation. Flow well back through portable test separator. Current Status: Operable Producer, Shut-In Recent Integrity: x 5/26/2023 – MIT-IA passed to 3,500 psi x 6/2/2023 – MIT-T passed to 3,613 psi Procedure: Slickline/Fullbore 1. MIRU SL. 2. Make a drift run past bottom perf (~7600’ MD). 3. Set plug in X-nipple at 7,421’. 4. Set catcher on top of the plug. 5. Pull LGLV’s. Install DGLV’s in Stations #2 thru #5 and flow sleeve in Station #1. 6. Circulate wellbore to 1% KCl or Seawater and crude freeze protect. U-tube crude freeze protect. a. Total TBG & IA Volume down to Station #1: 111 bbls + 390 bbls = 501 bbls b. Freeze protect volume to 2500’ in TBG & IA: 38 bbls + 134 bbls = 172 bbls 7. Pull flow sleeve from Station #1 and install DGLV. 8. Perform MIT-T to 3,500 psi (max applied 3800 psi). 9. Perform MIT-IA to 3,500 psi (max applied 3800 psi). Hold 1000 psi on tubing during MIT-IA. 10. Pull catcher and plug. Kuparuk Frac Well: S-32A PTD: 212-082 11. Fullbore to perform an injectivity test on formation once MIT’s are completed to max target pressure of 3000 psi. Frac 1. MIRU frac spread and associated equipment/tanks. a. Heat water to 110 deg F, minimum pumping temp – 90 deg F 2. Pull water from each tank and have SLB lab test our water quality: a. pH - ~7 i. Higher pH delays the hydration of the gel and delays break b. Calcium/magnesium <500 mg/l i. Mg/Ca Negative side effects in the formation such as carbonate deposits, which tend to be insoluble c. Bicarbonate - <400 mg/l i. High bicarbonate levels will cause slow hydration times and elevated delay times with X-linking fluids. If we have elevated bicarbonate levels and have introduced delay agents, it could have an exponential effect in delay times. d. Chlorides-<10,000 mg/l i. This fluid system should be able to cope with elevated Chloride levels e. Iron (Fe+3) - <5 mg/l i. Elevated Iron concentrations exist, the ammonium persulfate (breaker) can have an accelerated effect. Can cause viscosity degradation in linear gels (especially if batch mixed). Also can interfere with X-linking b/c iron will tie up the X-linking sites. f. TDS – minimal/<5000 i. Effects depend on the solids that are dissolved in the fluid. 3. Perform pressure tests prior to performing hydraulic fracture stimulation. a. Pressure test surface lines to at least 5,500 psi. b. Pressure test pump kick outs to 4,050 psi and global kick outs to 4,275 psi. c. Function test IA Pop-Off system to ensure operating properly. IA Pop-Offs to be set at 3,325 psi. d. Bring IA pressure up to a hold pressure of 3,025 psi. 4. Pump the hydraulic fracture stimulation per the proposed pump schedule below. Maximum allowable treating pressure is 4,500 psi. Test pop-offs to set pressure. Kuparuk Frac Well: S-32A PTD: 212-082 Anticipated Pressures: MIT-T 3,500 psi MIT-IA 3,500 psi Maximum Anticipated Treating Pressure:3,080 psi @ 25 BPM IA Pop-off Set Pressure (~95% of MIT-IA):3,325 psi IA Minimum Hold Pressure (POP-off – 300 psi):3,025 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T): 4,500 psi (tree limited to 5,000psi) Stagger Pump Kickouts Between 90 – 95% of MATP:4,050 – 4,275 Global Kickout (95% of MATP):4,275 psi N2 POP-off set pressure (MATP + 1000 psi):4,500 psi Treating Line Test Pressure (MATP + 1000 psi):5,500 psi OA Pressure:Monitor Max Anticipated Proppant Loading:12 PPA 5. RDMO frac equipment. Freeze protect well. Coil Tubing (Pending) – FCO if early screenout occurs during frac or perfs are covered w/ proppant 1. MU BDJSN. a. Recommended to run without checks so reverse circulating can be performed. 2. RIH dry and tag top of proppant. 3. PU and establish circulation. a. Recommended to perform reverse FCO until returns are less than ~70% 4. FCO down to ~9,000’ MD. a. Once returns fall below ~70% pickup and circulate coiled tubing clean. Swap circulation to the long way and continue FCO with gel sweeps. Kuparuk Frac Well: S-32A PTD: 212-082 b. If losses become unmanageable while forward circulating and perfs are still covered can attempt FCO with diesel. If losses are still unmanageable with diesel, coil will need to rig down for SL to install gas lift valves. Slickline 1. MIRU SL. Set LGLV design. Portable Testers 1. MIRU, pressure test 2. POP the well to LRS with 1-1.5 MMSCFD Lift gas at minimum choke, adjust GL rate as necessary to eliminate slugging. Flow the initial returns to the flowline as long as the shake-outs meet the returned fluid/solids management guidelines. a. If at any point, solids are >0.5%, divert returns to flowback tanks. 3. Limit flow to ~500 bpd 4. If solids are < 1%, after 1.5 wellbore volumes (188 bbls) increase the production rate to 750 BLPD. 5. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to 1000 BFPD. 6. Flow bottoms up (~125 bbls) and sample for solids production. If solids are still below 1% continue to increase the flow rate in 250 BPD increments. The objective is to achieve maximum drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well to clean up before choke is opened further. 7. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr piggyback well test. Attachments: x Current Wellbore Schematic x Sundry Revision Change Form Kuparuk Frac Well: S-32A PTD: 212-082 Current Wellbore Schematic: Kuparuk FracWell: S-32APTD: 212-082Sundry Revision Change Form:Changes to Approved Sundry ProcedureDate:Subject:Sundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDateProcedure ChangeHNSPreparedBy (Initials)HNSApprovedBy (Initials)AOGCC Written ApprovalReceived (Person andDate)Approval:Operations Manager DatePrepared:Operations Engineer Date S-32A Fracture Stimulation PTD: 212-082 Page 1 Date: April 24, 2025 Subject: S-32A Fracture Stimulation From: Hunter Gates O: (907) 777-8326 C: (215) 498-7274 To: AOGCC Estimated Start Date: 5/31/2025 Attached is Hilcorp’s proposal and supporting documents to perform a fracture stimulation on well S- 32A (PTD #212-082) in the Kuparuk reservoir of the Prudhoe Bay Unit. The objective of this program is to perform a single stage fracture stimulation to the existing Kuparuk perforations to improve well performance. S-32A was recently recompleted as a Kuparuk producer, previously an Ivishak producer. The Ivishak perforations were plugged on 4/8/2023 with cement filling the Ivishak production liner. Isolation from the Ivishak was demonstrated with a state witnessed passing MIT on 4/11/2023. The Kuparuk interval was recompleted and perforated on 6/04/2023. Hilcorp requests a variance to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling. Please direct questions or comments to Hunter Gates. Hilcorp requests a variance to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling. S-32A Fracture Stimulation PTD: 212-082 Page 2 SECTION 1 - AFFIDAVIT (20 AAC 25.283, a, 1): Below is an affidavit stating that the owners, landowners, surface owners and operators identified on a plat within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283, a 1 S-32A Fracture Stimulation PTD: 212-082 Page 3 SIGNED AFFIDAVIT: S-32A Fracture Stimulation PTD: 212-082 Page 4 COPY OF NOTIFICATION SENT VIA EMAIL: S-32A Fracture Stimulation PTD: 212-082 Page 5 SECTION 2 - PLAT IDENTIFYING ALL WELLS WITHIN ½ MILE (20 AAC 25.283, a, 2): Plat of wells within one-half mile of S-32A trajectory. S-32A Fracture Stimulation PTD: 212-082 Page 6 LIST OF WELLS IN PLAT WITHIN ½ MILES ON SURFACE (20 AAC 25.283, a, 2, C): Sw Name Well Class Desc Well Status Desc Sw Name Well Class Desc Well Status Desc Sw Name Well Class Desc Well Status Desc ϱ͏͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͕͐͐͑ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͑͏ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͏͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͖͐͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͑͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώŜēŪťώĖĲ ϱ͏͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͐͗ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͑͐͏ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͏͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͐͘ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͑͐͒ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͏͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͐͘ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͑͐͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͏͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͐ ôŘŽĖèô æÍĲîĺĲôî ϱ͑͐͒[͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ>īĺſĖĲČ ϱ͏͑[͐ "ôŽôīĺŕıôĲť iĖīώ®ôīī ϱ͐͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͑͐͒[͐ϱ͏͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ>īĺſĖĲČ ϱ͏͑[͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͑͐͒[͑ "ôŽôīĺŕıôĲť iĖīώ®ôīī ϱ͏͑͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͑͏ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͑͐͒[͒ "ôŽôīĺŕıôĲť iĖīώ®ôīī ϱ͏͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͑͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͔͑͐ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώŜēŪťώĖĲ ϱ͏͓ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ ϱ͐͑͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͕͑͐ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώŜēŪťώĖĲ ϱ͏͔ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͑͑ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώiŕôŘÍťĖĲČ ϱ͖͑͐ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώŜēŪťώĖĲ ϱ͏͔ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͐͑͑͐ "ôŽôīĺŕıôĲť īŪČČôîώ Íèħώ>ĺŘώôîŘĖīī ϱ͑͐͗ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͏͔͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͑͑͑ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͑͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͏͕ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͐͑͑͒ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͑͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͏͖ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͑͒ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťώĖĲ ϱ͑͑ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͏͖ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͓͐͑ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͑͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͏͗ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͔͐͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͓͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͏͗ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͔͐͑͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͑ ôŘŽĖèô æÍĲîĺĲôî ϱ͏͗ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͕͐͑ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘ ώēŪťώIĲ ϱ͓͑͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͏͘ ôŘŽĖèô æÍĲîĺĲôî ϱ͕͐͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͓͑ ôŘŽĖèô ®ÍťôŘ ώIĲĤôèťĺŘώēŪťώĖĲ ϱ͏͘ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώiŕôŘÍťĖĲČ ϱ͕͐͑͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͔͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͏͐͘ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͕͐͑ "ôŽôīĺŕıôĲť iĖīώŘĺ îŪèôŘώēŪťϱIĲ ϱ͔͑ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͏͑͘ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͑͗ ôŘŽĖèô aĖŜèĖæīôώIĲĤ ôèťĺŘώiŕôŘÍťĖĲČ ϱ͔͑͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͏͒͘ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͑͗͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͕͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͐͏ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͑͗͑ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͖͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͏ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͑͘ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͖͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͏ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͑͘ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͖͑͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͏͏͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͑͐͘ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͖͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͐͏͐ ôŘŽĖèô ®ÍŘôŘώIĲĤôèťĺŘώiŕôŘÍťĖĲČ ϱ͐͑͑͘ "ôŽôīĺŕıôĲť īŪČČôîώ Íèħώ>ĺŘώôîŘĖīī ϱ͑͗ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͑ "ôŽôīĺŕıôĲť æÍĲ îĺĲôî ϱ͑͗ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ ͑͗ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͏͑[͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͒ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͑͗͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͏͑[͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͐͒ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͑͘ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͑͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͔͐͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͑͘ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ ϱ͐͏͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͔͐͒͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͑͘[͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ ϱ͐͏͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͔͐͒͑ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͒͏ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͐͏͓ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώiŕôŘÍťĖĲČ ϱ͐͒ "ôŽôīĺŕıôĲť iĖīώŘĺî ŪèôŘώēŪťώĖĲ ϱ͒͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͔ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͒͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͒͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͐͏͔ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͓͐ ôŘŽĖèô æÍĲîĺĲôî ϱ͒͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͕ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͓͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ ϱ͒͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ S-106A "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͔͐ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώēŪťϱIĲ ϱ͒͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťώĖĲ S-106L1PB1 "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͔͐͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͒ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͐͏͕[͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͕͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͔͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͏͕͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͕͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͕͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͐͏͖ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώĖĲĤôèťĖĲČ ϱ͖͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͖͒ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͗ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͖͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͖͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͐͏͐͘ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͖͐[͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͖͒͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͏ "ôŽôīĺŕıôĲť ŪŜŕôĲîôî ϱ͖͐[͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώ ôîŘĖīī ϱ͒͗ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͐͏͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͖͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͏ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͏͑ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͖͐ "ôŽôīĺŕıôĲť æÍĲ îĺĲôî ϱ͓͏͏ ôŘŽĖèô æÍĲîĺĲôî ϱ͐͐ ôŘŽĖèô æÍĲîĺĲôî ϱ͖͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͓͏͏ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ ϱ͐͐͏ ôŘŽĖèô æÍĲîĺĲôî ϱ͖͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͏͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ ϱ͐͐͏ ôŘŽĖèô æÍĲîĺĲôî ϱ͖͐͑ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖ īī ϱ͓͏͐͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͐͏ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͐͗ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͓͏ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͐͐͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͐͗ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ ͓͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͐͐͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͗ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͓͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͐͐͐͑ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͘ "ôŽôīĺŕıôĲť iĖīώŘĺîŪ èôŘώēŪťϱIĲ ϱ͓͐[͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ ϱ͐͐͑ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͑͏ ôŘŽĖèô æÍĲîĺĲôî ϱ͓͐[͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͐͑[͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώIĲĤôèťĖĲČ ϱ͑͏͏ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͓͐͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͐͑[͐͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͑͏͏ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͓͑ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͐͐͑[͐͑ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͑͏͏͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͐͒ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͑͏͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͓͑͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͐͐͒ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͑͏͐ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώiŕôŘÍťĖĲČ ϱ͓͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͐͒ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͑͏͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͓͒[͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͐͐͒[͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώēŪťϱIĲ ϱ͑͏͑ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͓͓ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͓͐͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî S-202L1 "ôŽôīĺŕıôĲť iĖīώ®ôīī ϱ͓͓ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ>īĺſĖĲČ ϱ͓͐͐ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώiŕôŘÍťĖĲČ ϱ͑͏͑[͑ "ôŽôīĺŕıôĲť iĖīώ®ôīī ϱ͓͓[͐ "ôŽôīĺŕıôĲť æÍĲîĺĲôî ϱ͔͐͐ "ôŽôīĺŕıôĲť iĖīώŘĺîŪèôŘώ@ÍŜώ[Ėċť ϱ͑͏͑[͒ "ôŽôīĺŕıôĲť iĖīώ®ôīī ϱ͓͓[͐͐ "ôŽôīĺŕıôĲť īŪČČôîώÍèħώ>ĺŘώôîŘĖīī ϱ͕͐͐ ôŘŽĖèô æÍĲîĺĲôî ϱ͑͏͑[͓ "ôŽôīĺŕıôĲť iĖīώ®ôīī ϱ͔͏͓ ôŘŽĖèô ®ÍťôŘώIĲĤôèťĺŘώēŪťϱIĲ ϱ͕͐͐ ôŘŽĖèô aĖŜèĖæīôώIĲĤôèťĺŘώiŕôŘÍťĖĲČ ϱ͕͐͐͐ ôŘŽĖèô īŪČČôîώÍèħώ>ĺŘώôîŘĖīī S-32A Fracture Stimulation PTD: 212-082 Page 7 SECTION 3 - EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25.283, a, 3): Well S-32A is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1- 4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are situated at a depth and location that makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are reported to have total dissolved solids content of 7000 mg/ I or more. 4. By letter of July 1, 1986, EPA- Region 10 advises that the aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a non-substantial program revision not requiring notice in the Federal Registrar. Per the above findings, " Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC 25. 440" thus allowing Hilcorp exemption from 20 AAC 25. 283, a, 3- 4 which require identification of freshwater aquifers and establishing a plan for base-water sampling. S-32A Fracture Stimulation PTD: 212-082 Page 8 SECTION 4 - PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS (20 AAC 25.283, a, 4): There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable. S-32A Fracture Stimulation PTD: 212-082 Page 9 SECTION 5 - DETAILED CEMENTING AND CASING INFORMATION (20 AAC 25.283, a, 5): All casing is cemented and tested in accordance with 20 AAC 25.030, g when completed. See wellbore schematic for casing details: S-32A Fracture Stimulation PTD: 212-082 Page 10 SECTION 6 - ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL (20 AAC 25.283, a, 6): Summary: S-32 and S-32A History: S-32 was originally drilled in 1990. The 17-1/2” surface hole was drilled to 2700’, 13-3/8” casing was set and cemented with 3722 cu ft of AS III and II. A 12-1/4” hole was drilled to 10104’; the 9-5/8” casing was installed to 10099’ and cemented with 2078 cu ft of Class Gcement. The 9-5/8” casingwaspressure tested to 3000psi, then the shoe was drilled out and the 8-1/2” hole was drilledto TD at 10690’. An RFT log was run, then the 7” liner was run in hole and cemented with 332 cu. ft of Class G cement. They tested the casing and liner, then ran 4-1/2” tubing, set the production packer, and tested tubing to 2500psi before rigging down. The well was completed as a Zone 4 Ivishak producer. It was shut in most of the time since 2002 due to low oil production, and little wellwork options remaining. S-32Adrillingcommenced onSeptember 2, 2012to targetupper Zone 4 Ivishak in two ESE-WNW oriented fault blocks. Before milling the window, significant losses initially experienced were mitigated with a cement squeeze. Then thewindow was milled from 10,113’ to 10,121’ MD, with new formation / rat hole drilled to a depth of 10,131’ MD. Drilling proceeded through fault # 1, encountered at 10,400’ MD with no significant increase in losses (20-30bph throughout). Drilling continued, moving upward after encountering wet rock on logs and back downward after encountering the TSAD, drilling past the 45N into 45P reservoir to TD. The liner was run and cemented with 25.8 bbls cement pumped and estimated 20.6 bbls behind pipe. After several cleanout runs, the liner lap tested and failed, then the liner was perf’d on the rig. After CTD RDMO, SL installed a liner top packer. On 5/26/2023, a RWO was completed converting S-32A from an Ivishak producer to a Kuparuk producer. TheIvishakreservoir wasisolatedwith cement,filling the liner and lower tubing stub up to 9389’ MD. The cement plug was MIT-T’d to 2500psi. The tubing was cut and pulled from 9311’ MD. The intermediate casing packoff was replaced, and the 9-5/8" casing was logged for cement.ACAST-M logdated5/24/2023 found TOC at 2709' MD, with good quality cement found at and below 3659' MD. The new 4-1/2” completion was run in hole and the production packer was set at 7388’ MD. The new completion passed an MIT-T and an MIT-IA to 3500psi. Perforationswereaddedbetween7524-7590’ MDin the Kuparuk, andthe well is planned to bestimulated with the proposed frac. As part of the full abandonment of the Ivishak reservoir, a future ~150’ cement plug is planned to be laid just above the existing tubing stub filled with cement within 12 months of the RWO. All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, Hilcorp has determined that this well can be successfully fractured within its design limits. Hilcorp has identified that there may be unisolated Ugnu hydrocarbons above the TOC. They are requesting a variance to 20 AAC 25.383(6)(B). I recommend approval of this variance. See attached emails for details. -A.Dewhurst 22MAY25 TOC at 2709' MD good quality cement found at and below 3659' MD All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. S-32A Fracture Stimulation PTD: 212-082 Page 11 SECTION 7 - PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL (20 AAC 25.283, a, 7): On 5/26/2023, the production casing was pressure tested to 3500 psi for a passing MIT-IA. On 5/26/2023, the tubing was pressure tested to 3613 psi for a passing MIT-T. The production casing annulus pressure will be monitored during the frac, if any change of pressure is seen outside of thermal expansion, the job will be flushed and the pressure source diagnosed before frac operations continue. Anticipated Pressures: MIT-T 3,500 psi MIT-IA 3,500 psi Maximum Anticipated Treating Pressure:3,080 psi @ 25 BPM IA Pop-off Set Pressure (~95% of MIT-IA):3,325 psi IA Minimum Hold Pressure (POP-off – 300 psi):3,025 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T): 4,500 psi (tree limited to 5,000psi) Stagger Pump Kickouts Between 90 – 95% of MATP:4,050 – 4,275 Global Kickout (95% of MATP):4,275 psi N2 POP-off set pressure (MATP + 1000 psi):4,500 psi Treating Line Test Pressure (MATP + 1000 psi):5,500 psi OA Pressure:Monitor Max Anticipated Proppant Loading:12 PPA S-32A Fracture Stimulation PTD: 212-082 Page 12 SECTION 8 - PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD (20 AAC 25.283, a, 8): Wellbore Tubular Ratings Size/Name Weight Grade Burst, psi Collapse, psi 13-3/8” Surface Casing 68#NT-80 5020 2260 9-5/8” Surface Casing 47#NT-80S 6870 4760 7” Liner (below isolation plug)26#NT13Cr-80 7240 5410 4-1/2” Production Tubing 12.6#13Cr-80 8430 7500 Wellhead FMC manufactured wellhead, rated to 5,000 psi. Tubing head adaptor: 13-5/8" 5,000 psi x 4-1/16" 5,000 psi Tubing Spool: 13-5/8” 5,000psi w/ 2-1/16” side outlets Casing Spool: 13-5/8” 5,000psi w/ 2-1/16” side outlets Tree: CIW 4-1/16” 5,000psi x No tree saver planned to be used. Anticipated surface treating pressure <4,500 psi. S-32A Fracture Stimulation PTD: 212-082 Page 13 SECTION 9 - DATA FOR FRACTURING ZONE AND CONFINING ZONES (20 AAC 25.283, a, 9): Formation*MD Top MD Bot TVDss Top TVDss Bot TVD Thickness Frac Grad psi/ft Lith. Desc. THRZ 7490 7524 -6649 -6677 28 0.70 Shale Top Kup/C interval 7524 7590 -6677 -6730 53 0.62 Silts/SS LCU/ Kuparuk B 7590 7599 -6730 -6737 7 0.64 Silts/SS Kuparuk A 7599 7688 -6737 -6809 72 0.66 Silts/SS Miluveach 7688 8649 -6809 -7588 779 0.70 Shale *Depths are taken from the S-32. S-32A Fracture Stimulation PTD: 212-082 Page 14 SECTION 10 – LOCATION, ORIENTATION, AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE (20 AAC 25.283, a, 10): Plat of wells within one-half mile of S-32A wellbore reservoir trajectory and location of faults. The blue line indicates the approximate fracture length and orientation of the frac’s. The plat shows the location and orientation of each well that transects the confining zone within a ½ mile radius. Hilcorp has formed the opinion, based on the following assessments for each well and seismic, well and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. S-32A Fracture StimulationPTD: 212-082Page 15Casing and Cement assessments for all wells that transect the confining zone (AOR):®®ôīīώbÍıô"I"ĖŜťÍĲèôώϯώťÍťŪŜĺŕώĺċώiĖīώĺĺīϼϼXŪŕÍŘŪħϠώa"ϽĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠ«"ŜŜϽĺŕώĺċώıťϼa"Ͻĺŕώĺċώıťϼ«"ŜŜϽ¾ĺĲÍīIIŜĺīÍťĖĺĲĺııôĲťŜbX ͕͐͘ϱ͏͔͖ ͔͏ϱ͏͑͘ϱ͑͏͏͒͑ϱ͏͏ϱ͏͏ ͑Ϡ͔͑͑ДώϯώЭДî ͕Ϡ͖͖͔Д ͕Ϡ͖͖͔Д ŪŘċÍèô ŪŘċÍèô īĺŜôî®ôīīώſÍŜώŜŪèèôŜŜċŪīīƅώЭДîώſĖťēώèôıôĲťώÍèŘĺŜŜώÍīīώÍĲĲŪīĖϠώ͓͖͓Дώa"ώĖĲώ͖ГŕŘĺîŪèťĖĺĲώèÍŜĖĲČώÍĲîώѹ͔͐͏Дώa"ώĺĲώťēôώ͖ГƄ͘ϱ͔ϯ͗ГώÍĲĲŪīŪŜϟώ>ĖĲÍīώèŪťώÍĲîèÍŕώſÍŜώèĺıŕīôťôîώĖĲώ͑͏͐͐ϟϱ͏͔ ͐͗͑ϱ͖͐͘ ͔͏ϱ͏͑͘ϱ͑͏͕͗͘ϱ͏͏ϱ͏͏͑Ϡ͓͓͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͔͒Д ͕Ϡ͖͔͑Д ͓Ϡ͓͏͏Д ͓Ϡ͔͒͘Д īĺŜôîŪıŕôîώÍώ͑ώŜťÍČôώèôıôĲťώĤĺæώſĖťēώťēôώċĖŘŜťώŜťÍČôώæôĖĲČώ͒͏͓ϟ͒ώææīŜώĺċώ͐͒ϟ͑ŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͐͏͑ϟ͓ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДÍŜώťēôώťÍĖīϟώēôώŜôèĺĲîώŜťÍČôώſÍŜώ͑͒ϟ͖ώææīŜώĺċώ͔͐ϟ͕ώŕŕČώôŘıÍċŘĺŜťώŕŪıŕôîώĺŪťώĺċώťēôώ"«ώťĺĺīώÍťώ͑Ϡ͕͏͔ДϟώbĺώīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώēôώċĖŘŜťώ͑͏ŜÍèħŜώĺċώèôıôĲťώĖĲώťēôώīôÍîώŜīŪŘŘƅώèĺĲťÍĖĲôîώŘÍîĖĺÍèťĖŽôώťŘÍèôŘώÍĲîώťēô@ώīĺČώċĺŪĲîώiώÍťώ͓Ϡ͓͏͏Дώa"ϟώēĖŜώſĺŪīîώŽĺīŪıôťŘĖèÍīīƅώèĺŘŘôŜŕĺĲîώťĺϱ͏͔ ͔͐͘ϱ͐͗͘ ͔͏ϱ͏͑͘ϱ͑͏͕͗͘ϱ͏͐ϱ͏͏ ͑Ϡ͓͓͏ДώϯώiŕôŘÍæīôώ®I ͖Ϡ͖͔͒Д ͕Ϡ͖͔͑Д͓Ϡ͓͏͏Д ͓Ϡ͔͒͘Д īĺŜôîēôώ͖ГώīĖĲôŘώĺċώťēĖŜώώŪťĖīĖƏôŜώťēôώ͘ϱ͔ϯ͗Гώώĺċώϱ͏͔ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟÍŜŜôîώaIϱIώÍťώ͓͑͒͒ώŕŜĖώĺĲώ͑ϯ͓ϯ͑͏͑͒ϟϱ͏͔͐ ͔͐͘ϱ͐͗͘ ͔͏ϱ͏͑͘ϱ͑͏͕͗͘ϱ͖͏ϱ͏͏͑Ϡ͓͓͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͔͒Д ͕Ϡ͖͔͑Д ͓Ϡ͓͏͏Д ͓Ϡ͔͒͘Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͏͔ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͏͘ ͓͑͐ϱ͏͖͘ ͔͏ϱ͏͑͘ϱ͑͏͖͖͐ϱ͏͐ϱ͏͏͐Ϡ͗͏͏ДώϯώiŕôŘÍæīô®@ώIĲĤôèťĺŘ͗Ϡ͏͓͗Д ͕Ϡ͖͖͖Д ͔Ϡ͖͑͏Д ͔Ϡ͏͔͑Д īĺŜôîŪıŕôîώ͐͒͗ϟ͖ώææīŜώĺċώ͐͑ϟ͏ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώÍĲîώ͑͐ώææīŜώĺċ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώťÍĖīώŜīŪŘŘƅϟώ͑ϟ͔ώææīŜώĺċώīĺŜŜôŜώſôŘôώĲĺťôîϟώĲώťÍħôĲώĺĲώ͗ϯ͑͐ϯ͓͑ώŜēĺſŜώiώÍťώ͔Ϡ͖͑͏Дώa"ϟÍŜŜôîώaIϱIώÍťώ͔͓͓͑ώŕŜĖώĺĲώ͘ϯ͗ϯ͑͏͓͑ϱ͏͐͘ ͓͑͐ϱ͏͖͘ ͔͏ϱ͏͑͘ϱ͑͏͖͖͐ϱ͖͏ϱ͏͏͐Ϡ͗͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͗Ϡ͏͓͗Д ͕Ϡ͖͖͖Д ͔Ϡ͖͑͏Д ͔Ϡ͏͔͑Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͏͘ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͏͑͘ ͓͑͐ϱ͏͖͘ ͔͏ϱ͏͑͘ϱ͑͏͖͖͐ϱ͖͐ϱ͏͏͐Ϡ͗͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͗Ϡ͏͓͗Д ͕Ϡ͖͖͖Д ͔Ϡ͖͑͏Д ͔Ϡ͏͔͑Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͏͘ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͏͒͘ ͓͑͐ϱ͏͖͘ ͔͏ϱ͏͑͘ϱ͑͏͖͖͐ϱ͖͑ϱ͏͏͐Ϡ͗͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͗Ϡ͏͓͗Д ͕Ϡ͖͖͖Д ͔Ϡ͖͑͏Д ͔Ϡ͏͔͑Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͏͘ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͐͏ ͐͗͑ϱ͏͔͘ ͔͏ϱ͏͑͘ϱ͑͏͖͕͔ϱ͏͏ϱ͏͏͐Ϡ͕͘͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͓͔͗Д ͕Ϡ͖͐͘Д ͕Ϡ͓͕͗Д ͕Ϡ͕͒͐Д īĺŜôîŪıŕôîώ͑͐͒ϟ͕ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώèôıôĲťϟώbĺώīĺŜŜôŜώſôŘôŘôŕĺŘťôîϟώώ[ώŘÍĲώĺĲώ͐͐ϯ͐͗ϯ͑͏͓͑ώĖĲîĖèÍťôîώiώÍťώ͕Ϡ͓͕͗Дώa"ϟϱ͐͏ ͐͐͘ϱ͐͑͒ ͔͏ϱ͏͑͘ϱ͑͏͖͕͔ϱ͏͐ϱ͏͏͐Ϡ͕͘͏ДώϯώbĺťώiŕôŘÍæīôŪŜŕôĲîôîώŘĺîŪèôŘ͕Ϡ͓͔͗Д ͕Ϡ͖͐͘Д ͕Ϡ͓͕͗Д ͕Ϡ͕͒͐Д īĺŜôîēĖŜώŜĖîôťŘÍèħώħĖèħôîώĺċċώĖĲώťēôώ͘ϱ͔ϯ͗ГώèÍŜĖĲČώĺċώϱ͐͏ώÍĲîώťēôŘôċĺŘôώŪŜôŜťēôώŕÍŘôĲťώæĺŘôϟώĖîôťŘÍèħώĺŕôŘÍťĖĺĲŜώſôŘôώŪĲŜŪèèôŜŜċŪīώÍĲîώŜŪæŜŗŪôĲťīƅèôıôĲťôîώťĺώ͖Ϡ͒͑͏ДώĖĲŜĖîôώťēôώ͘ϱ͔ϯ͗ГώèÍŜĖĲČϟ®ôīīώĖŜώĖĲώŜŪŜŕôĲîôîώŜťÍťŪŜϟώÍŜŜôîώÍĲώaIϱIώťĺώ͒͏͏͏ώŕŜĖώώЭώaIϱiώťĺ͑͏͏͏ώŕŜĖώĺĲώ͕ϯ͓͐ϯ͑͏͐͒ϟϱ͐͏͐ ͐͐͘ϱ͐͑͒ ͔͏ϱ͏͑͘ϱ͑͏͖͕͔ϱ͖͏ϱ͏͏͐Ϡ͕͘͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͓͔͗Д ͕Ϡ͖͐͘Д ͕Ϡ͓͕͗Д ͕Ϡ͕͒͐Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͐͏ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͐͏͑ ͐͐͘ϱ͐͑͒ ͔͏ϱ͏͑͘ϱ͑͏͖͕͔ϱ͖͐ϱ͏͏͐Ϡ͕͘͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͓͔͗Д ͕Ϡ͖͐͘Д ͕Ϡ͓͕͗Д ͕Ϡ͕͒͐Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͐͏ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͐͑ ͐͗͑ϱ͏͓͏ ͔͏ϱ͏͑͘ϱ͑͏͖͑͘ϱ͏͏ϱ͏͏ ͑Ϡ͔͓͔ДώϯώЭДî ͖Ϡ͐͗͘Д ͕Ϡ͖͕͓Д ͕Ϡ͗͒͘Д ͕Ϡ͏͓͗Д īĺŜôîŪıŕôîώ͖͑͗ϟ͔ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώèôıôĲťϟώbĺώīĺŜŜôŜώſôŘôŘôŕĺŘťôîϟώIĲèīŪîĖĲČώŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēôŘôÍώĺċώôŽĖôſώώϱ͒͑ S-32A Fracture StimulationPTD: 212-082Page 16®®ôīīώbÍıô"I"ĖŜťÍĲèôώϯώťÍťŪŜĺŕώĺċώiĖīώĺĺīϼϼXŪŕÍŘŪħϠώa"ϽĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠ«"ŜŜϽĺŕώĺċώıťϼa"Ͻĺŕώĺċώıťϼ«"ŜŜϽ¾ĺĲÍīIIŜĺīÍťĖĺĲĺııôĲťŜϱ͔͐ ͓͐͗ϱ͏͖͐ ͔͏ϱ͏͑͘ϱ͑͐͐͐͒ϱ͏͏ϱ͏͏͐Ϡ͑͏͏ДώϯώbĺťώiŕôŘÍæīôŪŜŕôĲîôîώŘĺîŪèôŘ͖Ϡ͕͘͏Д ͕Ϡ͖͏͗Д ͑Ϡ͔͕͏Д ͑Ϡ͓͐͘Д īĺŜôîώiŘĖČĖĲÍīīƅώŕŪıŕôîώ͓͓͓ϟ͒ώææīŜώĺċώ͐͒ϟ͑ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώÍĲîώ͓͐ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώώîĺſĲŜŗŪôôƏôώĺĲώťēôώ͘ϱ͔ϯ͗ГώƄώ͐͒ϱ͒ϯ͗ГώÍĲĲŪīŪŜώŜÍſώ͓͘ϟ͖ώææīŜώĺċώ͔͐ϟ͖ώŕŕČώôŘıÍċŘĺŜťώώŕŪıŕôîϟώĲώŜēĺſŜώťēôώèôıôĲťώťĺŕώÍťώѹ͑Ϡ͔͕͏Дώa"ϟÍŜŜôîώÍώaIϱƄIώťĺώ͑͒͏͏ώŕŜĖώĺĲώ͐͑ϯ͕͑ϯ͑͏͑͑ϟϱ͔͐͐ ͓͐͗ϱ͏͖͐ ͔͏ϱ͏͑͘ϱ͑͐͐͐͒ϱ͏͏ϱ͏͏͐Ϡ͑͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͕͘͏Д ͕Ϡ͖͏͗Д ͑Ϡ͔͕͏Д ͑Ϡ͓͐͘Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͔͐ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͕͐ ͓͐͗ϱ͏͓͗ ͔͏ϱ͏͑͘ϱ͑͐͐͑͒ϱ͏͏ϱ͏͏͐Ϡ͔͓͔ДώϯώbĺťώiŕôŘÍæīôŘĺîŪèôŘ͖Ϡ͖͗͗Д ͕Ϡ͕͖͑Д ͔Ϡ͖͐͑Д ͓Ϡ͗͒͘Д īĺŜôîŪıŕôîώ͖͒͏ϟ͒ώææīŜώĺċώ͐͒ϟ͑ώŕŕČώīÍŜŜώД@ДώÍŜώīôÍîώèôıôĲťώċĺīīĺſôîώæƅώ͒͏ϟ͐ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώÍŜώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώĲĺťôîώæŪťώťēôƅώîĖîĲĺťώæŪıŕώťēôώŕīŪČώÍĲîώ͐ϟ͔ώææīŜώſÍŜώīôċťώĖĲώťēôώèÍŜĖĲČώÍæĺŽôώťēôώċīĺÍťèĺīīÍŘώÍĲîώĖŜώÍèèĺŪĲťôîώċĺŘώĖĲώťēôώŽĺīŪıôťŘĖèώèÍīèŪīÍťĖĺĲϟώIĲèīŪîôîώťēôŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώťēôώ͐ϟ͔ώææīώīĺŜŜϠώÍĲîώÍīŜĺώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťæŘĖĲČŜώťēôώťĺŕώťĺώ͔Ϡ͖͐͑Дώa"ϟ®ôīīώĖŜώIώÍĲîώbĺťώiŕôŘÍæīôϟώaIϱώċÍĖīôîώĺĲώ͓ϯ͓͑ϯ͑͏͑͒ϟϱ͕͐͐ ͓͐͗ϱ͏͓͗ ͔͏ϱ͏͑͘ϱ͑͐͐͑͒ϱ͏͏ϱ͏͏͐Ϡ͔͓͔ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͗͗Д ͕Ϡ͕͖͑Д ͔Ϡ͖͐͑Д ͓Ϡ͗͒͘Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͕͐ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͓͑ ͐͘͏ϱ͏͔͔ ͔͏ϱ͏͑͘ϱ͑͑͏͓͓ϱ͏͏ϱ͏͏͕͔͘ДώϯώbĺťώiŕôŘÍæīô®I͖Ϡ͖͒͒Д ͕Ϡ͖͓͒Д ͓Ϡ͔͐͘Д ͓Ϡ͖͐͘Д īĺŜôîŪıŕôîώ͕͑͏ϟ͘ώææīŜώĺċώ͐͒ϟ͔ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͐͏͑ϟ͓ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώIĲèīŪîĖĲČŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēôώťĺŕώĖŜώèÍīèŪīÍťôîώťĺæôώ͓Ϡ͔͐͘Дώa"ϟaIϱώŕÍŜŜôîώťĺώ͔͑͏͏ώŕŜĖώÍĲîώaIϱƄIώċÍĖīôîώîŪôώťĺώÍώŕŘĺîŪèťĖĺĲώŕÍèħôŘīôÍħώĺĲώ͖ϯ͑͑ϯ͑͏͓͑ϟώ®ôīīώĖŜώÍώIώÍĲîώbĺťώiŕôŘÍæīôώ®Iϟϱ͔͑ ͐͘͏ϱ͐͏͒ ͔͏ϱ͏͑͘ϱ͑͑͏͖͖ϱ͏͏ϱ͏͏͑Ϡ͔͑͐ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͖͒͘Д ͕Ϡ͕͖͔Д ͓Ϡ͕͖͗Д ͓Ϡ͕͖͗Д īĺŜôîŪıŕôîώ͑͑͘ϟ͖ώææīŜώĺċώ͐͒ϟ͔ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͐͏͑ϟ͓ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώIĲèīŪîĖĲČŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēôώťĺŕώĖŜώèÍīèŪīÍťôîώťĺæôώ͓Ϡ͕͖͗Дώa"ϟϱ͔͑ ͐͗͘ϱ͓͑͐ ͔͏ϱ͏͑͘ϱ͑͑͏͖͖ϱ͏͐ϱ͏͏ ͑Ϡ͔͑͐ДώϯώiŕôŘÍæīôώ®I ͕Ϡ͖͒͘Д ͕Ϡ͕͖͔Д͓Ϡ͕͖͗Д ͓Ϡ͕͖͗Д īĺŜôîēôώ͖ГώīĖĲôŘώĺċώťēĖŜώώŪťĖīĖƏôŜώťēôώ͘ϱ͔ϯ͗Гώώĺċώϱ͔͑ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟÍŜŜôîώÍĲώaIϱIώťĺώ͓͔͓͑ώŕŜĖώĺĲώ͔ϯ͐ϯ͑͏͑͒ϟϱ͔͑͐ ͐͗͘ϱ͓͑͐ ͔͏ϱ͏͑͘ϱ͑͑͏͖͖ϱ͖͏ϱ͏͏͑Ϡ͔͑͐ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͖͒͘Д ͕Ϡ͕͖͔Д ͓Ϡ͕͖͗Д ͓Ϡ͕͖͗Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͔͑ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͒͑ ͐͘͏ϱ͓͐͘ ͔͏ϱ͏͑͘ϱ͑͑͏͘͘ϱ͏͏ϱ͏͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͔͓͑Д ͕Ϡ͖͓͐Д ͒Ϡ͕͔͘Д ͒Ϡ͕͒͗ īĺŜôîŪıŕôîώ͖͑͏ώææīŜώĺċώ͐͒ϟ͔ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͐͏͏ϟ͑ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώώώ[ſÍŜώŘŪĲώĺĲώ͔ϯ͑͒ϯ͑͏͑͒ώĖĲîĖèÍťĖĲČώťĺŕώĺċώèôıôĲťώſÍŜώÍťώ͒Ϡ͕͔͘Дώa"ϟϱ͒͑ ͑͐͑ϱ͏͗͑ ͔͏ϱ͏͑͘ϱ͑͑͏͘͘ϱ͏͐ϱ͏͏͏ДώϯώiŕôŘÍæīôŘĺîŪèôŘώI͖Ϡ͔͓͑Д ͕Ϡ͖͓͐Д ͒Ϡ͕͔͘Д ͒Ϡ͕͒͗ īĺŜôîēôώ͖ГώīĖĲôŘώĺċώťēĖŜώώŪťĖīĖƏôŜώťēôώ͘ϱ͔ϯ͗Гώώĺċώϱ͒͑ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟēĖŜώĖŜώťēôώſôīīώťēÍťώťēĖŜώiώĖŜώæôĖĲČώŕŘôŕÍŘôîώċĺŘϟÍŜŜôîώæĺťēώaIϱώÍĲîώaIϱIώÍťώ͔͒͏͏ώŕŜĖώĺĲώ͔ϯ͕͑ϯ͑͏͑͒ϟ S-32A Fracture StimulationPTD: 212-082Page 17®®ôīīώbÍıô"I"ĖŜťÍĲèôώϯώťÍťŪŜĺŕώĺċώiĖīώĺĺīϼϼXŪŕÍŘŪħϠώa"ϽĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠ«"ŜŜϽĺŕώĺċώıťϼa"Ͻĺŕώĺċώıťϼ«"ŜŜϽ¾ĺĲÍīIIŜĺīÍťĖĺĲĺııôĲťŜϱ͒͒ ͐͑͘ϱ͐͏͑ ͔͏ϱ͏͑͘ϱ͑͑͑͒͘ϱ͏͏ϱ͏͏ ͑Ϡ͓͕͔ώϯώŘĺîŪèôŘώI ͖Ϡ͕͖͐Д ͕Ϡ͖͓͐ ͔Ϡ͓͑͏Д ͔Ϡ͓͔͐Д īĺŜôîŪıŕôîώ͕͕͐ϟ͘ώææīŜώĺċώ͐͐ϟ͔ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͔͒ϟ͘ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώÍŜώťÍĖīώŜīŪŘŘƅϟώēôƅώîĖîώĲĺťώæŪıŕώťēôώŕīŪČώÍĲîťÍČČôîώèôıôĲťώÍťώ͗Ϡ͐͏͔Дώa"ώϼĺŘώ͒͒ϟ͓ώææīŜώēĖČēϠώſēĖèēώĖŜώÍèèĺŪĲťôîώċĺŘώĖĲťēôώŽĺīŪıôťŘĖèŜώÍīĺĲČώſĖťēώŜēĺôώťŘÍèħώŽĺīŪıôϽϟώώIώīĺČČôîώĖĲώ͑͏͏͗ĖîôĲťĖċĖôŜώèôıôĲťώċĺŪĲîώÍťώ͑Ϡ͖͏͏Дώa"ώæŪťώŽĺīŪıôťŘĖèÍīīƅώťēĖŜώĖŜώŪĲīĖħôīƅÍĲîώťēôώīĺČώĖŜώĲĺťώîĖċċôŘôĲťĖÍťĖĲČώæôťſôôĲώîŘĖīīĖĲČώıŪîώÍĲîώèôıôĲťϟ"ôċÍŪīťĖĲČώťĺώťēôώŽĺīŪıôťŘĖèώıôťēĺîώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēĖŜæŘĖĲČŜώťēôώťĺŕώťĺώ͔Ϡ͓͑͏Дώa"ϟÍŜŜôîώÍĲώaIϱIώÍťώ͒Ϡ͓͑͏ώŕŜĖώĺĲώ͓ϯ͐͑ϯ͑͏͑͒ϟϱ͓͒ ͐͑͘ϱ͕͐͒ ͔͏ϱ͏͑͘ϱ͑͑͒͏͔ϱ͏͏ϱ͏͏͐Ϡ͔͐͘ДώϯώiŕôŘÍæīô®@ώIĲĤôèťĺŘ͖Ϡ͕͓͗Д ͕Ϡ͕͓͘Д ͒Ϡ͔͑͏Д ͒Ϡ͓͑͗Д īĺŜôîŪıŕôîώ͒͒͒ώææīŜώĺċώ͐͑ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͕͐ϟ͓ώææīŜĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώīŪČώſÍŜώĲĺťώæŪıŕôîώÍĲîώèôıôĲťώſÍŜĺŽôŘîĖŜŕīÍèôîώæƅώѹ͒ώææīŜϟώώIώīĺČώŘŪĲώĺĲώ͐͐ϯ͐͐ϯ͑͏͔͐ώĖĲîĖèÍťôŜώťĺŕώĺċèôıôĲťώÍťώ͒Ϡ͔͑͏Дώa"ϟÍŜŜôîώÍĲώaIϱIώÍťώ͔͑͑͑ώŕŜĖώĺĲώ͐ϯ͘ϯ͑͏͓͑ϟϱ͔͒ ͐͑͘ϱ͓͐͗ ͔͏ϱ͏͑͘ϱ͓͑͑͒͑ϱ͏͏ϱ͏͏͓͔͐ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͖Ϡ͔͑͑Д ͕Ϡ͖͖͒Д ͓Ϡ͖͕͓Д ͓Ϡ͔͏͓Д īĺŜôîŪıŕôîώ͑͘͏ϟ͖ώææīŜώĺċώ͐͑ϟ͑ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͕͐ϟ͓ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώIĲèīŪîĖĲČŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēôώťĺŕώĖŜώèÍīèŪīÍťôîώťĺæôώ͓Ϡ͖͕͓Дώa"ϟÍŜŜôîώI>[ώĺĲώ͔ϯ͐͘ϯ͑͏͑͏ϟϱ͕͒ ͐͑͘ϱ͕͐͐ ͔͏ϱ͏͑͘ϱ͑͑͒͏͐ϱ͏͏ϱ͏͏͑Ϡ͑͗͏ДώϯώbĺťώiŕôŘÍæīôŘĺîŪèôŘ͕Ϡ͖͐͘Д ͕Ϡ͕͓͘Д ͓Ϡ͕͔͑Д ͓Ϡ͕͓͖Д īĺŜôîŪıŕôîώ͒͐͑ώææīŜώĺċώ͐͑ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͕͐ϟ͓ώææīŜĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώIĲèīŪîĖĲČώŜēĺôťŘÍèħώŽĺīŪıôώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēôώťĺŕώĖŜώèÍīèŪīÍťôîώťĺώæô͓Ϡ͕͔͑Дώa"ϟaIϱώЭώaIϱƄIώæĺťēώċÍĖīôîώĺĲώ͔ϯ͐͒ϯ͑͏͐͘ϟώ®ôīīώĖŜώÍώIώbĺťώiŕôŘÍæīôŕŘĺîŪèôŘϟϱ͖͒ ͐͑͘ϱ͏͘͘ ͔͏ϱ͏͑͘ϱ͑͑͑͐͘ϱ͏͏ϱ͏͏͑Ϡ͔͔͑ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͓͗͗Д ͕Ϡ͖͐͘Д ͑Ϡ͐͘͏Д ͑Ϡ͘͏͐Д īĺŜôîŪıŕôîώ͐͗͘ϟ͒ώææīŜώĺċώ͐͐ϟ͔ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͔͓ϟ͘ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώĲώώŘÍĲĺĲώ͔ϯ͐͘ϯ͑͏͑͒ώŜēĺſŜώiώÍťώ͑Ϡ͐͘͏Дώa"ϟϱ͖͒ ͑͐͑ϱ͏͑͘ ͔͏ϱ͏͑͘ϱ͑͑͑͐͘ϱ͏͐ϱ͏͏͑Ϡ͔͔͑ДώϯώiŕôŘÍæīôŘĺîŪèôŘώI͕Ϡ͓͗͗Д ͕Ϡ͖͐͘Д ͑Ϡ͐͘͏Д ͑Ϡ͘͏͐Д īĺŜôîēôώ͔ϟ͔ГώīĖĲôŘώŪťĖīĖƏôŜώťēôώŕÍŘôĲťώæĺŘôДŜώ͖ϱ͔ϯ͗ГώèÍŜôώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟÍŜŜôîώæĺťēώaIϱώÍĲîώaIϱIώÍťώ͔͒͏͏ώŕŜĖώĺĲώ͔ϯ͑͏ϯ͑͏͑͒ϟϱ͖͒͐ ͑͐͑ϱ͏͑͘ ͔͏ϱ͏͑͘ϱ͑͑͑͐͘ϱ͖͏ϱ͏͏͑Ϡ͔͔͑ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͓͗͗Д ͕Ϡ͖͐͘Д ͑Ϡ͐͘͏Д ͑Ϡ͘͏͐Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͖͒ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͒͗ ͐͑͘ϱ͖͐͑ ͔͏ϱ͏͑͘ϱ͑͑͒͐͏ϱ͏͏ϱ͏͏͐Ϡ͔͕͔ДώϯώiŕôŘÍæīôŘĺîŪèôŘώI͕Ϡ͓͐͘Д ͕Ϡ͖͓͓Д ͓Ϡ͔͕͖Д ͓Ϡ͔͕͔Д īĺŜôîŪıŕôîώ͑͗͑ϟ͐ώææīŜώĺċώ͐͑ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͕͐ϟ͓ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώIĲèīŪîĖĲČŜēĺôώťŘÍèħώŽĺīŪıôώÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēôώťĺŕώĖŜώèÍīèŪīÍťôîώťĺæôώ͓Ϡ͔͕͖Дώa"ϟI>[ώŕÍŜŜôîώĺĲώ͐͏ϯ͖͐ϯ͑͏͔͐ϟώ®ôīīώĖŜώÍώ[IώiŕôŘÍæīôώŕŘĺîŪèôŘϟ S-32A Fracture StimulationPTD: 212-082Page 18*S-43 is 1,975’ south of S-32A frac location. Based on a modeled half-length of ~200’ and no mapped fault connecting the wells, S-43 will not interfere with containment of hydraulicfracturing fluid. In conjunction with monitoring S-32A well pressures, S-43 tubing, IA and OA pressures will be continuously monitored during fracturing operations to ensure no interferenceof the frac. If any anomalous changes in pressure is seen while monitoring either S-32A or S-43, the job will be flushed and the pressure source diagnosed before frac operations continue.®®ôīīīώbÍıô"I"ĖŜťÍĲèôôώϯϯώťÍťŪŜĺŕŕώĺċċώiĖīīώĺĺīϼϼXŪŕÍŘŪħϠϠώa"ϽĺŕŕώĺċċώiĖīīώĺĺīϼXŪŕÍŘŪħϠ«"ŜŜϽĺŕŕώĺċċώıťϼa"Ͻĺŕŕώĺċċώıťϼ«"ŜŜϽ¾ĺĲÍīIIŜĺīÍťĖĺĲĺııôĲťŜϱ͓͑ ͕͐͘ϱ͏͔͓ ͔͏ϱ͏͑͘ϱ͕͕͑͑͑ϱ͏͏ϱ͏͏͑Ϡ͖͔͐ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͑͒͗Д ͕Ϡ͖͑͏Д ͕Ϡ͕͑͑Д ͕Ϡ͐͏͖Д īĺŜôîŪıŕôîώ͔͐͘ϟ͑ώææīŜώĺċώ͐͐ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͒͑ϟ͗ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώīŪČώîĖîώĲĺťώæŪıŕώÍĲîώ͐͏͗ώææīŜώĺċīĺŜŜôŜώſôŘôώŘôŕĺŘťôîϟώēôƅώťÍČČôîώèôıôĲťώĖĲώèÍŜĖĲČώÍťώ͗Ϡ͓͒͘Дώϼ͔͒͐ДώēĖČēϽϟÍħĖĲČώĖĲťĺώÍèèĺŪĲťώťēôŜôώīĺŜŜôŜώÍĲîώŜēĺôώťŘÍèħώŽĺīŪıôώÍīĺĲČώſĖťēώ͒͏҇ſÍŜēĺŪťϠώťēôώèÍīèŪīÍťôîώťĺŕώĖŜώ͕Ϡ͕͑͑Дώa"ϟϱ͓͑͐ ͕͐͘ϱ͏͔͓ ͔͏ϱ͏͑͘ϱ͕͕͑͑͑ϱ͖͏ϱ͏͏͑Ϡ͖͔͐ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͑͒͗Д ͕Ϡ͖͑͏Д ͕Ϡ͕͑͑Д ͕Ϡ͐͏͖Д īĺŜôîēĖŜώŕīŪČώæÍèħώſÍŜώÍώŕĖīĺťώēĺīôώÍĲîώŜŪæŜôŗŪôĲťīƅώèôıôĲťôîώĺċċώĲĺťÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͓͑ ͔͑͐ϱ͏͔͔ ͔͏ϱ͏͑͘ϱ͕͕͑͑͑ϱ͏͐ϱ͏͏͔͒͘ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͗Ϡ͓͖͓Д ͕Ϡ͖͕͖Д ͓Ϡ͗͏͓Д ͓Ϡ͓͏͖Д īĺŜôîŪıŕôîώ͐͏͏ϟ͒ώææīŜώĺċώ͐͐ϟ͔ώŕŕČώ[ĖťôŘôťôώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͐͘ϟ͑ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώ͕͐ώææīŜώĺċώīĺŜŜôŜώſôŘôώĲĺťôîώæŪťώĲĺīĺŜŜôŜώĺĲèôώèôıôĲťώŕÍŜŜôîώťēôώ͖ГώŜēĺôϟώiώſÍŜώèÍīèŪīÍťôîώŪŜĖĲČώīĖċťŕŘôŜŜŪŘôŜώŕôŘώДŜώ͐͏ϱ͕͏ώƏĺĲÍīώĖŜĺīÍťĖĺĲώŕŘÍèťĖèôŜϟώÍħĖĲČώĖĲťĺώÍèèĺŪĲťώ͕͐ææīŜώĺċώīĺŜŜôŜώÍĲîώŜēĺôώťŘÍèħώŽĺīŪıôϠώťēĖŜώīĖċťώŕŘôŜŜŪŘôώèÍīèŪīÍťĖĺĲôŗŪÍťôŜώťĺώ͓͏҇ώſÍŜēĺŪťώæŘĖĲČĖĲČώťēôώťĺŕώťĺώ͓Ϡ͗͏͓Дώa"ϟI>[ώŕÍŜŜôîώĺĲώ͗ϯ͖͐ϯ͑͏͓͑ϟϱ͓͒Ϫ ͖͐͘ϱ͏͔͑ ͔͏ϱ͏͑͘ϱ͖͔͓͑͑ϱ͏͏ϱ͏͏͐Ϡ͖͔͘ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͕Ϡ͖͘͘Д ͕Ϡ͖͓͑Д ͗Ϡ͓͑͘Д ͖Ϡ͒͘͏Д iŕôĲŪıŕôîώ͐͗͗ϟ͕ώææīŜώĺċώ͐͐ώŕŕČώīÍŜŜώД@ДώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͔͑ϟ͗ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώēôώŕīŪČώîĖîώĲĺťώæŪıŕώÍĲîώîŘĖīīĖĲČŘôŕĺŘťŜώĖĲîĖèÍťôîώ͔͑҇ώÍŽôŘÍČôώŘôťŪŘĲŜώťēŘĺŪČēĺŪťώťēôώĤĺæϟώēôƅώťÍČČôîèôıôĲťώÍťώ͘Ϡ͖͘͏Дώa"ώϼ͓͐͐ДώēĖČēϽώĖĲîĖèÍťĖĲČώèôıôĲťώſÍŜώĲĺťĺŽôŘîĖŜŕīÍèôîϟώèèĺŪĲťώċĺŘώŜēĺôώťŘÍèħώŽĺīŪıôϠώ͒͏҇ώſÍŜēώĺŪťϠώÍĲîώ͖͔҇īĺŜŜôŜϠώťēôώèÍīèŪīÍťôîώiώĖŜώÍťώ͗Ϡ͓͑͘Дώa"ϟÍŜŜôîώæĺťēώaIϱώÍťώ͔͔͕͒ώŕŜĖώÍĲîώaIϱIώÍťώ͕͓͑͘ώŕŜĖώĺĲώ͕ϯ͐͗ϯ͑͏͑͑ϟϱ͓͒[͐Ϫ ͖͐͘ϱ͏͔͒ ͔͏ϱ͏͑͘ϱ͖͔͓͑͑ϱ͕͏ϱ͏͏͐Ϡ͖͔͘ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͕Ϡ͖͘͘Д ͕Ϡ͖͓͑Д ͗Ϡ͓͑͘Д ͖Ϡ͒͘͏Д iŕôĲēĖŜώīÍťôŘÍīώſÍŜώîŘĖīīôîώÍťώ͘Ϡ͖͓͗Дώa"ώťēôŘôċĺŘôώŪťĖīĖƏĖĲČώťēôώϱ͓͒ώŕÍŘôĲťæĺŘôϟϱ͐͏͔ ͑͏͏ϱ͔͐͑ ͔͏ϱ͏͑͘ϱ͖͖͑͑͘ϱ͏͏ϱ͏͏͑Ϡ͔͔͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͕͒͑Д ͕Ϡ͖͕͐Д ͒Ϡ͒͐͒Д ͒Ϡ͏͒͐Д īĺŜôîŪıŕôîώ͔͐͐ώææīŜώ͐͐ϟ͔ώŕŕČώ[ĖťôŘôťôώÍŜώīôÍîώèôıôĲťώċĺīīĺſôîώæƅώ͔͔ώææīŜ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώŘôŕĺŘťôîϟώIĲèīŪîĖĲČώŜēĺôώťŘÍèħŽĺīŪıôÍĲîώÍŜŜŪıĖĲČώ͒͏҇ώſÍŜēώĺŪťϠώťēĖŜώŽĺīŪıôťŘĖèÍīīƅώŕīÍèôŜώťēôώťĺŕώÍť͒Ϡ͒͐͒Дώa"ϟϱ͐͏͔ ͑͐͘ϱ͏͒͑ ͔͏ϱ͏͑͘ϱ͖͖͑͑͘ϱ͏͐ϱ͏͏͑Ϡ͔͔͏ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͖Ϡ͕͒͑Д ͕Ϡ͖͕͐Д ͒Ϡ͒͐͒Д ͒Ϡ͏͒͐Д īĺŜôîēĖŜώŜĖîôťŘÍèħώħĖèħôîώĺċċώÍťώ͖Ϡ͕͔͑ДώĖĲώťēôώŕÍŘôĲťώæĺŘôДŜώ͖ГώèÍŜĖĲČώÍĲîώîĺôŜĲĺťώÍċċôèťώĖŜĺīÍťĖĺĲϟI>[ώŕÍŜŜôîώĺĲώ͗ϯ͑͒ϯ͑͏͓͑ϟϱ͐͏͗ ͑͏͐ϱ͐͏͏ ͔͏ϱ͏͑͘ϱ͑͒͏͑͐ϱ͏͏ϱ͏͏ ͐Ϡ͓͔͗ДώϯώЭДî ͖Ϡ͔͒͒Д ͕Ϡ͖͐͑Д ͑Ϡ͔͖͗Д ͑Ϡ͔͔͗Д īĺŜôîēĖŜώĖŜώÍώЭДîώıĖèŘĺæĺŘôϟώēôŘôώſÍŜώÍώ͔ϱ͐ϯ͑ГώèÍŜĖĲČώŜťŘĖĲČώťĺώŜŪŘċÍèôώſĖťēÍώ͒ϱ͐ϯ͑ГώèÍŜĖĲČώŜťŘĖĲČώÍīŜĺώťĖôîώæÍèħώťĺώŜŪŘċÍèôϟώēôώ͔ϱ͐ϯ͑ГώèŘĺŜŜôîώĺŽôŘώťĺ͒ϱ͐ϯ͑ГώÍťώ͔Ϡ͓͖͘Дώa"ϟώēôώīôÍîώèôıôĲťώſÍŜώ͕͗ϟ͗ώææīŜώĺċώ͐͑ώŕŕČώ[ĖťôŘôťôċĺīīĺſôîώæƅώ͕͓ϟ͔ώææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώ(ŽôĲώèÍīèŪīÍťĖĲČ͒͏҇ώſÍŜēώĺŪťϠώťēôώťĺŕώĺċώèôıôĲťώŜēĺŪīîώēÍŽôώŘôÍèēôîώťēôώ͖ϱ͔ϯ͗ГώèÍŜĖĲČŜēĺôώÍťώ͑Ϡ͔͖͗Дώa"ϟώĲώaώſÍŜώŘŪĲώŕĺŜťϱŘĖČώÍĲîώŜēĺſôîώèôıôĲťώŪŕώťĺťēôώťĺŕώĺċώťēôώ͔ϱ͐ϯ͑ГώƄώ͒ϱ͐ϯ͑ГώèŘĺŜŜĺŽôŘώÍťώ͔Ϡ͓͖͘Дώa"ϟώ(ĖťēôŘώèÍŜôώŕŘĺŽĖîôŜèĺŽôŘÍČôώċĺŘώťēôώXŪŕÍŘŪħϟ*S-43 is 1,975’ south of S-32A frac location. Based on a modeled half-length of ~200’ and no mapped fault connecting the wells, S-43 will not interfere with containment of hydraulicfracturing fluid. In conjunction with monitoring S-32A well pressures, S-43 tubing, IA and OA pressures will be continuously monitored during fracturing operations to ensure no interferenceof the frac. S-32A Fracture StimulationPTD: 212-082Page 19®®ôīīώbÍıô"I"ĖŜťÍĲèôώϯώťÍťŪŜĺŕώĺċώiĖīώĺĺīϼϼXŪŕÍŘŪħϠώa"ϽĺŕώĺċώiĖīώĺĺīϼXŪŕÍŘŪħϠ«"ŜŜϽĺŕώĺċώıťϼa"Ͻĺŕώĺċώıťϼ«"ŜŜϽ¾ĺĲÍīIIŜĺīÍťĖĺĲĺııôĲťŜϱ͐͏͘ ͑͏͑ϱ͓͔͑ ͔͏ϱ͏͑͘ϱ͔͑͒͐͒ϱ͏͏ϱ͏͏͑Ϡ͕͑͘ДώϯώiŕôŘÍæīôŘĺîŪèôŘ͖Ϡ͕͗͐Д ͕Ϡ͖͒͗Д ͒Ϡ͓͔͏Д ͒Ϡ͑͐͏Д īĺŜôîŪıŕôîώ͐͒͑ϟ͗ώææīŜώĺċώ͐͑ώŕŕČώ[ĖťôŘôťôώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͐͗ϟ͓ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώŘôŕĺŘťôîϟώώIώīĺČώŘŪĲώĺĲ͐ϯ͕͐ϯ͑͏͏͒ώĖĲîĖèÍťôîώťĺŕώĺċώèôıôĲťώÍťώ͒Ϡ͓͔͏Дώa"ϟI>[ώŕÍŜŜôîώĺĲώ͑ϯ͘ϯ͑͏͓͑ϟϱ͐͏͐͘ ͑͏͑ϱ͓͔͑ ͔͏ϱ͏͑͘ϱ͔͑͒͐͒ϱ͖͏ϱ͏͏͑Ϡ͕͑͘ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͕͗͐Д ͕Ϡ͖͒͗Д ͒Ϡ͓͔͏Д ͒Ϡ͑͐͏Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͐͏͘ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͐͐͏ ͑͏͐ϱ͐͑͘ ͔͏ϱ͏͑͘ϱ͑͒͏͒͏ϱ͏͏ϱ͏͏͑Ϡ͏͏͔ДώϯώЭДîώċĺŘĖîôťŘÍèħ͗Ϡ͓͖͘Д ͕Ϡ͗͏͓Д ͒Ϡ͓͔͏Д ͑Ϡ͖͗͑Д īĺŜôîŪıŕôîώ͕͔͐ϟ͒ώææīŜώĺċώ͐͑ώŕŕČώ[ĖťôŘôťôώèôıôĲťώÍŜώīôÍîϟώbĺώīĺŜŜôŜŘôŕĺŘťôîϟώώIώīĺČώŘŪĲώĺĲώ͐ϯ͖ϯ͑͏͐͑ώĖĲîĖèÍťôîώťĺŕώĺċώèôıôĲťώÍťώ͒Ϡ͓͔͏Дa"ϟϱ͐͐͏ ͑͐͐ϱ͐͑͘ ͔͏ϱ͏͑͘ϱ͑͒͏͒͏ϱ͏͐ϱ͏͏͐Ϡ͔͔͔ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͘͘Д ͕Ϡ͖͕͖Д ͓Ϡ͕͏͏Д ͒Ϡ͓͗͐Д īĺŜôîŪıŕôîώ͐͘ϟ͕ώææīŜώĺċώ͐͐ώŕŕČώ[ĖťôŘôťôώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͓͒ϟ͒ææīŜώĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώŘôŕĺŘťôîϟώώIώīĺČώŘŪĲώĺĲ͑ϯ͐͒ϯ͑͏͐͑ώĖĲîĖèÍťôîώťĺŕώĺċώèôıôĲťώÍťώ͓Ϡ͕͏͏Дώa"ϟÍŜŜôîώÍĲώaIϱIώťĺώ͕͔͑͒ώŕŜĖώĺĲώ͒ϯ͔ϯ͑͏͑͒ϟϱ͐͐͏͐ ͑͐͐ϱ͐͑͘ ͔͏ϱ͏͑͘ϱ͑͒͏͒͏ϱ͖͏ϱ͏͏͐Ϡ͔͔͔ДώϯώЭДîώċĺŘĖîôťŘÍèħ͖Ϡ͖͘͘Д ͕Ϡ͖͕͖Д ͓Ϡ͕͏͏Д ͒Ϡ͓͗͐Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͐͐͏ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͐͐͑ ͑͏͑ϱ͔͐͒ ͔͏ϱ͏͑͘ϱ͑͒͏͘͘ϱ͏͏ϱ͏͏ ͐͘͏͏ДώϯώiŕôŘÍæīôώ®I ͕Ϡ͕͗͘Д ͕Ϡ͖͏͘Д ͒Ϡ͔͑͏Д ͒Ϡ͑͐͒Д īĺŜôîŪıŕôîώ͑͘ϟ͓ώææīŜώĺċώ͐͑ώŕŕČώ[ĖťôŘôťôώèôıôĲťώÍŜώīôÍîώċĺīīĺſôîώæƅώ͒͗ώææīŜĺċώ͔͐ϟ͗ώŕŕČώīÍŜŜώД@ДώťÍĖīώŜīŪŘŘƅϟώbĺώīĺŜŜôŜώŘôŕĺŘťôîϟώώIώīĺČώŘŪĲώĺĲ͗ϯ͒ϯ͑͏͏͑ώĖĲîĖèÍťôîώťĺŕώĺċώèôıôĲťώÍťώ͒Ϡ͔͑͏Дώa"ϟÍŜŜôîώÍĲώaIϱIώťĺώ͒͒͑͘ώŕŜĖώĺĲώ͒ϯ͓͐ϯ͑͏͑͒ϟϱ͐͐͑[͐ ͔͑͐ϱ͑͑͑ ͔͏ϱ͏͑͘ϱ͑͒͏͘͘ϱ͕͏ϱ͏͏͐͘͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͕͗͘Д ͕Ϡ͖͏͘Д ͒Ϡ͔͑͏Д ͒Ϡ͑͐͒Д īĺŜôîēĖŜώīÍťôŘÍīώħĖèħŜώĺċċώÍťώ͕Ϡ͐͑͘Дώa"ώſēĖèēώĖŜώæôīĺſώťēôώ͖ГώèÍŜĖĲČώŜēĺôώÍť͕Ϡ͔͗͑ДώťēôŘôċĺŘôώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͐͐͑[͐͐ ͔͑͐ϱ͑͑͑ ͔͏ϱ͏͑͘ϱ͑͒͏͘͘ϱ͖͏ϱ͏͏͐͘͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͕͗͘Д ͕Ϡ͖͏͘Д ͒Ϡ͔͑͏Д ͒Ϡ͑͐͒Д īĺŜôî ēĖŜώĖŜώÍώŕīŪČώæÍèħώĺċώϱ͐͐͑[͐ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟϱ͐͐͑[͐͑ ͔͑͐ϱ͑͑͑ ͔͏ϱ͏͑͘ϱ͑͒͏͘͘ϱ͖͐ϱ͏͏͐͘͏͏ДώϯώЭДîώċĺŘĖîôťŘÍèħ͕Ϡ͕͗͘Д ͕Ϡ͖͏͘Д ͒Ϡ͔͑͏Д ͒Ϡ͑͐͒Д īĺŜôî ēĖŜώĖŜώÍώŜôèĺĲîώŕīŪČώæÍèħώĺċώϱ͐͐͑[͐ώĲĺťώÍċċôèťĖĲČώĖŜĺīÍťĖĺĲϟ S-32A Fracture Stimulation PTD: 212-082 Page 20 SECTION 11 - LOCATION OF, ORIENTATION OF, AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFING ZONES (20 AAC 25.283, a, 11): Hilcorp’s technical analysis based on seismic, well and other subsurface information available indicates that there are 4 mapped faults that transect the Kuparuk interval and enter the confining zone within the ½ radius of the production and confining zone trajectory for the planned S-32A. Fracture gradients within the confining zone (Kalubik and HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. The HRZ and Kalubik in this area are predominately shale with some silts with an estimated fracture pressure of ~13.5ppg. Faults 1-4 intersect the production interval and confining zone within the ½ mile radius of the planned fracs. Their displacements, sense of throw, and zone in which they terminate upwards are given below. The wellbore trajectory is essentially a vertical/slant penetration. Maximum stress direction is estimated to be ~30 deg W of N. The frac stage should have sufficient offset to and should not intersect faults the faults. The frac is 1,850’ from fault #1, 825’ from fault #2, 760’ from fault #3, 2050’ from fault #4. The maximum anticipated fracture half-length of 200’ is well short of these faults. Half length is modeled using hydraulic fracture modelling software and is corroborated by what we have seen in other frac treatments. If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot be explaining by fluids pumped or annular pressure monitoring, pumping operation will stop until a plan forward and explanation can be put forth. >>ÍŪīť ēŘĺſ ""Ė ŘôèťĖĺĲ ĺŕ ĺťťĺı ͐ ͒͏ϱ͖͔Д "® ĺīŽĖīīô aĖīŪŽôÍèē ͑ ͏ϱ͐͑͏Д "b F¾ ÍŜôıôĲť ͒ ͏ϱ͔͒Д "® F¾ IŽĖŜēÍħ ͓͏ϱ͓͏"bF¾XĖĲČÍħ S-32A Fracture Stimulation PTD: 212-082 Page 21 SECTION 12 – PROPOSED HYDRAULIC FRACTURING PROGRAM (20 AAC 25.283, a, 12): Proposed Procedure: 1. Conduct safety meeting, inspect location, and review 10-403. 2. Ensure all pre-frac well work has been completed, and the tubing & IA are freeze protected. 3. MIRU frac equipment and associated frac tanks. 4. Pressure test surface lines to at least 5,500 psi. 5. Test IA Pop-off system to ensure functioning properly. IA Pop-off to be set at 3,325 psi. 6. Bring IA pressure up to a hold pressure of 3,025 psi. 7. Pump the fracture stimulation per the proposed pump schedule below. Maximum allowable treating pressure is 4,500 psi. 8. RDMO frac equipment. Ensure tubing is freeze protected. 9. Return the well to production / flowback post slickline gas lift and contingent coiled tubing cleanout. Fracture Stimulation Pump Schedule: There are three overpressure devices that protect the surface equipment and wellbore from overpressure. 1) Each individual frac pump has an electronic kickout that will shift the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are staggered between 90% and 95% of the maximum allowable treating pressure. 2) A primary pressure transducer in the treating line will trigger a global kickout that will shift all the pumps into neutral. 3) There is a manual kickout that is controlled from the frac van that can shift all pumps into neutral. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. Stage #Fluid Stage Prop Con (ppa) Rate (bpm) Volume (bbls) CUM Volume (bbls)Proppant Name Proppant (#) CUM Proppant (#) 1 FW w/ Adds Injection Test 0 25 125 125 0 0 2 Shutdown 125 0 3 28# X-Link Pad 0.5 25 150 275 0 0 4 28# X-Link Scour 0 25 100 375 100 Mesh 2055 2055 5 28# X-Link Pad 0 25 150 525 0 2055 6 28# X-Link Flat 1 25 100 625 16/20 CarboBOND 4022 6077 7 28# X-Link Flat 2 25 75 700 16/20 CarboBOND 5788 11865 8 28# X-Link Flat 3 25 75 775 16/20 CarboBOND 8343 20208 9 28# X-Link Flat 4 25 75 850 16/20 CarboBOND 10705 30913 10 28# X-Link Flat 5 25 75 925 16/20 CarboBOND 12897 43810 11 28# X-Link Flat 6 25 75 1000 16/20 CarboBOND 14935 58745 12 28# X-Link Flat 7 25 75 1075 16/20 CarboBOND 16836 75581 13 28# X-Link Flat 8 25 85 1160 16/20 CarboBOND 21094 96675 14 28# X-Link Flat 9 25 85 1245 16/20 CarboBOND 22979 119654 15 28# X-Link Flat 10 25 85 1330 16/20 CarboBOND 24750 144404 16 28# X-Link Flat 11 25 85 1415 16/20 CarboBOND 26414 170818 17 28# X-Link Flat 12 25 85 1500 16/20 CarboBOND 27983 198801 18 FW w/ Adds Flush 0 25 76 1576 198801 19 Diesel Freeze Protect 0 25 40 1616 198801 S-32A Fracture Stimulation PTD: 212-082 Page 22 Frac Dimensions: Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft 1 7524 -6677 -6812 ~200’ Frac Modelling: Maximum Anticipated Treating Pressure: ~3,080 psi Surface pressure is calculated based on a closure pressure of ~0.62 psi/ft or ~4,180 psi. Closure pressure plus anticipated net pressure to be built (500 psi) and friction pressure minus hydrostatic results in a surface pressure of ~3,080 psi at the time of flush. 4180 psi (closure) + 500 psi (net) + 3000 psi (friction) - 4600 psi (hydrostatic) = 3080 psi (max surface press) The difference in closure pressures of the confining shale layers determines height of the fracture. Average confining layer stress is anticipated to be ~0.7 psi/ft. Fracture half-length is determined from confining layer stress as well as leak-off and formation modulus. The modeled frac is anticipated to reach a half-length of ~200 ft with a height of ~135 ft TVD. Disclaimer Notice: This model was generated using commercially available modelling software and is based on engineering estimates of reservoir properties. Hilcorp is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results. S-32A Fracture Stimulation PTD: 212-082 Page 23 Pre-Job Anticipated Chemicals to be pumped: S-32A Fracture Stimulation PTD: 212-082 Page 24 SECTION 13 - POST FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN (20 AAC 25.283, a, 13): After the fracture stimulation and potentially during the post frac coil fill cleanout, the well will be put on production through a portable well test separator. All liquids will be captured and either sent to production facilities or diverted to flowback tanks if solids percentage becomes too high for our production facility to manage. The initial flowback period is intended to produce back the fracture fluids to tanks as quickly as possible, until the well is produced less than 0.5% solids, at which time the produced fluids meet the GC2 acceptance criteria for start-up. There will be a tank farm on pad to store the produced fluids from flowback operations. The flowback fluids not suitable for GC2 processing will be hauled to another facility’s slop tank for additional settling time and/or disposal. Hilcorp will work to separate and recover fluid that meets the facility specification for the flowback fluids. A fluid manifest form will be completed for each load trucked offsite. 1 Dewhurst, Andrew D (OGC) From:Hunter Gates <Hunter.Gates@hilcorp.com> Sent:Wednesday, 21 May, 2025 16:54 To:Joseph Syzdek; Dewhurst, Andrew D (OGC) Cc:Lau, Jack J (OGC); Wallace, Chris D (OGC); Davies, Stephen F (OGC) Subject:S-32A Frac Sundry Afternoon Andy, Since we were discussing S-17C, I wanted to get ahead and look at S-32A. A CBL shows TOC in S-32A at 3,659’ MD. There are no open hole logs to or above this depth. By looking at o Ưsetting wells, it appears that our well may just be clipping the top of the Ugnu formation which would be the shallowest hydrocarbon bearing zone in our well. Should this be deemed as the reality of our well, Hilcorp would like to request a variance to regulation 20 AAC 25.283 6B which states that cement isolation across all hydrocarbon bearing zones is required. For S-32A, we are requesting a variance to this rule due to the fact that our cement likely does not extend up to cover the shallowest hydrocarbon bearing zone, the Ugnu formation. Top of cement logged behind the 9-5/8” casing is from the shoe up to 3,659’ MD. With the Kuparuk top being 7,524’ MD, this would provide 3,865’ of cement above the proposed stimulated zone (Kuparuk fm.) giving us conƱdent isolation and protect the overlaying hydrocarbon zones. Hunter Gates Operations Engineer I M & S Pads I Prudhoe Bay West Hilcorp Alaska, LLC Email: hunter.gates@hilcorp.com Cell: (215) 498-7274 Office: (907) 777-8326 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of the individual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any d issemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU S-32A Reservoir Cement Plug Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 212-082 50-029-22099-01-00 11848 Conductor Surface Intermediate Production Liner 8987 80 2657 10071 253 1990 9007 20" 13-3/8" 9-5/8" 7" 3-1/2" x 3-1/4" x 2-7/8" 7941 34 - 114 33- 2685 31- 10099 9860 - 10113 9855 - 11845 34 - 114 28 - 2685 28 - 8810 8264 - 8821 8621 - 8987 None 2260 4760 5410 10530 9007, 9389 5020 6870 7240 10160 7524 - 7590 4-1/2" 12.6# 13Cr80 28 - 7445, 9314 - 9913 6741 - 6795 Structural 4-1/2" HES TNT Packer 9832, 8603 7388, 9832 6632, 8603 Torin Roschinger Operations Manager Leslie Manning lreavis@hilcorp.com (907)777-8326 PRUDHOE BAY, Aurora Oil Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028257 28 - 6678, 8189 - 8666 9007' - 9389'MD Pump 22-bbls of 15.8-ppg Class G Cement. Final pressure = 1400-psi. Well Not Online Well Not Online 1625 1350 240 300 323-658 13b. Pools active after work:Aurora Oil 4-1/2" TIW Packer 7388, 6632 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Grace Christianson at 11:34 am, May 15, 2024 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2024.05.15 07:24:14 -08'00' Torin Roschinger (4662) RBDMS JSB 051524 DSR-5/15/24WCB 8-29-2024 ACTIVITY DATE SUMMARY 2/23/2024 T/I/O = 1350/1610/70. Temp = SI. T & IA FL (CT). ALP = 1900 psi, SI @ CV. T FL @ surface. IA FL @ 740' (6540' above sta # 1 SO). SV, WV, SSV = C. MV = O. IA, OA = OTG. 21:30 2/29/2024 *** WELL S/I ON ARRIVAL*** RIH 3.84" GAUGE RING TAG X PROFILE @ 2135'SLM / 2170'MD POOH. RIH WITH DUAL SPARTEK GAUGES: 10MIN @ SURFACE 15MIN - 7642' SLM / 7677' MD / 6800' TVD 15MIN - 7518' SLM / 7553' MD / 6700' TVD 15MIN - 7394' SLM / 7429' MD / 6600' TVD 10MIN @ SURFACE *** WELL LEFT S/I ON DEPARTURE *** 4/23/2024 LRS #2 2" coil 0.156WT Objective: Reservoir P&A MIRU. MU 2" BDN cementing BHA. RIH w/2" BDN, swap coil over to KCI. Tagged TOC pumping min rate 9,370' ctm / 9,389' MD (+19' correction). PUH to 9,290' ctm / 9,309' MD and swap well to KCI. Pump 15.8 ppg cement as per program: 5 bbl FW spacer, 22 bbls of 15.8 ppg cement, FW spacer. Online down coil w/KCI displacement. .......Continued on 4/24/24 WSR. 4/24/2024 LRS #2 2" coil 0.156WT Objective Res P&A Continue KCI displacement down coil. With cement at nozzle, lay in 22 bbls of 15.8 ppg cement in 9-5/8" casing 1:1 while pulling 13.7 fpm from 9,309' MD - 9,009' MD. With cement out nozzle, shut in choke and Pooh w/BHA pumping PD, maintain 1300 - 1400 psi on WHP. On surface, pumped 5 bbls gel and flushed coil to tanks. FP coil w/60 bbls of diesel. RIH w/2" BDN to 2500' and FP tubing with diesel. Pooh w/BHA pumping diesel PD. RDMO LRS CTU #2. ***Tubing x IA communication, likely GLV leaking*** ***Job Completed*** 5/4/2024 ***WELL S/I ON ARRIVAL*** RAN 3.70" CENT, 4-1/2" TEL, 2-1/2" S. BAILER (msfb). LOC TT @ 7439' SLM/7445' MD (+6' correction), PERFORM AOGCC WITNESS TAG TOC (NOBLE) TAG TOC @ 9001' SLM/9007' MD (bailer full of cement) ***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED OF WELL STATUS*** Daily Report of Well Operations PBU S-32A Agreement w/AOGCC was to place cement from 9314' up to 9164' (150'). The cement reaches 9007', so there is 307' of cement in place. -WCB () @ PERFORM AOGCC WITNESS TAG TOC (NOBLE) TAG TOC() @ 9001' SLM/9007' MD MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:35 Township:12N Range:12E Meridian:Umiat Drilling Rig:n/a Rig Elevation:n/a Total Depth:11848 ft MD Lease No.:ADL 028257 Operator Rep:Suspend:P&A:x Conductor:20"O.D. Shoe@ 114 Feet Csg Cut@ Feet Surface:13 3/8"O.D. Shoe@ 2685 Feet Csg Cut@ Feet Intermediate:9 5/8"O.D. Shoe@ 10099 Feet Csg Cut@ Feet Production:7"O.D. Shoe@ 10113 Feet Csg Cut@ Feet Liner:3.5 x 3.25 x 2.88 O.D. Shoe@ 11845 Feet Csg Cut@ Feet Tubing:4 1/2"O.D. Tail@ 9913 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Fullbore Other 9314 ft 9007 ft 7 ppg Wireline tag Initial 15 min 30 min 45 min Result Tubing IA OA Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: May 4, 2024 Bob Noble Well Bore Plug & Abandonment PBU S-32A Hilcorp North Slope LLC. PTD 2120820; Sundry 323-658 none Test Data: Casing Removal: Jerimiah Galloway Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Plug was founded on existing cement plug. Top of Cement was located with a slick line tag. Bailer was full of what looked tike thick contaminated cement. I ask the co man why there not pressure testing this plug. He said because the plug that this one was founded on had been pressure tested. rev. 3-24-2022 2024-0502_Plug_Verification_PBU_S-32A_bn               From:Rixse, Melvin G (OGC) To:Michael Hibbert Cc:Leslie Reavis; AOGCC Records (CED sponsored); DOA AOGCC Prudhoe Bay Subject:20240201 1311 PTD 212-082 Sundry 323-658 PBU S-32A, PTD 212-092 Sundry 323 PBU S-37A - No pressure test required Date:Thursday, February 1, 2024 1:16:58 PM Attachments:Sundry_323-658_013124.pdf Sundry_323-657_013124.pdf Michael, No pressure test required of the lower plug for these two sundries. The approved Sundries should not include an AOGCC witnessed pressure test as the pressure test was previously performed. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Michael Hibbert <Michael.Hibbert@hilcorp.com> Sent: Thursday, February 1, 2024 1:04 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Leslie Reavis <lreavis@hilcorp.com> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Hi Mel, Attached are the approved sundries for the cement plugs in PBU S-32 and PBU S-37. The AOGCC wrote in under the ‘Other Conditions of Approval’ that the cement plugs will need to be pressure tested to 2500 psi. The reservoir plugs were already AOGCC witness tagged and pressure tested on 4/11/23 and 4/8/23 respectively. These sundries will place additional cement above the tubing stubs, but they cannot be pressure tested due to the Kuparuk formation being perforated uphole. As agreed previously (below in this email chain) the cement plugs will be tagged with AOGCC witness, but not pressure tested. Please advise. Thanks, Michael Hibbert CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. PBW OE – Hilcorp AK From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Tuesday, November 14, 2023 4:36 PM To: Michael Hibbert <Michael.Hibbert@hilcorp.com> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Michael, It sounds like an appropriate plan forward. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Michael Hibbert <Michael.Hibbert@hilcorp.com> Sent: Tuesday, November 14, 2023 2:28 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: FW: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Hello Mel, I wanted to touch bases with you about these 2 jobs that I am taking over from Claire Mayfield. I am planning on placing 150’ of cement above the tubing stubs on S-37 and S-32 as agreed earlier this year after recompleting the wells up-hole as Kuparuk wells. I plan on submitting 10-403’s for this work including AOGCC witness tags post-cement placement. Let me know if that sounds like the appropriate path forward? Thanks, Michael Hibbert PBW Operations Engineer 907-903-5990 CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, May 1, 2023 9:15 AM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Claire, I want to limit the time to 12 months to lay in the 150’ of cement. Then I believe it will work. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Friday, April 28, 2023 10:44 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Hi Mel, Thanks for sending the recent Sundry approval for S-37A. I wanted to send in the same addendum for S-32A attached since it is a similar plan. We can complete this with the same terms as S-37A if that works for you. Recently completed pre-RWO scope on S-32A: 1. SL tagged cement plug at 9378’ SLMD on 4/11/2023 2. MIT-T to 2500 psi passed on 4/11/20233. Eline tagged TOC at 9389’ MD with junk basket on 4/13/2023.4. Eline cut tubing at 9314’ MD on 4/13/2023 Future Abandonment of Ivishak & Sag Reservoir Plan 1. Coiled Tubing to lay ~150’ of cement inside the 9-5/8” casing directly on top of tubing stub at 9314’ to achieve cement across all annuli in the confining zone above the Sag reservoir. 2. SL tag TOC, state witnessed. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Wednesday, April 26, 2023 2:09 PM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Claire, Nice to hear. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Wednesday, April 26, 2023 1:40 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Hi Mel, We can lay that proposed ~150’ of cement above the tubing stub after the workovers are completed (tubing will be out of the way) so that cement across all annuli is achieved over the ivishak more near term rather than ~20 years from now at final abandonment. If it can be done sometime in the next six to twelve months, that would give us a lot of flexibility with coil units and cementing crews. We will likely be sending in a separate sundry to frac this well post RWO, so I just want to make sure we are in good shape for that. Give me a call if you’d like to discuss. Thanks, Claire From: Claire Mayfield Sent: Tuesday, April 25, 2023 9:47 AM To: 'Rixse, Melvin G (OGC)' <melvin.rixse@alaska.gov> Cc: 'Davies, Stephen F (OGC)' <steve.davies@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com>; 'McLellan, Bryan J (OGC)' <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Hi Mel, Please see attached for an addendum that can be attached to the sundry request. Alternatively I can send a full word document or PDF with the addendum included. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Let me know if you would like more information to be included. I only specified the abandonment of the Ivishak/Sag zone. Thanks, Claire From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Monday, April 24, 2023 5:26 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Mel, Can do – thanks for the clarification. Apologies for the delayed response, I’ve been in an offsite training today. I’ll send over that information tomorrow morning or by mid-day. Thanks, Claire From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, April 24, 2023 9:55 AM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com>; McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Claire, Include a final future Ivishak P&A schematic and brief procedure in this sundry request. It should be clear to commissioners, Hilcorp, and AOGCC staff what the future commitment is from Hilcorp to assure permanent isolation of the oil pools. Reading our discussion from February 27, 2023 I am unclear why I would approve a future Ivishak abandonment without a proper cement plug on this sundry. I won’t require this upper plug on these wells today but anticipate a proper Ivishak abandonment to permanently isolate these pools on up coming sundries. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). cc. Bryan, Steve Davies, Aras Worthington From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Monday, April 24, 2023 8:35 AM To: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Hi Bryan, Mel, We aligned in February that a plug on top of the tubing stub would be set upon final abandonment of the well (email discussion attached). Therefore, those steps would be on a future separate sundried program not the workover sundry, correct? We have already tagged and MIT-T’d the current plugs and cut tubing as described in the approved sundries and approved change to leave the LTP in place (email attached). The only program change that is outstanding prompting the 10-403 MOC form, is that Thunderbird Rig 1 rather than Nordic 3 will perform the tubing pull/run steps of the recomplete. Let me know if any other information would be helpful or if you would like to discuss over the phone. Thanks, Claire Mayfield Hilcorp Energy Company Prudhoe Bay West – Operations Engineer Office: (907) 564-4375 Cell: (713) 443-3631 From: McLellan, Bryan J (OGC) <bryan.mclellan@alaska.gov> Sent: Saturday, April 22, 2023 8:16 PM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Cc: Davies, Stephen F (OGC) <steve.davies@alaska.gov>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Hi Claire, Could you send the following information so I can attach it to the Sundry for S-37: 1. Detail your procedure for the P&A plug that you plan to place above the tubing stub. 2. TOC tag depth with SL 3. Results of MIT-T post-cementing 4. Depth of tubing cut. 5. Updated Proposed P&A schematic Thank you Bryan McLellan Senior Petroleum Engineer Alaska Oil & Gas Conservation Commission 333 W 7th Ave Anchorage, AK 99501 Bryan.mclellan@alaska.gov +1 (907) 250-9193 From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, February 27, 2023 3:10 PM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Claire, I am good with that. Please request through proper AOGCC account that you want to recall last week’s sundries. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Monday, February 27, 2023 2:50 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Thanks Mel – Agreed that upon final abandonment, we can lay in cement just above that production packer in the production casing. If you’re good with leaving the LTP’s in place, not punching holes and documenting via email, then I am good to withdraw the recent change sundries submitted. Thanks, Claire From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Monday, February 27, 2023 2:38 PM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Claire, I can approve the original sundries if we lay in cement across all annuli at the confining zones above the Ivishak (and above the existing production packer) for the final well abandonment sometime in the future. Do you want to just withdraw the sundries you submitted last week for ‘change to approved program’? Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Monday, February 27, 2023 8:37 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Mel, Can you give me a call on this when you get a chance? Thanks, Claire From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, February 24, 2023 5:05 PM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Claire, AOGCC wants cement across all annuli for a reservoir abandonment. Please assure you put 100’ of cement above your existing production packer within the 9-5/8” on S-32A and 100’ above your production packer within the 7-5/8” on S-37A. No reason to cut your tubing higher. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Rixse, Melvin G (OGC) Sent: Tuesday, February 21, 2023 3:18 PM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Claire, Sorry to do this to you but AOGCC should get new sundries with ‘change to approved program’ checked. The field inspectors will be confused if we don’t do this step. CAUTION: External sender. DO NOT open links or attachments from UNKNOWN senders. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Monday, February 20, 2023 4:56 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: RE: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Hi Mel, Yes I can confirm the two statements below. I am comfortable with setting the TOC’s >=100’MD above the production packers in both cases. Also, for S-32, I had a step for punching holes in the tubing tail just below the production packer. However, with 100’ of cement above the production packer, that step seems redundant. If we get a passing pressure test on that production packer (meaning the cement from the window up to the tubing tail is competent), I’d like to avoid punching holes, and go ahead with the fullbore cement P&A with the TOC >=100’MD above the production packer. Let me know if all sounds good to you. Thanks, Claire From: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Sent: Friday, February 17, 2023 3:50 PM To: Claire Mayfield <Claire.Mayfield@hilcorp.com> Subject: [EXTERNAL] RE: S-32A and S-37A Liner Top Packers Claire, Please confirm the following: CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. 1. PTD212-082, S-32A the production tubing packer at 9832’ MD is within and greater than 100’ below the top of the PB oil pool confining zones. Yes/No? Yes 2. PTD212-092, S-37 the production tubing packer at 8837’ MD is within and greater than 100’ below the top of the PB oil pool confining zones. Yes/No? Yes If you are able to answer ‘Yes’ to the two questions above, I will approve not pulling the LTPs in these wells, but AOGCC would like to see a minimum of 100’ MD of cement above the packers. That would be the following: 1. For S-32A, TOC would be at shallower than 9732’ MD. 2. For S-37A, TOC would be at shallower than 8737’ MD. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Wednesday, February 15, 2023 8:36 AM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: S-32A and S-37A Liner Top Packers Hi Mel, On two of our upcoming recomplete wells, S-32 and S-37, we were unable to pull the LTPs after many hours of jarring as planned pre-abandonment of the ivishak completion. We will plan to leave the LTP’s in place, pump the fullbore cement P&A into the liner and above the liner top with ~25’ of cement on top of the LTP (same target TOC’s as in original sundries approved). Please let me know if you have any questions/concerns with leaving the LTP’s in place. Thanks, Claire Mayfield Hilcorp Energy Company Prudhoe Bay West – Operations Engineer Office: (907) 564-4375 Cell: (713) 443-3631 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in thes pool? Will perfs require a spacing exception due to property boundaries?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStratigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify AOGCC so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other Conditions of Approval: Post Initial Injection MIT Req'd?Yes No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU S-32A Reservoir Cement Plug Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 212-082 50-029-22099-01-00 457B ADL 0028257 11848 Conductor Surface Intermediate Production Liner 8987 80 2657 10071 253 1990 9389 20" 13-3/8" 9-5/8" 7" 3-1/2" x 3-1/4" x 2-7/8" 8250 34 - 114 33- 2685 31- 10099 9860 - 10113 9855 - 11845 3409 34 - 114 28 - 2685 28 - 8810 8264 - 8821 8621 - 8987 None 2260 4760 5410 10530 9389 5020 6870 7240 10160 7524 - 7590 4-1/2" 12.6# 13Cr80 28 - 7445, 9314 - 99136741 - 6795 Structural 4-1/2" HES TNT Packer 4-1/2" TIW Packer 9832, 8603 7388, 6632 Date: Torin Roschinger Operations Manager Michael Hibbert michael.hibbert@hilcorp.com (907) 903-5990 PRUDHOE BAY 1/15/2024 Current Pools: Aurora Oil Proposed Pools: Aurora Oil Suspension Expiration Date: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 06/2023 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov No SSSV Installed Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.12.08 17:00:55 -09'00' Torin Roschinger (4662) By Grace Christianson at 12:50 pm, Dec 11, 2023 323-658 10-404 DSR-12/14/23MGR31JAN24SFD 12/20/2023 AOGCC to witness slickline tag and pressure test of cement plug to 2500 psi. TOC ~ 9239' MD 3409 *&:JLC 1/31/2024 1/31/24Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2024.01.31 15:23:18 -09'00' RBDMS JSB 020124 Ivishak Cement Plug Well: S-32A Well Name:S-32A API Number:50-029-22099-01 Current Status:Kuparuk Producer - SI Estimated Start Date:1/15/2024 Rig:Coiled Tubing Sundry #TBD Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker Permit to Drill Number:212-082 First Call Engineer:Michael Hibbert (907) 903-5990 (M) Second Call Engineer:Kirsty Glasheen (907) 350-4310 (C) Est Bottom Hole Pressure:4079 psi @ 6700 TVD 11.8 PPG | (Est based on 2018 data) Max. Anticipated Surface Pressure:3409 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:1100 psi (Taken on 6/4/2023) Min ID:3.813” at 7359’ MD X-nipple Max Angle:40 Deg @ 5,628’ MD Cement Tag:EL tagged TOC at 9,389’ on 4/13/23 with 3.5” JetCutter Last Intervention:Slickline pulled PX plug from 7,421’ Brief Well Summary: S-32A was originally completed as a Sag/Ivishak well, but had been shut in for several years, so that reservoir was abandoned and recompleted to be a Kuparuk well. The Ivishak/Sag was isolated with a cement plug pumped on 4/8/23. An AOGCC witnessed tag of the cement top was completed on 4/11/23, 9389’ MD. An AOGCC witnessed MIT-T was completed on 4/11/23 to 2500 psi. A RWO was executed in May 2023 which pulled the existing 4-1/2” tubing and install new 4-1/2” tubing and a 4-1/2” x 9-5/8” packer at 7388’. Kuparuk perforations were added from 7,524’-7,590’. WC was high and the planned frac was never completed. As part of the Kuparuk recomplete, Hilcorp made an agreement with the AOGCC to place a 150’ cement plug in the 9-5/8” casing above the cut tubing stub by the end of Q1 2024. Job includes pumping excess cement to allow for any contamination/slumping of cement top. Objective: x Place cement plug in the 9-5/8” casing from ~9,314’ - ~9,164’. AOGCC witnessed tag of cement top. Slickline 1. Drift to cement top at 9,389’. Tie into tubing tail for depth correction. 2. Collect sample from TD. DHD 1. Get tubing and IA fluid levels and pressures Coiled Tubing 1. MIRU 1.75” CT w/ cementers 2. MU and RIH w/ cementing BHA a. Note there are open perforations above the cement placement depths from 7,524’-7,590’. b. 3. Layin 22 bbls of Class G cement from 9314’-9014’ a. Let ~2 bbls exit nozzle and then layin 1 for 1. 9-5/8” casing has a capacity of 13.7 ft/bbls. Pump at 1 bpm and pull at 13.7 fpm. b. TOC should be at ~9014’. 4. POOH. 5. RDMO. Ivishak Cement Plug Well: S-32A Slickline – Wait on Cement 1. Give AOGCC 24 hours notice prior to tag 2. Perform AOGCC witnessed tag of cement. Ivishak Cement Plug Well: S-32A Current WBD: Ivishak Cement Plug Well: S-32A PTD: 212-082 Proposed WBD: Cement Plug in 9-5/8” from 9,389’-9,239’ Estimated TOC ~5448’ MD Hi l c o r p N o r t h S l o p e , L L C Hi l c o r p N o r t h S l o p e , L L C Ch a n g e s t o A p p r o v e d W o r k O v e r S u n d r y P r o c e d u r e Da t e : D e c e m b e r 8 , 2 0 2 3 Su b j e c t : C h a n g e s t o A p p r o v e d S u n d r y P r o c e d u r e f o r W e l l S - 3 2 A Su n d r y # : An y m o d i f i c a t i o n s t o a n a p p r o v e d s u n d r y w i l l b e d o c u m e n t e d a n d a p p r o v e d b e l o w . C h a n g e s t o a n a p p r o v e d s u n d r y w i l l b e c o m m u n i c a t e d t o th e AO G C C b y t h e w o r k o v e r ( W O ) “ f i r s t c a l l ” e n g i n e e r . A O G C C w r i t t e n a p p r o v a l o f t h e c h a n g e i s r e q u i r e d b e f o r e i m p l e m e n t i n g t h e c h a n g e . St e p Pa g e Da t e P r o c e d u r e C h a n g e HNS Pr e p a r e d By ( I n i t i a ls ) HN S Ap p r o v e d By ( I n i t i a l s ) AO G C C W r i t t e n Ap p r o v a l R e c e i v e d (P e r s o n a n d D a t e ) Ap p r o v a l : As s e t T e a m O p e r a t i o n s M a n a g e r D a t e Pr e p a r e d : Fi r s t C a l l O p e r a t i o n s E n g i n e e r D a t e 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: 11/28/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20231128 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# BCU-13 50133205250000 203138 11/13/2023 HALLIBURTON RMT3D MPU B-28 50029235660000 216027 11/20/2023 HALLIBURTON LDL MPU B-28 50029235660000 216027 11/21/2023 HALLIBURTON MFC MPU C-20 50029219140000 189015 11/21/2023 HALLIBURTON LDL NS-24 50029231110000 202164 11/20/2023 READ LeakPointSurvey PBU 13-20 50029207050000 182009 11/16/2023 HALLIBURTON WFL-TMD3D PBU L-216 50029232060000 204065 7/20/2023 PROBE MSIL (CBL) PBU S-09A 50029207710100 214097 7/7/2023 PROBE MSIL (CBL) PBU S-32A 50029220990100 212082 7/13/2023 PROBE MSIL (CBL) PBU S-124 50029233230000 206136 7/15/2023 PROBE MSIL (CBL) Please include current contact information if different from above. T38150 T38151 T38151 T38152 T38153 T38154 T38155 T38156 T38157 T38158 11/29/2023 PBU S-32A 50029220990100 212082 7/13/2023 PROBE MSIL (CBL) Kayla Junke Digitally signed by Kayla Junke Date: 2023.11.29 11:22:45 -09'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:AOGCC Permitting (CED sponsored) To:Brooks, James S (OGC) Subject:FW: Cancellation Request: PBU S-32A (PTD #212-082) 10-403 Request #323-347 Date:Tuesday, November 14, 2023 12:54:55 PM Attachments:Sundry_323-347_063023.pdf FYI From: Abbie Barker <Abbie.Barker@hilcorp.com> Sent: Monday, November 13, 2023 1:55 PM To: AOGCC Permitting (CED sponsored) <aogcc.permitting@alaska.gov> Cc: Torin Roschinger <Torin.Roschinger@hilcorp.com>; Tyson Shriver <Tyson.Shriver@hilcorp.com>; Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov>; Aras Worthington <Aras.Worthington@hilcorp.com> Subject: Cancellation Request: PBU S-32A (PTD #212-082) 10-403 Request #323-347 Hello, We request cancellation of Sundry 323-347 (attached for reference). No reportable work was executed and the fracture stimulation has been cancelled. Please let me know if you have any questions. Thank you, Abbie Abbie Barker Regulatory Tech, Prudhoe Bay West Team Hilcorp North Slope Email: Abbie.Barker@hilcorp.com Cell: (907)351-2459 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are hereby notified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, please immediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently delete this message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that theonward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibilityis accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in thes pool? Will planned perforations require a spacing exception?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStrastigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other: Post Initial Injection MIT Req'd? Spacing Exception Required?Yes Yes No No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU S-32A Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 212-082 50-029-22099-01-00 457B ADL 0028257 11848 Conductor Surface Intermediate Liner Liner 8987 80 2657 10071 253 1990 9389 20" 13-3/8" 9-5/8" 7" 3-1/2" x 3-1/4" x 2-7/8" 8250 34 - 114 33- 2685 31- 10099 9860 - 10113 9855 - 11845 2539 34 - 114 28 - 2685 28 - 8810 8264 - 8821 8621 - 8987 None 2260 4760 5410 10530 9389 5020 6870 7240 10160 7524 - 7590 4-1/2" 12.6# 13Cr80 28 - 7445, 9314 - 99136741 - 6795 Structural 4-1/2" HES TNT Packer 4-1/2" TIW Packer 7388, 6632 9832, 8603 Date: Torin Roschinger Area Operations Manager Claire Mayfield Claire.Mayfield@hilcorp.com 907-564-4375 PRUDHOE BAY 7/4/2023 Current Pools: Aurora Oil Proposed Pools: Aurora Oil STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 10/2022 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Grace Christianson at 12:33 pm, Jun 15, 2023 323-347 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.06.15 11:49:32 -08'00' Torin Roschinger (4662) MGR28JUN23 Fracture Stimulate DSR-6/15/23 10-404 Monitor T/IA/OA pressures in the following wells during fracture-stimulation operations: S-15, S-43, S-42A, S-35, and S-24. Stop fracture-stimulation injection operations if any unexpected pressures are observed. CDW 06/29/2023 SFD 6/29/2023 2539 JLC 6/30/23 06/30/23Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.06.30 11:33:34 -05'00' RBDMS JSB 071123 Frac post RWO Well: S-32A PTD: 212-082 Well Name:S-32A API Number:50-029-22099-01 Current Status:Producer SI Estimated Start Date:7/4/2023 Rig:SL/Coil Sundry #?Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker First Call Engineer:Claire Mayfield (907) 564-4375 (O)(713) 443-3631 (M) Second Call Engineer:Brodie Wages (907) 564-5006 (O)(907) 380-9836 (M) Current Bottom Hole Pressure:3209 psi @ 6700 TVD 9.21 PPG | (S-122 06/15/2022 static) 11.1 PPG with 2500’ diesel freeze protect Max. Anticipated Surface Pressure:2539 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:N/A since recomplete Min ID:3.813” X at 2170’ MD (smaller ID’s below cement plug) Max Angle:40 Deg @ 5357’ MD (higher deviations below cement plug) Formation Tops: Kuparuk: 7522 MD, 6740 TVD Kingak: 8648 MD, 7651TVD Sag: 10090 MD, 8804TVD Shublik: 10150 MD, 8848TVD Sadlerochit: 10260 MD, 8897 TVD MITs: MIT-T: 3600 psi on 5/26/2023 MIT-IA: 3900 psi on 5/26/2023 Brief Well Summary: S-32A was originally completed as a Sag/Ivishak producer, but it had been shut in for several years as uncompetitive, so a RWO was executed to recomplete the well to Kuparuk. The Sag/Ivishak perfs were isolated with a fullbore cement plug filling the liner up to the old tubing stub. The workover pulled old tubing and ran in new tubing to complete the well as a Kuparuk producer. Eline perforated the Kuparuk on 6/4/23 for this proposed single stage frac. Notes Regarding Wellbore Condition 11/17/2002 CMIT-TxIA Passed to 2400 psi 7/8/2004 MITOA to 2400 psi - Pass 10/25/2008 Caliper 267 jts 0-10%, run DGLV's MIT-IA Passed to 2400 psi 4/16/2009 MIT-IA Passed to 2500 psi 3/8/2009 LDL found packer leak at 9832' LLR 0.14gpm @ 3000psi on IA 5/31/2009 Conductor Treated with 3.4 gal RG-2401 11/7/2009 Set TTP @ 9826", Pull DGLV STA #1, MIT-T Passed to 2500 psi 11/14/2009 Sealtite treatment -IC 12/7/2009 LGLVs in Sta # 5, 4, & 3, pulled TTP 12/8/2009 SL Set Rock screen @ 9900' 12/31/2009 Seal-Tite treatment IC 9/1/2011 SL Pulled Rock screen @ 9900' 4/20/2012 SL Set DGLV's, MIT-IA Passed to 2500 psi, MIT-OA Passed to 2000 psi |9.21 PPG Frac post RWO Well: S-32A PTD: 212-082 7/27/2012 PPPOT-T Passed to 5000 psi 9/18/2012 CTD drilled, completed S-32A 9/26/2012 SL Set LTP @ 9855', MIT-T to 2500 psi Passed 9/27/2012 SL Set LGLVs in GLM #s 5, 4, & 3, Set OGLV in GLM # 1 11/25/2012 PPPOT-IC Passed 6/27/2013 Seal-Tite treatment IC 2/16/2015 PPPOT-T Passed to 5000 psi, PPPOT-IC Passed to 3500 psi, LDS ok 9/30/2015 Set PX Plug @ 9826' MD, MIT-T Passed to 2000 psi 10/1/2021 SL subsidence drift to 3000' 4/28/2023 Fullbore cement P&A of Ivishak completion, TOC 9389’MD 5/22/2023 RWO pulled tubing, replaced IC seals 5/26/2023 RWO ran new tubing for Kuparuk completion 6/04/2023 Eline perforated Kuparuk Objective: x DMY valves, circ packer fluid, frac and flowback Slickline with fullbore assist 1. Set plug in X nipple at 7421’MD 2. Dummy GLVs above St1 3. Pull St1 GLV for circ’ing in KWF 4. Load hole with 1% KCl + Freeze protect a. Total T+IA volume to St#1: 389+110 = 500 bbls b. Freeze protect volume to 2500’ in tbg and IA: 38bbl + 133bbls = 171 bbls 5. Dummy st#1 6. MIT-T to 4000 psi, hold 1000psi on IA 7. Obtain 3500 psi MIT-IA a. Hold 1000 psi on the tubing during MIT-IA 8. Pull plug in X nipple Sundry Procedure (Approval Required to Proceed) Frac/Special Projects 1. Spot water tanks and fill with fresh water a. Heat water to 110 degF b. Minimum pumping temp for water: 90 degF 2. Pull water from each tank and have SLB lab test our water quality: a. pH - ~7 i. Higher pH delays the hydration of the gel and delays break b. Calcium/magnesium <500 mg/l MIT-T to 4000 psi, hold 1000psi on IA 3900 psi per statement below. -mgrObtain 3500 psi MIT-IA Pressure test treating lines to 5500 psi. Test IA pop off system to 3700 psi.-mgr Frac post RWO Well: S-32A PTD: 212-082 i. Mg/Ca Negative side effects in the formation such as carbonate deposits, which tend to be insoluble c. Bicarbonate - <400 mg/l i. High bicarbonate levels will cause slow hydration times and elevated delay times with X-linking fluids. If we have elevated bicarbonate levels and have introduced delay agents, it could have an exponential effect in delay times. d. Chlorides-<10,000 mg/l i. This fluid system should be able to cope with elevated Chloride levels e. Iron (Fe+3) - <5 mg/l i. Elevated Iron concentrations exist, the ammonium persulfate (breaker) can have an accelerated effect. Can cause viscosity degradation in linear gels (especially if batch mixed). Also can interfere with X-linking b/c iron will tie up the X-linking sites. f. TDS – minimal/<5000 i. Effects depend on the solids that are dissolved in the fluid. 3. Frac per pump schedule MIT-T 3600 psi MIT-IA 3900 psi Maximum Anticipated Treating Pressure:2900 psi @ 25 BPM IA Pop-off Set Pressure (~95% of MIT-IA):3700 psi IA Minimum Hold Pressure (POP-off – 300 psi):3400 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T): 4500 psi (tree limited to 5000psi) Stagger Pump Kickouts Between 90 – 95% of MATP:4050 - 4300 Global Kickout (95% of MATP):4300 psi N2 POP-off set pressure (MATP + 1000 psi):5500 psi Treating Line Test Pressure (MATP + 1000 psi):5500 psi x If treating pressure starts acting sporadic, consider dropping rate to as low as 11 ppa. If it is acting up at 11 ppa, we should be on flush. Slickline 1. Drift, tag fill – determine whether coil FCO likely needed 2. Install catcher 3. Install LGLVs 4. Pull catcher 5. RDMO Coil Tubing - Pending – Only FCO if unable to get returns due to fill 1. MIRU and pressure test 2. MU JSN or down jet 3. FCO to 7,700’ MD 4. POH 4000 psi with 1000 on IA is a 3900 psi test. Frac post RWO Well: S-32A PTD: 212-082 Testers: 1. MIRU, pressure test 2. POP the well to ASRC with 1-1.5 MMSCFD Lift gas at minimum choke, adjust GL rate as necessary to eliminate slugging. Flow the initial returns to the flowline as long as the shake-outs meet the returned fluid/solids management guidelines. 3. Limit flow to 500 bpd 4. If solids are < 1%, after 1.5 wellbore volumes (120 bbls) increase the production rate to 750 BLPD. 5. Flow bottoms up and sample for solids production. If solids are still below 1%, increase flow to 1000 BFPD. 6. Flow bottoms up and sample for solids production. If solids are still below 1% continue to increase the flow rate in 250 BPD increments. The objective is to achieve maximum drawdown. Watch returns and do not continue to open choke if solids > 1%; allow well clean up before choke is opened further. 7. Once at FOC, stabilize the well for 4 hrs. Obtain an 8 hr welltest. Attachments: 1. Wellbore Schematic 2. Frac Detail 3. Sundry Change Form Frac post RWO Well: S-32A PTD: 212-082 Current WBD: S-32A Fracture Stimulation PTD: 212-082 Page 1 Date: June 14, 2023 Subject: S-32A Fracture Stimulation From: Claire Mayfield O: (907) 564-4375 C: (713) 443-3631 To: AOGCC Estimated Start Date: 7/4/2023 Attached is Hilcorp’s proposal and supporting documents to perform a fracture stimulation on well S- 32A in the Kuparuk reservoir of the Prudhoe Bay Unit. The objective of this program is to perform a single stage fracture stimulation to the existing Kuparuk perforations to improve well performance. S-32A was recently recompleted as a Kuparuk producer, previously an Ivishak producer. The Ivishak perforations were plugged on 4/8/2023 with cement filling the Ivishak production liner. Isolation from the Ivishak was demonstrated with a state witnessed passing MIT on 4/11/2023. The Kuparuk interval was perforated on 6/04/2023. Hilcorp requests a variance to sections 20 AAC 25. 283, a, 3- 4 which require identification of fresh - water aquifers and a plan for base-water sampling. Please direct questions or comments to Claire Mayfield. Recommend approving requested variance: no freshwater aquifers are present and, therefore, no base-water sampling should be required. SFD 6/29/2023 S-32A Fracture Stimulation PTD: 212-082 Page 2 SECTION 1 - AFFIDAVIT (20 AAC 25. 283, a, 1): Below is an affidavit stating that the owners, landowners, surface owners and operators identified on a plat within one-half mile radius of the current or proposed wellbore trajectory have been provided notice of operations in compliance with 20 AAC 25.283, a 1 S-32A Fracture Stimulation PTD: 212-082 Page 3 SIGNED AFFIDAVIT: S-32A Fracture Stimulation PTD: 212-082 Page 4 COPY OF NOTIFICATION SENT VIA EMAIL: S-32A Fracture Stimulation PTD: 212-082 Page 5 SECTION 2: PLAT IDENTIFYING ALL WELLS WITHIN ½ MILE (20 AAC 25. 283, a, 2): Plat of wells within one-half mile of S-32A trajectory. S-32A Fracture Stimulation PTD: 212-082 Page 6 List of wells in Plat 20 AAC 25.283, a, 2 Sw Name Well Class Desc Well Status Desc Sw Name Well Class Desc Well Status Desc S-01 Development Abandoned S-13A Development Oil Producer Gas Lift S-01A Development Abandoned S-13APB1 Development Plugged Back For Redrill S-01B Development Abandoned S-14 Service Abandoned S-01C Development Oil Producer Gas Lift S-14A Service Water Injector Shut-In S-02 Development Abandoned S-15 Service Miscible Injector Shut-In S-02A Development Oil Producer Gas Lift S-15PB1 Service Plugged Back For Redrill S-02AL1 Development Oil Well S-16 Development Oil Producer Shut-In S-02AL1PB1 Development Plugged Back For Redrill S-16PB1 Development Plugged Back For Redrill S-02APB1 Service Plugged Back For Redrill S-17 Development Abandoned S-03 Development Oil Producer Gas Lift S-17A Development Abandoned S-04 Service Water Injector Shut-In S-17AL1 Development Abandoned S-05 Development Abandoned S-17AL1PB1 Development Plugged Back For Redrill S-05A Service Water Injector Injecting S-17APB1 Development Plugged Back For Redrill S-05APB1 Service Plugged Back For Redrill S-17B Development Abandoned S-06 Service Water Injector Injecting S-17C Development Oil Producer Shut-In S-07 Development Abandoned S-17CPB1 Development Plugged Back For Redrill S-07A Development Oil Producer Shut-In S-17CPB2 Development Plugged Back For Redrill S-08 Development Abandoned S-18 Development Abandoned S-08A Development Abandoned S-18A Development Abandoned S-08B Development Oil Producer Gas Lift S-18B Development Oil Producer Shut-In S-09 Service Abandoned S-19 Development Oil Producer Shut-In S-09A Service Water Injector Injecting S-20 Service Abandoned S-09APB1 Service Plugged Back For Redrill S-200 Development Abandoned S-09APB2 Service Plugged Back For Redrill S-200A Development Oil Producer Gas Lift S-09APB3 Service Plugged Back For Redrill S-200PB1 Development Plugged Back For Redrill S-10 Development Abandoned S-201 Development Abandoned S-100 Development Oil Producer Flowing S-201A Service Miscible Injector Operating S-101 Service Miscible Injector Operating S-201PB1 Development Plugged Back For Redrill S-101PB1 Development Plugged Back For Redrill S-202 Development Oil Producer Gas Lift S-102 Development Oil Producer Shut-In Development Oil Well S-102L1 Development Abandoned S-202L2 Development Oil Well S-102L1PB1 Development Plugged Back For Redrill S-202L3 Development Oil Well S-102PB1 Development Plugged Back For Redrill S-202L4 Development Oil Well S-103 Development Oil Producer Gas Lift S-20A Service Water Injector Injecting S-104 Service Water Injector Injecting S-21 Development Oil Producer Gas Lift S-105 Development Abandoned S-210 Service Water Injector Injecting S-105A Development Oil Producer Gas Lift S-213 Development Abandoned S-106 Development Abandoned S-213A Development Oil Producer Gas Lift S-106A Development Oil Producer Gas Lift S-213AL1 Development Oil Producer Flowing S-106L1PB1 Development Plugged Back For Redrill S-213AL1-01 Development Oil Producer Flowing S-106L1 Development Abandoned S-213AL2 Development Oil Well S-106PB1 Development Plugged Back For Redrill S-213AL3 Development Oil Well S-107 Service Miscible Injector Shut-In S-215 Service Water Injector Injecting S-108 Development Oil Producer Shut-In S-216 Service Miscible Injector Operating S-109PB1 Development Plugged Back For Redrill S-217 Service Miscible Injector Operating S-10A Development Suspended S-218 Service Water Injector Injecting S-10APB1 Development Plugged Back For Redrill S-22 Development Abandoned S-10APB2 Development Plugged Back For Redrill S-22A Development Abandoned S-11 Service Abandoned S-22B Service Water Injector Injecting S-110 Service Abandoned S-23 Development Oil Producer Gas Lift S-110A Service Abandoned S-24 Development Abandoned S-110B Service Water Injector Injecting S-24A Service Abandoned S-111 Service Water Injector Injecting S-24APB1 Service Plugged Back For Redrill S-111PB1 Service Plugged Back For Redrill S-24B Service Water Injector Injecting S-111PB2 Service Plugged Back For Redrill S-25 Development Abandoned S-112 Service Water Injector Injecting S-25A Service Water Injector Injecting S-112L1 Service Water And Gas Injector S-25APB1 Service Plugged Back For Redrill S-112L1PB1 Service Plugged Back For Redrill S-26 Development Oil Producer Shut-In S-112L1PB2 Service Plugged Back For Redrill S-27 Development Abandoned S-113 Development Abandoned S-27A Development Abandoned S-113A Development Abandoned S-27APB1 Development Plugged Back For Redrill S-113B Development Oil Producer Shut-In S-27B Development Oil Producer Shut-In S-113BL1 Development Oil Producer Shut-In S-28 Development Abandoned S-114 Development Abandoned S-28A Development Abandoned S-114A Service Water Injector Shut-In S-28B Development Oil Producer Shut-In S-115 Development Oil Producer Gas Lift S-28BPB1 Development Plugged Back For Redrill S-116 Service Abandoned S-29 Development Abandoned S-116A Service Miscible Injector Operating S-29A Service Water Injector Shut-In S-116APB1 Service Plugged Back For Redrill S-29AL1 Service Water Injector Shut-In S-116APB2 Service Plugged Back For Redrill S-30 Development Oil Producer Shut-In S-117 Development Oil Producer Gas Lift S-31 Development Abandoned S-118 Development Oil Producer Gas Lift S-31A Service Water Injector Injecting S-119 Development Abandoned S-32 Development Abandoned S-119A Development Oil Producer Shut-In S-32A Development Oil Producer Shut-In S-11A Service Abandoned S-33 Development Oil Producer Gas Lift S-11B Service Water Injector Injecting S-34 Service Water Injector Injecting S-12 Development Abandoned S-35 Development Oil Producer Gas Lift S-120 Service Water Injector Injecting S-36 Development Oil Producer Shut-In S-121 Development Oil Producer Gas Lift S-37 Development Abandoned S-121PB1 Development Plugged Back For Redrill S-37A Development Oil Producer Shut-In S-122 Development Oil Producer Gas Lift S-37APB1 Development Plugged Back For Redrill S-122PB1 Development Plugged Back For Redrill S-38 Development Oil Producer Shut-In S-122PB2 Development Plugged Back For Redrill S-40 Development Abandoned S-122PB3 Development Plugged Back For Redrill S-400 Service Abandoned S-123 Service Water Injector Injecting S-400A Service Water Injector Shut-In S-124 Service Water Injector Injecting S-401 Service Water Injector Shut-In S-125 Development Oil Producer Gas Lift S-401PB1 Service Plugged Back For Redrill S-125PB1 Development Plugged Back For Redrill S-40A Development Oil Producer Shut-In S-126 Service Miscible Injector Operating S-41 Development Abandoned S-128 Service Water Injector Injecting S-41A Service Water Injector Injecting S-128PB1 Service Plugged Back For Redrill S-41AL1 Service Water Injector Shut-In S-128PB2 Service Plugged Back For Redrill S-41L1 Development Abandoned S-129 Development Abandoned S-41PB1 Service Plugged Back For Redrill S-129A Development Oil Producer Gas Lift S-42 Development Abandoned S-129PB1 Development Plugged Back For Redrill S-42A Development Oil Producer Gas Lift S-129PB2 Development Plugged Back For Redrill S-42PB1 Service Plugged Back For Redrill S-12A Development Abandoned S-43 Development Oil Producer Gas Lift S-12B Development Oil Producer Shut-In S-43L1 Development Oil Producer Gas Lift S-13 Development Abandoned S-44 Development Abandoned S-134 Service Water Injector Injecting S-44A Development Oil Producer Flowing S-135 Development Oil Producer Gas Lift S-44L1 Development Abandoned S-135PB1 Development Plugged Back For Redrill S-44L1PB1 Development Plugged Back For Redrill S-135PB2 Development Plugged Back For Redrill S-504 Service Water Injector Shut-In NKUPST Exploration Abandoned S-106A S-32A Fracture Stimulation PTD: 212-082 Page 7 SECTION 3: EXEMPTION FOR FRESWATER AQUIFERS (20 AAC 25. 283, a, 3): Well S-32A is in the West Operating Area of Prudhoe Bay. Per Aquifer Exemption Order No. 1 dated July 11, 1986 where Standard Alaska Production Company requested the Alaska Oil and Gas Conservation Commission to issue an order exempting those portions of all aquifers lying directly below the Western Operating Area and K Pad Area of the Prudhoe Bay Unit for Class II Injection activities. Findings 1- 4 state: 1. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit do not currently serve as a source of drinking water. 2. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are situated at a depth and location that makes recovery of water for drinking water purposes economically impracticable. 3. Those portions of freshwater aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit are reported to have total dissolved solids content of 7000 mg/ I or more. 4. By letter of July 1, 1986, EPA- Region 10 advises that the aquifers occurring beneath the Western Operating and K pad areas of the Prudhoe Bay Unit qualify for exemption. It is considered to be a minor exemption and a non-substantial program revision not requiring notice in the Federal Registrar. Per the above findings, " Those portions of freshwater aquifers lying directly below the Western Operating and K Pad Areas of the Prudhoe Bay Unit qualify as exempt freshwater aquifers under 20 AC 25. 440" thus allowing Hilcorp exemption from 20 AAC 25. 283, a, 3- 4 which require identification of freshwater aquifers and establishing a plan for base-water sampling. Agree SFD 6/28/2023 S-32A Fracture Stimulation PTD: 212-082 Page 8 SECTION 4: PLAN FOR BASELINE WATER SAMPLING FOR WATER WELLS 20 AAC 25.283.a.4 There are no water wells located within one-half mile of the current or proposed wellbore trajectory and fracturing interval. A water well sampling plan is not applicable.Agree SFD 6/29/2023 S-32A Fracture Stimulation PTD: 212-082 Page 9 SECTION 5: DETAILED CEMENTING AND CASING INFORMATION (20 AAC 25. 283, a, 5): All casing is cemented in accordance with 20 AAC 25.52, b and tested in accordance with 20 AAC 25.030, g when completed. See wellbore schematic for casing details: S-32A Fracture Stimulation PTD: 212-082 Page 10 SECTION 6: ASSESSMENT OF EACH CASING AND CEMENTING OPERATION TO BE PERFORMED TO CONSTRUCT OR REPAIR THE WELL 20 AAC 25.283, a, 6 Summary: S-32 and S-32A History: S-32 was originally drilled in 1990. The 17-1/2” surface hole was drilled to 2700’, 13-3/8” casing was set and cemented with 3722 cu ft of AS III and II. A 12-1/4” hole was drilled to 10104’; the 9-5/8” casing was installed to 10099’ and cemented with 2078 cu ft of Class Gcement. The 9-5/8” casingwaspressure tested to 3000psi, then the shoe was drilled out and the 8-1/2” hole wasdrilledto TD at 10690’. AnRFT log was run, then the 7” liner was run in hole and cemented with 332 cu. ft of Class G cement. They tested the casing and liner, then ran 4-1/2” tubing, set the production packer, and tested tubing to 2500psi before rigging down. The well was completed as a Zone 4 Ivishak producer. It was shut in most of the time since 2002 due to low oil production, and little well work options remaining. S-32Adrillingcommenced onSeptember 2, 2012to targetupper Zone 4 Ivishak in two ESE-WNW oriented fault blocks. Before milling the window, significant losses initially experienced were mitigated with a cement squeeze. Then thewindow was milled from 10,113’ to 10,121’ MD, with new formation / rat hole drilled to a depth of 10,131’ MD. Drilling proceeded through fault # 1, encountered at 10,400’ MD with no significant increase in losses (20-30bph throughout). Drilling continued, moving upward after encountering wet rock on logs and back downward after encountering the TSAD, drilling past the 45N into 45P reservoir to TD. The liner was run and cemented with 25.8 bbls cement pumped and estimated 20.6 bbls behind pipe. After several cleanout runs, the liner lap tested and failed, then the liner was perf’d on the rig. After CTD RDMO, SL installed a liner top packer. On 5/26/2023, a RWO was completed converting S-32A from an Ivishak producer to a Kuparuk producer. The ivishak reservoir wasisolatedwith cement,filling the liner and lower tubing stub up to 9389’ MD. The cement plug was MIT-T’d to 2500psi. The tubing was cut and pulled from 9311’ MD. The intermediate casing packoff was replaced, and the 9-5/8" casing was loggedfor cement. ACAST-Mlog dated5/24/2023 found TOC at 2709' MD, with good quality cement found at and below 3659' MD. The new 4-1/2” completion was run in hole and the production packer was set at 7388’ MD. The new completion passed an MIT-T and an MIT-IA to 3500psi. Perforationswereaddedbetween7524-7590’ MDin the Kuparuk, andthe well is planned to bestimulated with the proposed frac. As part of the full abandonment of the Ivishak reservoir, a future ~150’ cement plug is planned to be laid just above the existing tubing stub filled with cement within 12 months of the RWO. All casing is cemented in accordance with 20 AAC 25.030 and each hydrocarbon zone penetrated by the well is isolated. Based on engineering evaluation of the wells referenced in this application, Hilcorp has determined that this well can be successfully fractured within it’s design limits. Perforations wereaddedbetween 7524-7590’ MDin the Kuparuk, . ACAST-Mlog dated5/24/2023 found TOC at 2709' MD, with good quality cement found at and below 3659' MD. S-32A Fracture Stimulation PTD: 212-082 Page 11 SECTION 7 – PRESSURE TEST INFORMATION AND PLANS TO PRESSURE TEST CASINGS AND TUBING INSTALLED IN THE WELL 20 AAC 25.283, A, 7 On 5/26/2023, the production casing was pressure tested to 3910 psi for a passing MIT-IA. On 5/26/2023, the tubing was pressure tested to 3600 psi for a passing MIT-T. The production casing annulus pressure will be monitored during the frac, if any change of pressure is seen outside of thermal expansion, the job will be flushed and the pressure source diagnosed before frac operations continue. 3910 o 3600 psi f S-32A Fracture Stimulation PTD: 212-082 Page 12 SECTION 8: PRESSURE RATINGS AND SCHEMATICS FOR THE WELLBORE, WELLHEAD, BOPE AND TREATING HEAD 20 AAC 25.283, A, 8 Wellbore Tubular Ratings Size/Name Weight Grade Burst, psi Collapse, psi 13-3/8” Surface Casing 68#NT-80 5020 2260 9-5/8” Surface Casing 47#NT-80S 6870 4760 7” Liner (below isolation plug)26#NT13Cr-80 7240 5410 4-1/2” Production Tubing 12.6#13Cr-80 8430 7500 Wellhead FMC manufactured wellhead, rated to 5, 000 psi. Tubing head adaptor: 13-5/8" 5, 000 psi x 4-1/16" 5,000 psi Tubing Spool: 13-5/8” 5,000psi w/ 2-1/16” side outlets Casing Spool: 13-5/8” 5,000psi w/ 2-1/16” side outlets Tree: CIW 4-1/16” 5,000psi No tree saver planned to be used. Planned surface treating pressure <4000psi. S-32A Fracture Stimulation PTD: 212-082 Page 13 SECTION 9: DATA FOR FRACTURING ZONE AND CONFINING ZONES 20 AAC 25.283, A, 9 Formation MD Top MD Bot TVDss Top TVDss Bot TVD Thickness Frac Grad psi/ft Lith. Desc. THRZ 7490 7524 -6649 -6676 27 .7 Shale Top Kup/C interval 7524 7590 -6676 -6730 54 .62 Silts/SS LCU/ Kuparuk B 7590 7599 -6730 -6737 7 .64 Silts/SS Kuparuk A 7599 7688 -6737 -6808 71 .64 Silts/SS Miluveach 7688 8649 -6808 7587 779 .68 Shale S-32A Fracture Stimulation PTD: 212-082 Page 14 SECTION 10: LOCATION, ORIENTATION AND A REPORT ON MECHANICAL CONDITION OF EACH WELL THAT MAY TRANSECT CONFINING ZONE 20 AAC 25.283, a, 10 Plat of wells within one-half mile of S-32A wellbore reservoir trajectory and location of faults. The blue line indicates the approximate fracture length and orientation of the frac’s. The plat shows the location and orientation of each well that transects the confining zone. Hilcorp has formed the opinion, based on the following assessments for each well and seismic, well and other subsurface information currently available that none of these wells will interfere with containment of the hydraulic fracturing fluid within the one-half mile radius of the proposed wellbore trajectory. S-32A Fracture Stimulation PTD: 212-082 Page 15 Casing and Cement assessments for all wells that transect the confining zone: There are 26 primary cement jobs that have been evaluated for zonal isolation that transect the confining zone within a ½ mile of the S-32A wellbore trajectory. Many of the 26 wells have sidetracks and/or plugbacks that exit below the top of Kuparuk, so the motherbore primary cement job is used for zonal isolation in these evaluations. Of the 26 primary cement jobs, 7 wells have casing cement bond logs that were used to determine TOC, and the logged TOC’s generally show a correlation with their drilling and cementing volumetrics placing TOC above the Kuparuk. For the remaining 19 wells without logs, drilling reports were used to volumetrically calculate TOC with an assumed washout for contingency. S-43 and S-15 are two wells identified within the area that have unknown or minimal zonal isolation across the Kuparuk. S-43 has no CBL and its drilling and cementing reports show low (<25%) returns while circulating cement. Therefore, volumetric calculations are unlikely to represent TOC accurately and zonal isolation of the Kuparuk is unknown. S-15’s CBLwas only run to 6770’ MD which is 1300’ above top of Kuparuk, but it shows poor cement bonding across all logged depths below the permafrost interval. S-15 has since been plugged with cement and is suspended. These well locations are beyond the expected frac wing distance, so we do not consider it to be a major risk of creating a flow path between zones via that uncemented wellbores during the frac. S-15 is 1,190 ft away from S-32A and S- 43 is 1,730 feet away from S-32A in the Kuparuk interval and S-32A’s expected fracture half length is only ~300 feet, so the proposed treatment on S-32A does not pose a significant risk to S-43 and S-15. The T/I/O pressures of these wells will be monitored during the frac, and the frac operation will be stopped if anomalous pressures are observed. Listed below are summaries of the logging (where available) or cementing records used in volumetric calculations for the subsequent zonal isolation table that details measured depth and TVDss depths for top of pay and top of cement. NKUPST: 7" csg was run to 9446'. 2 stage cmt job. Stg 1 (from shoe at 9446'): 375 sx G, Stg2 (from 6916' DV tool) 330 sx Class G. S-05/S-05PB1 / S-05A: 2 stage cmt job, cmt fr. 10010' to 5645', 2605' to surface, Kuparuk Isolated, no comment of losses. No CBL data over the 9-5/8" production casing. S-05 abandoned with bridge plug set at 9045' with a cement cap that was milled to 8800. S-05A millout window is below top of Kuparuk, so zonal isolation is covered by motherbore primary cement job. S-09A / S-09APB1/PB2/PB3: Top of WS set at 2726', intermediate hole through Kuparuk section drilled with little formation issues and full returns through section until the top of Sag was reached where the well went on full losses. When the 7" liner was on bottom, returns were 5-15%. Cemented with 138.9 bbls LiteCrete + 21.1 bbls of ClassG. A USIT / CBL was logged in 2014 and found cement throughout the wellbore with good bonding at 7790' MD and below. S-09APB1/PB2/PB3: occurred below top of Sag in S-09A, Production casing TOC unaffected. t shows poor cement bon 26 returns were 5-15%. zonal isolation of the Kuparuk is unknown. S-43 7 wells have casing cement bond logs t S-43 and S-15 a S-15’s CBL w The T/I/O pressures of these wells will be monitored during the frac, and the frac operation will be stopped if anomalous pressures are observed. S-32A Fracture Stimulation PTD: 212-082 Page 16 S-10 / S-10A / S-10APB1/PB2: 9 5/8" casing was run to 8697'. Two stage cement job. Stg 1 (from shoe at 8697'): 1043 sx (1199 ft3) 15.8 G. Stg 2 (from DV tool at 2514'). 140 sx (130 ft3) arcticset 1 15.7 ppg. S- 10A / S-10APB1/PB2 Sidetrack was at -7885' md (-7691' SSTVD) below the kuparuk. S-10 9 5/8" cement job isolates kuparuk. S-12: After running the 9-5/8" casing, S-12 was cemented with the 1st stage around the shoe with 1360 sks of Class G cement. The 2nd stage pumped 140 sks Arctic Set I cement though the DV port at 2626' MD up the IA. The well was drilled in 1982, then abandoned in 1984: A CIBP was set at 10,351'MD in the 7" liner with 30sks of Class G cement from 10351-10246' MD. In the 9-5/8" casing, 8 bbls plug of Coldset II from 2680-2574' MD and 9bbls Coldset II from 60'MD to surface. S-15 / S-15PB1: 9-5/8" casing run to 11307' MD and cemented with 2494 cuft of class g followed by 230 cu ft Class g. After drilling the 8-1/2" production hole and plug back, the 9-5/8" x 13 3/8" annulus was later down squeezed with 279 cu ft of permafrost C cement followed by Arctic Pack. In 2021, S-15's Ivishak perforations were abandoned with a 25' cement plug; a passing CMIT was obtained on 9/14/21, and workover was attempted to recomplete the well as a Schrader Bluff injector. After pulling the tubing, a CBL showed cement across the permafrost but insufficient cement for isolation of injection fluids into the Schrader Bluff formation, so a CIBP was set at 6000' MD and cement squeeze was attempted, but the cement retainer failed. A follow up cement squeeze was attempted in Nov 2022, however only half of planned cement volume was circulated behind the 9-5/8" casing. A subsequent CBL was indeterminate and full isolation deemed unsuccessful after a failed MIT. Finally, a cement plug was laid from 6000'-5000' MD to complete isolation of the Schrader Bluff, and the well is suspended. The deepest CBL was only run to 6770' MD which is 1300' above the Kuparuk, so isolation unknown, but unlikely and volumetrics are not sufficient. The Kuparuk formation was never opened in this well and remains isolated behind cemented 9-5/8" casing and bounded by Schrader Bluff and Ivishak isolation plugs within the wellbore. S-16 / S-16PB1: 9-5/8" casing run to 10693' MD and cemented with 2260 cu ft lead slurry class G and 230 cu ft tail slurry class G. Tested casing to 3000psi, passed. After drilling the production hole, they down squeezed the 9-5/8" casing with 279 cu ft arcticset II cement followed by arctic pack. Well is currently shut in due to history of bubbling in cellar when on production. Ivishak perforations were isolated with an IBP and cement at 10531' MD in the 7" production liner in preparation for a proposed workover, and integrity work is ongoing. S-22B: Sidetracked from S-22 at 5402’MD, and new 7" tieback casing was run from 5204’ to 9452' MD and cemented with 130 bbls 11 ppg G and 39 bbls 15.8 ppg tail. They returned 20 bbls of cement from the backside of the 7” tieback casing, indicating full cement coverage behind the 7” casing. RBL dated 2- 11-19 showed isolation between ivishak and kuparuk in the 4.5 x 7" liner annulus. S-24: The 9-5/8" casing was cemented with 1465 cr. Ft of 13.5ppg lead cement and 575 cu ft of 15.8 ppg. S-24 was converted to a water injector in 1993, then was P&A'd in 1999 in prep for the S-24A sidetrack. The fullbore P&A injected 40bbls cement with tagged TOC in tubing @ 9016' MD. Tubing was cut and pulled from 4512' MD, and a bridge plug set at 3020' in the 9-5/8" casing. The 9-5/8" casing was then cut at 2659' MD and pulled OOH, remaining 9-5/8" casing was milled to 2739' MD then cement was laid so isolation unknown, but unlikely and volumetrics are not sufficient. cement job isolates kuparuk. currently shut in due to history of bubbling in cellar when on production. S-32A Fracture Stimulation PTD: 212-082 Page 17 in and above the casing stub from the bridge plug to 2669' before sidetracking the well for S-24A. S-24A does not transect the Kuparuk within ½ mile radius of S-32. S-25 / S-25A / S-25APB1: 9-5/8" casing was run to 9140' MD and cemented with 1290 cu ft of 13.5ppg premium G cement followed by 575 cu ft of 15.8 ppg tail cement. S-25A & S-25APB1 was sidetracked below the top of Kuparuk so TOC is unaffected. S-32 / S-32A: After setting 9-5/8" casing to 10099'MD, the casing was cemented with 270bbl lead 13.5ppg class g cement followed by 100 bbl 15.8ppg tail cement. The 9-5/8" casing was logged with a CAST-M tool on 5/24/2023 after tubing was pulled for a RWO and found TOC at 2709' MD, good quality cement found at and below 3659' MD. S-32A was sidtracked below top of Kuparuk so is unaffected. S-33: 7-5/8" casing run to 9018' MD, cemented with 167bbls 11.5ppg class g cement followed by 54bbls 15.8ppg class g tail cement. A USIT Log was run on 4-15-2008 showing TOC at 2700' MD in the 7-5/8" casing. S-35: 9-5/8" casing was run to 9536' MD and cemented with 680 sks of 12.2 ppg, (2.4 cuft/sk) lead and 300 sks 15.8 ppg (1.15 cuft/sk) tail cement. S-36: 9-5/8" casing was run to 9720' MD and cemented with 312 bbls lead 12ppg cement followed by 61 bbls tail 15.8ppg cement. S-37 / S-37A / S-37APB1: After setting 7-5/8" casing down to 9108' MD, pumped 179 bbls of 11.5ppg class G cement follwed by 53bbls of 15.8ppg class g cement. No losses were reported, bumped plug. A RBT log dated 5/19/2023 found TOC @ 2900' MD. S-37A was sidetracked below the Kuparuk so TOC is unaffected. S-38: 9-5/8" casing was run to 9221' MD and cemented with 286 bbls lead and 61 bbl tail Class G cement S-41 / S-41L1 / S-41A / S-41AL1: 7" casing run to 12408' and cemented with 179 bbls 11 ppg G, 45 bbls 18 ppg G tail. Bumped plug. 85% returns noted. S-41L1: Millout window 11892-11905'. Isolated from Kuparuk by S-41 7" primary cement job and 9/22/2010 squeeze. S-41A window at 12017'. Isolated from Kuparuk by S-41 7" Primary cement job S-41AL1 Window at 11947'. Isolated from kuparuk by S-41 7" primary cement job S-41PB1: Pilot hole drilled to 12360'. S-41 sidetracked from 9470'. Cmt plugs in PB1: stg1: 173 bbl 15.8 ppg G f/ 12360-->10620'. Stg2: 100 bbls G 17 ppg f/ 10620' -->9204'. S-42 / S-42PB1: 9-5/8" surface casing was run to 3078' MD, cemented with 1150sks of cement, then 7" production casing was hung inside the surface casing at 3077' to 9376' MD and cemented with 430sks of class G cement. The well was P&A'd in 2015 with 200 bbls cement laid at 9004' MD, the tubing was punched at 8962'. An additional 86bbl cement plug was laid at 6169' MD. The tubing was cut and pulled from 4500', the 7" casing was cut and pulled from 3077' MD, then a EZSV bridge plug was set at 3035' MD and whipstock set at 3013' MD for sidetrack. A USIT Log was run on 4-15-2008 showing TOC at 2700' MD S-32A Fracture Stimulation PTD: 212-082 Page 18 S-43 / S-43L1: 7" casing was run to 10196' MD, cemented with 189bbls 11.0 ppg class g lead cement followed by 53bbls 15.8 ppg class g cement. Cement was displaced with 382 bbls and reported ~25% returns. Due to low returns, zonal isolation of the Kuparuk is unknown. If only 25% of cement volume were used for the volumetric calculation, calculated TOC would be below the top of Kuparuk; zonal isolation is unknown. S-105 / S-105A: 7" production casing run to 8103' MD and cemented with 115 bbls 11.5ppg lead and 55 bbls 15.8ppg tail cement (bumped plug). S-105A: Sidetrack from S-105 kicked off below the top of kuparuk. S-108: drilled a 6-3/4" production hole, set 5-1/2" x 3-1/2" casing string from surface to 7835'MD (XO from 5.5 to 3.5" at 5497'MD). Casing was cemented with 87bbls 12 ppg LiteCrete lead and 57 bbls 15.8ppg gas blok tail slurry. S-108 was suspended in 2015 after failed RWO attempt to remove collapsed 3.5" tubing and 5.5" casing. All strings were cemented to surface and wellhead was cut and capped ~2' below pad grade. S-109 / S-109PB1: 7" casing was run to 7820'. USIT logged 1/15/2003 showed great cement to 3150'. S-110: 7" casing was run to 8773' MD and cemented with 165bbls cement. In 2012, the well was P&A'd for a sidetrack: the tubing was punched at 8312' MD and cemented with 19 bbls of cement at 8237' with an EZSV plug set at 8131' MD. An additional 92 bbls of class G cement were laid at 5789' MD and a second EZSV plug with whipsotock on top was set at 3180' MD. A USIT log was run pre-P&A on Jan 7, 2012 with field pick TOC at 1590' MD and top of good isolation at 3500' MD. S-110A / S-110APB1: sidetrack kicked off at 3165' MD of motherbore S-110, new 7" casing was run from surface to 7974' MD and cemented with 92bbls 11.0 ppg litecrete and 34bbls 15.8ppg cement. A USIT log (2/13/2012) evaluated cement and found TOC in 7" as 4140' MD with >80% bond at 4608' MD. S-112 / S-112L1 / S-112L1PB1/ S-112L1PB2: 7" casing was run to 6718' MD and cemented with 93bbls of 12.0 ppg litecrete lead cment followed by 38 bbls of 15.8 ppg tail cement. Currently operating as bi- lateral Kuparuk PWI injection well. zonal isolation of the Kuparuk is unknown. S-32A Fracture Stimulation PTD: 212-082 Page 19 Well Name Casing type Casing Size Casing Depth Hole Size Vol cmt TOC est. via TOC TOC Top of pay Interval Zonal Isolation?Latest MIT Comments in MD in Cu Ft MD TVDss TVDss NKUPST Production 7 6916 8.5 380 Volumetric 4614 -4582 -6743 Yes P&A'd in 2011 Volumetric calc TOC using 30% assumed washout. Stg 1 cmt top calculates close to DV tool. S-05 Production 9.625 10010 12.25 1709 Volumetric 5645 -5369 -6650.4 Yes 2/4/2023: MIT-IA to 2433 psi 2 stage cmt job, cmt fr. 10010' to 5645', 2605' to surface, Kuparuk Isolated S-05PB1 Production 9.625 10010 12.25 1709 Volumetric 5645 -5369 -6650.4 Yes 2/4/2023: MIT-IA to 2433 psi 2 stage cmt job, cmt fr. 10010' to 5645', 2605' to surface, Kuparuk Isolated S-05A Production 8.5 10538 12.25 460 Volumetric 6790 -6224 -6654.8 Yes 2/4/2023: MIT-IA to 2433 psi Single stage cement job, no comments of losses while cementing S-09A Production 7 10528 8.5 898 USIT 12- 02-2014 7790 -6480 -6699.65 YES 4/13/2023: MIT-IA to 2369 psi Single stage cement job S-09APB1 Production 7 10528 8.5 898 USIT 12- 02-2014 7790 -6480 -6699.65 YES 4/13/2023: MIT-IA to 2369 psi Single stage cement job S-09APB2 Production 7 10528 8.5 898 USIT 12- 02-2014 7790 -6480 -6699.65 YES 4/13/2023: MIT-IA to 2369 psi Single stage cement job S-09APB3 Production 7 10528 8.5 898 USIT 12- 02-2014 7790 -6480 -6699.65 YES 4/13/2023: MIT-IA to 2369 psi Single stage cement job S-10 Intermediate 9.625 8697 12.25 1099 Volumetric 5188 -5011 -6652.93 Yes 6/14/2013: MIT-IA to 3000 psi; suspended well. Volumetric calc TOC using 30% assumed washout. S-10A Intermediate 9.625 8697 12.25 1099 Volumetric 5998 -5809 -6651.46 Yes 6/14/2013: MIT-IA to 3000 psi; suspended well. Volumetric calc TOC using 30% assumed washout. S-10APB1 Intermediate 9.625 8697 12.25 1099 Volumetric 5998 -5809 -6651.46 Yes 6/14/2013: MIT-IA to 3000 psi; suspended well. Volumetric calc TOC using 30% assumed washout. S-10APB2 Intermediate 9.625 8697 12.25 1099 Volumetric 5998 -5809 -6651.46 Yes 6/14/2013: MIT-IA to 3000 psi; suspended well. Volumetric calc TOC using 30% assumed washout.???? S-32A Fracture Stimulation PTD: 212-082 Page 20 Well Name Casing type Casing Size Casing Depth Hole Size Vol cmt TOC est. via TOC TOC Top of pay Interval Zonal Isolation?Latest MIT Comments in MD in Cu Ft MD TVDss TVDss S-12 Production 9.625 10780 12.25 1564 Volumetric 6939 -5986 -6698.57 Yes P&A'd in 1984 Volumetric calc TOC using 30% assumed washout S-15 Intermediate 9.625 11307 12.25 2724 USIT & RBT Logs N/A N/A -6639.44 No / Unknown 12/26/2022: CMIT to 2300 psi. Well is suspended after multiple remedial casing cement squeeze attempts. CBL showed poor cement bonding but was only run to 6770'MD which is 1300' above the top of Kuparuk S-15PB1 Intermediate 9.625 11307 12.25 2724 USIT & RBT Logs N/A N/A -6639.44 No / Unknown 12/26/2022: CMIT to 2300 psi. Well is suspended after multiple remedial casing cement squeeze attempts. CBL showed poor cement bonding but was only run to 6770'MD which is 1300' above the top of Kuparuk S-16 Intermediate 9.625 10693 12.25 2490 Volumetric 4578 -4424 -6604.7 Yes 4/24/2023: MIT-T failed, LDL found leak on 4/23/23 pending repair. Volumetric calc TOC using 30% assumed washout S-16PB1 Intermediate 9.625 10693 12.25 2490 Volumetric 4578 -4424 -6604.7 Yes 4/24/2023: MIT-T failed, LDL found leak on 4/23/23 pending repair. Volumetric calc TOC using 30% assumed washout S-22B Intermediate 7 9452 8.5 837 Rev Cir 5204 -4955 -6612.09 Yes 1/5/2022: MIT-IA to 2658 psi Rev cir cmt f/ 5204' atLTP 6/30/97. Calculated TOC is shallower than LTP. S-24 Production 9.625 9804 12.25 2040 Volumetric 4794 -4500 -6667.6 Yes P&A'd in 1999 Volumetric calc TOC using 30% assumed washout S-25 Intermediate 9.625 9140 12.25 1865 Volumetric 4560 -4489 -6609.76 Yes 5/1/2023: MIT-IA to 2454 psi Volumetric calc TOC using 30% assumed washout S-25A Intermediate 9.625 9140 12.25 1865 Volumetric 4560 -4489 -6609.54 Yes 5/1/2023: MIT-IA to 2454 psi Volumetric calc TOC using 30% assumed washout S-25APB1 Intermediate 9.625 9140 12.25 1865 Volumetric 4560 -4489 -6609.54 Yes 5/1/2023: MIT-IA to 2454 psi Volumetric calc TOC using 30% assumed washout S-32 Production 9.625 10099 12.25 2076 CAST-M Log 3659 -3376 -6676.55 Yes 5/26/2023: MIT-IA to3900psi, MIT-T to 3600 psi CAST-M on 5/24/2023 found TOC at 2709' MD, good quality cement found at and below 3659' MD. S-32A Production 9.625 10099 12.25 2076 CAST-M Log 3659 -3376 -6676.72 Yes 5/26/2023: MIT-IA to 3900psi, MIT-T to 3600 psi CAST-M on5/24/2023 found TOC at 2709' MD, good quality cement found at and below 3659' MD. S-33 Intermediate 7.625 9018 9.875 1238 USIT Log 2700 -2630 -6599.48 Yes 4/12/2023: MIT-IA to 3420 psi USIT Log was run on 4-15-2008 showing TOC at 2700' MD in the 7- 5/8" casing. No / Unknown N/A N/A No / Unknown S-32A Fracture Stimulation PTD: 212-082 Page 21 Well Name Casing type Casing Size Casing Depth Hole Size Vol cmt TOC est. via TOC TOC Top of pay Interval Zonal Isolation?Latest MIT Comments in MD in Cu Ft MD TVDss TVDss S-35 Intermediate 9.625 9536 12.25 1977 Volumetric 4681 -4343 -6671.34 Yes 5/19/2020: TIFL passed; 4/26/2018 inconclusive MIT-OA, thermal effects suspected. Volumetric calc TOC using 30% assumed washout S-36 Intermediate 9.625 9720 12.25 2093 Volumetric 4581 -4510 -6609.41 Yes 5/09/2019: CMIT failed; currently SI w/ TT plug, non-operable LTSI pending diagnostics Volumetric calc TOC using 30% assumed washout S-37 Production 7.625 9108 9.875 1371 RBT Log 2900 -2776 -6641.75 Yes 5/20/2022: MIT-IA to 3500psi, MIT-T to 3500psi RBT log 5/19/2023 found TOC @ 2900' MD S-37A Production 7.625 9108 9.875 1371 RBT Log 2900 -2776 -6641.75 Yes 5/20/2022: MIT-IA to 3500psi, MIT-T to 3500psi RBT log 5/19/2023 found TOC @ 2900' MD S-37APB1 Production 7.625 9108 9.875 1371 RBT Log 2900 -2776 -6641.75 Yes 5/20/2022: MIT-IA to 3500psi, MIT-T to 3500psi RBT log 5/19/2023 found TOC @ 2900' MD S-38 Intermediate 9.625 9221 12.25 1929 Volumetric 4484 -4371 -6649.74 Yes 10/17/2015 TIFL passed; 10/13/2014 CMIT to 2500psi Volumetric calc TOC using 30% assumed washout S-41 Intermediate 7 12408 8.5 1258 Volumetric 4779 -4950 -6831 Yes 9/2/2021: MIT-IA to 2354 psi Volumetric calc TOC using 30% assumed washout S-41A Intermediate 7 12408 8.5 1258 Volumetric 4779 -4950 -6831 Yes 9/2/2021: MIT-IA to 2354 psi Volumetric calc TOC using 30% assumed washout S-41AL1 Intermediate 7 12408 8.5 1258 Volumetric 4779 -4950 -6831 Yes 9/2/2021: MIT-IA to 2354 psi Volumetric calc TOC using 30% assumed washout S-41L1 Intermediate 7 12408 8.5 1258 Volumetric 4779 -4950 -6831 Yes 9/2/2021: MIT-IA to 2354 psi Volumetric calc TOC using 30% assumed washout S-41PB1 Intermediate 7 12408 8.5 1258 Volumetric 4779 -4950 -6831 Yes 9/2/2021: MIT-IA to 2354 psi Volumetric calc TOC using 30% assumed washout S-42 Production 7 9376 8.5 1078 Volumetric 2839 -2769 -6648.26 Yes P&A'd in 2015 Volumetric calc TOC using 30% assumed washout S-42 Production 7 9376 8.5 1078 Volumetric 2839 -2769 -6648.26 Yes P&A'd in 2015 Volumetric calc TOC using 30% assumed washout S-32A Fracture Stimulation PTD: 212-082 Page 22 Well Name Casing type Casing Size Casing Depth Hole Size Vol cmt TOC est. via TOC TOC Top of pay Interval Zonal Isolation?Latest MIT Comments in MD in Cu Ft MD TVDss TVDss S-42A Intermediate 7 8480 8.5 668 Volumetric 4431 -4143 -6684.2 Yes 8/28/2015: MIT-IA to 4000 psi Volumetric calc TOC using 30% assumed washout S-42PB1 Production 7 9376 8.5 1078 Volumetric 2839 -2769 -6648.86 Yes P&A'd in 2015 Volumetric calc TOC using 30% assumed washout S-42PB1 Production 7 9376 8.5 1078 Volumetric 2839 -2769 -6648.86 Yes P&A'd in 2015 Volumetric calc TOC using 30% assumed washout S-43 Intermediate 7 10196 8.5 1358 Volumetric 7726 -7414 -6640.24 No / Unknown 5/25/2022: CMIT to 2360 psi Volumetric calc TOC using 25% of cement volume due to low reported returns. S-43L1 Intermediate 7 10196 8.5 1358 Volumetric 7726 -7414 -6640.24 No / Unknown 5/25/2022: CMIT to 2360 psi Volumetric calc TOC using 25% of cement volume due to low reported returns. S-105 Production 7 8103 8.75 954 Volumetric 3223 -2957 -6700.23 Yes 10/4/2019: MIT-IA to 3654 psi, MIT-T to 4445 psi Volumetric calc TOC using 30% assumed washout. Reservoir P&A'd for S-105A sidetrack. S-105A 0 7 8103 8.75 954 Volumetric 3223 -2957 -6700.23 Yes 10/4/2019: MIT-IA to 3654 psi, MIT-T to 4445 psi Volumetric calc TOC using 30% assumed washout. Well kicks off below top of kuparuk in motherbore. S-108 Production 5.5 x 3.5 7835 6.75 808 Volumetric 3108 -3032 -6641.76 Yes Suspended in 2015, P&A'd in 2021.Estimated TOC based on drilling and cementing reports S-109 Intermediate 7 7820 8.75 842 USIT 1/15/2003 3150 -2877 -6673.99 Yes 5/26/23: TIFL failed, currently under evaluation for TxIA. 4/23/2018 MIT- IA to 3681psi. Ran 8.75" reamer. USIT (1/15/2003) found TOC 3032'. Great bond deeper than 3150' S-109PB1 Intermediate 7 7820 8.75 842 USIT 1/15/2003 3150 -2877 -6673.99 Yes 5/26/23: TIFL failed, currently under evaluation for TxIA. 4/23/2018 MIT- IA to 3681psi. Ran 8.75" reamer. USIT (1/15/2003) found TOC 3032'. Great bond deeper than 3150' S-110 Intermediate 7 8773 8.5 926 USIT Log 3500 -2840 -6734.87 Yes 3/5/2023: MIT-IA to 2500 psi USIT log (1/07/2012) field pick TOC at 1590' MD, top of good isolation at 3500' MD. S-110A Intermediate 7 7974 8.75 707 USIT Log 4608 -3750 -6696.76 Yes 3/5/2023: MIT-IA to 2500 psi USIT log (2/13/2012) found TOC in 7" as 4140' MD with >80% bond at 4608' MD. S- 110APB1 Intermediate 7 7974 8.75 707 USIT Log 4608 -3750 -6696.76 Yes 3/5/2023: MIT-IA to 2500 psi USIT log (2/13/2012) found TOC in 7" as 4140' MD with >80% bond at 4608' MD. No / Unknown low reported returns. -7414 -6640.24 low reported returns. -7414 -6640.24 No / Unknown S-32A Fracture Stimulation PTD: 212-082 Page 23 Well Name Casing type Casing Size Casing Depth Hole Size Vol cmt TOC est. via TOC TOC Top of pay Interval Zonal Isolation?Latest MIT Comments in MD in Cu Ft MD TVDss TVDss S-112 Intermediate 7 6718 8.75 735 Volumetric 2958 -2833 -6639.12 Yes 3/14/2023: MIT-IA to 3200 psi Volumetric calc TOC using 30% assumed washout S-112L1 Intermediate 7 6718 8.75 735 Volumetric 2958 -2833 -6638.93 Yes 3/14/2023: MIT-IA to 3200 psi Volumetric calc TOC using 30% assumed washout S- 112L1PB1 Intermediate 7 6718 8.75 735 Volumetric 2958 -2833 -6638.93 Yes 3/14/2023: MIT-IA to 3200 psi Volumetric calc TOC using 30% assumed washout S- 112L1PB2 Intermediate 7 6718 8.75 735 Volumetric 2958 -2833 -6638.93 Yes 3/14/2023: MIT-IA to 3200 psi Volumetric calc TOC using 30% assumed washout S-32A Fracture Stimulation PTD: 212-082 Page 24 SECTION 11: LOCATION OF, ORIENTATION OF AND GEOLOGICAL DATA FOR FAULTS AND FRACTURES THAT MAY TRANSECT THE CONFING ZONES 20 AAC 25.283, A, 11 Hilcorp’s technical analysis based on seismic, well and other subsurface information available indicates that there are 5 mapped faults that transect the Kuparuk interval and enter the confining zone within the ½ radius of the production and confining zone trajectory for the planned S-32A. Fracture gradients within the confining zone (HRZ) will not be exceeded during fracture stimulation and would therefore confine injected fluids to the pool. The HRZ in this area is predominately shale with some silts with an estimated fracture pressure of ~14ppg. Faults 1-5 intersect the production interval and confining zone within the ½ mile radius of the planned fracs. Their displacements, sense of throw, and zone in which they terminate upwards are given below. The wellbore trajectory is essentially a vertical/slant penetration. Maximum stress direction is estimated to be ~30 deg W of N. The frac stage should have sufficient offset to and should not intersect faults #1, #2, #3, 4# and #5. The frac is 790’ from fault #1, 860’ from fault #2, 1820’ from fault #3, 1340’ from fault #4 and 2100’ from fault #5 and maximum anticipated fracture half length of 300’ is well short of this distance. Half length is modeled using hydraulic fracture modelling software and is corroborated by what we have seen in other frac treatments. If a sudden drop in treating pressure or increase in pump rate is seen during the stimulation that cannot be explaining by fluids pumped or annular pressure monitoring, pumping operation will stop until a plan forward and explanation can be put forth. Fault Throw Direction Upward Termination 1 0-50' DTW Schrader Bluff 2 0-100' DTN Schrader Bluff 3 20-80' DTW Colville 4 0-40' DTNE Colville 5 0-60' DTN Colville maximum anticipated fracture half length of 300’ is Fracture gradients within the confining zone (HRZ) will not be exceeded during fracture stimulation a S-32A Fracture Stimulation PTD: 212-082 Page 25 SECTION 12: PROPOSED HYDRAULIC FRACTURING PROGRAM 20 AAC 25.283, a, 12 Fracture Stimulation Pump Schedule Please see Frac program included with this sundry application ATTACHMENT 1: PUMP SCHEDULE MIT-T 4000 Pressure Test 6000 Max WHT Pressure 5000 Slurry Rate 25 Proppant Density Well Name S-32A AFE MIT-IA 3900 Pump Trips 4700 Ann Pressure 3500 Fluid Type 28# X-Link Proppant Used STEP STAGE AVERAGE COMMENTS FLUID PUMP CF DIRTY VOLUME DIRTY VOLUME PROPPANT # # PPA TYPE RATE RATE STAGE CUM STAGE CUM STAGE CUM SIZE GROSS CUM (BPM)(BPM)(BBL) (BBL) (GAL) (GAL) (LBS) (LBS) (BBL) (BBL) 0 28# X-Link 0.0 0 00 00 0 0.0 0 Step-Rate-Test N/A 0.0 0 00 00 1 Prime up, pressure test FreezeProt 5 5.0 10 10 420 420 10 10 2 ~KCl 5 5.0 0 10 0420 010 3 Injection test ~KCl 25 25.0 75 85 3,150 3,570 75 85 Shut down and monitor pressure 0 0.0 85 03,570 0 85 4 Calibration Test 28# X-Link 25 25.0 0 85 03,570 0 85 5 Flush ~KCl 25 25.0 0 85 0 3,570 0 85 HARD SHUTDOWN, MONITOR PRESSURE TILL CLOSURE. FLUID PUMP CF DIRTY VOLUME DIRTY VOLUME PROPPANT CLEAN VOLUME STEP STAGE AVERAGE COMMENTS TYPE RATE RATE STAGE CUM TOT JOB STAGE CUM STAGE CUM SIZE GROSS CUM # # PPA (BPM)(BPM)(BBL) (BBL) (BBL) (GAL) (GAL) (LBS) (LBS) (BBL) (BBL) Volume to Top Perf 113 6 1PAD28# X-Link 25 25.0 150 235 320 6,300 9,870 0 0 150 235 7 2 1 FLAT 28# X-Link 25 23.9 25 260 345 1,050 10,920 1,006 1,006 16/20 C-Lite 24 259 8 3 2 FLAT 28# X-Link 25 23.0 25 285 370 1,050 11,970 1,929 2,935 16/20 C-Lite 23 281 9 4 3 FLAT 28# X-Link 25 22.1 25 310 395 1,050 13,020 2,781 5,716 16/20 C-Lite 23 304 10 5 4 FLAT 28# X-Link 25 21.2 25 335 420 1,050 14,070 3,568 9,284 16/20 C-Lite 22 326 11 6 5 FLAT 28# X-Link 25 20.5 25 360 445 1,050 15,120 4,299 13,583 16/20 C-Lite 21 346 12 7 6 FLAT 28# X-Link 25 19.8 25 385 470 1,050 16,170 4,978 18,561 16/20 C-Lite 20 367 13 8 7 FLAT 28# X-Link 25 19.1 25 410 495 1,050 17,220 5,612 24,173 16/20 C-Lite 19 386 14 9 8 FLAT 28# X-Link 25 18.5 150 560 645 6,300 23,520 37,224 61,398 16/20 C-Lite 113 499 15 10 9 FLAT 28# X-Link 25 17.9 150 710 795 6,300 29,820 40,552 101,949 16/20 C-Lite 109 608 16 11 10 FLAT 28# X-Link 25 17.3 150 860 945 6,300 36,120 43,676 145,625 16/20 CBL 106 713 17 12 11 FLAT 28# X-Link 25 16.8 150 1,010 1,095 6,300 42,420 46,613 192,239 16/20 CBL 102 816 18 13 Flush FLUSH ~KCl 25 25.0 75 1,085 1,170 3,155 45,575 0 192,239 75 891 19 14 FLUSH FreezeProt 25 25.0 38 1,123 1,208 1,598 47,173 0 192,239 38 929 TOTALS 1123 192,239 929 Total Chems SD and obtain ISIP & 15 min SIP.Cost CLEAN VOLUME S-32A Fracture Stimulation PTD: 212-082 Page 26 Table 5 – Anticipated Pressures MIT-T 3600 psi MIT-IA 3900 psi Maximum Anticipated Treating Pressure:2900 psi @ 25 BPM IA Pop-off Set Pressure (~95% of MIT-IA):3700 psi IA Minimum Hold Pressure (POP-off – 300 psi):3400 psi Maximum Allowable Treating Pressure (MATP = Ann hold + MIT-T):4500 psi (tree limited to 5000psi) Stagger Pump Kickouts Between 90 – 95% of MATP:4050 - 4300 Global Kickout (95% of MATP):4300 psi N2 POP-off set pressure (MATP + 1000 psi):5500 psi Treating Line Test Pressure (MATP + 1000 psi):5500 psi OA Pressure:Monitor Max Anticipated Proppant Loading:11 PPA There are three overpressure devices that protect the surface equipment and wellbore from overpressure. 1) Each individual frac pump has an electronic kickout that will shift the pumps into neutral as soon as the set pressure is reached. Since there are multiple pumps, these set pressures are staggered between 90% and 95% of the maximum allowable treating pressure. 2) A primary pressure transducer in the treating line will trigger a global kickout that will shift all the pumps into neutral. 3) There is a manual kickout that is controlled from the frac van that can shift all pumps into neutral. All three of these shutdown systems will be individually tested prior to high pressure pumping operations. Additionally, the treating pressure, IA pressure and OA pressure will be monitored in the frac van. Based on a regional stress map, the maximum horizontal stress in the Kuparuk sands is determined to run ~30° W of N). The slant section of the well though the Kuparuk is drilled parallel to the maximum horizontal stress meaning the induced fracture will also be directionally parallel to the wellbore. 3900 psi S-32A Fracture Stimulation PTD: 212-082 Page 27 Frac Dimensions: Frac #MD Location, ft TVDss top, ft TVDss Bottom, ft Frac Half-Length, ft 1 7524 -6725 -6812 ~300’ Disclaimer Notice: This model was generated using commercially available modelling software and is based on engineering estimates of reservoir properties. Hilcorp is providing these model results as an informed prediction of actual results. Because of the inherent limitations in assumptions required to generate this model, and for other reasons, actual results may differ from the model results. S-32A Fracture Stimulation PTD: 212-082 Page 28 Frac Modelling: Maximum Anticipated Treating Pressure: ~2900 psi Surface pressure is calculated based on a closure pressure of ~0.63 psi/ ft or ~4200 psi. Closure pressure plus anticipated net pressure to be built (750 psi) and friction pressure minus hydrostatic results in a surface pressure of ~2885 psi at the time of flush. 4200 psi (closure)+ 750 psi (net) + 1010 psi (friction) - 3015 psi (hydrostatic)= 2885 psi (max surface press) The difference in closure pressures of the confining shale layers determines height of the fracture. Average confining layer stress is anticipated to be ~0.7 psi/ ft limiting fracture height to ~109 ft TVD. Fracture half-length is determined from confining layer stress as well as leak-off and formation modulus. The modeled frac is anticipated to reach a half-length of ~300 ft. S-32A Fracture Stimulation PTD: 212-082 Page 29 S-32A Fracture Stimulation PTD: 212-082 Page 30 Pre-Job Anticipated Chemicals to be pumped: 39,009 gal S-32A Fracture Stimulation PTD: 212-082 Page 31 SECTION 13: POST FRACTURE WELLBORE CLEANUP AND FLUID RECOVERY PLAN 20 AAC 25.283, A, 13 After the fracture stimulation and potentially during the post frac coil fill cleanout, the well will be put on production through portable well testers. All liquids will be captured and either sent to production facilities or diverted to flowback tanks if solid% becomes too high for our facilities to manage. The initial flowback period is intended to produce back the fracture fluids to tanks as quickly as possible, until the well is produced less than 0.5% solids, at which time the produced fluids meet the GC2 acceptance criteria for start-up. There will be a tank farm on pad to store the produced fluids from flowback operations. The flowback fluids not suitable for GC2 processing will be hauled to another facilities slop tanks for additional settling time and or disposal. Hilcorp will work to separate and recover fluid that meets the facility specification for the flowback fluids. A fluid manifest form will be completed for each load trucked offsite. Hilcorp North Slope, LLC Hilcorp North Slope, LLC Changes to Approved Work Over Sundry Procedure Date: June 14, 2023 Subject: Changes to Approved Sundry Procedure for Well S-32A Sundry #: Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to the AOGCC by the workover (WO) “first call” engineer. AOGCC written approval of the change is required before implementing the change. Step Page Date Procedure Change HNS Prepared By (Initials) HNS Approved By (Initials) AOGCC Written Approval Received (Person and Date) Approval: Asset Team Operations Manager Date Prepared: First Call Operations Engineer Date ϮϬϮϱ͘Ϯϴϯ,ǇĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚ Wh^ͲϯϮ;WdEŽ͘ϮϭϮͲϬϴϮ͖^ƵŶĚƌǇEŽ͘ϯϮϯͲϯϰϳͿ WĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍ K' WĂŐĞϭ :ƵŶĞϮϭ͕ϮϬϮϯ ;ĂͿƉƉůŝĐĂƚŝŽŶĨŽƌ ^ƵŶĚƌǇƉƉƌŽǀĂů;ĂͿ;ϭͿĨĨŝĚĂǀŝƚWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘D' ϲͬϮϬͬϮϬϮϯ ;ĂͿ;ϮͿWůĂƚWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘D' ϲͬϮϬͬϮϬϮϯ ;ĂͿ;ϮͿ;ͿtĞůůůŽĐĂƚŝŽŶ ^ƵƌĨĂĐĞůŽĐĂƚŝŽŶůŝĞƐŝŶ^ĞĐƚŝŽŶϯϱŽĨdϭϮE͕ZϭϮ͕hD͘ tĞůůďŽƌĞƉĂƐƐĞƐƚŚƌŽƵŐŚ^ĞĐƚŝŽŶϭϴŽĨdϭϭE͕ZϭϮ͖ƚŚĞ ƐŝŶŐůĞͲƐƚĂŐĞĨƌĂĐŝŶƚĞƌǀĂůůŝĞƐŝŶ^ĞĐƚŝŽŶϮϲ͕dϭϮE͕ZϭϮ͖ ƚŚĞĚĞĞƉĞƌ͕ŝƐŽůĂƚĞĚƉŽƌƚŝŽŶŽĨƚŚĞǁĞůůĐŽŶƚŝŶƵĞƐƚŽƚŚĞ ǁĞůůdǁŝƚŚŝŶ^ĞĐƚŝŽŶϮϲ͕dϭϮE͕ZϭϮ͕hD͘ D' ϲͬϮϬͬϮϬϮϯ ;ĂͿ;ϮͿ;ͿĂĐŚǁĂƚĞƌǁĞůůǁŝƚŚŝŶЪŵŝůĞ EŽŶĞ͗ĐĐŽƌĚŝŶŐƚŽƚŚĞtĂƚĞƌƐƚĂƚĞŵĂƉĂǀĂŝůĂďůĞ ƚŚƌŽƵŐŚEZ͛ƐůĂƐŬĂDĂƉƉĞƌĂƉƉůŝĐĂƚŝŽŶ;ĂĐĐĞƐƐĞĚ ŽŶůŝŶĞ:ƵŶĞϮϭϮϬϮϯͿ͕ƚŚĞƌĞĂƌĞŶŽǁĞůůƐĂƌĞƵƐĞĚĨŽƌ ĚƌŝŶŬŝŶŐǁĂƚĞƌƉƵƌƉŽƐĞƐĂƌĞŬŶŽǁŶƚŽůŝĞǁŝƚŚŝŶЪŵŝůĞŽĨ ƚŚĞƐƵƌĨĂĐĞůŽĐĂƚŝŽŶŽĨWh^ͲϯϮ͘dŚĞƌĞĂƌĞŶŽ ƐƵďƐƵƌĨĂĐĞǁĂƚĞƌƌŝŐŚƚƐŽƌƚĞŵƉŽƌĂƌǇƐƵďƐƵƌĨĂĐĞǁĂƚĞƌ ƌŝŐŚƚƐǁŝƚŚŝŶϰ͘ϰϱŵŝůĞƐŽĨƚŚĞƐƵƌĨĂĐĞůŽĐĂƚŝŽŶŽĨWh^Ͳ ϯϮ͘ D' ϲͬϮϭͬϮϬϮϯ ;ĂͿ;ϮͿ;Ϳ/ĚĞŶƚŝĨǇĂůůǁĞůůƚǇƉĞƐǁŝƚŚŝŶЪ ŵŝůĞ >ŝƐƚŽĨĂůůǁĞůůƐǁŝƚŚŝŶЪͲŵŝůĞƌĂĚŝƵƐŽĨƚŚĞWh^ͲϯϮǁĞůů ƉĂƚŚŝƐƉƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ D' ϲͬϮϭͬϮϬϮϯ ;ĂͿ;ϯͿ&ƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐ͗ŐĞŽůŽŐŝĐĂů ŶĂŵĞ͖ŵĞĂƐƵƌĞĚĂŶĚƚƌƵĞǀĞƌƚŝĐĂůĚĞƉƚŚ EŽŶĞ͘EŽĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐĂƌĞƉƌĞƐĞŶƚǁŝƚŚŝŶƚŚĞ WƌƵĚŚŽĞĂǇhŶŝƚƉĞƌƋƵŝĨĞƌǆĞŵƉƚŝŽŶKƌĚĞƌEŽ͘ϭ͘ ŶŽƵƚůŝŶĞŽĨƚŚĞW͛ƐĐƵƌƌĞŶƚƋƵŝĨĞƌǆĞŵƉƚŝŽŶƌĞĂ ĨŽƌƚŚĞWƌƵĚŚŽĞĂǇhŶŝƚŝƐĂǀĂŝůĂďůĞŽŶƚŚĞW͛Ɛ͞ůĂƐŬĂ KŝůΘ'ĂƐƋƵŝĨĞƌǆĞŵƉƚŝŽŶƐ/ŶƚĞƌĂĐƚŝǀĞDĂƉ͟ĂǀĂŝůĂďůĞ ŽŶůŝŶĞƵŶĚĞƌƚŚĞ͞WĞƌŵŝƚƐ͟ƐĞĐƚŝŽŶŽĨWZĞŐŝŽŶϭϬ͛ƐǁĞď ƉĂŐĞĂƚŚƚƚƉƐ͗ͬͬǁǁǁ͘ĞƉĂ͘ŐŽǀͬƵŝĐͬƵŶĚĞƌŐƌŽƵŶĚͲŝŶũĞĐƚŝŽŶͲ ĐŽŶƚƌŽůͲƌĞŐŝŽŶͲϭϬͲĂŬͲŝĚͲŽƌͲĂŶĚͲǁĂ͘ D' ϲͬϮϭͬϮϬϮϯ ;ĂͿ;ϰͿĂƐĞůŝŶĞǁĂƚĞƌƐĂŵƉůŝŶŐƉůĂŶEŽŶĞƌĞƋƵŝƌĞĚ͗EŽĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐĂƌĞƉƌĞƐĞŶƚ͘D' ϲͬϮϭͬϮϬϮϯ ϮϬϮϱ͘Ϯϴϯ,ǇĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚ Wh^ͲϯϮ;WdEŽ͘ϮϭϮͲϬϴϮ͖^ƵŶĚƌǇEŽ͘ϯϮϯͲϯϰϳͿ WĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍ K' WĂŐĞϮ :ƵŶĞϮϭ͕ϮϬϮϯ ;ĂͿ;ϱͿĂƐŝŶŐĂŶĚĐĞŵĞŶƚŝŶŐŝŶĨŽƌŵĂƚŝŽŶWƌŽǀŝĚĞĚ͘ϵͲϱͬϴ͟ĐĂƐŝŶŐƉĂƐƐĞƐƉƌĞƐƐƵƌĞƚĞƐƚ͘dKĂƚ ϮϳϬϵ͛D͘D'ZϲͬϮϴͬϮϯ ;ĂͿ;ϲͿĂƐŝŶŐĂŶĚĐĞŵĞŶƚŝŶŐŽƉĞƌĂƚŝŽŶ ĂƐƐĞƐƐŵĞŶƚ ĞŵĞŶƚďŽŶĚůŽŐĨŽƌ^ͲϯϮƌĞĐŽŵƉůĞƚĞ;^ƵŶĚƌǇηϯϮϯͲ ϮϮϮͿ͘ĐĐŽƌĚŝŶŐƚŽ,ĂůůŝďƵƌƚŽŶ͛ƐĂŶĂůǇƐŝƐ;ƉĂŐĞϮŽĨƚŚĞ ůŽŐƌĞƉŽƌƚͿ͕ƚŽƉŽĨĐĞŵĞŶƚĂƌŽƵŶĚƚŚĞϵͲϱͬϴ͟ĐĂƐŝŶŐǁĂƐ ůŽĐĂƚĞĚĂƚϮϳϬϵ͛D͕ĂŶĚŚĂƐŐŽŽĚĐĞŵĞŶƚďŽŶĚƋƵĂůŝƚǇ ĨƌŽŵϯϲϱϵ͛DʹϵϮϴϰ͛D;ďĂƐĞŽĨůŽŐŐĞĚŝŶƚĞƌǀĂůͿ͘dŚĞ ƚŽƉŽĨ<ƵƉĂƌƵŬƌĞƐĞƌǀŽŝƌŝƐĂƚϳϱϮϮ͛D͘dŽƉŽĨŽƌĞĂůŝƐ ƉĞƌĨƐŝŶĐŽŵƉĞƚĞŶƚϵͲϱͬϴ͟ĐĂƐŝŶŐĂƚϳϱϮϰ͛D͘ D'ZϬϲͬϮϴͬϮϯ ;ĂͿ;ϲͿ;ͿĂƐŝŶŐĐĞŵĞŶƚĞĚďĞůŽǁ ůŽǁĞƌŵŽƐƚĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌĂŶĚ ĐŽŶĨŽƌŵƐƚŽϮϬϮϱ͘ϬϯϬ EŽĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐƉƌĞƐĞŶƚ͘;^ĞĞ^ĞĐƚŝŽŶ;ĂͿ;ϯͿ͕ ĂďŽǀĞ͘Ϳ D' ϲͬϮϭͬϮϬϮϯ ;ĂͿ;ϲͿ;ͿĂĐŚŚǇĚƌŽĐĂƌďŽŶǌŽŶĞŝƐ ŝƐŽůĂƚĞĚ zĞƐ͗^ƵƌĨĂĐĞĐĂƐŝŶŐǁĂƐƐĞƚĂƚϮ͕ϭϭϵ͛D;ͲϮ͕ϬϲϬ͛ds^^Ϳ ĂŶĚĐĞŵĞŶƚĞĚƚŽƐƵƌĨĂĐĞǁŝƚŚĂƉƉƌŽǆŝŵĂƚĞůǇϭ͕ϵϯϴƐĂĐŬƐ ŽĨƌĐƚŝĐ^Ğƚ//ĂŶĚ///ĐĞŵĞŶƚ͘ &ŽƌWh^ͲϯϮ;WdϭϵϬͲϭϰϵͿ͕ϭϮͲϭͬϰ͟ŚŽůĞǁĂƐĚƌŝůůĞĚĨƌŽŵ ƐƵƌĨĂĐĞƚŽϭϬ͕ϭϬϰ͛D;Ͳϴ͕ϳϱϱ͛ds^^ͿĂŶĚŝŶƚĞƌŵĞĚŝĂƚĞ ĐĂƐŝŶŐǁĂƐƐĞƚĂƚϭϬ͕Ϭϵϵ͛D;Ͳϴ͕ϳϱϮ͛ds^^ͿŽŶ ϭϭͬϭϵͬϭϵϵϬĂŶĚĐĞŵĞŶƚĞĚǁŝƚŚĂƉƉƌŽǆŝŵĂƚĞůǇϭ͕ϳϵϭ ƐĂĐŬƐŽĨůĂƐƐ'ĐĞŵĞŶƚ͘Wh^ͲϯϮ;WdϮϭϮͲϬϴϮͿŬŝĐŬĞĚ ŽĨĨĨƌŽŵƉĂƌĞŶƚƚŚƌŽƵŐŚǁŝŶĚŽǁŵŝůůĞĚϭϬ͕ϭϭϯ͛ͲϭϬ͕ϭϮϭ͛͘ /ŶƚŚĞŽƌŝŐŝŶĂůǁĞůůWh^ͲϯϮ͕ϭϯͲϯͬϴ͟ƐƵƌĨĂĐĞĐĂƐŝŶŐǁĂƐ ƐĞƚĂƚϮ͕ϲϴϱ͛D;ͲϮ͕ϲϮϬ͛ds^^ͿĂŶĚĐĞŵĞŶƚĞĚ͘ sŽůƵŵĞƚƌŝĐĐĂůĐƵůĂƚŝŽŶƐŝŶĚŝĐĂƚĞƚŚĞĐĞŵĞŶƚƉƵŵƉĞĚǁĂƐ ƐƵĨĨŝĐŝĞŶƚƚŽƌĞĂĐŚƐƵƌĨĂĐĞ͕ďƵƚƚŚĞĚĂŝůǇĚƌŝůůŝŶŐŽƉĞƌĂƚŝŽŶƐ ƐƵŵŵĂƌǇĨŽƌWh^ͲϯϮĚŽĞƐŶŽƚƉƌŽǀŝĚĞĂŶǇĨƵƌƚŚĞƌ ĚĞƐĐƌŝƉƚŝŽŶƐŽƌĚĞƚĂŝůƐ͘EĞǆƚ͕ϭϮͲϭͬϰ͟ŚŽůĞǁĂƐĚƌŝůůĞĚĂŶĚ ϵͲϱͬϴ͟ŝŶƚĞƌŵĞĚŝĂƚĞĐĂƐŝŶŐǁĂƐƌƵŶĂŶĚĐĞŵĞŶƚĞĚĂƚ ϭϬ͕Ϭϵϵ͛D;Ͳϴ͕ϳϰϲ͛ds^^Ϳ͕ǁŝƚŚĂĐĂůĐƵůĂƚĞĚƚŽƉŽĨ ĐĞŵĞŶƚĂƚϱ͕ϬϬϴ͛D;Ͳϰ͕ϳϬϲ͛ds^^Ϳ͘>Ͳ^důŽŐƌƵŶ ĂĐƌŽƐƐƚŚĞϵͲϱͬϴ͟ĐĂƐŝŶŐŝŶDĂǇϮϬϮϯĐŽŶƚĂŝŶƐĂĐŽŵŵĞŶƚ D'ZϬϲͬϮϴͬϮϯ ^& ϲͬϮϴͬϮϬϮϯ ϮϬϮϱ͘Ϯϴϯ,ǇĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚ Wh^ͲϯϮ;WdEŽ͘ϮϭϮͲϬϴϮ͖^ƵŶĚƌǇEŽ͘ϯϮϯͲϯϰϳͿ WĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍ K' WĂŐĞϯ :ƵŶĞϮϭ͕ϮϬϮϯ ƚŚĂƚŐŽŽĚĐĞŵĞŶƚďŽŶĚĞǆŝƐƚƐĨƌŽŵϯ͕ϲϱϵ͛ƚŽϵ͕Ϯϴϰ͛D ǁŚŝĐŚǁŽƵůĚŝƐŽůĂƚĞďŽƚŚƚŚĞ^ĐŚƌĂĚĞƌůƵĨĨĂŶĚ<ƵƉĂƌƵŬ ŝŶƚĞƌǀĂůƐ͘DǇŝŶƚĞƌƉƌĞƚĂƚŝŽŶŽĨƚŚĞůŽŐŝƐĨĂŝƌƚŽŐŽŽĚ ĐĞŵĞŶƚĂĐƌŽƐƐƚŚĞhŐŶƵ>ĂŶĚDƐĂŶĚƐ͕ƉĂƚĐŚǇĐĞŵĞŶƚ ĂĐƌŽƐƐƚŚĞ^ĐŚƌĂĚĞƌůƵĨĨEĂŶĚKƐĂŶĚƐ͕ĂŶĚĨĂŝƌƚŽŐŽŽĚ ĐĞŵĞŶƚĂĐƌŽƐƐƚŚĞ,ZƐŚĂůĞ͕<ƵƉĂƌƵŬƐĂŶĚƐ͕DŝůƵǀĞĂĐŚ ƐŚĂůĞ͕ĂŶĚ<ŝŶŐĂŬƐŚĂůĞŝŶƚĞƌǀĂůƐ͘ /ŶƚŚĞŽƌŝŐŝŶĂůǁĞůůWh^ͲϯϮ͕ϴͲϭͬϮ͟ŚŽůĞǁĂƐĚƌŝůůĞĚĨƌŽŵ ƚŚĞďĂƐĞŽĨŝŶƚĞƌŵĞĚŝĂƚĞĐĂƐŝŶŐĂŶĚϳ͟ĐĂƐŝŶŐǁĂƐƌƵŶĂŶĚ ĐĞŵĞŶƚĞĚĂƚϭϬ͕ϲϴϴ͛D;Ͳϴ͕ϴϲϯ͛ds^^Ϳ͘sŽůƵŵĞƚƌŝĐ ĐĂůĐƵůĂƚŝŽŶƐƵŐŐĞƐƚƐƚŚĞƚŽƉŽĨĐĞŵĞŶƚƌĞĂĐŚĞĚϴ͕ϲϴϬ͛D ;Ͳϳ͕ϲϭϯ͛ds^^Ϳ͕ǁŚŝĐŚŝƐƐƵĨĨŝĐŝĞŶƚƚŽŝƐŽůĂƚĞƚŚĞ^ĂŐZŝǀĞƌ͕ ^ŚƵďůŝŬ͕ĂŶĚ/ǀŝƐŚĂŬ͘ /ŶWh^ͲϯϮ͕ƚŚĞ<KWŝƐϭϬ͕ϭϭϯ͛D;Ͳϴ͕ϳϱϳ͛ds^^Ϳ͖ƚŚĞ ƉƌŽĚƵĐƚŝŽŶůŝŶĞƌǁĂƐƌƵŶƚŽϭϭ͕ϴϰϴ͛D;Ͳϴ͕ϵϮϮ͛ds^^Ϳ ĂŶĚĐĞŵĞŶƚĞĚƚŽĂĐĂůĐƵůĂƚĞĚƚŽƉŽĨϵ͕ϯϮϭ͛D;Ͳϴ͕ϵϮϮ͛ ds^^Ϳ͕ǁŚŝĐŚŝƐƐƵĨĨŝĐŝĞŶƚƚŽŝƐŽůĂƚĞƚŚĞĞŶƚŝƌĞůŝŶĞƌ͘ ;ĂͿ;ϳͿWƌĞƐƐƵƌĞƚĞƐƚ͗ŝŶĨŽƌŵĂƚŝŽŶĂŶĚ ƉƌĞƐƐƵƌĞͲƚĞƐƚƉůĂŶƐĨŽƌĐĂƐŝŶŐĂŶĚƚƵďŝŶŐ ŝŶƐƚĂůůĞĚŝŶǁĞůů WƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ϯϵϬϬƉƐŝĐĂƐŝŶŐƚĞƐƚ;D/dͲ/Ϳ ƉƌĞĨƌĂĐƚƵƌŝŶŐĨƵůůďŽƌĞ͕D/dͲdƚŽϰϬϬϬƉƐŝƚƵďŝŶŐƚĞƐƚǁŝƚŚ ϭϬϬϬƉƐŝŽŶ/ƚŽďĞƉĞƌĨŽƌŵĞĚ͘ D'Z ϬϲͬϮϴͬϮϬϮϯ ;ĂͿ;ϴͿWƌĞƐƐƵƌĞƌĂƚŝŶŐƐĂŶĚƐĐŚĞŵĂƚŝĐƐ͗ ǁĞůůďŽƌĞ͕ǁĞůůŚĞĂĚ͕KW͕ƚƌĞĂƚŝŶŐŚĞĂĚ WƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ϱ<ƉƐŝǁĞůůŚĞĂĚ͘ϰϱϬϬƉƐŝ ŵĂǆŝŵƵŵƚƌĞĂƚŝŶŐƉƌĞƐƐƵƌĞ͘WƵŵƉŬŶŽĐŬŽƵƚϰϯϬϬƉƐŝ͘ 'KZsϱϱϬϬƉƐŝƉůĂŶƐ͘ D'Z ϬϲͬϮϴͬϮϬϮϯ ;ĂͿ;ϵͿ;Ϳ&ƌĂĐƚƵƌŝŶŐĂŶĚĐŽŶĨŝŶŝŶŐǌŽŶĞƐ͗ ůŝƚŚŽůŽŐŝĐĚĞƐĐƌŝƉƚŝŽŶĨŽƌĞĂĐŚǌŽŶĞ ;ĂͿ;ϵͿ;Ϳ'ĞŽůŽŐŝĐĂůŶĂŵĞŽĨĞĂĐŚǌŽŶĞ ;ĂͿ;ϵͿ;ͿĂŶĚ;ĂͿ;ϵͿ;ͿDĞĂƐƵƌĞĚĂŶĚƚƌƵĞ ǀĞƌƚŝĐĂůĚĞƉƚŚƐ hƉƉĞƌĐŽŶĨŝŶŝŶŐǌŽŶĞƐ͗,Z^ŚĂůĞĐŽŶƐŝƐƚŝŶŐŽĨ ĐŽŶĚĞŶƐĞĚŵƵĚƐƚŽŶĞĂŶĚĐůĂǇƐƚŽŶĞĂŶĚƐŝůƚǇĐůĂǇƐƚŽŶĞ ƚŚĂƚŚĂƐĂŶĂŐŐƌĞŐĂƚĞƚŚŝĐŬŶĞƐƐŽĨĂďŽƵƚϯϬ͛ƚƌƵĞǀĞƌƚŝĐĂů ƚŚŝĐŬŶĞƐƐ;dsdͿ͕ǁŚŝĐŚŝƐŝŶƚƵƌŶŽǀĞƌůĂŝŶďǇŵƵĚƐƚŽŶĞ ĂŶĚƐŝůƚƐƚŽŶĞĂƐƐŝŐŶĞĚƚŽƚŚĞ,ƵĞ^ŚĂůĞĂŶĚdŽƌŽŬ;͍ͿƚŚĂƚ ĂƌĞŵĂŶǇŚƵŶĚƌĞĚƐŽĨĨĞĞƚƚŚŝĐŬŝŶƚŚŝƐĂƌĞĂ͘&ƌĂĐƚƵƌĞ ŐƌĂĚŝĞŶƚŝƐĞǆƉĞĐƚĞĚƚŽďĞĂďŽƵƚϬ͘ϳϬƉƐŝͬĨƚ;ϭϯ͘ϱƉƉŐ DtͿ͘ ^& ϲͬϮϴͬϮϬϮϯ ϮϬϮϱ͘Ϯϴϯ,ǇĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚ Wh^ͲϯϮ;WdEŽ͘ϮϭϮͲϬϴϮ͖^ƵŶĚƌǇEŽ͘ϯϮϯͲϯϰϳͿ WĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍ K' WĂŐĞϰ :ƵŶĞϮϭ͕ϮϬϮϯ ;ĂͿ;ϵͿ;Ϳ&ƌĂĐƚƵƌĞƉƌĞƐƐƵƌĞĨŽƌĞĂĐŚǌŽŶĞ &ƌĂĐƚƵƌŝŶŐŽŶĞ͗WĞƌĨŽƌĂƚĞĚŝŶƚĞƌǀĂůĨƌŽŵϳ͕ϱϮϰ͛ƚŽ ϳ͕ϱϵϬ͛D;Ͳϲ͕ϲϳϳ͛ƚŽͲϲ͕ϳϯϬ͛ds^^ͿůŝĞƐǁŝƚŚŝŶ ͲͲͲͲͲͲͲͲͲͲƚŚĞ<ƵƉĂƌƵŬƐĂŶĚŝŶƚĞƌǀĂůƚŚĂƚŚĂƐĂŶĂŐŐƌĞŐĂƚĞ ƚŚŝĐŬŶĞƐƐŽĨĂďŽƵƚϱϰ͛ƚƌƵĞǀĞƌƚŝĐĂůƚŚŝĐŬŶĞƐƐ;dsdͿ͘ &ƌĂĐƚƵƌĞŐƌĂĚŝĞŶƚĞǆƉĞĐƚĞĚƚŽƌĂŶŐĞĨƌŽŵĂďŽƵƚϬ͘ϲϮƚŽ Ϭ͘ϲϰƉƐŝͬĨƚ;ϭϭ͘ϵƚŽϭϮ͘ϯƉƉŐDtͿ͘ >ŽǁĞƌŽŶĨŝŶŝŶŐŽŶĞ͗DŝůƵǀĞĂĐŚ^ŚĂůĞĐŽŶƐŝƐƚŝŶŐŽĨ ĐŽŶĚĞŶƐĞĚŵƵĚƐƚŽŶĞ͕ĐůĂǇƐƚŽŶĞ͕ĂŶĚƐŝůƚǇĐůĂǇƐƚŽŶĞƚŚĂƚ ŚĂƐĂŶĂŐŐƌĞŐĂƚĞƚŚŝĐŬŶĞƐƐŽĨĂďŽƵƚϳϴϬ͛ƚƌƵĞǀĞƌƚŝĐĂů ƚŚŝĐŬŶĞƐƐ;dsdͿŝŶƚŚŝƐĂƌĞĂ͘&ƌĂĐƚƵƌĞŐƌĂĚŝĞŶƚŝƐĞǆƉĞĐƚĞĚ ƚŽƌĂŶŐĞĨƌŽŵĂďŽƵƚϬ͘ϲϴƉƐŝͬĨƚϭϯ͘ϭƉƉŐDtͿ͘ ;ĂͿ;ϭϬͿ>ŽĐĂƚŝŽŶ͕ŽƌŝĞŶƚĂƚŝŽŶ͕ƌĞƉŽƌƚŽŶ ŵĞĐŚĂŶŝĐĂůĐŽŶĚŝƚŝŽŶŽĨĞĂĐŚǁĞůů WƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘,ŝůĐŽƌƉŚĂƐƉƌŽǀŝĚĞĚĐĞŵĞŶƚ͕ ŝŶƚĞŐƌŝƚǇ͕ǌŽŶĂůŝƐŽůĂƚŝŽŶĨŽƌĞĂĐŚǁĞůůŝĚĞŶƚŝĨǇŝŶŐǁĞůůƐ ƚŚĂƚŵĂǇďĞĂĨĨĞĐƚĞĚďǇƚŚŝƐĨƌĂĐĂŶĚĞǆƉĞĐƚĞĚĨƌĂĐǁŝŶŐ ŽĨϯϬϬĨƚ͘YƵĞƐƚŝŽŶĂďůĞǁĞůůƐǁĞƌĞŝĚĞŶƚŝĨŝĞĚĨŽƌ ŵŽŶŝƚŽƌŝŶŐĚƵƌŝŶŐĨƌĂĐĂŶĚK'ĂĚĚĞĚŵŽƌĞƚŽ ĐŽŶĚŝƚŝŽŶƐ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ĂͿ;ϭϭͿ^ƵĨĨŝĐŝĞŶƚŝŶĨŽƌŵĂƚŝŽŶƚŽ ĚĞƚĞƌŵŝŶĞǁĞůůƐǁŝůůŶŽƚŝŶƚĞƌĨĞƌĞǁŝƚŚ ĐŽŶƚĂŝŶŵĞŶƚǁŝƚŚŝŶЪŵŝůĞ zĞƐ͘dŚĞƌĞĂƌĞϮϲǁĞůůƐǁŝƚŚŝŶƚŚĞЪͲŵŝůĞƌĞĂŽĨZĞǀŝĞǁ ĨŽƌWh^ͲϯϮ͘KĨƚŚĞƐĞ͕^ͲϭϱĂŶĚ^ͲϰϯŚĂǀĞƵŶĐĞƌƚĂŝŶ ŝƐŽůĂƚŝŽŶĚƵĞƚŽĂůĂĐŬŽĨĐĞŵĞŶƚŝŶŐŝŶĨŽƌŵĂƚŝŽŶ͘ƚƚŚĞ ƚŽƉŽĨƚŚĞ<ƵƉĂƌƵŬƌĞƐĞƌǀŽŝƌ͕ƚŚĞƐĞǁĞůůƐůŝĞϭϮϬϬ͛ĂŶĚ ϭϳϯϬ͛ĨƌŽŵ^ͲϯϮ͕ĂŶĚƚŚĞǇǁŝůůďĞŵŽŶŝƚŽƌĞĚĨŽƌ ƵŶĞǆƉĞĐƚĞĚƉƌĞƐƐƵƌĞƐĚƵƌŝŶŐƐƚŝŵƵůĂƚŝŽŶŽƉĞƌĂƚŝŽŶƐ͘dŚĞ ŵŽĚĞůĞĚĨƌĂĐƚƵƌĞŚĂůĨͲůĞŶŐƚŚĨŽƌƚŚĞŝŶĚƵĐĞĚĨƌĂĐƚƵƌĞ;ƐͿ ŝŶ^ͲϯϮŝƐϯϬϬ͛͘EĞĂƌďǇǁĞůů^ͲϰϮůŝĞƐϯϰϬ͛ĨƌŽŵ^ͲϯϮ ĂŶĚĂůŽŶŐƚŚĞůŝŬĞůǇĨƌĂĐƚƵƌĞƚƌĞŶĚ͕ƐŽŝƚĂůƐŽŵƵƐƚďĞ ŵŽŶŝƚŽƌĞĚĚƵƌŝŶŐĨƌĂĐƚƵƌŝŶŐ͘dŽĞŶƐƵƌĞƐĂĨĞƚǇ͕^ͲϯϱĂŶĚ^Ͳ Ϯϰ;ůŽĐĂƚĞĚϰϮϱ͛ĂŶĚϳϬϬ͛ĨƌŽŵ^ͲϯϮ͕ƌĞƐƉĞĐƚŝǀĞůǇͿ ƐŚŽƵůĚĂůƐŽďĞŵŽŶŝƚŽƌĞĚ͘dŚĞƌĞŵĂŝŶŝŶŐǁĞůůƐǁŝƚŚŝŶƚŚĞ KZůŝĞĂƚƐƵĨĨŝĐŝĞŶƚĚŝƐƚĂŶĐĞĨƌŽŵ^ͲϯϮƐŽĂƐƚŽďĞ ŚŝŐŚůǇƵŶůŝŬĞůǇƚŽŝŶƚĞƌĨĞƌĞǁŝƚŚĐŽŶƚĂŝŶŵĞŶƚ͘,ŽǁĞǀĞƌ͕ ^& ϲͬϮϵͬϮϬϮϯ ϮϬϮϱ͘Ϯϴϯ,ǇĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚ Wh^ͲϯϮ;WdEŽ͘ϮϭϮͲϬϴϮ͖^ƵŶĚƌǇEŽ͘ϯϮϯͲϯϰϳͿ WĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍ K' WĂŐĞϱ :ƵŶĞϮϭ͕ϮϬϮϯ ĂƐŶŽƚĞĚďĞůŽǁ͕ŝĨĂŶǇƵŶĞǆƉĞĐƚĞĚƉƌĞƐƐƵƌĞƐĂƌĞ ŽďƐĞƌǀĞĚĚƵƌŝŶŐĨƌĂĐƚƵƌĞͲƐƚŝŵƵůĂƚŝŽŶŽƉĞƌĂƚŝŽŶƐƚŚĞ ŽƉĞƌĂƚŽƌǁŝůůŝŵŵĞĚŝĂƚĞůǇƚĞƌŵŝŶĂƚĞƚŚĞƐƚĂŐĞ͘ ;ĂͿ;ϭϭͿ&ĂƵůƚƐĂŶĚĨƌĂĐƚƵƌĞƐ͕>ŽĐĂƚŝŽŶ͕ ŽƌŝĞŶƚĂƚŝŽŶ ;ĂͿ;ϭϭͿ&ĂƵůƚƐĂŶĚĨƌĂĐƚƵƌĞƐ͕^ƵĨĨŝĐŝĞŶƚ ŝŶĨŽƌŵĂƚŝŽŶƚŽĚĞƚĞƌŵŝŶĞŶŽŝŶƚĞƌĨĞƌĞŶĐĞ ǁŝƚŚĐŽŶƚĂŝŶŵĞŶƚǁŝƚŚŝŶЪŵŝůĞ dŚĞŽƉĞƌĂƚŽƌŚĂƐŝĚĞŶƚŝĨŝĞĚϱĨĂƵůƚƐƵƐŝŶŐƐĞŝƐŵŝĐĂŶĚǁĞůů ŝŶĨŽƌŵĂƚŝŽŶǁŝƚŚŝŶĂЪͲŵŝůĞƌĂĚŝƵƐŽĨWh^ͲϯϮ͕ƚŚĞ ĐůŽƐĞƐƚŽĨǁŚŝĐŚĂƌĞϳϵϬ͛ĂŶĚϴϮϬ͛ĨƌŽŵƚŚĞĨƌĂĐƚƵƌŝŶŐ ǌŽŶĞ͘dŚĞŵŽĚĞůĞĚŚĂůĨͲůĞŶŐƚŚŽĨƚŚĞŝŶĚƵĐĞĚĨƌĂĐƚƵƌĞƐŝƐ ϯϬϬ͕͛ƐŽŝƚŝƐƵŶůŝŬĞůǇƚŚĂƚĂŶǇĨĂƵůƚƐǁŝůůŝŶƚĞƌĨĞƌĞǁŝƚŚ ĐŽŶƚĂŝŶŵĞŶƚŽĨƚŚĞŝŶũĞĐƚĞĚĨƌĂĐƚƵƌŝŶŐĨůƵŝĚƐ͘,ŽǁĞǀĞƌ͕ŝĨ ƚŚĞƌĞĂƌĞŝŶĚŝĐĂƚŝŽŶƐƚŚĂƚĂĨƌĂĐƚƵƌĞŚĂƐŝŶƚĞƌƐĞĐƚĞĚĂ ĨĂƵůƚŽƌŶĂƚƵƌĂůͲĨƌĂĐƚƵƌĞŝŶƚĞƌǀĂůĚƵƌŝŶŐĨƌĂĐŽƉĞƌĂƚŝŽŶƐ͕ ƚŚĞŽƉĞƌĂƚŽƌǁŝůůŐŽƚŽĨůƵƐŚĂŶĚƚĞƌŵŝŶĂƚĞƚŚĞƐƚĂŐĞ ŝŵŵĞĚŝĂƚĞůǇ͘ ^& ϲͬϮϴͬϮϬϮϯ ;ĂͿ;ϭϮͿWƌŽƉŽƐĞĚƉƌŽŐƌĂŵĨŽƌĨƌĂĐƚƵƌŝŶŐ ŽƉĞƌĂƚŝŽŶWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ĂͿ;ϭϮͿ;ͿƐƚŝŵĂƚĞĚǀŽůƵŵĞWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ϭϭϮϯďďůĚŝƌƚǇǀŽů͕͘ϭϵϮ<ƉŽƵŶĚ ƉƌŽƉƉĂŶƚ t ϬϲͬϮϵͬϮϬϮϯ ;ĂͿ;ϭϮͿ;ͿĚĚŝƚŝǀĞƐ͗ŶĂŵĞƐ͕ƉƵƌƉŽƐĞƐ͕ ĐŽŶĐĞŶƚƌĂƚŝŽŶƐ WƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘EŽƉƌŽƉƌŝĞƚĂƌǇĐŚĞŵŝĐĂůƐ ŵĞŶƚŝŽŶĞĚŽƌŝŶĐůƵĚĞĚ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ĂͿ;ϭϮͿ;ͿŚĞŵŝĐĂůŶĂŵĞĂŶĚ^ ŶƵŵďĞƌŽĨĞĂĐŚWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ĂͿ;ϭϮͿ;Ϳ/ŶĞƌƚƐƵďƐƚĂŶĐĞƐ͕ǁĞŝŐŚƚŽƌ ǀŽůƵŵĞŽĨĞĂĐŚWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ĂͿ;ϭϮͿ;ͿDĂǆŝŵƵŵƚƌĞĂƚŝŶŐƉƌĞƐƐƵƌĞ ǁŝƚŚƐƵƉƉŽƌƚŝŶŐŝŶĨŽƚŽĚĞƚĞƌŵŝŶĞ ĂƉƉƌŽƉƌŝĂƚĞŶĞƐƐĨŽƌƉƌŽŐƌĂŵ DĂǆ͘ϮϵϬϬƉƐŝĂŶƚŝĐŝƉĂƚĞĚƚƌĞĂƚŝŶŐƉƌĞƐƐƵƌĞŝƐƐƚŝŵƵůĂƚŝŽŶ ŵŽĚĞů͘ƚŵĂǆ͘ůůŽǁĂďůĞƚƌĞĂƚŝŶŐƉƌĞƐƐƵƌĞŽĨϰϱϬƉƐŝ ǁŝƚŚϯϰϬϬŵŝŶŝŵƵŵŚŽůĚƉƌĞƐƐƵƌĞ t ϬϲͬϮϵͬϮϬϮϯ ϮϬϮϱ͘Ϯϴϯ,ǇĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚ Wh^ͲϯϮ;WdEŽ͘ϮϭϮͲϬϴϮ͖^ƵŶĚƌǇEŽ͘ϯϮϯͲϯϰϳͿ WĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍ K' WĂŐĞϲ :ƵŶĞϮϭ͕ϮϬϮϯ ;ĂͿ;ϭϮͿ;&Ϳ&ƌĂĐƚƵƌĞƐʹŚĞŝŐŚƚ͕ůĞŶŐƚŚ͕D ĂŶĚdsƚŽƚŽƉ͕ĚĞƐĐƌŝƉƚŝŽŶŽĨĨƌĂĐƚƵƌŝŶŐ ŵŽĚĞů WƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘dŚĞĂŶƚŝĐŝƉĂƚĞĚŚĂůĨͲůĞŶŐƚŚƐŽĨ ƚŚĞŝŶĚƵĐĞĚĨƌĂĐƚƵƌĞƐĂƌĞϯϬϬ͛ĂĐĐŽƌĚŝŶŐƚŽƚŚĞ KƉĞƌĂƚŽƌ͛ƐĐŽŵƉƵƚĞƌƐŝŵƵůĂƚŝŽŶ͘ŽŵƉƵƚĞƌƐŝŵƵůĂƚŝŽŶ ŝŶĚŝĐĂƚĞƐƚŚĞĂŶƚŝĐŝƉĂƚĞĚŚĞŝŐŚƚŽĨƚŚĞŝŶĚƵĐĞĚĨƌĂĐƚƵƌĞƐ ǁŝůůďĞϵϬ͛;ƚŽƉŽĨĂďŽƵƚͲϲ͕ϳϱϬ͛ĂŶĚďĂƐĞŽĨĂďŽƵƚͲϲ͕ϴϭϮ͛ ds^^Ϳ͕ƐŽŝŶĚƵĐĞĚĨƌĂĐƚƵƌĞƐǁŝůůůŝŬĞůǇƉĞŶĞƚƌĂƚĞŝŶƚŽ͕ďƵƚ ŶŽƚƚŚƌŽƵŐŚ͕ƚŚĞŽǀĞƌůǇŝŶŐĐŽŶĨŝŶŝŶŐŝŶƚĞƌǀĂůƐ͘ ^& ϲͬϮϴͬϮϬϮϯ ;ĂͿ;ϭϯͿWƌŽƉŽƐĞĚƉƌŽŐƌĂŵĨŽƌƉŽƐƚͲ ĨƌĂĐƚƵƌŝŶŐǁĞůůĐůĞĂŶƵƉĂŶĚĨůƵŝĚƌĞĐŽǀĞƌǇ EŽƚƉƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶďƵƚ,ŝůĐŽƌƉŚĂƐŵƵůƚŝƉůĞ ĚŝƐƉŽƐĂůŽƉƚŝŽŶƐŽŶEŽƌƚŚ^ůŽƉĞ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ďͿdĞƐƚŝŶŐŽĨĐĂƐŝŶŐ ŽƌŝŶƚĞƌŵĞĚŝĂƚĞ ĐĂƐŝŶŐ dĞƐƚĞĚхϭϭϬйŽĨŵĂǆĂŶƚŝĐŝƉĂƚĞĚ ƉƌĞƐƐƵƌĞ D/d/ŽĨϯϵϬϬƉƐŝ͘ƵƌŝŶŐĨƌĂĐϯϰϬϬƉƐŝďĂĐŬƉƌĞƐƐƵƌĞƐŽ ƚĞƐƚŝŶŐŵĞĞƚƐϭϭϬй t ϬϲͬϮϵͬϮϬϮϯ ;ĐͿ&ƌĂĐƚƵƌŝŶŐƐƚƌŝŶŐ;ĐͿ;ϭͿWĂĐŬĞƌхϭϬϬ͛ďĞůŽǁdKŽĨ ƉƌŽĚƵĐƚŝŽŶŽƌŝŶƚĞƌŵĞĚŝĂƚĞĐĂƐŝŶŐ ϰͲЪΗƉƌŽĚƵĐƚŝŽŶƚƵďŝŶŐƚĞƐƚĞĚƚŽϰϬϬϬƉƐŝ͘WƌŽĚƵĐƚŝŽŶ ƉĂĐŬĞƌĂƚϳϯϴϴ͛DǁŚŝĐŚŚĂƐŐŽŽĚĐĞŵĞŶƚďŽŶĚƋƵĂůŝƚǇ ĨƌŽŵϯϲϱϵ͛DʹϵϮϴϰ͛D D'Z ϬϲͬϮϴͬϮϬϮϯWĞƚ ŶŐ ;ĐͿ;ϮͿdĞƐƚĞĚхϭϭϬйŽĨŵĂǆĂŶƚŝĐŝƉĂƚĞĚ ƉƌĞƐƐƵƌĞĚŝĨĨĞƌĞŶƚŝĂů D/ddŽĨϯϲϬϬƉƐŝƉůĂŶ͘ŶƚŝĐŝƉĂƚĞĚĨƌĂĐŽĨϮϵϬϬƉƐŝǁŝƚŚ/ ŵŝŶŝŵƵŵŚŽůĚŽĨϯϰϬϬƉƐŝƐŽƐŵĂůůŶĞŐĂƚŝǀĞĚŝĨĨĞƌĞŶƚŝĂů ƉůĂŶŶĞĚ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ĚͿWƌĞƐƐƵƌĞƌĞůŝĞĨ ǀĂůǀĞ >ŝŶĞƉƌĞƐƐƵƌĞфсƚĞƐƚƉƌĞƐƐƵƌĞ͕ƌĞŵŽƚĞůǇ ĐŽŶƚƌŽůůĞĚƐŚƵƚͲŝŶĚĞǀŝĐĞ DĂǆĂŶƚŝĐŝƉĂƚĞĚĨƌĂĐƐƵƌĨĂĐĞƉƌĞƐƐƵƌĞŽĨϮϵϬϬƉƐŝ͘ WƌĞƐƐƵƌĞƚĞƐƚůŝŶĞƐƚŽϱϱϬϬƉƐŝĂĚĚĞĚďǇDĞů͘ϱϬϬϬƉƐŝ ƚƌĞĞ͘ƉƵŵƉŬŶŽĐŬŽƵƚϰϬϱϬͲϰϯϬϬƉƐŝǁŝƚŚŐůŽďĂůŬŝĐŬŽƵƚ ĂƚϰϯϬϬƉƐŝĂŶĚEŝƚƌŽŐĞŶƉŽƉŽĨĨŽĨϱϱϬϬƉƐŝ͘/WZsƐĞƚĂƐ ϯϳϬϬƉƐŝ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ĞͿŽŶĨŝŶĞŵĞŶƚ&ƌĂĐĨůƵŝĚƐĐŽŶĨŝŶĞĚƚŽĂƉƉƌŽǀĞĚ ĨŽƌŵĂƚŝŽŶƐWƌŽǀŝĚĞĚǁŝƚŚĂƉƉůŝĐĂƚŝŽŶ͘ t ϬϲͬϮϵͬϮϬϮϯ ;ĨͿ^ƵƌĨĂĐĞĐĂƐŝŶŐ ƉƌĞƐƐƵƌĞƐ DŽŶŝƚŽƌĞĚǁŝƚŚŐĂƵŐĞĂŶĚƉƌĞƐƐƵƌĞƌĞůŝĞĨ ĚĞǀŝĐĞ/WZsƐĞƚĂƚϯϳϬϬƉƐŝ͘^ƵƌĨĂĐĞĂŶŶƵůƵƐŽƉĞŶ͘ t ϬϲͬϮϵͬϮϬϮϯ ϮϬϮϱ͘Ϯϴϯ,ǇĚƌĂƵůŝĐ&ƌĂĐƚƵƌŝŶŐƉƉůŝĐĂƚŝŽŶʹŚĞĐŬůŝƐƚ Wh^ͲϯϮ;WdEŽ͘ϮϭϮͲϬϴϮ͖^ƵŶĚƌǇEŽ͘ϯϮϯͲϯϰϳͿ WĂƌĂŐƌĂƉŚ^ƵďͲWĂƌĂŐƌĂƉŚ^ĞĐƚŝŽŶŽŵƉůĞƚĞ͍ K' WĂŐĞϳ :ƵŶĞϮϭ͕ϮϬϮϯ ;ŐͿŶŶƵůƵƐ ƉƌĞƐƐƵƌĞ ŵŽŶŝƚŽƌŝŶŐΘ ŶŽƚŝĨŝĐĂƚŝŽŶ ϱϬϬƉƐŝĐƌŝƚĞƌŝĂ t ϬϲͬϮϵͬϮϬϮϯ ;ŐͿ;ϭͿEŽƚŝĨǇK'ǁŝƚŚŝŶϮϰŚŽƵƌƐ ;ŐͿ;ϮͿŽƌƌĞĐƚŝǀĞĂĐƚŝŽŶŽƌƐƵƌǀĞŝůůĂŶĐĞ ;ŐͿ;ϯͿ^ƵŶĚƌǇƚŽK' ;ŚͿ^ƵŶĚƌǇZĞƉŽƌƚ ;ŝͿZĞƉŽƌƚŝŶŐ;ŝͿ;ϭͿ&ƌĂĐ&ŽĐƵƐZĞƉŽƌƚŝŶŐ ;ŝͿ;ϮͿK'ZĞƉŽƌƚŝŶŐ͗ƉƌŝŶƚĞĚΘ ĞůĞĐƚƌŽŶŝĐ ;ũͿWŽƐƚͲĨƌĂĐǁĂƚĞƌ ƐĂŵƉůŝŶŐƉůĂŶ ;ŬͿŽŶĨŝĚĞŶƚŝĂů ŝŶĨŽƌŵĂƚŝŽŶ ůĞĂƌůǇŵĂƌŬĞĚĂŶĚƐƉĞĐŝĨŝĐĨĂĐƚƐ ƐƵƉƉŽƌƚŝŶŐŶŽŶĚŝƐĐůŽƐƵƌĞEŽŶͲĐŽŶĨŝĚĞŶƚŝĂůǁĞůů͘^& ϲͬϮϵͬϮϬϮϯ ;ůͿsĂƌŝĂŶĐĞƐ ƌĞƋƵĞƐƚĞĚ DŽĚŝĨŝĐĂƚŝŽŶƐŽĨĚĞĂĚůŝŶĞƐ͕ƌĞƋƵĞƐƚƐĨŽƌ ǀĂƌŝĂŶĐĞƐŽƌǁĂŝǀĞƌƐ ZĞĐŽŵŵĞŶĚĂƉƉƌŽǀŝŶŐƌĞƋƵĞƐƚĞĚǀĂƌŝĂŶĐĞƐĨŽƌ ĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐĂŶĚďĂƐĞͲǁĂƚĞƌƐĂŵƉůŝŶŐďĞĐĂƵƐĞŶŽ ĨƌĞƐŚǁĂƚĞƌĂƋƵŝĨĞƌƐĂƌĞƉƌĞƐĞŶƚƉĞƌKϭ͘ ^& ϲͬϮϵͬϮϬϮϯ EŽƉůĂŶĨŽƌƉŽƐƚĨƌĂĐƚƵƌĞǁĂƚĞƌǁĞůůĂŶĂůǇƐŝƐ͘ŽŵŵŝƐƐŝŽŶŵĂǇƌĞƋƵŝƌĞƚŚŝƐĚĞƉĞŶĚŝŶŐŽŶƉĞƌĨŽƌŵĂŶĐĞŽĨƚŚĞĨƌĂĐƚƵƌŝŶŐŽƉĞƌĂƚŝŽŶ͘ Nolan Vlahovich Hilcorp Alaska, LLC Geo Tech 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 564-4558 E-mail: nolan.vlahovich@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal. Received By: Date: Date: 06/13/2023 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 SFTP DATA TRANSMITTAL T#20230417 Well API #PTD #Log Date Log Company Log Type AOGCC Eset# MPU B-21 50029215350000 186023 5/8/2023 HALLIBURTON Jewelry Log MPU B-21 50029215350000 186023 5/12/2023 HALLIBURTON Leak Detection Log MPU B-21 50029215350000 186023 5/13/2023 HALLIBURTON Multi Finger Caliper Report MPU I-04A 50029220680100 201092 4/17/2023 HALLIBURTON Cement Bond Log NS-16A 50029230960100 206141 4/3/2023 HALLIBURTON RBT NS-23 50029231460000 203050 4/25/2023 HALLIBURTON RBT PBU 09-24A 50029214280100 223003 4/9/2023 HALLIBURTON RBT-Coilflag PBU C-26A 50029208340100 198145 3/17/2023 HALLIBURTON Production Profile PBU M-201 50029237110000 222030 5/29/2023 HALLIBURTON Inj. Profile PBU S-32A 50029220990100 212082 5/23/2023 HALLIBURTON CAST CBL PBU S-37A 50029222910100 212092 5/19/2023 HALLIBURTON RBT PBU V-221 50029232460000 205013 5/14/2023 HALLIBURTON Inj. Profile PBU W-04 50029219070000 189008 3/8/2023 HALLIBURTON CAST CBL PBU W-209 50029231700000 203128 5/13/2023 HALLIBURTON Inj. Profile PBU W-219 50029234290000 210105 4/16/2023 HALLIBURTON Inj. Profile PBU Z-223 50029237200000 222080 2/28/2023 HALLIBURTON Inj. Profile SRU 213B-15 50133206540000 215130 4/28/2023 HALLIBURTON Perf Please include current contact information if different from above. T37729 T37729 T37729 T37730 T37731 T37732 T37733 T37734 T37735 T37736 T37737 T37738 T37739 T37740 T37741 T37742T37743 PBU S-32A 50029220990100 212082 5/23/2023 HALLIBURTON CAST CBL Kayla Junke Digitally signed by Kayla Junke Date: 2023.06.13 13:09:15 -08'00' CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Rixse, Melvin G (OGC) To:AOGCC Records (CED sponsored) Subject:20230525 1000 PTD212-082 S-32A RWO CBL (Sundry #323-222) Date:Thursday, May 25, 2023 11:06:06 AM From: Rixse, Melvin G (OGC) Sent: Thursday, May 25, 2023 10:07 AM To: Claire Mayfield <claire.mayfield@hilcorp.com> Subject: FW: S-32A RWO CBL (Sundry #323-222) Claire, Approved to progress Sundry 323-222. CBL log received and demonstrated isolation above 7200’ MD for Kuparuk sands isolation. Mel Rixse Senior Petroleum Engineer (PE) Alaska Oil and Gas Conservation Commission 907-793-1231 Office 907-297-8474 Cell 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 Mel Rixse at (907-793-1231 ) or (Melvin.Rixse@alaska.gov). From: Claire Mayfield <Claire.Mayfield@hilcorp.com> Sent: Wednesday, May 24, 2023 4:00 PM To: Rixse, Melvin G (OGC) <melvin.rixse@alaska.gov> Subject: S-32A RWO CBL (Sundry #323-222) Mel, Please see attached cement bond log for S-32A recomplete (Sundry #323-222). According to Halliburton’s analysis (page 2 of the log report), top of cement around the 9-5/8” casing was located at 2709’ MD, and has good cement bond quality from 3659’ MD – 9284’ MD (base of logged interval). The top of Kuparuk reservoir is at 7522’ MD, so we will plan to proceed with the proposed completion in the sundry if no concerns. Let me know if you have any questions. Thanks, Claire Mayfield Hilcorp Energy Company Prudhoe Bay West – Operations Engineer Office: (907) 564-4375 Cell: (713) 443-3631 The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. STATE OF ALASKA OIL AND GAS CONSERVATION COMMISSION BOPE Test Report for: Reviewed By: P.I. Suprv Comm ________PRUDHOE BAY UNIT S-32A JBR 07/25/2023 MISC. INSPECTIONS: FLOOR SAFTY VALVES:CHOKE MANIFOLD:BOP STACK: ACCUMULATOR SYSTEM:MUD SYSTEM: P/F P/F P/FP/FP/F Visual Alarm QuantityQuantity Time/Pressure SizeQuantity Number of Failures:9 Tested with 4 1/2" test joint. Test fluid was 60/40 meth water. Housekeeping better than last visit but still unsatisfactory for Alaska standards. Pit houses 1 and 2 meth and h2s detectors needed calibrated and would not read high enough to even set off visual alarms. Pit #2 H2s sensor needed batteries replaced. IA gauges not adequate for reading low pressure ( 2 -5 k gauges and one was broken reading 2200psi., replaced bad gauge and hooked up canrig which also needed calibrated. CMV#2 Failed during shell test, grease, function, and pass. Blinds Failed, exercise and fail again, replace test, and fail again, Replace with third set, retest and pass. No other failures. Test Results TEST DATA Rig Rep:Adan FloresOperator:Hilcorp North Slope, LLC Operator Rep:Anthony Knowles Rig Owner/Rig No.:Hilcorp Thunderbird 1 PTD#:2120820 DATE:5/22/2023 Type Operation:WRKOV Annular: 250/2500Type Test:INIT Valves: 250/3000 Rams: 250/3000 Test Pressures:Inspection No:bopSTS230521140642 Inspector Sully Sullivan Inspector Insp Source Related Insp No: INSIDE REEL VALVES: Quantity P/F (Valid for Coil Rigs Only) Remarks: Test Time 22 MASP: 2629 Sundry No: 323-222 Control System Response Time (sec) Time P/F Housekeeping:FP PTD On Location P Standing Order Posted P Well Sign P Hazard Sec.P Test Fluid O Misc NA Upper Kelly 0 NA Lower Kelly 0 NA Ball Type 1 P Inside BOP 1 P FSV Misc 0 NA 9 FPNo. Valves 2 PManual Chokes 0 NAHydraulic Chokes 0 NACH Misc Stripper 0 NA Annular Preventer 1 13 5/8 P #1 Rams 1 2 7/8x5 vari P #2 Rams 1 blinds FP #3 Rams 0 NA #4 Rams 0 NA #5 Rams 0 NA #6 Rams 0 NA Choke Ln. Valves 1 3 1/8 P HCR Valves 1 3 1/8 P Kill Line Valves 3 3 1/8 P Check Valve 0 NA BOP Misc 2 IA gauges FP System Pressure P2950 Pressure After Closure P1450 200 PSI Attained P13 Full Pressure Attained P137 Blind Switch Covers:Pall stations Bottle precharge P Nitgn Btls# &psi (avg)P3@2283 ACC Misc NA0 P PTrip Tank P PPit Level Indicators P PFlow Indicator FP FPMeth Gas Detector FP FPH2S Gas Detector NA NAMS Misc Inside Reel Valves 0 NA Annular Preventer P19 #1 Rams P7 #2 Rams P8 #3 Rams NA0 #4 Rams NA0 #5 Rams NA0 #6 Rams NA0 HCR Choke P1 HCR Kill NA0 9 9 9 9 9999 9 9 9 9 9 9 9 99 9 9 9 Housekeeping unsatisfactory Pit houses 1 and 2 meth and h2s detectors IA gauges not adequate for reading low pressure CMV#2 Failed Blinds Failed, FP FP FP FP FP FPFP FP MEMORANDUM State of Alaska Alaska Oil and Gas Conservation Commission TO: Jim Regg DATE: P.I. Supervisor SUBJECT: FROM: Petroleum Inspector Section:35 Township:12N Range:12E Meridian:Umiat Drilling Rig:NA Rig Elevation:NA Total Depth:11848 ft MD Lease No.:ADL0028257 Operator Rep:Suspend:P&A:X Conductor:20"O.D. Shoe@ 114 Feet Csg Cut@ Feet Surface:13 3/8"O.D. Shoe@ 2685 Feet Csg Cut@ Feet Intermediate:9 5/8"O.D. Shoe@ 10099 Feet Csg Cut@ Feet Production:7"O.D. Shoe@ 10113 Feet Csg Cut@ Feet Liner:3.5x3.2.5x2.9 O.D. Shoe@ 11845 Feet Csg Cut@ Feet Tubing:4.5 O.D. Tail@ 9913 Feet Tbg Cut@ Feet Type Plug Founded on Depth (Btm)Depth (Top)MW Above Verified Fullbore Bottom 11845 ft 9381 ft Wireline tag Initial 15 min 30 min 45 min Result Tubing 2783 2692 2667 IA 71 71 71 OA 545 46 46 Initial 15 min 30 min 45 min Result Tubing IA OA Remarks: Attachments: Caleb Piakowski Casing/Tubing Data (depths are MD): Plugging Data (depths are MD): Initial tag at 9371 ft MD with no cement in bailer. Changed centrilizer and retag with good cement sample @ 9381 ft MD. MITT with ambient diesel. Plan to recomplete in Kuparuk zone. April 11, 2023 Sean Sullivan Well Bore Plug & Abandonment PBU S-32A Hilcorp North Slope LLC PTD 2120820; Sundry 323-032 none Test Data: P Casing Removal: rev. 3-24-2022 2023-0411_Plug_Verification_PBU_S-32A_ss              7. Property Designation (Lease Number): 1. Operations Performed: 2. Operator Name: 3. Address: 4. Well Class Before Work:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Logs (List logs and submit electronic data per 20AAC25.071): 10. Field/Pool(s): Susp Well Insp Install Whipstock Mod Artificial Lift Perforate New Pool Perforate Plug Perforations Coiled Tubing Ops Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown 11. Present Well Condition Summary: Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 14. Attachments (required per 20 AAC 25.070, 25.071, & 25.283) 16. Well Status after work: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. OIL GAS WINJ WAG GINJ WDSPL GSTOR Suspended SPLUG Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: PBU S-32A Recomplete to Aurora Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 212-082 50-029-22099-01-00 11848 Conductor Surface Intermediate Production Liner 8987 80 2657 10071 253 1990 9389 20" 13-3/8" 9-5/8" 7" 3-1/2" x 3-1/4" x 2-7/8" 8250 34 - 114 33- 2685 31- 10099 9860 - 10113 9855 - 11845 34 - 114 28 - 2685 28 - 8810 8264 - 8821 8621 - 8987 None 2260 4760 5410 10530 9389 5020 6870 7240 10160 7524 - 7590 4-1/2" 12.6# 13Cr80 28 - 7445, 9314 - 9913 6741 - 6795 Structural 4-1/2" HES TNT Packer 9832, 8603 7388, 9832 6632, 8603 Torin Roschinger Area Operations Manager Claire Mayfield Claire.Mayfield@hilcorp.com 907-564-4375 PRUDHOE BAY, Prudhoe Oil / Aurora Oil Total Depth Effective Depth measured true vertical feet feet feet feet measured true vertical measured measured feet feet feet feet measured true vertical Plugs Junk Packer Measured depth True Vertical depth feet feet Perforation depth Tubing (size, grade, measured and true vertical depth) Packers and SSSV (type, measured and true vertical depth) 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure: 13a.Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Subsequent to operation: 15. Well Class after work: Exploratory Development Service StratigraphicDaily Report of Well Operations Copies of Logs and Surveys Run Electronic Fracture Stimulation Data Sundry Number or N/A if C.O. Exempt: ADL 0028257 28 - 6678, 8189 - 8666 9389 - 11808' MD in Tubing/Liner Pumped 14.5-bbls 14-ppg cement with 1430-psi final pressure. 58 Well Not Online 670 1620 1150 333 400 323-032, 323-222 13b. Pools active after work:Aurora Oil 4-1/2" TIW Packer 7388, 6632 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Sr Pet Eng: Sr Pet Geo: Form 10-404 Revised 10/2022 Submit in PDF format to aogcc.permitting@alaska.gov Sr Res Eng: Due Within 30 days of Operations By Grace Christianson at 8:56 am, Jun 13, 2023 Digitally signed by Torin Roschinger (4662) DN: cn=Torin Roschinger (4662), ou=Users Date: 2023.06.12 15:33:38 -08'00' Torin Roschinger (4662) RBDMS JSB 071423 WCB 2-1-2024 DSR-6/13/23 ACTIVITY DATE SUMMARY 2/3/2023 T/I/O=Shut in/700/100. PPPOT-T (PASS) Pre RWO Tubing hanger void had 200 psi., bled off, shut in 10 min., 0 psi, function upper lock down screws one at a time, all went to 4-3/4 inches out from flange to end of lock down screw, ran back in tag hanger, tighten gland nuts, torqued lock down screws to 500 ft/lbs., test void 500 psi./5 min., 0 psi . loss, test 5,000 psi/30 min., lost 100 psi in the first 15 min., lost 0 psi in the last 15 min., pass, bled off. Control & balance lines plugged @ tubing head termination point. Intermediate casing packoff had been previously plastic packed, still has Hoki valves in both ½ inch NPT ports, functioned all ten lock down screws one at a time, all were very stiff, went to 4-3/4 inches out from flange to end of lock down screw, the one at the 7:00 position only went to 4-1/2 inches, the one at the 4:00 position is bent, but functioned okay, the gland nut at the 1:00 position is out 1/16 of an inch farther than the rest. For the purpose of this report, there are no intermediate casing lock down screws at the 3:00 & 9:00 positions. RDMO 2/13/2023 T/I/O = SSV/760/110. Temp = SI. Investigate gas leak (OP's call-in). AL SI @ CV = 750 psi. When entering well house a faint smell of gas is present, nothing audible. Unable to find any gas leaks, Snooped every flange connection and valve stems on tree, CV's and jewelry. No response from 4 gas meter. 2/14/2023 T/I/O = SSV/760/110. Temp = SI. Repair leaking wellhead (OP's call-in). AL SI @ CV = 750 psi. Torqued all LDS on well head. Attempt to PT IC test void, void has been green sticked. Pressured up against green stick. SV, WV, SSV = C. MV = O. IA & OA = OTG. 16:30 2/17/2023 LRS Well Test Unit 6. POP/Flowback. Begin WSR on 2/17/23. IL well S-32, OL well S- 38. Unit Move, RU, PT,. Job in progress. Continue WSR 2/18/23 2/18/2023 LRS Well Test Unit 6. POP/Flowback. Cont WSR from 2/17/23. IL well S-32, OL well S-38. Complete RU, PT, POP Well, SI & allow well to Stack Out, REPOP. Job in progress. Continue WSR on 2/19/23 2/19/2023 LRS Well Test Unit 6. POP/Flowback. Cont WSR from 2/18/23. IL well S-32, OL well S-38. Flow and Stabilze. Job in progress. Continue WSR on 2/20/23 2/20/2023 LRS Well Test Unit 6. POP/Flowback. Cont WSR from 2/19/23. IL well S-32, OL well S-38. Flow and Stabilze, Completed 8 HR WT, DHD Performed PPPOT-IC Test. Job Complete. END WSR. 2/20/2023 T/I/O = 330/1620/170. Temp = 65°. PPPOT-IC (under eval). ALP = 1590 psi, SI @ CV. Upon arrival LRS test unit in control of well. Test port was RU w/ hoke valve upn arrival. LRS in control of well upon departure. PPPOT- IC: RU to test port (700 psi). Bled void to 0 psi. SI & monitored for 10 min. Pressured void to 3500 psi for 30 min test, first 15 min lost 400 psi (FAILED). Bled void to 0 psi. SV = O. WV = C. SSV, MV = O. IA, OA = OTG. 17:00 2/21/2023 (Assist LRS Testers with Freeze Protect) TFS U-3, Pumped 9 bbls 60/40 and 22 bbls crude down (S-38 FL) for FP, and pumped 1 bbls 60/40 and 38 bbls crude down S-32 TBG for FP. Both wells secured and S/I, IA and OA= OTG on both wells. Daily Report of Well Operations PBU S-32A Daily Report of Well Operations PBU S-32A 2/22/2023 T/I/O = SSV/1850/100. Temp = SI. Repair leaking wellhead (OP's call-in). ALP = 1850 psi, SI @ CV. found 1 LDS assembly on TBG head and 4 LDS assemblies on CSG weeping gas/fluid. Stung into TBG test port (0+ psi). Adjusted leaking LDS and wiped up flange. PT hanger void to 5000 psi, leak mitigated. Bled to 0 psi. Unable to bleed IC test void to 0 psi (1850 psi). Adjusted 4 leaking LDS while holding open bleed. PT test void to 3500 psi, pressure bleeding off rapidly. LDS leaks mitigated. SV, WV, SSV = C. MV = O. IA & OA = OTG. 17:00. 2/27/2023 ***WELL S/I ON ARRIVAL*** DRIFTED w/ 10' x 3-3/8" DUMMY GUN TO TOP OF LTP @ 9,854' MD. LOGGED READ CALIPER FROM 9854' MD TO SURFACE (GOOD DATA), SET 3.81" PX PLUG BODY @ 9826' MD. ***WSR CONTINUED ON 2-28-23*** 2/28/2023 T/I/O= 1800/1775/71 Temp= SI TFS unit 4 Assist SL (RWO Capital) Pumped 2 bbls 60/40 followed by 684 bbls KCL down TBG. Further pumped 2 bbls 60/40 followed by 171 bbls crude down TBG for freeze protect & up IA taking returns down S-38 FL. Fp'd Hardline and S-38 FL with 8 bbls 60/40 and 40 bbls Crude. U-Tubed TxIA for FP. *******WSR Continued on 3/1/23*********** 2/28/2023 ***WSR CONTINUED FROM 2-27-23*** SET BAITED EQ PRONG IN PX PLUG BODY @ 9,826' MD PULLED RK-OGLV FROM ST#1 @ 9,798' MD PULLED RK-LGLV FROM ST#3 @ 7,719' MD PULLED RK-LGLV FROM ST#4 @ 5,551' MD PULLED RK-LGLV FROM ST#5 @ 3,101' MD SET RK-DGLV IN ST#5 @ 3,101' MD SET RK-DGLV IN ST#4 @ 5,551' MD SET RK-DGLV IN ST#3 @ 7,719' MD T-BIRD TO LOAD WELL W/ 688 BBLS KCL AND U-TUBE 171 BBL CRUDE F/P. DHD TO REPLACE LEAKY LOCKDOWN SCREW ON CASING HANGER. ***WSR CONTINUED ON 3-1-23*** 3/1/2023 T/I/O = SSV/250/0. Temp = SI. Eval LDS leak (ops call in). ALP = 1100 psi, AL SI @ casing valve. 1 leaking LDS @ the 6:00 position. Removed LDS & cleaned polished bore. Re-install LDS & torque to 450 ft/lbs. Pressured IAP to 2130 psi when pump stopped increasing IAP, replacement triplex after shift change nights to complete MIT-IA. SV, WV, SSV = C. MV = O. IA, OA = OTG. 16:30 3/1/2023 *******WSR Continued from 2/28/23******* (TFS unit 4 Assist SL with MIT-IA) MIT-IA ********PASS******* Max applied pressure=2750 Target pressure=2500. Pumped 6 bbls of crude down IA to reach max applied pressure. 1st 15 min IA lost 62 psi, 2nd 15 min IA lost 30 psi. IA lost a total of 92 psi in a 30 min rest. MIT-IA ********FAIL******* Max applied pressure=3750 Target pressure=3500. Pumped .5 bbls of crude down IA to reach max applied pressure. 1st 15 min IA lost 34 psi, 2nd 15 min IA lost 34 psi. IA lost a total of 68 psi in a 30 min test. Bled back - 8.4 bbls. See log for details. SL in control of well upon departure. FWHP= 700/600/0 Daily Report of Well Operations PBU S-32A 3/1/2023 ***WSR CONTINUED FROM 2-28-23*** SET RK-DGLV IN STA#1 @ 9798' MD. T-BIRD TO MITIA 2500 PSI (PASSED). T-BIRD TO MITIA 3500 PSI (FAILED 2 TESTS; LINEAR LEAKS W/ TBG INCREASE). PULLED BAITED EQ PRONG & PLUG BODY FROM X-NIP @ 9,826' MD ***WELL S/I ON DEPARTURE, DHD TO TROUBLE SHOOT LEAKING LOCKDOWN SCREW*** 3/2/2023 T/I/O = 50/2020/30. Temp = SI. MIT-IA to 3500 psi PASSED (eval leaking LDS). ALP = 940 psi, SI @ CV. IA FL @ surface. Used 4 bbls of diesel to pressure IAP to 3500 psi. TP unchanged, OAP increased 10 psi, LDS @ 06:00 not leaking. Monitored for 30 min. Lost 35 psi in the 1st 15 min & 15 psi in the 2nd 15 min for a total loss of 50 psi in 30 min. LDS @ 06:00 not leaking. Bled IAP to BT to 10 psi returning 7.5 bbls of fluid. Final WHPs = 50/10/30. SV, WV, SSV = C. MV = O. IA, OA = OTG. 01:00 3/23/2023 Injectivity Test (RWO CAPITAL) Pumped 3 bbls 60/40 meth, 211 bbls 1% KCL, and 38 bbls Diesel down TBG. Got an injectivity of ~3.2 bpm @ 2500 psi down Tbg. Pad Op notified of well status per LRS departure. SV,WV,SSV=C MV=O IA,OA=OTG 3/29/2023 T/I/O=0/0/0 Set 4" CIW "H" TWC through tree. N/D production tree, N/U dryhole tree. Torqued to specs. PT'd tree through tree cap against TWC 250/5000 psi. pass. Pulled TWC. Installed drilling scaffolding job complete. FWP's 0/800/0. 4/8/2023 T/I/O=7/80/42 (RWO CAPITAL) Pre heated diesel tanker to 80*. Pumped 5 bbls 60/40 down TBG for a Spear. HES pumped 14.5 bbls of 14 ppg cement followed by 145 bbls 80* diesel down tbg to spot cement. FWHP=1430/67/52 Turn well over to dso. EST TOC @ ~9825' 4/11/2023 ***WELL S/I ON ARRIVAL*** RAN KJ, 3' x 1-3/4", 3.50" CENT, 2-1/2" S-BAILER TO TOC @ 9,378' SLM LRS CONDUCT PASSING STATE WITNESS MIT-T (STATE WITNESS REP Sean Sullivan) RAN KJ, 3' x 1-3/4", 3.67" CENT, 2-1/2" S-BAILER TO 9,374' SLM RAN KJ, 3' x 1-3/4", 3.25" CENT, 2-1/2" S-BAILER TO TOC @ 9,381' SLM ***JOB COMPLETE, WELL LEFT S/I ON DEPARTURE, PAD-OP NOTIFIED.*** 4/11/2023 T/I/O=1020/70/45 AOGCC MIT TBG PASSED to 2500 psi ( Post Cement ) Pump 1.5 bbls diesel down tbg to 2756 psi. TP lost 147 psi 1st 15 min & 41 psi 2nd 15 min. ( Pre Test ) Bled back to 1060 psi to start AOGCC witnessed MIT T. Pumped 1.2 bbls diesel to 2783 psi. TP lost 91 psi 1st 15 min & 25 psi 2nd 15 min. Bled back 1.2 bbls to 1060 psi. cont to bleed to 500 psi. FWHPs=500/70/46 Pumped 5 bbls() 60/40 down TBG for a Spear. HES pumped 14.5 bbls of 14 ppg cement followed by 145 bbls 80* diesel down tbg to spot cement A passing state witnessed MIT-T to 2500 psi was required by Sundry 323-222. -WCB AOGCC MIT TBG PASSED to 2500 psi ( Post Cement ) Pump @ LRS CONDUCT PASSING STATE WITNESS MIT-T (STATE WITNESS REP Sean Sullivan) Daily Report of Well Operations PBU S-32A 4/13/2023 ***WELL S/I ON ARRIVAL*** ( JOB SCOPE: CUT 4.5'' TUBING WITH JET CUTTER) RIG UP YJ ELINE. PT PCE 300 PSI LOW /3000 PSI HIGH RIH W/CH/X2 1 11/16'' WB/ 1 11/16'' CCL/ 3.5'' JET CUTTER AND CUT 4.5'' TBG @ 9314' . CCL TO CUTTER = 2.6'. CCL TO STOP DEPTH @ 9311.4' TAG TOC @ 9389' CCL CORRELATED TO TUBING TALLY DATED 11/23/1990 PRE-CUT PRESSURE T/IA/OA= 1200/100/50 PSI AFTER CUT T/IA/OA= 500/125/50 PSI PUMPED THRU TUBING TO CONFIRM CUT AND COMMUNICATING TO IA, IA INCREASED FROM 100 PSI TO 125 PSI JOB COMPLETE ***WELL S/I ON DEPARTURE*** 4/17/2023 T/I/O=620/130/47 CMIT TxIA (PRE CTD) Pump down IA w/ 13.5 bbls diesel down IA to reach test pressure CMIT PASSED to 3479.3149 TxIA PSI. , Loss of 14/13 psi 1st 15 min. Loss of 09/08 TxIA PSI during 2nd 15 min. Bled back 13 bbls. FWHP=600/140/0 4/18/2023 T/I/O= 682/285/49 **CIRC-OUT W/U-TUBE** Pumped 15 bbls 60/40, 100 bbls deep clean, 780 bbls 1% KCL, and 180 bbls diesel down the TBG taking returns up the IA to S-38. Pumped 6 bbls 60/40 and 40 bbls crude down the flow line for freeze protect on S-38 U-Tube completed. FWHP'S 0/0/96 5/13/2023 T/I/O = VAC/VAC/60. Temp = SI. Bleed WHPS/C&B lines to 0 psi (pre rig). AL, FL & S-riser disconnected, wellhouse and flooring removed, Dryhole tree. Bled C&B lines to 0 psi. OA FL @ near surface. Bled OAP to BT to 0 psi in 30 min. Monitored for 30 min. OAP unchanged. Final WHPs = VAC/VAC/0. MV, SV = C. IA, OA = OTG. 5/19/2023 T/I/O=Vac/Vac/5. Pre TB #01. Well head Tech set 4" CTS "H" BPV with dryrod. ND 4" dryhole tree and 13 3/8" FMC NSSH THA. Wellhead tech installed CTS plug and X- over into lift threads. PT CTS/ BPV to 500/3500 psi. Passed. Removed X-over and NU 13 /8" CIW BOP. Installed shooting flange. ***Job Complete*** Final WHP's BPV/0/5. 5/20/2023 Check void & (2) CCLs for psi., all @ 0 psi., remove THA, cut & cap (2) ¼" CCLs, install CTS plug, make up 4-1/2" TDS test sub to tubing hanger lift threads, test 500 psi./5 min., 4200 psi./10 min., good tests, bleed off test psi., rig down test sub, clean ring groove, install NEW BX-160, RDMO. 5/21/2023 TBird RWO Job Scope: Recomplete Ivishak to Kuparuk MIRU Thunderbird-1. Spot rig, pits, pump house, koomey, choke house. R/U choke/kill lines. Raise derrick. R/U scaffolding around BOPE stack. Take on fluids to the pits. RU the floor & scaffolding. Elec connect the Koomy Generator and Load bank. Hook up Koomy lines and charge system. Shell Test 250 psi low / 3000 psi high. Begin AOGCC witnessed BOPE test w/4-1/2" test joint (Sean Sullivan). Test annular 250 psi low / 3000 psi high. Test BOPE 250 psi low / 3000 psi high as per sundry. Blinds rams failed, cycle and re-test. Blind rams failed second test. Contact Yellowjacket for new blind ram inserts. ......Job in progress @ TAG TOC @ 9389' Sundry 323-222 required a TOC tag to ~9825' MD. TOC is 436' MD higher than this, at 9389' MD. Daily Report of Well Operations PBU S-32A 5/22/2023 TBird RWO Job Scope: Recomplete Ivishak to Kuparuk YJ PCE specialist not available. C/O blind ram blocks / horse shoe rubbers. Retest blind rams 250 psi low / 3000 psi high, AOGCC witnessed (Sean Sullivan). R/D test equipment. Pulled TWC. Rock out diesel freeze protect from Tbg & IA. R/U to pull completion. M/U landing joint. BOLDS. Pull hanger to floor and lay down, 109k to release hanger. Run control line through sheave and back to spooler. Begin pulling 4- 1/2" 12.6# NT13-CR-80 TDS tubing & dual encapsulated control lines. ......Job in progress 5/22/2023 Pull CTS plug & BPV w/ T bar, S/B for rig to rock out diesel, M/U 4-1/2" TDS landing joint 8 RH, back out lock down screws, pull hanger to floor, cut & cap (2) ¼" CCL, RDMO. 5/23/2023 ***T-BIRD IN CONTROL OF WELL ON ARRIVAL*** RIH W/ 1-7/16" CHD (1" FN), HES CAST-M PERFORM FREE PIPE CAL @ 800' job continued 5/24/2023 5/23/2023 TBird RWO Job Scope: Recomplete Ivishak to Kuparuk Continue pulling 4-1/2" 12.6# NT13-CR-80 TDS tubing & dual encapsulated control lines. Recovered SVLN (4 SS bands, 27 clamps), 3 GLMs, 233 TDS full joints, and 20.20' cut joint. MIRU Ak Eline w/HES CAST-M BHA. RIH w/CAST-M BHA to just above tubing stub @ 9314' MD. ......Job in progress 5/24/2023 TBird RWO Job Scope: Recomplete Ivishak to Kuparuk Continue RIH w/CAST-M BHA to just above tubing stub @ 9314' MD. Correlate to casing tally 11-15-90. Logged from tubing stub @ 9,233' MD to surface, good data. Send logs to OE. Wait on approval from AOGCC. MU & RIH with pack off pulling tool. Engage PO, BOLDS. Encounter potential subsidence casing growth. RILDS. Discuss plan forward with OE. RU completion running equipment. Line up jewlery according to run tally. Damaged WLEG on stump test of torque turn equipment. Take to TSB to re-cut. Start running 4-1/2" 13Cr VamTop completion. ***Cont on WSR 5/25/23*** 5/24/2023 job continued from 5/23/2023 LOG REPEAT PASS FROM 9,233'-9,000' LOG MAIN PASS FROM 9,233'-SURFACE NO CLEAR TOC FOR FIELD PICK ***T-BIRD RIG LEFT IN CONTROL OF WELL*** 5/25/2023 Check OA for psi/bleed off gas, make up pack off running tool to pack off, back out lock down screws, got to the last one & it was hard to back out, torque one lock down screw on each side of the last one, then the last one backed out easily indicating casing pushing up. Run in all lock down screws & torque to 500 ft/lbs., remove packoff running tool, S/B for storm packer with completion string hanging below it. Make up pack off running tool to pack off, back out lock down screws, all backed out easily, pull old pack off out of hole, grease ID & OD of new pack off, run in hole, run in lock down screws, torque to 500 ft/lbs. per FMC procedure, test pack off void to 500 psi./5 min., 5,000 psi./30 min., good tests, bleed off test pressure, RDMO. Daily Report of Well Operations PBU S-32A 5/25/2023 TBird RWO Job Scope: Recomplete from Ivishak to Kuparuk Continue running 4-1/2" 13Cr completion to 4051'. MU Storm Packer & XO to the 4- 1/2 VT tubing. RIH set storm packer 70' below wellhead. LD packer.. MU & RIH with Pack off run/pull tool. BOLDS checking for casing growth, none detected. Change out IC pack off and PT to 3500 psi.- Good test. Pull & LD storm packer. RU All Torque. Resume running 4-1/2" tubing from 4009' to 6249'. ***Cont on WSR 5/26/23*** 5/26/2023 Make up tubing hanger to string, make up landing joint to tubing hanger, run in hole, run in lock down screws, torque to 500 ft/lbs. per FMC procedure, set 4" H TWC, clean void, hanger neck & ID, press in new SBMS, install new BX-160, test void 500 psi./5 min., 5,000 psi./30 min., good tests, bleed off test psi., RDMO 5/26/2023 TBird RWO Job Scope: Recomplete from Ivishak to Kuparuk Continue running 4-1/2" 13Cr completion from 6249' to 7445'. MU and land Tbg hanger. Up/Dn Wts 89/69K. RILDS. Pump 50 bbls 1% EPT-3744 Corr. Inhibitor tbg x IA and spot from 6489' to packer. RU Landing Joint. Drop B&R 6.9' 1-7/8" Ball. Pressure up the Tbg to set 9-5/8" x 4-1/2" HES TNT Packer. MIT-T and IA to 3500 psi. Passing test for both. Shear out the DCR valve. RU TB Pump truck and FP well with 170 bbls of diesel. Install TWC. RD and move to S-17 ***Job Complete*** 5/26/2023 T/I/O= 0/0/0 Temp= S/I (TFS Unit 4 Assist T-Bird rig with Freeze Protect) Pumped 3 bbls of 60/40 Followed by 170 bbls of DSL down the IA to freeze protect the IA and TBG via U-tube. Tag hung on IA and mastercard given to DSO. FInal WHPS 0/234/0 5/27/2023 T/I/O=TWC/0/0. Post-T-Bird, R/U, pulled BOP's. Installed 4 1/8" Tree and new THA. PT Tree and Tree Cap to 5000 psi against TWC. (Pass). Well Head Tech removed 4"H TWC #712 with T-Bar. Well on Vac. ***Job complete*** Final WHP's Vac/0/0 5/30/2023 Standby for SL to rig up to well. Water rising at the bridges, called back to Prudhoe side of bridges. 5/30/2023 ***WELL S/I UPON ARRIVAL*** (post rig) PULLED B&R FROM 7,414' SLM ***CONT WSR ON 5/31/23*** 5/31/2023 ***CONT WSR FROM 5/30/23*** (post rig) PULLED CIRC VALVE FROM STA #5 @ 3,329' MD MADE 2 ATTEMPTS TO SET RK-LGLV IN STA #5 @ 3,329' MD (rubber debris in kots) ***CONT WSR ON 06/01/2023*** 6/2/2023 ***CONT WSR FROM 05/31/2023*** RAN 3.77" JUNK BASKET TO RHC-M @ 7,420' SLM (recovered about a dozen thick rubber pieces) SET RK-LGLV IN STA.# 5 @ 3,329' MD LRS PERFORMED MULTIPLE PASSING MIT-T TO 3,500psi & 3,600psi (see lrs log for details) PULLED STA.# 1 & 2 RK-DGLV FROM 7,290 & 6,617' MD ***CONTINUE ON 6-3-23 WSR*** Daily Report of Well Operations PBU S-32A 6/2/2023 T/I/O= 190/139/24 (RWO CAPITAL) MIT-T to 3,600 psi *****PASSED***** Max Applied Pressure= 3,650 psi Pumped 10.45 bbls of Diesel to pressure TBG up to 2645 psi. 1st 15-minute loss of 17 psi, 2nd 15-minute loss of 15 psi, 3rd 15-minute loss of 13 psi, for a total loss of 45 psi in 45 minutes. Bled back ~5.34 bbls. SL in control of well upon departure. FWHPs= 505/495/25 6/3/2023 ***CONTINUE ON FROM 6-2-23 WSR*** PULL 1-1/2" RK-DMY GLV FROM STA #3 @ 5,705' MD PULL 1-1/2" RK-DMY GLV FROM STA #4 @ 4,532' MD SET 1-1/2" RK-LGLV (16/64" ports, 1583# tro) IN STA #4 @ 4,532' MD SET 1-1/2" RK-LGLV (16/64" ports, 1533# tro) IN STA #3 @ 5,705' MD SET 1-1/2" RK-LGLV (16/64" ports, 1489# tro) IN STA #2 @ 6,617' MD SET 1-1/2" RK-OGLV (24/64" ports) IN STA #1@ 7,290' MD PULL 4-1/2" RHC FROM X-NIPPLE @ 7,421' MD ***WELL LEFT S/I ON DEPARTURE, PAD OP NOTIFIED ON WELL STATUS*** 6/4/2023 ***BEGIN JOB. WELL SHUT IN ON ARRIVAL*** RIG UP PERFORATING RUN 1 7557' TO 7590' PERFORATING RUN 2 7524' TO 7557' CORRELATED TO SLB CNL DATED 20-NOV-1990 CORRELATION APPROVAL GRANTED GEOLOGIST S. WAGNER RIG DOWN ***END WSR. WELL LEFT SI ON DEPARTURE**** PERFORATING RUN 1 7557' TO 7590' PERFORATING RUN 2 7524' TO 7557' The adperfs are correctly shown on the new WBS, below. -WCB 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in thes pool? Will planned perforations require a spacing exception?Yes No 11. Total Depth MD (ft):Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size:Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStrastigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other: Post Initial Injection MIT Req'd? Spacing Exception Required?Yes Yes No No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER Conductor Surface Intermediate Production Liner 2260 4760 5410 10530 Structural Date: Current Pools:Proposed Pools: Comm.Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 10/2022 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov April 11, 2023 MGR11MAY23 DSR-4/13/23 BOPE test to 3000 psi. Annular to 2500 psi. CBL to AOGCC immediately upon completion. State witness of pressure test (MIT-T to 2500 psi) and slick line tag of cement (TOC ~9825' MD) of reservoir abandonment plug. Perforate New Pool 10-404 SFD 4/24/2023JLC 5/12/2023 GCW 05/12/23 5/12/2023 Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.05.12 10:40:11 -08'00' RBDMS JSB 051523 Recomplete to Kuparuk Well: S-32A PTD: 212-082 Well Name:S-32A API Number:50-029-22099-01 Current Status:Producer SI Estimated Start Date:5/10/2023 Rig:Thunderbird #1 Sundry #?323-032 / TBD Date Reg. Approval Rec’vd:02/03/2023 / TBD Regulatory Contact:Abbie Barker Permit to Drill Number:212-082 First Call Engineer:Claire Mayfield (907) 564-4375 (O)(713)443-3631 (M) Second Call Engineer:Brodie Wages (907) 564-5006 (O)(713) 380-9836 (M) Current Bottom Hole Pressure:3509 psi @ 8800 TVD 7.7 PPG | (9/26/2012 static) 8.1 PPG with 2500’ freeze protect Max. Anticipated Surface Pressure:2629 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:580 psi (Taken on 10/1/2021) Min ID:2.377” at 9955’ MD XO Max Angle:96 Deg @ 10,990’ MD 70 deg: 10250’ MD High DLS from 10160-10300’ MD Formation Tops: Kuparuk: 7522 MD, 6740 TVD Kingak: 8648 MD, 7651TVD Sag: 10090 MD, 8804TVD Shublik: 10150 MD, 8848TVD Sadlerochit: 10260 MD, 8897 TVD MITs: MIT-T: 2000 psi on 10/2/2015 MIT-IA: 2500 psi on 4/20/2012 Brief Well Summary: The Kuparuk interval of S-32A is located near two no-flow boundaries in a relatively low recovery factor area of the Kuparuk and should increase and/or accelerate oil production of the zone. The Sag/Ivishak completion of S-32A is not competitive and has been shut in for several years, so the reservoir will be abandoned prior to the recomplete. A RWO is planned to pull and re-run the tubing, setting a production packer above the Kuparuk and proceed with a frac treatment if water cut is low. S-32 and S-32A History: S-32 was originally drilled in 1990. The 17-1/2” surface hole was drilled to 2700’, 13-3/8” casing was set and cemented with 3722 cu ft of ASIII and II. A 12-1/4” hole was drilled to 10104’; the 9-5/8” casing was installed to 10099’ and cemented with 2078 cu ft of Class G. The 9-5/8” casing pressure tested to 3000psi, the shoe was drilled out and the 8-1/2” hole was drilled to TD at 10690’. A RFT log was run, then the 7” liner was run in hole and cemented with 332 cu. Ft of Class G cement. They tested the casing and liner, then ran the 4-1/2” tubing, set the tubing packer, and tested tubing to 2500psi before rigging down. The well was completed as a Zone 4 Ivishak producer. Itwasshut in most of the time since 2002 due to low oil production,and littlewell work options remaining. S-32A drilling commenced on September 2, 2012 to target upper Zone 4 Ivishak in two ESE-WNW oriented fault blocks.Before milling the window, significant losses initially experienced were mitigated with a cement squeeze. Then the window was milled from 10,113’ to 10,121’ MD, with new formation / rat hole drilled to a depth of 10,131’ MD. Drilling proceeded through fault # 1, encountered at 10,400’ MD with no significant increase in losses (20-30bph throughout). Drilling continued, moving upward after encountering wet rock on logs and back downward after encountering the TSAD, drilling past the 45N into 45P reservoir to TD. The liner was run and reservoir will be abandoned prior to the recomplete. Recomplete to Kuparuk Well: S-32A PTD: 212-082 cemented with 25.8 bbls cement pumped and estimated 20.6 bbls behind pipe. After several cleanout runs, the liner lap tested and failed, then the liner was perf’d on the rig. After CTD RDMO, SL installed a liner top packer. Notes Regarding Wellbore Condition 11/17/2002 CMIT-TxIA Passed to 2400 psi 7/8/2004 MITOA to 2400 psi - Pass 10/25/2008 Caliper 267 jts 0-10%, run DGLV's MIT-IA Passed to 2400 psi 4/16/2009 MIT-IA Passed to 2500 psi 3/8/2009 LDL found packer leak at 9832' LLR 0.14gpm @ 3000psi on IA 5/31/2009 Conductor Treated with 3.4 gal RG-2401 11/7/2009 Set TTP @ 9826", Pull DGLV STA #1, MIT-T Passed to 2500 psi 11/14/2009 Sealtite treatment -IC 12/7/2009 LGLVs in Sta # 5, 4, & 3, pulled TTP 12/8/2009 SL Set Rock screen @ 9900' 12/31/2009 Seal-Tite treatment IC 9/1/2011 SL Pulled Rock screen @ 9900' 4/20/2012 SL Set DGLV's, MIT-IA Passed to 2500 psi, MIT-OA Passed to 2000 psi 7/27/2012 PPPOT-T Passed to 5000 psi 9/18/2012 CTD drilled, completed S-32A 9/26/2012 SL Set LTP @ 9855', MIT-T to 2500 psi Passed 9/27/2012 SL Set LGLVs in GLM #s 5, 4, & 3, Set OGLV in GLM # 1 11/25/2012 PPPOT-IC Passed 6/27/2013 Seal-Tite treatment IC 2/16/2015 PPPOT-T Passed to 5000 psi, PPPOT-IC Passed to 3500 psi, LDS ok 9/30/2015 Set PX Plug @ 9826' MD, MIT-T Passed to 2000 psi 10/1/2021 SL subsidence drift to 3000' The last caliper performed was 10/24/2008 and showed little to no wall loss <5% of the tubing. A second caliper can be performed pre-RWO to determine re-usability of the tubing. Objective: Abandon Ivishak & Sag, Recomplete to Kuparuk Pre-Rig 1. Obtain updated pressure tests on WH seals Slickline & Fullbore 1. Drift, broach scale as needed Completed 2/28. 2. Load tbg & IA with 1% KCl + Freeze protect Completed 2/28. a. Total IA volume to St#1: 524 bbls b. Freeze protect volume to 2500’: 171 bbls 3. Dummy GLVs.Completed 2/28. Abandon Ivishak & Sag,Recomplete to Kuparuk Recomplete to Kuparuk Well: S-32A PTD: 212-082 4. Obtain 2500 psi MIT-IA (ensure all DGLV’s set); MIT-IA to 3500psi to test existing production packer** discuss results with OE.Completed, passed MIT-IA to 2500 3/1/23 and initially failed 3500psi MIT-IA, but was leaking through LDS. Tightened LDS and subsequent MIT-IA to 3500psi passed on 3/2/23. a. Note: in 2009, LDL found production packer leaked at 3000psi. But in 2012, cement was pumped pre-CTD past the tubing tail and may have isolated the tubing tail from the window/reservoir. (~100ft cement between tubing tail and window) 5. Pull X plug (if not already pulled)completed 1/21/22. 6. Pull LTP @ 9854 –attempted 1/21/22, unable to unseat. Aligned with state to cement over LTP. 7. Run caliper from liner top to surface.Completed 2/27. Contingent Eline Step** -not needed since MIT-IA passed. 8. If MIT-IA to 2500 passes but MIT-IA to 3500 fails, EL punch holes in tubing tail @ 9850 (below production packer, above liner top) – this will allow reservoir P&A to prevent the potential outstanding packer leak when DP > 3000psi (LDL in 2009). Fullbore 9. Injectivity test with KCL pre-Fullbore P&A.Completed 3/23/23. a. Bullhead 205bbls of 1%KCL or SW down the TBG into formation i. Note pressures and rates ii. Max pressure ~2,500psi b. Freeze protect with 38bbls of diesel c. Send rate/pressure information to OE for final cement design d. Note IA pressure during pumping operations Well Support – Prep Tree and WH for P&A work.Completed 3/29/23. 1. Secure wellbore with tubing hanger plug or check valve 2. Pull production tree 3. Install dry hole tree for P&A work; pressure test tree. 4. Drop IA casing valves and install integral valves 5. Pull tubing hanger ----------------------------------------------Sundry Required Before Proceeding-------------------------------------------------- Fullbore P&A of Ivishak completion: 1. Pump Reservoir abandonment plug per schedule below, Planned TOC is 9825’, in the confining zone above the Sag River formation. Hold back pressure on IA to reduce DP across TxIA.Completed 4/8/23. Estimated TOC 9825’MD. a. 5bbls meth spear b. 10bbls fresh water spacer c.14.3 bbls 14ppg class G cement d. 5 bbls fresh water spacer e. Foam wiper ball f.145 bbls diesel displacement – Hot i.(Maximum 145 bbls to get TOC target, minimum 125bbl to avoid kuparuk) 2. Note pressure after shutting down pump, do not bleed WHP after cement is in place 3. Max treating pressure during cement job is 3,500 psi 4. Before starting the cement job confirm displacement pump metering accuracy to avoid over/under displacing cement. Recomplete to Kuparuk Well: S-32A PTD: 212-082 Slickline: 1. WOC. Drift and tag TOC ~9825’MD a. Notify AOGCC 24 hours in advance 2. MIT-T to 2,500psi a. Use calibrated crystal gauge for MIT Eline 1. Cut tubing @ ~9750’ MD (or ~50’ above tag)with mechanical or jet cutter a. Likely between GLM #1 and #2 Pre-RWO*Note: Depending on timing of rig move, well kill and BOP installation steps may be performed on rig rather than pre-rig. 1. Spot Pump Truck, RU and PT. a. Circulate in at least 770 bbls of 1% KCl through tubing cut b. Annular Volume to cut:521 bbls c. Tubing Volume to cut:148 bbls d. Total volume to cut:670 bbls 2. RDMO pumpers 3. RD well house and flowlines. Clear and level area around well. 4. Set BPV w/insert (TWC) and test. ND Dry Hole Tree and THA. 5. NU BOPE configured top down: Annular, 2-7/8” x 5-1/2” VBRs, Blinds and integral flow cross. RWO Procedure: 1. MIRU Thunderbird 1 workover rig and ancillary equipment 2. Bleed TBG/IA pressures to ~0psi. Kill well w/1% KCl as needed. 3. Test BOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “Thunderbird 1 Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram and Annular on 4-1/2’.No plans to run workstring. If workstring run required, repeat Step 3 BOP test with 2-7/8” joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Pull TWC insert and BPV. a. Utilize lubricator for BPV removal if potential for trapped pressure exists. 5. MU landing joint or spear, BOLDS and PU on the tubing hanger. Recomplete to Kuparuk Well: S-32A PTD: 212-082 a.~9750’of 4-1/2” 12.6# tubing weighs ~106klbs(buoyed by 8.4 ppg fluid) b. If pulled up to 230 Klbs (80% of 4-1/2” yield strength) with no hanger movement, RU eline and perform 2nd tubing cut in cut window, discuss with OE. 6. POOH and lay down the 4-1/2” tubing. a. Save tubing for re-run if possible; discard joints with visible defects or damaged threads 7. RU Eline 8. Wellhead/Valve Shop: Replace IC seals while tubing is out of well. Failed PPPOTs after multiple seal- tite treatments. 9. Eline Pull CBL from tubing stub to surface to verify cement quality over Kuparuk interval a. Send copy of log to claire.mayfield@hilcorp.com b. Send copy of log with vendor TOC interpretation to AOGCC (Melvin.rixse@alaska.gov) c. If no cement, work with OE for plan forward, very likely will run kill string 10. PU 4-1/2” completion (re-using original 13Cr tubing if possible) and run per S-32A Proposed Completion Running Order. a. Load IA with inhibited KWF brine b. Land tubing with mule shoe/WLEG @ ~7414’ a. Packer must be within 200’ of top perf. (Kuparuk top ~7524’ MD) c. Ensure RHC plug body pre-installed in lowermost X profile 11. Land the tubing hanger and RILDS. Lay down landing joint. Note Pick-up and slack-off weights on tally. 12. Drop ball and rod and hydraulically set the packer per manufacturer’s setting procedure a. Conduct MIT-T to 3500 psi and MIT-IA to 3,500 psi for 30 mins (charted, state witnessed) 13. Shear circ valve in shallow GLM and circ freeze protect. 14. Bleed tubing pressure back to ~0 psi. Set BPV with TWC insert. 15. RDMO Thunderbird WO Rig and ancillary equipment. Move to next well location. 16. RU crane. ND BOPE. 17. NU the tubing head adapter and production tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 18. Pull BPV with TWC insert. 19. Replace wellhouse and gauge(s) if removed. Post-Rig Procedure: Slickline 1. Spot Slickline unit, RU and PT. 2. RIH and pull RHC plug from X profile at ±6680’ MD 3. MIT-T to 3,500psi a. Discuss with OE possible dump of 20-40 sand on top of tubing stub to cover old packer if MIT issues 4. Install LGLVs per GL engineer Eline 5. Perforate per geologist a. Charges will be 2-7/8” MaxForce or similar b. 6 SPF CBL f to verify cement quality over Kuparuk interval (Kuparuk top ~7524’ MD) Recomplete to Kuparuk Well: S-32A PTD: 212-082 c. 60 deg Phasing 6. RDMO and turn well over to operations. Operations 7. POP well 8. Obtain AOGCC witnessed SVS test within 5 days of putting well online. NOTE: A separate frac sundry and program will be submitted. This program only covers the RWO. Details to be included in future frac program that will require a frac sundry: 1. Slickline dummy GLVs, load hole with 1% KCl and freeze protect, obtain 3500 psi MIT-T and MIT-IA 2. Special Projects frac well 3. Contingent post frac coil FCO 4. Slickline install LGLVs 5. Well testers POP well for frac flowback 6. Handover to OPs Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3.Thunderbird 1 BOP Stack 4. Sundry Change form Recomplete to Kuparuk Well: S-32A PTD: 212-082 Current WBD: Recomplete to Kuparuk Well: S-32A PTD: 212-082 Proposed WBD: Recomplete to Kuparuk Well: S-32A PTD: 212-082 Thunderbird 1 BOP Schematic Hilcorp North Slope, LLCHilcorp North Slope, LLCChanges to Approved Rig Work Over Sundry Procedure CAUTION: This email originated from outside the State of Alaska mail system. Do not click links or open attachments unless you recognize the sender and know the content is safe. From:Regg, James B (OGC) To:AOGCC Records (CED sponsored) Subject:FW: UNDER EVALUATION: Producer S-32A (PTD# 2120820) Evaluate Seal-Tite repair Date:Saturday, February 18, 2023 7:24:05 PM Attachments:S-32A wellbore schematic.pdf S-32A TIO 03-23-13.docx Jim Regg Supervisor, Inspections AOGCC 333 W. 7th Ave, Suite 100 Anchorage, AK 99501 907-793-1236 From: PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Sent: Friday, February 17, 2023 2:04 PM To: Regg, James B (OGC) <jim.regg@alaska.gov> Cc: Wallace, Chris D (OGC) <chris.wallace@alaska.gov>; Stan Golis <sgolis@hilcorp.com>; Oliver Sternicki <Oliver.Sternicki@hilcorp.com>; PB Wells Integrity <PBWellsIntegrity@hilcorp.com> Subject: UNDER EVALUATION: Producer S-32A (PTD# 2120820) Evaluate Seal-Tite repair Mr. Regg, Producer S-32A (PTD #2120820) was made Not Operable in 2013 for unmanageable IAxOA communication via well head seals. A Seal-Tite treatment of the IC packoffs was performed in June of 2013. However, the well was never brought online to test the effectiveness of the treatment due to a bad surface kit. The well is now ready to be brought online and will be classified as UNDER EVALUATION to monitor for unmanageable IAxOA communication. Plan forward: 1. Portable Test Unit: POP well, monitor for unmanageable IAxOA communication 2. DHD: PPPOT-IC 3. Well Integrity: Additional diagnostics as needed Please respond with any questions. Andy Ogg Hilcorp Alaska LLC Field Well Integrity andrew.ogg@hilcorp.com P: (907) 659-5102 M: (307)399-3816 _____________________________________________ From: AK, D&C Well Integrity Coordinator Sent: Sunday, April 7, 2013 9:01 AM To: AK, OPS GC2 OSM <AKOPSGC2OSM@bp.com>; AK, OPS GC2 Field O&M TL <AKOPSGC2FieldOMTL@BP.com>; AK, OPS GC2 Wellpad Lead <AKOPSGC2WellpadLead@bp.com>; AK, OPS Prod Controllers <AKOPSProdControllers@bp.com>; Cismoski, Doug A <CismosDA@BP.com>; Daniel, Ryan <Ryan.Daniel@bp.com>; AK, D&C Wireline Operations Team Lead <AKDCWirelineOperationsTeamLead@BP.com>; AK, D&C Well Services Operations Team Lead <AKDCWellServicesOperationsTeamLead@BP.com>; AK, RES GPB West Wells Opt Engr <AKRESGPBWestWellsOpt@BP.com>; AK, RES GPB East Wells Opt Engr <AKRESGPBEastWellsOptEngr@bp.com>; 'jim.regg@alaska.gov' <jim.regg@alaska.gov>; 'Schwartz, Guy L (DOA)' <guy.schwartz@alaska.gov>; Weiss, Troy D <Troy.Weiss@bp.com>; Glasheen, Brian P <Brian.Glasheen@bp.com>; AK, OPS WELL PAD S <AK_OPSWELLPADS@bp.com> Cc: AK, D&C DHD Well Integrity Engineer <AKD&CDHDWellIntegri@bp.com>; AK, D&C Well Integrity Coordinator <AKDCWellIntegrityCoordinator@bp.com>; Holt, Ryan P <Ryan.Holt@bp.com>; Arend, Jon <Jon.Arend@bp.com>; Sayers, Jessica <Jessica.Sayers@bp.com> Subject: NOT OPERABLE: Producer S-32A (PTD# 2120820) Sustained OA Casing Pressure Not Manageable by Bleeds All, Producer S-32A (PTD #2120820) OA repressurizes when the well is shut in, and is not manageable by bleeds. A passing TIFL was performed on 04/06/2013 that confirms tubing integrity. The well is reclassified as Not Operable until the IA x OA communication is repaired and barriers confirmed. Plan forward: 1. APE to evaluate for Seal-Tite repair Please call with any questions. Jack Disbrow (Alternate: Laurie Climer) BP Alaska - Well Integrity Coordinator Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinator@bp.com _____________________________________________ From: AK, D&C Well Integrity Coordinator Sent: Saturday, March 23, 2013 8:17 AM To: ''Regg, James B (DOA)' (jim.regg@alaska.gov)'; ''Schwartz, Guy L (DOA)' (guy.schwartz@alaska.gov)'; Cismoski, Doug A; Daniel, Ryan; AK, D&C Well Services Operations Team Lead; AK, D&C Wireline Operations Team Lead; AK, OPS Prod Controllers; AK, OPS GC2 OSM; AK, OPS GC2 Ops Lead; AK, OPS GC2 Wellpad Lead; AK, OPS GC2 Field O&M TL; AK, RES GPB West Wells Opt Engr; AK, OPS Well Pad SW; Derrick, Mackie; Glasheen, Brian P Cc: AK, D&C DHD Well Integrity Engineer; Climer, Laurie A Subject: UNDER EVALUATION: Producer S-32A (PTD# 2120820) OA exceeded MOASP All, Producer S-32A (PTD# 2120820) has sustained casing pressure on the OA above MOASP on 03/22/13. The TBG/IA/OA pressures were equal to 320/1900/1490 psi. A passing PPPOT-IC was performed on 11/25/12. At this time the well has been reclassified as Under Evaluation and may remain online for further diagnostics. The plan forward: 1. DHD: warm Outer Annulus Repressurization Test (OART) to determine if manageable by bleeds 2. WIE: Evaluate for Seal-Tite treatment pending results of OART Attached are a TIO plot and wellbore schematic for reference. Please call if you have any questions. Regards, Laurie Climer (Alternate: Jack Disbrow) BP Alaska - Well Integrity Coordinator WIC Office: 907.659.5102 WIC Email: AKDCWellIntegrityCoordinator@BP.com ________________________________ The information contained in this email message is confidential and may be legally privileged and is intended only for the use of theindividual or entity named above. If you are not an intended recipient or if you have received this message in error, you are herebynotified that any dissemination, distribution, or copy of this email is strictly prohibited. If you have received this email in error, pleaseimmediately notify us by return email or telephone if the sender's phone number is listed above, then promptly and permanently deletethis message. While all reasonable care has been taken to avoid the transmission of viruses, it is the responsibility of the recipient to ensure that the onward transmission, opening, or use of this message and any attachments will not adversely affect its systems or data. No responsibility is accepted by the company in this regard and the recipient should carry out such virus and other checks as it considers appropriate. ________________________________ 4-1116' GW NFLLHFAD= FMC ACTIATOR= OTS MNL KB. aEV = 64.53' 2800' 36.63' KOP= 3104 Max Angle = 36' 010990' Datum NO 10176' Datum TVD= Baou, ss 20' CONUXTOR 7 13-30' CSG, 68#. M-80, D = 12.415' 2685' Minimum ID = 2.377" @ 9955' 3-3116 X 2-718" XO TOP OF TMV 7- LNR 1-� 9BSO' 4-112" TBG, 126k, Nr13-CR-80 TDS, - 913' 9 .0152 bpf, Note.- Refer to Production DB for historical perf data 3-112' LNR, 9.31f, L-80 STL, 0087 bpf, D = 2 992" 9955' 9-518" CSG, 4711, NT -80S NSCC, D = 8 681' '10099' SHOT SO7 4112" 13M WHPSTOCK (TAGGED 09103112) 10109' PERFORATION SUMMARY REFLOG: SLB MEN! GRI CCi1CTL ON 09/15/12 ANGLE AT TOP PERF. 81' 0107W Note.- Refer to Production DB for historical perf data SIZE SPF INTT3ZVAL Opn/Sqz SHOT SO7 2" 6 10700 - 10750 O 09/15/12 PK 2' 6 10770 - 10790 O 09115/12 39 2" 6 11065 - 11085 O 09115/12 3 2" 6 11250 - 11300 O 09115/12 RK 2" 6 11470 - 11580 O 09/15/12 36 2" 6 11700 -11730 O 09115/12 1 12-718" LNR, 6.5#. 13CR-BO STL, .0058 bpf, D= 2.441" 1--1 11845' S -32A SAFETY NOTE: WELL ANGLE> 70 @ 10990' CHROME TBG & LNR - DO NOT ACIDIZE ""' I 2102' I—I4-112" OTIS SSSV NP, ID= 3 813" 1 [eS1"aaIT, '_12 EN 1161 ST MD TVD DEV TYPE VLV LATCH PORT DATE 5 3107 310D 9 CAMEO DOME PK 16 09127!72 4 5551 5193 39 CAMCO DOME RK 16 09127/12 3 7719 6998 37 CAMDD DOME RK 16 09127/12 2 9462 8309 36 CAMDO DMf RK 0 04/19/97 1 9798 8576 39 CAMEO 50 RK 24 09127112 f 9826' Ij4-112"PARKHRSWSNP,D=3.813" 4-112" PARKERSWS NP, D= 3.813' 9901' 4111"PARKER SWN NF, BEHIND 9630• RIGHTHANDREI-EASE 9632' 9-518"X4-112"TNV H0RD=3.99" 9864' 4-1/2- KR LNR TOP PIDRD=238" 9855' 3.370" DEPLOY SLV, D= 3.110" 96fi0' 9-518'X7"TNVLNRTOPr-KRASSY 9876' 3-112" HES X NP, D = 2.813" 9680' 4-112" PARKERSWS NP, D= 3.813' 9901' 4111"PARKER SWN NF, BEHIND 09/18!12 NOMC CTDSIDETRACK(S-32A) MILLED TO 380"(0783112) CT LNR 9913' 4112" WILEG, ID = 3.958 9902' ELMDTTLOGGID02108192 9955' 1 3-112" X 33116' XO, D = 2786' MILLOUT WINDOW (S -32A) 10113' - 10121' 10994' 33116 X 2-718- XO, D = 2.377' DATE REV BY COMMENTS DATE REV BY COMMB4T5 12/21190 N18E ORIGINALCOMPLEr1ON 09/18!12 NOMC CTDSIDETRACK(S-32A) 09118112 PJC DRLG DRAFT CORRECTIONS 0926112 MSSIPJC SET LTP(09126112) 09127/12 MSSIPJC GLV 00 (09127112) 01127/13 RR/ PJC FINAL DRLG CORRECTIONS PRUDHOE BAY IMF WR-LS-32A PERMIT M-'2120820 AH No.: 50-029-22099-01 SEC 35. T12N. T12E 1643' FNL 8 1705' FWL BP Exploration (Alaska) S-38A (PTD# 2120820) TIO Plot 03/23/2013 7. If perforating: 1. Type of Request: 2. Operator Name: 3. Address: 4. Current Well Class:5. Permit to Drill Number: 6. API Number: 8. Well Name and Number: 9. Property Designation (Lease Number):10. Field: Abandon Suspend Plug for Redrill Perforate New Pool Perforate Plug Perforations Re-enter Susp Well Other Stimulate Fracture Stimulate Alter Casing Pull Tubing Repair Well Other: Change Approved Program Operations shutdown What Regulation or Conservation Order governs well spacing in thes pool? Will planned perforations require a spacing exception?Yes No 11. Total Depth MD (ft): Total Depth TVD (ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): PRESENT WELL CONDITION SUMMARY Perforation Depth MD (ft): Perforation Depth TVD (ft):Tubing Size: Tubing Grade: Tubing MD (ft): Packers and SSSV Type:Packers and SSSV MD (ft) and TVD (ft): Casing Length Size MD TVD Burst Collapse Exploratory Stratigraphic Development Service 12. Attachments: 14. Estimated Date for Commencing Operations: 13. Well Class after proposed work: 15. Well Status after proposed work: 16. Verbal Approval: 17. I hereby certify that the foregoing is true and the procedure approved herein will not be deviated from without prior written approcal. Proposal Summary Wellbore schematic BOP SketchDetailed Operations Program OIL GAS WINJ WAG GINJ WDSPL GSTOR Op Shutdown Suspended SPLUG Abandoned ServiceDevelopmentStrastigraphicExploratory Authorized Name and Digital Signature with Date: Authorized Title: Contact Name: Contact Email: Contact Phone: AOGCC USE ONLY Commission Representative: Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Location ClearanceMechanical Integrity TestBOP TestPlug Integrity Other: Post Initial Injection MIT Req'd? Spacing Exception Required?Yes Yes No No Subsequent Form Required: Approved By:Date: APPROVED BY THE AOGCCCOMMISSIONER PBU S-32A Recomplete to Aurora Hilcorp North Slope, LLC 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 212-082 50-029-22099-01-00 341J / 457B ADL 0028257 11848 Conductor Surface Intermediate Production Liner 8987 80 2657 10071 253 1990 9826 20" 13-3/8" 9-5/8" 7" 3-1/2" x 3-1/4" x 2-7/8" 8598 34 - 114 33- 2685 31- 10099 9860 - 10113 9855 - 11845 2629 34 - 114 28 - 2685 28 - 8810 8264 - 8821 8621 - 8987 None 2260 4760 5410 10530 9826 5020 6870 7240 10160 10700 - 11730 4-1/2" 12.6# 13Cr80 28 - 99138929 - 8977 Structural 4-1/2" TIW Packer No SSSV Installed 9832, 8603 Date: Stan Golis Sr. Area Operations Manager Claire Mayfield Claire.Mayfield@hilcorp.com 907-564-4375 PRUDHOE BAY 3/15/23 Current Pools: PRUDHOE OIL Proposed Pools: Aurora Oil STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 Comm. Comm.Sr Pet Eng Sr Pet Geo Sr Res Eng Form 10-403 Revised 10/2022 Approved application is valid for 12 months from the date of approval.Submit PDF to aogcc.permitting@alaska.gov By Meredith Guhl at 9:42 am, Jan 20, 2023 323-032 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2023.01.20 08:52:41 -09'00' Stan Golis (880) X DLB 01/24/2023 DSR-1/20/23 * State witness of pressure test (MIT-T to 2500 psi) and slick line tag (TOC ~9825' MD of reservoir abandonment plug. * BOPE test to 3000 psi. Annular to 2500 psi. 10-404 2629 MGR02FEB23GCW 02/03/23JLC 2/3/2023 02/03/2023Brett W. Huber, Sr. Digitally signed by Brett W. Huber, Sr. Date: 2023.02.03 10:37:31 -09'00' RBDMS JSB 020723 Recomplete to Kuparuk Well: S-32A PTD: 212-082 Well Name:S-32A API Number:50-029-22099-01 Current Status:Producer SI Estimated Start Date:3/15/2023 Rig:Nordic #3 Sundry #?XXX-XXX Date Reg. Approval Rec’vd: Regulatory Contact:Abbie Barker Permit to Drill Number:212-082 First Call Engineer:Claire Mayfield (907) 564-4375 (O)(713) 443-3631 (M) Second Call Engineer:Brodie Wages (907) 564-5006 (O)(713) 380-9836 (M) Current Bottom Hole Pressure:3509 psi @ 8800 TVD 7.7 PPG | (9/26/2012 static) 8.1 PPG with 2500’ freeze protect Max. Anticipated Surface Pressure:2629 psi (Based on 0.1 psi/ft. gas gradient) Last SI WHP:580 psi (Taken on 10/1/2021) Min ID:2.377” at 9955’ MD XO Max Angle:96 Deg @ 10,990’ MD 70 deg: 10250’ MD High DLS from 10160-10300’ MD Formation Tops: Kuparuk: 7522 MD, 6740 TVD Kingak: 8648 MD, 7651TVD Sag: 10090 MD, 8804TVD Shublik: 10150 MD, 8848TVD Sadlerochit: 10260 MD, 8897 TVD MITs: MIT-T: 2000 psi on 10/2/2015 MIT-IA: 2500 psi on 4/20/2012 Brief Well Summary: The Kuparuk interval of S-32A is located near two no-flow boundaries in a relatively low recovery factor area of the Kuparuk and should increase and/or accelerate oil production of the zone. The Sag/Ivishak completion of S-32A is not competitive and has been shut in for several years, so the reservoir will be abandoned prior to the recomplete. A RWO is planned to pull and re-run the tubing, setting a production packer above the Kuparuk and proceed with a frac treatment if water cut is low. S-32 and S-32A History: S-32 was originally drilled in 1990. The 17-1/2” surface hole was drilled to 2700’, 13-3/8” casing was set and cemented with 3722 cu ft of AS III and II. A 12-1/4” hole was drilled to 10104’; the 9-5/8” casing was installed to 10099’ and cemented with 2078 cu ft of Class G. The 9-5/8” casing pressure tested to 3000psi, the shoe was drilled out and the 8-1/2” hole was drilled to TD at 10690’. A RFT log was run, then the 7” liner was run in hole and cemented with 332 cu. Ft of Class G cement. They tested the casing and liner, then ran the 4-1/2” tubing, set the tubing packer, and tested tubing to 2500psi before rigging down. The well was completed as a Zone 4 Ivishak producer. Itwasshut inmost of the time since 2002 due to low oil production,and littlewell work options remaining. S-32A drilling commenced on September 2, 2012 to target upper Zone 4 Ivishak in two ESE-WNW oriented fault blocks. Before milling the window, significant losses initially experienced were mitigated with a cement squeeze. Then the window was milled from 10,113’ to 10,121’ MD, with new formation / rat hole drilled to a depth of 10,131’ MD. Drilling proceeded through fault # 1, encountered at 10,400’ MD with no significant increase in losses (20-30bph throughout). Drilling continued, moving upward after encountering wet rock on logs and back downward after encountering the TSAD, drilling past the 45N into 45P reservoir to TD. The liner was run and 2629 psi -00 DLB so the reservoir will be abandoned prior to the recomplete. A Recomplete to Kuparuk Well: S-32A PTD: 212-082 cemented with 25.8 bbls cement pumped and estimated 20.6 bbls behind pipe. After several cleanout runs, the liner lap tested and failed, then the liner was perf’d on the rig. After CTD RDMO, SL installed a liner top packer. Notes Regarding Wellbore Condition 11/17/2002 CMIT-TxIA Passed to 2400 psi 7/8/2004 MITOA to 2400 psi - Pass 10/25/2008 Caliper 267 jts 0-10%, run DGLV's MIT-IA Passed to 2400 psi 4/16/2009 MIT-IA Passed to 2500 psi 3/8/2009 LDL found packer leak at 9832' LLR 0.14gpm @ 3000psi on IA 5/31/2009 Conductor Treated with 3.4 gal RG-2401 11/7/2009 Set TTP @ 9826", Pull DGLV STA #1, MIT-T Passed to 2500 psi 11/14/2009 Sealtite treatment -IC 12/7/2009 LGLVs in Sta # 5, 4, & 3, pulled TTP 12/8/2009 SL Set Rock screen @ 9900' 12/31/2009 Seal-Tite treatment IC 9/1/2011 SL Pulled Rock screen @ 9900' 4/20/2012 SL Set DGLV's, MIT-IA Passed to 2500 psi, MIT-OA Passed to 2000 psi 7/27/2012 PPPOT-T Passed to 5000 psi 9/18/2012 CTD drilled, completed S-32A 9/26/2012 SL Set LTP @ 9855', MIT-T to 2500 psi Passed 9/27/2012 SL Set LGLVs in GLM #s 5, 4, & 3, Set OGLV in GLM # 1 11/25/2012 PPPOT-IC Passed 6/27/2013 Seal-Tite treatment IC 2/16/2015 PPPOT-T Passed to 5000 psi, PPPOT-IC Passed to 3500 psi, LDS ok 9/30/2015 Set PX Plug @ 9826' MD, MIT-T Passed to 2000 psi 10/1/2021 SL subsidence drift to 3000' The last caliper performed was 10/24/2008 and showed little to no wall loss <5% of the tubing. A second caliper can be performed pre-RWO to determine re-usability of the tubing. Objective: x Abandon Ivishak & Sag, Recomplete to Kuparuk Procedure: Pre-Rig – 1. Obtain updated pressure tests on WH seals Slickline & Fullbore 1. Drift, broach scale as needed 2. Load tbg & IA with 1% KCl + Freeze protect a. Total IA volume to St#1: 524 bbls b. Freeze protect volume to 2500’: 171 bbls 3. Dummy GLVs 4. Obtain 2500 psi MIT-IA (ensure all DGLV’s set) Recomplete to Kuparuk Well: S-32A PTD: 212-082 5. Pull X plug (if not already pulled) 6. Pull LTP @ 9854 7. Run caliper from liner top to surface. 8. Punch holes in tubing tail @ 9850 (below production packer, above liner top) – this will allow reservoir P&A to prevent the potential outstanding packer leak when DP > 3000psi (LDL in 2009). 9. Injectivity test with KCL pre-Fullbore P&A a. Bullhead 205bbls of 1%KCL or SW down the TBG into formation i. Note pressures and rates ii. Max pressure ~2,500psi b. Freeze protect with 38bbls of diesel c. Send rate/pressure information to OE for final cement design d. Note IA pressure during pumping operations Well Support – Prep Tree and WH for P&A work 1. Pull production tree 2. Install dry hole tree for P&A work 3. Drop IA casing valves and install integral valves ----------------------------------------------Sundry Required Before Proceeding-------------------------------------------------- Fullbore P&A of Ivishak completion: 1. Pump Reservoir abandonment plug per schedule below, Planned TOC is 9825’, in the confining zone above the Sag River formation. Hold back pressure on IA to reduce DP across TxIA. a. 5bbls meth spear b. 10bbls fresh water spacer c. 23.2bbls 14ppg class G cement d. 5 bbls fresh water spacer e. Foam wiper ball f. 145 bbls diesel displacement – Warm 2. Note pressure after shutting down pump, do not bleed WHP after cement is in place 3. Max treating pressure during cement job is 3,500psi 4. Before starting the cement job confirm displacement pump metering accuracy to avoid over/under displacing cement. Cement Type/weight:Class G 14 ppg Slurry Temperature:between 80° and 110°F Fluid Loss:20-100cc/30 min Compressive Strength: 1000 psi in 48 hrs. Thickening Time:Minimum 8 hours Slickline: 1. WOC. Drift and tag TOC ~9825’ a. Notify AOGCC 24 hours in advance 2. MIT-T to 2,500psi a. Use calibrated crystal gauge for MIT Prior to pulling tree, secure wellbore with tubing hanger plug or check valve. Pressure test tree. Pull tubing hanger plug. Recomplete to Kuparuk Well: S-32A PTD: 212-082 Eline 1. Cut tubing @ 9811 with mechanical cutter a. Midway in jt below GLM #1 Pre-RWO*Note: Depending on timing of rig move, well kill and BOP installation steps may be performed on rig rather than pre-rig. 1. Spot Pump Truck, RU and PT. a. Circulate in at least 775 bbls of 1% KCl through tubing cut b. Annular Volume to cut: 525 bbls c. Tubing Volume to cut: 134 bbls d. Total volume to cut: 674 bbls 2. RDMO pumpers 3. RD well house and flowlines. Clear and level area around well. 4. Set BPV w/insert (TWC) and test. ND Dry Hole Tree and THA. 5. NU BOPE configured top down: Annular, 2-7/8” x 5-1/2” VBRs, Blinds and integral flow cross. RWO Procedure: 1. MIRU Nordic 3 workover rig and ancillary equipment 2. Bleed TBG/IA pressures to ~0psi. Kill well w/1% KCl as needed. 3. Test BOPE to 250 psi Low/ 3,000 psi High, annular to 250 psi Low/ 2,500 psi High (hold each ram/valve and test for 5-min). Record accumulator pre-charge pressures and chart tests. a. Notify AOGCC 24 hours in advance of BOP test. b. Perform Test per “Nordic #3 Test Procedure” c. Confirm test pressures per the Sundry Conditions of approval. d. Test VBR ram and Annular on 4-1/2”No plans to run 4” workstring. If 4” workstring run required, repeat Step 3 BOP test with 4” joint. e. Submit to AOGCC completed 10-424 form within 5 days of BOPE test. 4. Pull TWC insert and BPV. a. Utilize lubricator for BPV removal if potential for trapped pressure exists. 5. MU landing joint or spear, BOLDS and PU on the tubing hanger. a. ~9811’ of 4-1/2” 12.6# tubing weighs ~ 108klbs (buoyed by 8.4 ppg fluid) b. If pulled up to 230 Klbs (80% of 4-1/2” yield strength) with no hanger movement, RU eline and perform 2nd tubing cut in cut window, discuss with OE. 6. POOH and lay down the 4-1/2” tubing. a. Save tubing for re-run if possible; discard joints with visible defects or damaged threads 7. RU Eline 8. Pull CBL from tubing stub to surface to verify cement quality over Kuparuk interval a. Send copy of log to claire.mayfield@hilcorp.com b. Send copy of log with vendor TOC interpretation to AOGCC c. If no cement, work with OE for plan forward, very likely will run kill string email: melvin.rixse@alaska.gov Recomplete to Kuparuk Well: S-32A PTD: 212-082 9. PU 4-1/2” completion (re-using original 13Cr tubing if possible) and run per S-32A Proposed Completion Running Order. a. Load IA with inhibited KWF brine b. Land tubing with mule shoe/WLEG @ ~7414’ a. Packer must be within 200’ of top perf. (Kuparuk top ~7524’ MD) c. Ensure RHC plug body pre-installed in lowermost X profile 10. Land the tubing hanger and RILDS. Lay down landing joint. Note Pick-up and slack-off weights on tally. 11. Drop ball and rod and hydraulically set the packer per manufacturer’s setting procedure a. Conduct MIT-T to 3500 psi and MIT-IA to 3,500 psi for 30 mins (charted, state witnessed) 12. Shear circ valve in shallow GLM and circ freeze protect. 13. Bleed tubing pressure back to ~0 psi. Set BPV with TWC insert. 14. RDMO Nordic 3 WO Rig and ancillary equipment. Move to next well location. 15. RU crane. ND BOPE. 16. NU the tubing head adapter and production tree. Test tubing hanger void and tree to 500 psi low/5,000 psi high. 17. Pull BPV with TWC insert. 18. Replace wellhouse and gauge(s) if removed. Post-Rig Procedure: Slickline 1. Spot Slickline unit, RU and PT. 2. RIH and pull RHC plug from X profile at ±6680’ MD 3. Dump ~30’ of 20-40 sand on top of tubing stub a. Packer to top of stub: ~21’ 4. After dumping all the sand, tag top of sand to verify fillup, dump more sand as needed. POH a. Top of sand should be right at/above the tubing stub 5. MIT-T to 3,500psi 6. Install LGLVs per GL engineer Eline 7. Perforate per geologist a. Charges will be 2-7/8” MaxForce or similar b. 6 SPF c. 60 deg Phasing 8. RDMO and turn well over to operations. Operations 9. POP well 10. Obtain AOGCC witnessed SVS test within 5 days of putting well online. Recomplete to Kuparuk Well: S-32A PTD: 212-082 NOTE: A separate frac sundry and program will be submitted. This program only covers the RWO. Details to be included in future frac program that will require a frac sundry: 1. Slickline dummy GLVs, load hole with 1% KCl and freeze protect, obtain 3500 psi MIT-T and MIT-IA 2. Special Projects frac well 3. Contingent post frac coil FCO 4. Slickline install LGLVs 5. Well testers POP well for frac flowback 6. Handover to Ops Attachments: 1. Current Wellbore Schematic 2. Proposed Wellbore Schematic 3. Nordic 3 BOP Stack 4. Sundry Change form Recomplete to Kuparuk Well: S-32A PTD: 212-082 Current WBD: Recomplete to Kuparuk Well: S-32A PTD: 212-082 Proposed WBD: Recomplete to Kuparuk Well: S-32A PTD: 212-082 Nordic Rig 3 BOP Schematic Hilcorp North Slope, LLCHilcorp North Slope, LLCChanges to Approved Rig Work Over Sundry ProcedureDate: January 19, 2023Subject: Changes to Approved Sundry Procedure for Well S-32ASundry #:Any modifications to an approved sundry will be documented and approved below. Changes to an approved sundry will be communicated to theAOGCC by the rig workover (RWO) “first call” engineer. AOGCC written approval of the change is required before implementing the change.StepPageDate Procedure ChangeHNSPreparedBy (Initials)HNSApprovedBy (Initials)AOGCC WrittenApproval Received(Person and Date)Approval:Asset Team Operations Manager DatePrepared:First Call Operations Engineer Date C M ca la O . w cr, p W > N d N ON Z C •J + a) O Ft C p) >- > I N Cl) O) O) d' .- U N E O) U NIJ J C 0) a) G O 1 >- W C C NO n n L >. V) c I Cl) O O Cl) O N nco N 0) U N C T ca a <d a) n ° o O O Z Z 2 n Za .Eao mmO E co a) a) cu Cl) Q i o iN ` ` 0 og cai cdQ + ap0„ o o ca U U J• nJ n g. °U >. 0O o c 0a UU� o) E ct m E a) O dz o o- z E EJ0>. N a) ce a o) o r r cu,_ a)L @ E w>-. 0 E >- p Ce Q o 2 2 2F- 20 2CC F.- CC 2 U cis D �_ //�� Q O C N N M M M M M G r W c-' LV U Y > N N O O N N N co in" 7 'Q-O O W (O (O N N N w Z U) Oa) ca) Ce a ��, O O M M cn LL E J X C C C C C C C .o ui N W W J 2 2 n a s a a a m m rn n V m p1 O U O O O 0 0 0 O j a E J E Z CC di a? co 0.100 coW coO coW co,,.GD coM W O O co _ w 66 W W 13) J n Q a) 7 v) a- a- U E J O. f0 r r r 7 O 7 CL p o a; t en co c U U I 5c M C ' ZI C n co M M co O o fn G O N ! N N O a) Lo O O O j co ONn O E 0_ N U =' UCO 1 m co c „\ 0 o J Q 1 R7' Z CJl c CU ~r I 2 O Q M N } P co to EI O Z N '. Z p d O O O ) O 2 U U U as U _S = N O @ CO COCC 01 Q) ! U en TO O U N N C O F” E W U JfA •� w Cl) 0 a) 1 ,� 5 rn N v� o p 0 N . c o Q cC = c ca a Iii °I 11' W ° m O Q do E Z 0 v t 0 Z o w > w 1 2 8 N iii m E 0 J o- aTi 0 > > > O 2 0 co Z H N N Z 7 U) CO a) 0 N I 75 To CC cC iY C E o o C c o 0 0 E 1 co oO 2 t p W d' Z N N 7 7 7 7 7 ;0 U) a) a) -o v 0 )o > p) - - c c c E . 0 z 1 0 6. — la.0 Z z . 6 . 0 , N > O .- a`+ N a oo Qo N N N w 1 ; co M O a T o I c Q1M� M rn o N Z � N I Ci , U O I rl z N 7 I m 76 o J U) 0 112 O o Om W 0 I Ce J a W LU J V m o Z Q II w II 7 II II J o Si 1I O. U) I M CC le N O _ a p E .y,, N J cp E N Q <IN E u U a z o I N G CO N_ .1 m a) I O m :: I o 0 0 1I Qc a ° 1 a Q _ a Z E m 0o E m z N .- N O O c^p N N CD co I CO N N II CD a aN O) m 9 N y N 3 Nd d _ c 1 Q' .. co 0 d C Q co c co O I! V .C. O D Q. C I c U a+ N N 'C .I O E a E E m ``ni 1 E I E Q a 0 0 CC o , 0 0 CIV rill- AY 2 9 2013 BILKER PRINT �DESTR[ I�>UTi 1{®l TUBI Nutmegs AOGC COMPANY BP Exploration(Alaska)Inc. INTERMEDIATE FINAL Yes (mandatory) 2'Z-0"6 2_ WELL NAME RUN NUMBER (mandatory) 2.2.,Il Z FIELD Prudhoe Bay BH SALESMAN Chris Klotz (mandatory) (mandatory) COUNTY Nortlu Slope Borough BH DISTRICT Alaska (mandatory) (mandatory) STATE Alaska PAGE OF (mandatory) LOG DATE: TODAYS DATE: 4/3/2013 (mandatory) DISTRIBUTION LIST AUTHORIZED BY: BP Exploration(Alaska)Inc. (mandatory) HAS CLIENT BEEN INVOICED FOR ADDITIONAL PRINTS? COMPANY FIELD FINAL Co (digital/ ADDRESS.(FEDEX WILL NOT DELIVER TO P.O.BOX LOGS LOGS image) FILL PERSON ATTENTION #OF PRINTS_ #UI-PHIN 15 #OF COPIES 6#OF COPIES 1 P Exploration(Alaska)Inc. I 1 3 I 1 etrotechnical Data Center LR2-1 900 E.Benson Blvd. Anchorage,Alaska 99508 2 ConocoPhillips Alaska Inc. 1 I 1 1 I I Attn Ricky Elgarico PO Box 100361) Anchorage,Alaska 99510 3 ExxonMobil,Alaska I I 1 I 1 1 I Attn Lynda M.Yaskell and/or Leonardo Elias 3700 Centerpointe Dr. Suite 600 y Anchorage,Alaska 99503 4 tate of Alaska-AOGCC 1 1 I I 1 i I 1 pristine Shartzer I; 1333 West 7th Ave,Suite 100 1 Anchorage,Alaska 99501 5 NR-Division of Oil&Gas ii I 1 1 1 I 1 Attn:Sean Clifton :1550 W.7th Ave,Suite 800 ii 1 :Anchorage,Alaska 99501 TOTALS FOR THIS PAGE: 0 5 5 0 0 0 TOTALS FOR ALL PAGES: 0 5 5 0 0 0 f&& Regg, James B (DOA) FNS ZtzE , • From: AK, D&C Well Integrity Coordinator[AKDCWeIllntegrityCoordinator@bp.com] � 4/(,/ Sent: 3 Sent: Sunday, April 07, 2013 9:01 AM (l To: AK, OPS GC2 OSM; AK, OPS GC2 Field O&M TL; AK, OPS GC2 Wellpad Lead; AK, OPS Prod Controllers; Cismoski, Doug A; Daniel, Ryan; AK, D&C Wireline Operations Team Lead; AK, D&C Well Services Operations Team Lead; AK, RES GPB West Wells Opt Engr; AK, RES GPB East Wells Opt Engr; Regg, James B (DOA); Schwartz, Guy L (DOA); Weiss, Troy D; Glasheen, Brian P; AK, OPS WELL PAD S Cc: AK, D&C DHD Well Integrity Engineer; AK, D&C Well Integrity Coordinator; Holt, Ryan P; Arend, Jon; Sayers, Jessica Subject: NOT OPERABLE: Producer S-32A(PTD#2120820) Sustained OA Casing Pressure Not Manageable by Bleeds All, Producer S-32A (PTD#2120820) OA repressurizes when the well is shut in, and is not manageable by bleeds. A passing TIFL was performed on 04/06/2013 that confirms tubing integrity. The well is reclassified as Not Operable until the IA x OA communication is repaired and barriers confirmed. Plan forward: 1. APE to evaluate for Seal-Tite repair Please call with any questions. Jack Disbrow BP Alaska-Well Integrity Coordinator BPR I I Globa:ruiWaielly C>rq,� or` Office: 907.659.5102 WIC Email:AKDCWeIllntegrityCoordinator@bp.com From: AK, D&C Well Integrity Coordinator Sent: Saturday, March 23, 2013 8:17 AM To: "Regg, James B (DOA)' (jim.regg@alaska.gov)'; "Schwartz, Guy L(DOA)' (•u .schw • alaska..ov)'; Cismoski, Doug A; Daniel, Ryan; AK, D&C Well Services Operations Team Lead; AK, D&C Wirer e Operations Team Lead; AK, OPS Prod Controllers; AK, OPS GC2 OSM; AK, OPS GC2 Ops Lead; AK, OPS GC2 Wellp-.i Lead; AK, OPS GC2 Field O&M TL; AK, RES GPB West Wells Opt Engr; AK, OPS Well Pad SW; Derrick, Mackie; GI- een, Brian P Cc: AK, D&C DHD Well Integrity Engineer; Climer, Laurie A Subject: UNDER EVALUATION: Producer S-32A (PTD# 2120820) OA - eeded MOASP All, Producer S-32A(PTD#2120820) has sustained casing pre : re on the OA above MOASP on 03/22/13. The TBG/IA/OA pressures were equal to 320/1900/1490 psi.A passing ••POT-IC was performed on 11/25/12. At this time the well has been reclassified as Under Evaluation and may re rn ' online for further diagnostics. The plan forward: 1. DHD: warm Outer Annulus Repressurization Test (OART)to determine if manageable by bleeds 2. WIE: Evaluate for Seal-Tite treatment pending results of OART 1 FSU(, Z(LoZD t egg, James B (DOA) From: AK, D&C Well Integrity Coordinator[AKDCWelllntegrityCoordinator@bp.com] Sent: Saturday, March 23, 2013 8:17 AM To: Regg, James B (DOA); Schwartz, Guy L (DOA); Cismoski, Doug A; Daniel, Ryan; AK, D&C Well Services Operations Team Lead; AK, D&C Wireline Operations Team Lead; AK, OPS Prod Controllers; AK, OPS GC2 OSM; AK, OPS GC2 Ops Lead; AK, OPS GC2 Wellpad Lead; AK, OPS GC2 Field O&M TL; AK, RES GPB West Wells Opt Engr; AK, OPS Well Pad SW; Derrick, Mackie; Glasheen, Brian P Cc: AK, D&C DHD Well Integrity Engineer; Climer, Laurie A Subject: UNDER EVALUATION: Producer S-32A(PTD#2120820) OA exceeded MOASP Attachments: S-32A TIO 03-23-13.docx; S-32A wellbore schematic.pdf All, Producer S-32A (PTD# 2120820) has sustained casing pressure on the OA above MOASP on 03/22/13. The TBG/IA/OA pressures were equal to 320/1900/1490 psi. A passing PPPOT-IC was performed on 11/25/12. At this time the well has been reclassified as Under Evaluation and may remain online for further diagnostics. The plan forward: 1. DHD: warm Outer Annulus Repressurization Test (OART) to determine if manageable by bleeds _ 2. WIE: Evaluate for Seal-Tite treatment pending results of OART Attached are a TIO plot and wellbore schematic for reference. «S-32A TIO 03-23-13.docx» «S-32A wellbore schematic.pdf» .� Please call if you have any questions. OA- Se--f) Regards, xP= i410 )-454-1P= SOOes, Laurie Climer .eep. Zfi7 e29 ( 11c'r}rate: Jack !)i.s.b,o i') BP Alaska - Well Integrity Coordinator LI WIC Office: 907.659.5102 WIC Email: AKDCWellIntegritvCoordinator@BP.com 1 sg8i& off fl ---.7 , a O FS j I I I i .a o n C o � n i 0 a " i z o 0 N CO L ri ON CO H i n N O L M § § § It 0. m I— N O \- _.. .... -. _ _. i CL d co F-' TREE= 4-1/16"CIW WELLIEAD=-• FMC AMA:TOR= OTIS -32A SAFE.- NOTE: WELL ANGLE>70 @ 10990'm CHROME THG& LNR-DO NOT ACIDIZE*** NTIAL Ka E. = 64.53' I I 2800' 36.63' KOP= 3100' 2102' —14-1/2"OTIS SSSV NP,ID=3.813" Max Angie= 36"©10990' ,. ri J , , Datum hEl= 10176' GAS LFT MANDRELS Datum IVO= 8800 SS k ST MD TVD DEV TYPE VLV LATCH FORT DATE [20.CONDUCTOR --4 4-----1 5 3101 3100 9 CAMCO DOME RK 16 09/27/12 4 5551 5193 39 CAMCO DONE RK 16 09/27/12 13-3/8"CSG,68#,NT-80, =12.415" —I 2685' LI 3 7719 6898 37 CAMCO DOME RK 16 09/27/12 ms(-0--= 6ozpsi 2 9462 8309 36 CAMCO DMY RK r 0 04/19/97 1 9798 8576 39 CAMCO SO FE 24 09/27/12 Minimum ID =2.377" @ 9955' 9826' —14-1/2"PARKER SINS MP 0=3.813' III 3-3/16 X 2-7/8" X0 9830' H RIGHT HAND RELEASE ii 9832' 1-9-5/8"X 4-1/2"TW PKR,13=3.99" 9854' H4-1/2"KB LW.TOP PKR,ID=2.38" 9855' -3.370'DEPLOY SLV,0=3.00" TOP OF TM/7"LM i H 9860' 9860' —I 9-5/8"X 7"TM/LNR TOP PKR ASSY t li 9876' H3 1/2"I IM X NF,VD=2.813" A ,,,,' ' •..,----1 9880' —4-1/2"PARKER SVVS143,ID=3.813" .., , 9901' —4-1/2'PARKER SWN NP, BEHIND 4-1/2"TBG,12.6#,N113-CR-80 TDS, —I 9913' •. MLLED TO 3.80"(07/23/12)1 CT LNR 0152 bpf,0=3.958" _ ., I '-#.."C 1„_ 9913' +1/2"W/LEG,ID=3.958" .. . 3-1/2"LNR 9.3#,L-80 STL,.0087 bpf,ID=2_992" ---1 9955' —,. . 4 , ., 9902' H ELMO TT LOGGED 02/08/92 4 '4...t.... 9-5/8*CSG,47#,NIT-80S NSCC,D=8.681" — 10099' k00,..:. :„... 4's.,„'''t 9955' H3-1/2"X 3-3/16'XO,D=2.786" 6.*.•'‘4 & 4-1/2-BKR WHPSTOCK(TAGGED 09/03/12) —{ 10109' 7"LNR 26#,NT13CR-80 NSCC,.0383 bpf,ID=6.2—i 10113' •,4 1; MILLOUT WINDOW (S-32A) 10113'-10121' PERFORATION SL*AvtARY , REF LOG:SLB IVEMGR/CCUCNL ON 09/15/12 ANGLE AT TOP MY':81°©10700' I Note:Refer to Production DB for historical perf data SIZE SPF FTITERVAL Opn/Sqz SHOT SQZ I 2" 6 10700-10750 0 09/15/12 10994' --I 3-3/16 X 2-7/8"XO,ID=2.377" 2' 6 10770-10790 0 09/15/12 2" 6 11065-11085 0 09/15/12 2" 6 11250-11300 0 09/15/12 2" 6 11470-11580 0 09/15/12 2" 6 11700-11730 0 09/15/12 3-1/4"LNR,6.6#,L-80 TCI .0079 bpf,ID=3.850" --I 1099A / I I PBTD 10808' I 2-7/8"LNR,6.5#,13CR-80 STL,.0058 bpf,ID=2.441" —I 11845' ,vg DATE REV BY COIVIVENTS DATE REV BY COMVENTS FRLDHOE BAY UNIT 12/21/90 N18E ORIGINAL COMPLETION WELL. S-32A 09/18/12 NORDIC 2 CTD SIDETRACK(S-32A) PERMIT No: 2l20820 09/18/12 PJC DRL.G DRAFT CORRETIONDAPI No; 50-029-22099-01 , . 09/26/12 MSS/PJC SET LTP(09/26/12) SEC 35,T12N,T12E,1643'FM_&1705'FWL 09127/12 MSS/PJC GLV 00(09/27/12) 01/27/13 RR/PJC FFIAL DREG CORRECTIONS BP Exploration(Alaska) bp Date 14-DEC-2012 0 Transmittal Number: 93270 tutiVIED BPXA WELL DATA TRANSMITTAL DEC 14 2012 Enclosed are the materials listed below. AOGCC (BPXA FIELD LOG DATA) If you have any questions,please contact Doug Dortch at the PDC at 564-4973 Delivery Contents 1 CD-ROM Containing Field Log Data& Electronic Log Prints for the following wells: B-27B 2,Z 13732-2fcj C-03C Zl2"O 2.5C,9 C-03CPB1 C-09BPB1 C-24 B 2 2_,-0 G ,2255 I C-24BPB1 S-12B 2 -32A 2\ `,� `� -37A 2 223- , c`—. S-37APB1 Z-34 2\2-0GL )2-2_<-61 vJ „ft:A *. oZ, 1137 7, Please Sign and Retumlene copy of this transmittal. Thank You, Doug Dortch Petrotechnical Data Center Attn: State of Alaska - AOGCC Attn: Christine Shartzer 333 W. 7th Ave, Suite 100 Anchorage, Alaska 99501 Petrotechnical Data Center LR2-1 900 E. Benson Blvd. PO Box 196612 Anchorage,AK 99519-6612 • McMains, Stephen E (DOA) From: Lastufka, Joseph N [Joseph.Lastufka©bp.com] Sent: Thursday, November 08, 2012 9:57 AM _ To: McMains, Stephen E (DOA) f p) Subject: PBU S-32A/PTD#212-082 Hi Steve, Please reference the following well: Well Name: PBU S-32A Permit#: 212-082 API #: 50-029-22099-01-00 Date of Test: 10/31/12 Type of Test: IPT (Initial Production Test) Choke Size: 176 Choke Unit: 64ths Production Method: Gas Lift a Duration (Hours Tested): 6 R8�'i�S NOV Mk. &&1 Top Reference (Top Perf MD): 10700' Bottom Reference (Bottom Perf MD): 11730' Tubing Flowing (Pressure): 260 Casing Pressure: 1560 Total Test (Rate f/O,W, G): 145/2113/ 1218 24-Hour Rate (0,W, G): 434/6340/3655 Gravity(Oil, API): 28.5 GOR (Gas-Oil Ratio): 8428 This well began Production on Method of Operations on this date: 10/30/2012 1 ;a-1 , 1v.: STATE OF ALASKA �, I ., r.''"� ALASKA OIL AND GAS CONSERVATION COMMISSION t..1 WELL COMPLETION OR RECOMPLETION REPORT AND LOG la. Well Status: ®Oil 0 Gas 0 SPLUG ❑Other 0 Abandoned 0 Suspended 1b. Well Class: 2OAAC 25 105 2OAAC 25 110 ®Development 0 Exploratory 0 GINJ 0 WINJ 0 WAG 0 WDSPL 0 Other No.of Completions One ❑Service 0 Stratigraphic 2. Operator Name: 5.Date Comp,Susp.,or Aband.: 12 Permit to Drill Number: BP Exploration (Alaska) Inc. 9/26/2012 212-082 3. Address: 6.Date Spudded: 13. API Number: P.O. Box 196612,Anchorage,Alaska 99519-6612 9/8/2012 50-029-22099-01-00 4a. Location of Well(Governmental Section): 7.Date T.D.Reached' 14. Well Name and Number: Surface: 9/14/2012 PBU S-32A 1643'FNL, 1705' FWL,Sec. 35,T12N, R12E, UM 8. KB(ft above MSL): 64.53' 15. Field/Pool(s): Top of Productive Horizon. 2141'FSL,3873' FWL, Sec.26,T12N, R12E, UM GL(ft above MSL): 36.63' Prudhoe Bay/Prudhoe Bay Total Depth: 9.Plug Back Depth(MD+TVD): 3067'FSL,4318' FWL, Sec.26,T12N, R12E, UM 11808' 8983' 4b. Location of Well(State Base Plane Coordinates,NAD 27)• 10.Total Depth(MD+TVD). 16. Property Designation: Surface: x- 619867 y- 5979855 Zone- ASP4 11848' 8987' ADL 028257 TPI. x- 621970 y- 5983674 Zone- ASP4 11.SSSV Depth(MD+TVD) 17. Land Use Permit: Total Depth:x- 622399 y- 5984607 Zone- ASP4 None 18. Directional Surve y ®Yes ❑No 19.Water depth,if offshore: 20. Thickness of Permafrost(TVD): (Submit electronic and printed information per 20 AAC 25.050) N/A ft MSL 1900'(Approx.) 21.Logs Obtained (List all logs here and submit electronic and printed information per 20 AAC 25.071): 22. Re-Drill/Lateral Top Window MD/TVD: MWD/GR/RES, GR/CCL/MCNL 10113' 8821' 23. CASING, LINER AND CEMENTING RECORD SETTING DEPTH MD SETTING DEPTH TVD HOLE AMOUNT CASING WT.PER FT. GRADE Top BOTTOM Top BOTTOM SIZE CEMENTING RECORD PULLED 20" Insulated Conductor Surface 110' Surface 110' -260 sx Arctic Set(Approx.) 13-3/8" 68# Nt-80 Surface 2685' Surface 2685' 17-1/2" 3722 cu ft Arcticset III& II 9-5/8" 47# NT-80S Surface 10099' Surface 8810' 12-1/4" 2078 cu ft Class'G' 7" 26# 13Cr80 9860' 10113' 8625' 8821' 8-1/2" 332 cu ft Class'G' 3-1/2"x3-1/4" 9.3#/6.6# L-80 9840' 11845'V 8609' 8987' 4-1/8" 133 sx Class'G' x 2-7/8" /6.5# /13Cr80 24. Open to production or injection? ®Yes 0 No 25. TUBING RECORD If Yes,list each interval open SIZE DEPTH SET(MD) PACKER SET(MD/ (MD+TVD of Top&Bottom;Perforation Size and Number): TVD) 2"Gun Diameter,6 spf 4-1/2", 12.6#, 13Cr80 9913' 9832'/8603' MD TVD MD TVD 10700'-10750' 8929'-8937' 26. ACID,FRACTURE,CEMENT SQUEEZE,ETC. 10770'-10790' 8940'-8944' 11065'-11085' 8955'-8954' { DEPTH INTERVAL(MD) AMOUNT AND KIND OF MATERIAL USED 11250'-11300' 8944'-8940' NA 2500' Freeze Protect w/Diesel 11700'-11730' 8975'-8977' l R; r 27. PRODUCTION TEST Date First Production. Method of Operation(Flowing,Gas Lift,etc.). Not on Production N/A Date of Test: Hours Tested. Production For OIL-BBL GAS-MCF. WATER-BBL: CHOKE SIZE: GAS-OIL RATIO: Test Period Flow Tubing Casing Press. Calculated OIL-BBL' GAS-MCF. WATER-BBL: OIL GRAVITY-API(CORR)' Press. 24-Hour Rate 28. CORE DATA Conventional Core(s)Acquired? 0 Yes ®No Sidewall Core(s)Acquired? 0 Yes ®No If Yes to either question,list formations and intervals cored(MD+TVD of top and bottom of each),and summarize lithology and presence of oil,gas or water (submit separate sheets with this form, if needed). Submit detailed descriptions,core chips,photographs and laboratory analytical results per 20 AAC 250.071. None R DMS OCT 2 4 2012 Form 10-407 Revised 12/2009 CONTINUED ON REVERSE /'pilit Original Only 29. GEOLOGIC MARKERS(List all formations ar 'rkers encountered): 30. FORMATION TESTS NAME J ND Well Tested? ,J Yes ®No Permafrost Top If yes,list intervals and formations tested,briefly summarizing test Permafrost Base results. Attach separate sheets to this form,if needed,and submit detailed test information per 20 AAC 25.071. Shublik 10151' 8849' None Ivishak/Zone 4 10398' 8898' Ivishak/Zone 4 10578' 8910' Ivishak/Zone 4 11436' 8942' Formation at Total Depth (Name): Ivishak/Zone 4 11436' 8942' 31.List of Attachments: Summary of Daily Drilling Reports, Summary of Post-Rig Work,Well Schematic Diagram, Surveys 32.I hereby certify that the f. -..‘.ng is t u - ' r= t to the best of my knowledge Signed: Joe Lastufka ( Title: Drilling Technologist Date: [0 a. PBU S-32A 212-082 Prepared By Name/Number Joe Lastufka, 564-4091 Well Number Permit No./Approval No. Drilling Engineer. Zach Sayers, 564-5790 INSTRUCTIONS General: This form is designed for submitting a complete and correct well completion report and log on all types of lands and leases in Alaska. Submit a well schematic diagram with each 10-407 well completion report and 10-404 well sundry report when the downhole well design is changed. Item la. Classification of Service Wells: Gas Injection,Water Injection,Water-Alternating-Gas Injection,Salt Water Disposal,Water Supply for Injection, Observation,or Other. Multiple completion is defined as a well producing from more than one pool with production from each pool completely segregated. Each segregated pool is a completion. Item 4b. TPI(Top of Producing Interval). Item 8. The Kelly Bushing and Ground Level elevation 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 13: The API number reported to AOGCC must be 14 digits(ex: 50-029-20123-00-00). Item 20: Report true vertical thickness of permafrost in Box 20 Provide MD and ND for the top and base of permafrost in Box 28. Item 23: Attached supplemental records for this well should show the details of any multiple stage cementing and the location of the cementing tool. Item 24: If this well is completed for separate production from more than one interval(multiple completion),so state in item 1,and in item 23 show the producing intervals for only the interval reported in item 26. (Submit a separate form for each additional interval to be separately produced, showing the data pertinent to such interval). Item 27• Method of Operation: Flowing,Gas Lift,Rod Pump,Hydraulic Pump,Submersible,Water Injection,Gas Injection,Shut-In,or Other(explain). Item 28. Provide a listing of intervals cored and the corresponding formations,and a brief description in this box. Submit detailed description and analytical laboratory information required by 20 AAC 25.071. Item 30. Provide a listing of intervals tested and the corresponding formation,and a brief summary in this box. Submit detailed test and analytical laboratory information required by 20 AAC 25.071. Form 10-407 Revised 12/2009 Submit Original Only North America-ALASKA- BP ur ��;, ;� r.'-ge 1 of 17 Operation Summary Report Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date:9/2/2012 End Date: 9/14/2012 IX3-0129C-C: (2,554,817.00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release:9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs 1 Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 9/2/2012 06:00 - 09:00 3.00 MOB P PRE BEGIN RON EVENT WITH NORDIC 2 CTD RIG AT 0600 HOLD PJSM WITH CREW. DISCUSS COMMS, SPOTTER ASSIGNMENTS,SIGNAL TO STOP. PERFORM FINAL WALKAROUND. WARM UP MOVING SYSTEM. JACK UP RIG. BACK OFF S-37A 09:00 - 12:00 3.00 MOB P PRE REMOVE RIG MATS FROM S-37A. SPOT SAME AROUND S-32A. HOLD PJSM WITH CREW. MOVE RIG OVER WELL. SET DOWN RIG. ACCEPT RIG AT 1200 HRS ON 9-2-12 12:00 - 15:00 3.00 MOB P PRE CONTINUE SPOT EQUIPMENT AND RU FOR WELL WORK. 15:00 - 17:00 2.00 BOPSUR P PRE VERIFY MASTER AND SSV CLOSED.PT SWAB VALVE FROM WING VALVE. PASSED. TWO BARRIERS VERIFIED. ND TREE CAP. 17:00 - 21:00 4.00 BOPSUR P PRE NU BOPS. 21:00 - 22:00 1.00 BOPSUR P PRE FILL STACK, GREASE AND RECONFIGURE LUBRICATOR TO RIGHT HEIGHT 22:00 - 23:00 1.00 BOPSUR P PRE SHELL TEST BOP. 'FUNCTION TEST BOPE FROM BOTH REMOTE PANALS 23:00 - 00:00 1.00 BOPSUR P PRE PJSM FOR BOPE TEST. BOB NOBLE WITH AOGCC WAIVED STATE'S RIGHT TO WITNESS BOPE TEST AT 2300. 9/3/2012 00:00 - 04:00 4.00 BOPSUR P PRE PRESSURE TEST BOPE PER ADWOP AND AOGCC REGULATIONS TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH. STATE'S RIGHT TO WITNESS WAIVED BY AOGCC REPRESENTATIVE BOB NOBLE. -PRESSURE TEST ANNULAR PREVENTER WITH 2-3/8"TEST JOINT -PRESSURE TEST VBRS WITH 2-3/8"AND 3-1/2"TEST JOINT. -NO FAILURES DURING TESTING. -SEE ATTACHED DOCUMENTATION REPORT AND CHARTS. 04:00 - 04:30 0.50 BOPSUR P PRE RIG EVAC DRILL WITH AAR.ALL PEOPLE ON LOCATION MUSTERED. GOOD PARTICIPATION FROM TRUCK DRIVERS. DISCUSSED IMPORTANCE OF CHECKING WIND DIRECTION AND LEAVING DOORS OF RIG OPEN IF POSSIBLE TO CIRCULATE AIR 04:30 - 06:00 1.50 BOPSUR P PRE PJSM FOR INNER REEL VALVE AND PACK-OFF TEST. FILL COIL WITH KCL. LINE UP TO TEST. 06:00 06:30 0.50 BOPSUR P PRE CREW CHANGE. DISCUSS OPERATIONS AND RIG STATUS. CONTINUE TO TEST BOPS. 06:30 - 11:00 4.50 BOPSUR P PRE TEST MANUAL RAM LOCKS FOR 2-3/8'COMBI AND VBR RAMS TO 250 AND 3500 PSI. NO FAILURES. Printed 10/8/2012 1:3106PM North America-ALASKA- BP Page 2 of 0•eration Summary Report Common Well Name: S-32 'AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date:9/14/2012 X3-0129C-C: (2,554,817.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:OOAM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To I Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 11:00 - 15:00 4.00 RIGU P PRE RU FLOOR FOR COIL MANAGEMENT. CUT 600'OF COIL. PUMP SLACK FORWARD. CUT E-LINE. CUT 200'OF COIL. 15:00 - 16:30 1.50 RIGU P PRE DRESS COIL FOR E-CONNECTOR. 16:30 - 17:00 0.50 BOPSUR P PRE HOLD RIG EVACUATION DRILL. ALL HANDS .,.REPORT TO SAT CAMP AND/OR SIGN IN SHACK. ALL ACCOUNTED FOR. 'HOLD AAR. 17:00 - 19:30 2.50 BOPSUR P PRE SPOT DSM CREW. PU AND RU TWC LUBRICATOR. TEST LUBRICATOR TO 250/3500 PSI. PULL TWC,CONFIRM 0 PSI ON WELLHEAD. RD DSM LUBRICATOR. 19:30 - 21:00 1.50 BOPSUR P PRE MUD GAS SEPARATOR DRILL, REVIEW PROCEDURE AND STANDING ORDERS,WALK THROUGH VALVE LINE UP AND OPTIONS FOR FLOW PATHS USING CHOKE MANIFOLD. 21:00 - 22:00 1.00 RIGU P PRE PREP FOR BULLHEAD WHILE WAITING ON MEOH PUP REPLACEMENT. 22:00 - 23:00 1.00 RIGU P PRE HOOK UP MEOH PUP AND KCL TRUCK FOR WELL KILL,HOLD PJSM FOR OPERATION 23:00 - 23:30 0.50__ RIGU- P PRE -TEST NIGHT CAP PRIOR 0 BULLHEADING TO 250/3500 PSI. GOOD TEST. 23:30 - 00:00 0.50 RIGU P PRE START WELL KILL PUMPING 4.5 BPM OF KCL FOLLOWING 5 BBLS MEOH 9/4/2012 00:00 - 01:00 1.00 RIGU P PRE PUMP 270 BBLS KCL AT 6 BPM,WELL TAKING FLUID AT-10 BPM. NO WELLHEAD PRESSURE, CONTINUE PUMPING 200 BBLS OF MUD AT 6 BPM,168 PSI FINAL CIRC PRESSURE. MONITOR WELL, IMMEDIATELY ON STRONG VACUUM. SI MASTER AND SWAB 01:00 - 02:30 1.50 RIGU P PRE PICKUP INJECTOR,PRESSURE TEST COIL CONNECTOR TO 3800 PSI PUMP SLACK FORWARD. TET E-LINE,GOOD CONDUCTIVITY. 02:30 - 03:30 1.00 RIGU P PRE REHEAD BHI TOOLS 03:30 - 04:00 0.50 RIGU P PRE TEST CHECKS TO 250/3500 PSI. 04:00 - 04:30 0.50 RIGU P PRE SWAP COIL OVER TO MUD. CALL ODE AND NS SUPT WITH CURRENT STATUS. 04:30 - 06:00 1.50 RIGU N DPRB 10,110.00 PRE WAIT ON PLAN FROM TOWN TO MITIGATE LOSSES. 06:00 - 06:30 0.50 RIGU N DPRB 10,110.00 PRE CREW CHANGE. DISCUSS CURRENT OPERATIONS AND RIG STATUS. CONTINUE TO WAIT ON PLAN FORWARD. 06:30 - 10:30 4.00 RIGU N DPRB 10,110.00 PRE WAIT ON PLAN TO ADDRESS FLUID LOSSES. SHUT IN AND LOCK OUT S-25i AS PER TWON REQUEST. ORDER 60 BBLS LCM PILL FROM MI. 10:30 - 15:00 4.50 RIGU N DPRB 10,110.00 PRE WAIT ON FLUIDS FROM HOTWATER PLANT AND MI PLANT. 15:00 - 16:00 1.00 RIGU N DPRB 10,110.00 PRE 580 BBLS FLO PRO AND 580 BBLS 1%KCL ON LOCATION. 60 BBLS 60#LCM ON LOCATION. HOLD PJSM. SPOT AND PREP TRUCKS. Printed 10/8/2012 1:31:06PM �. • North America-ALASKA- BP � . Pa � „, ate ge 3 of 17 Operation Summary Report Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) I Start Date: 9/2/2012 End Date:9/14/2012 X3-0129C-C: (2,554,817 00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time. 11/1/1990 12:00:OOAM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task ' Code NPT NPT Depth Phase Description of Operations (hr) (ft) 16.00 - 17 00 1.00 RIGU N DPRB 10,110.00 PRE PUMP 60 BBLS LCM. WELL SUCKING FLUID OFF TRUCK AT 5-7 BPM. DISPLACE WITH FLO PRO MUD AT 5-7 BPM. WITH 10 BBLS LCM IN PERFS,WHP SLOWLY CLIMBING. BULLHEAD 50 BBLS LCM AWAY AT 2.5 BPM. MAX WHP.450 PSI. 60 PPB,60 BBL LCM PILL RECIPE. 20 PPB SAFE CARB 250 20 PPB G SEAL 10 PPB MIX II 10 PPB NUT PLUG MEDIUM 17:00 - 18.00 1.00 RIGU N DPRB 10,110.00 PRE MONITOR WELL FOR TEN MINUTES- FILL HOLE WITH 0.5 BPM. CIRCULATE ACROSS WELL. 0.5 BPM IN/0.4 BPM OUT. ESTIMATE STATIC LOSS RATE AT 6-8 BPM. 18:00 - 22.30 4.50 RIGU N DPRB 10,110.00 PRE ORDER ADDITIONAL 60 BBLS LCM FROM MI MUD PLANT. CONTINUE TO CIRCULATE OVER TOP OF WELL. LOSSES CONSTANT AT 6-8 BPH. HOLD PJSM FOR PUMPING LCM PILL#2. 22:30 - 00:00 1.50 RIGU N DPRB 10,110.00 PRE PUMP 60 BBL LCM PILL OFF TRUCK AT 2 BPM, INITIAL WELLHEAD PRESSURE=290 PSI, FINAL WHP=200 PSI. DISPLACE LCM PILL TO PERFORATIONS AT 10104'MD WITH 100 BBLS 8.5 PPG MUD AT 2.5 BPM. INITIAL WHP=200 PSI, FINAL WHP=355 PSI. DISPLACE ENTIRE LCM PILL INTO PERFORATIONS WITH 60 BBLS 8.5 PPB MUD AT 1 BPM, INITIAL WHP= 150 PSI. FINAL WHP =205 PSI(COMPLETED PUMPING AT 00 30 ON 9/5/2012). 60 PPB,60 BBL LCM PILL RECIPE. 20 PPB SAFE CARB 250 20 PPB G SEAL 10 PPB MIX II 10 PPB NUT PLUG MEDIUM 9/5/2012 00:00 - 00:30 0.50 RIGU N DPRB 10,110.00 PRE COMPLETE DISPLACEMENT OF LCM PILL THROUGH PERFS WITH NO SIGNIFICANT PRESSURE BUILDUP AND NO OPPORTUNITY TO SQUEEZE PILL. SHUT DOWN PUMPS WHEN ALL AND WELLHEAD PRESSURE IMMEDIATELY BLEEDS FRM FINAL PRESSURE OF 205 PSI TO 0 PSI. 00:30 - 03:30 3.00 RIGU N DPRB 10,110.00 PRE CIRCULATE OVER TOP OF WELL AND ESTIMATE LOSS RATE WHILE DISCUSSING PLAN FORWARD. ESTABLISH ABILITY TO MAINTAIN HOLE FILL WITH 0.8 BPM IN,0.3 BPM OUT(30 BPH LOSSES. NOTE: LOSSES TO PERFORATIONS FOLLOWING FIRST LCM PILL WERE 10 BPH) Printed 10/8/2012 1 3106P • North America-ALASKA- BP Operation Summary Report Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date: 9/14/2012 X3-0129C-C: (2,554,817.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:OOAM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 03:30 06:00 2.50 RIGU N DPRB 10,110.00 PRE CONTINUE TO CIRCULATE OVER TOP OF HOLE AT 0.8 BPM,30 BPH LOSSES TO EXISTING PERFORATIONS. ORDER THIRD LCM PILL FROM MI MUD PLANT. 60 PPB,50 BBL LCM PILL RECIPE: -10 PPB SAFE GARB 250(DECREASE OF 10 PPB FROM LAST TWO PILLS) -10 PPB G SEAL(DECREASE OF 10 PPB FROM LAST TWO PILLS) -20 PPB MIX II COURSE(INCREASE OF 10 PPB OVER LAST TWO PILLS) 10 PPB NUT PLUG MEDIUM(SAME AS LAST TWO PILLS) 10 PPB MI-SEAL MEDIUM(NEW ADDITION OVER LAST TWO PILLS) 06:00 - 06:15 0.25 RIGU N DPRB 10,110.00 PRE CREW CHANGE. DISCUSS OPERATIONS AND RIG EQUIPMENT STATUS. MAKE ALL CHECKS AND ROUINDS. CONTINUE TO WAIT ON LCM PILL FROM MI. 06:15 - 09:45 3.50 RIGU N DPRB 10,110.00 PRE CONTINUE TO WAIT ON LCM PILL FROM MI. - SPOT VAC TRUCK WITH LCM. HOLD PJSM TO DISCUSS PUMPING PILL. 09:45 - 12:15 2.50 RIGU N DPRB 10,110.00 PRE PUMP 50 BBLS PILL AS PER ABOVE BLEND. DISPLACE WITH 148 BBLS FLO PRO MUD. AVG RATE/PRESS:2.0 BPM AT 350 PSL SQUEEZE LCM AT 1.0 BPM IN TO PERFS. INITIAL SQUEEZE PRESS WAS 350 PSI. FINAL"SQUEEZE'PRESSURE WAS 395 PSI WITH 40 AWAY INTO PERFS. 10 BBLS LEFT IN TBG. TBG PRS BLED DOWN FROM 395 PSI TO 50 PSI IN 10 MIN. 12:15 - 14:00 1.75 RIGU N DPRB 10,110.00 PRE CIRCULATE ACROSS WELLHEAD. 0.67 BPM IN/0.53 BPM OUT WITH KCL. CONTINUE TO CIRCULATE WHILE PREPPING FOR CEMENT SQUEEZE JOB. 14:00 - 00:00 10.00 RIGU N DPRB 10,110.00 PRE PUMP SLACK FROM REEL AND CUT(180' PUMPED OUT,-20'REMAIN IN COIL) DISCUSS CEMENT JOB WITH SLB IN DEADHORSE. CIRCULATE ACROSS WELL WHILE SCHLUMBERGER LOADING CEMENT. LOSSES INCREASE FROM 30 BPH TO 110 BPH OVER TIME PERIOD. SWAP OUT ALL FLUID IN PITS FROM MUD TO 1%KCL WITH SAFELUBE. LINEUP TRUCKS FOR CEMENT JOB. 9/6/2012 00:00 - 00:30 0.50 RIGU N DPRB 10,110.00 PRE CONTINUE TO CIRCULATE ACROSS TOP OF WELL AT 1 7 BPM IN AND 0 1 BPM OUT(-100 BPH LOSSES)WHILE PREPARING FOR CEMENT JOB. 00:30 - 01:30 1.00 RIGU N DPRB 10,110.00 PRE MAKEUP AND RUN IN HOLE WITH CEMENTING BHA. STAB ON WITH INJECTOR AND PRESSURE TEST QUICK TEST SUB TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH(PASSING TESTS). -NOZZLE HOLE SIZE= 15/16" -4 JOINTS 2-3/8"PH-6, BHA OAL= 131' Printed 10/8/2012 1:31:06PM • North America-ALASKA- BP � � Page 5 of 17 Operation Summary Report Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date: 9/14/2012 X3-0129C-C: (2,554,817.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 01:30 - 05:00 3.50 RIGU N DPRB 10,110.00 PRE RUN IN HOLE AT 50-60 FPM FROM BHA AT 131'MD TO TAG WHIPSTOCK AT 10134'MD UNCORRECTED(ON DEPTH BASED PREVIOUS DEPTH CORRECTIONS AND WHIPSTOCK TRAY LENGTH). CIRCULATE AT 1.75 BPM DOWN COIL TO MAINTAIN HOLE FILL AND RETURNS,0.2 BPM OUT,775 PSI. CONTINUE TO LOSE 110 BPH TO EXISTING PERFS WHILE TRIPPING IN HOLE. PICKUP WEIGHT=38 KLBS, SLACKOFF=21 KLBS. PAINT WHITE FLAG ON COIL ON DOWNSTROKE AT 10105'MD(-10'ABOVE TOP OF PERFS). MIRU SCHLUMBERGER CEMENTERS. 05:00 - 06:00 1.00 RIGU N DPRB 10,110.00 PRE CIRCULATE COIL WHILE SITTING ABOVE WHIPSTOCK AT 10094'MD,1.9 BPM IN,0.1 BPM OUT(110 BPH LOSSES). 06:00 - 06:30 0.50 RIGU N DPRB 10,110.00 PRE CREW CHANGE. DISCUSS OPERATIONS AND RIG EQUIPMENT STATUS. 06:30 - 08:30 2.00 RIGU N DPRB 10,110.00 PRE WAIT ON SLB FIELD BLEND PILOT TEST RESULTS. 08:30 - 09:15 0.75-_ RIGU- N DPRB 10,110.00 PRE HOLD PJSM WITH ALL CREWS. DISCUSS COMMS,SAFETY AREA, PUMP SCHEDULE, PT, ROLES AND RESPONSIBILITIES FOR ALL HANDS. 09:15 - 10:45 1.50 RIGU_ N DPRB 10,110.00 PRE PUMP 5 BBLS WATER. PT CEMENT LINES TO 250 AND 4000 PSI. FILL COIL AND CT ANN WITH KCL 10:45 - 12:00 1.25 RIGU N DPRB 10,110.00 PRE CLOSE CHOKE. NOZZLE AT 10094' PUMP 10 BBLS CLASS G NEAT.25 BBLS W/ 10PPB AGGREGATE. 1.85 BPM AT 1350 PSI. 10 BBLS CLASS G NEAT. 5 BBLS WATER. DISPLACE WITH RIG PUMP WITH 2#BIOZAN. 2.5 BPM AT 1500-1800 PSI BULLHEAD 20 BBLS INTO PERFS. WHP 230 PSI. POOH 1.1 IN 7"AND 4-1/2"TBG MAINTAIN 220-240 PSI WHP. CIP: 1150. TAKE UCA SAMPLE TO LAB IN DEADHORSE. 12:00 - 13:30 1.50 RIGU N DPRB 10,110.00 PRE NOZZLE AT 8770'. EST TOC AT 9090' SQUEEZE CMT AT 1 0 BPM. 6 BBLS 216 PSI 10 BBLS 297 PSI SHUT DN PUMP. MONITOR WHP FROM 12.15 TO 12:45 WHP DROPPED TO 23 PSI AT 12:30 PUMP 5 ADDITIONAL BBLS. WHP INC FROM 22 PSI TO 270 PSI. SHUT DN PUMP MONITOR WHP FROM 12.45 TO 1315. 270 PSI DOWN TO 15 PSI IN 30 MIN PUMP ADDITIONAL 5 BBLS AT 0.90 BPM. WHP INC FROM 15 TO 300 PSI. MONITOR WHP FROM 1315 TO 1330. 300 PSI DN TO 88 PSI. Printed 10/8/2012 1:31:06PM y .,.v a North America-ALAS Page 6 8w x�d O•eration Summa Report fes. Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date:9/2/2012 End Date: 9/14/2012 .X3-0129C-C:(2,554,817.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release:9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code l NPT NPT Depth Phase Description of Operations (hr) (ft) 13:30 - 14:30 1.00 RIGU N DPRB 10,110.00 PRE BLEED OFF WHP. CIRC AT 1.10 BPM IN/1.03 BPM OUT. RIH CIRCULATING 2#BIOZAN AT 42 FPM. 1.11 BPM IN/1.24 BPM OUT. 90-95%RTNS. WASH GLMS AT 9809'AND 9473'. THREE PASSES EACH. CONTINUE TO RIH CIRCULATING BIO AT 1.12 BPM IN. WASH TO 10,000'. PU 50'. WASH DOWN TO 10084(20'ABOVE PERFS). 14:30 - 17:30 3.00 RIGU N DPRB 10,110.00 PRE HOLD PJSM FOR POOH. PVT:398 BELS AT 10,000'. CIRCULATE OUT OF HOLE. 1.49 BPM IN. APPEAR TO BE LOSING 0.1-0.15 BPM. STOP COIL AT 9000'. CIRC AT 1.0 BPM. 0.87 BPM OUT AT 550 PSI. CIRC AT 2.0 BPM. 1.85 BPM OUT AT 1106 PSI. FLOW CHECK WELL. CONTINUE TO CIRCULATE OUT OF HOLE. HOLD PJSM NEAR SURFACE. 17:30 - 19:00 1.50 RIGU N DPRB 10,110.00 PRE TAG UP. FLOW CHECK. GET OFF WELL. LD BHA AND CUTOFF COILED TUBING CONNECTOR. STATIC LOSSES TO WELLBORE MEASURED AT 5 BPH. NOTE: CEMENT AT 1000 PSI COMPRESSIVE STRENGTH AT 18:00 19:00 - 20:00 1.00 RIGU N. DPRB 10,110.00 PRE CLOSE SWAB VALVE AND STAB ON WELL WITH INJECTOR. PUMP E-LINE SLACK BACK INTO COIL WITH KCL. UNSTAB INJECTOR FROM WELL. 20:00 - 20:30 0.50 RIGU N DPRB 10,110.00 PRE CUT 244'2-3/8"COILED TUBING WITH HYDRAULIC CUTTER(NEW COIL LENGTH= 13545',51.1 BBLS VOLUME, E-LINE SLACK= 1.8%). 20:30 - 21:00 0.50 RIGU N DPRB 10,110.00 PRE MAKEUP NEW SLB EXTERNAL COILED TUBING CONNECTOR AND PULL TEST TO 35 KLBS. 21:00 - 22:00 1.00 RIGU N DPRB 10,110.00 PRE PUMP E-LINE SLACK FORWARD. STAB ON WELL WITH INJECTOR AND PRESSURE TEST LUBRICATOR TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH PASSING TESTS). OPEN SWAB VALVE TO MONITOR WELL. 22:00 - 23:00 1.00 RIGU N DPRB 10,110.00 PRE MAKEUP BHI E-LINE HEAD AND TEST(PASS). PRESSURE TEST COILED TUBING CONNECTOR TO 4000 PSI. NOTE: END NPT FOR LOSSES TO EXISTING PERFORATIONS. 23:00 - 00:00 1.00 STWHIP P WEXIT MAKEUP WINDOW MILLING BHA AND RUN IN HOLE. STAB ON WITH INJECTOR AND PRESSURE TEST QUICK TEST SUB TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH(PASSING TESTS). SHALLOW TEST ALL TOOLS. -3.8"HCC WINDOW MILL AND 3.8"HCC DIAMOND STRING REAMER -2-7/8"STRAIGHT BOT X-TREME MUD MOTOR +2 JTS 2-3/8"PH-6 -3"COILTRAK TOOLS -BHA OAL= 121' Printed 10/8/2012 1:31:06PM ._ North America-ALASKA-BP Page 7 of 17 O•eration Summary Report F�"7... ..m.,aeignkse�..a wrrsa " Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE (RON) Start Date: 9/2/2012 End Date: 9/14/2012 X3-0129C-C: (2,554,817 00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12.00:OOAM Rig Release:9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 9/7/2012 00:00 - 02:45 2.75 STWHIP P WEXIT RUN IN THE HOLE FROM BHA AT 121'MD TO TIE-IN DEPTH AT 9800'MD;60 FPM,1.4 BPM IN,450 PSI,OPEN EDC. LOSSES AVERAGE 20-30 BPH WHILE TRIPPING IN HOLE. 02:45 - 04:00 1.25 STWHIP P WEXIT LOG FOR INITIAL DEPTH CONTROL TIE-IN AT 300 FPH FROM 9850'MD TO 10050'MD. APPLY-22'CORRECTION BASED ON KINGAK 'JB MARKER. SLOW PUMP RATES AT 10110'MD,8.5 PPG: PUMP#1 1200 PSI @ 1 BPM,948 PSI @ 0.5 BPM PUMP#2 1179 PSI @ 1 BPM,952 PSI @ 0.5 BPM 04:00 - 06:00 2.00 STWHIP P WEXIT DISPLACE WELL FROM 8.4 PPG KCL TO 8.5 PPG FLO-PRO MUD;2.5 BPM IN-1.5 BPM OUT. 06:00 - 06:30 0.50 STWHIP . P WEXIT RIH F/10,050'-10,084'MD PUMPING AT 0.5 BPM,TAG CEMENT BRIDGE,BEGIN WASHING DOWN F/10,084'-10,101'MD;2.6 BPM.2.6 BPM IN-2.6 BPM OUT 06:30 - 07:00 0.50 STWHIP P WEXIT CIRCULATE AND CONDITION MUD;MONITOR LOSS RATE;2.6 BPM IN-2.6 BPM OUT 07:00 - 08:00 1.00- STWHIP P WEXIT TAG TOP OF CEMENT @ 10,101'MD,CLEAN OUT CEMENT F/10,101-10,113'MD.TOP OF WHIPSTOCK. LOSSES:2.6 BPM IN-1.28 BPM OUT 08:00 - 11:00 3.00 STWHIP- P WEXIT KICKOFF NEW SIDETRACK AND MILL WINDOW IN 7"CHROME LINER F/10,113'MD; 2450 PSI FREESPIN,2550-2685 PSI PUMP PRESSURE,1-3 DHWOB.MW IN/OUT=8.5, ECD=9.6 PPG. IA/OA=31/72.NO STALLS DURING START OF WINDOW. 0 LOSSES:2.6 BPM IN-1.93 BPM OUT. AVERAGE 45-50 BPH MILL TO 10114.5' 11 00 - 16:00 5.00 STWHIP P WEXIT CONTINUE MILLING WINDOW FROM 10.114.5' 2520 PSI FS AT 2.60 BPM IN/2.00 BPM OUT. 350-550 PSI MTR WORK. 3.0-3.75K#DHWOB. MILL TO 10,116.4' LOTS OF METAL ON MAGNETS. 16:00 - 00:00 8.00 STWHIP P WEXIT CONTINUE TO MILL WINDOW FROM 10,116.4' MD TO 10120'MD AT MIDNIGHT(3.5' IN 8 HOURS=0.4 FPH), FREESPIN=2470 PSI, 2650-2800 PSI, NO STALLS,3-4 KLBS DHWOB, 2.6 BPM,446 MILL RPM. MW IN/OUT=8.5 PPG, ECD=9.8 PPG, IA/OA=75/275 PSI. LOSSES TO FORMATION AVERAGE 30 BPH DURING MILLING OPERATIONS. DHWOB DROPS OFF FROM 3.5 KLBS TO 1.5 KLBS AT 10120'MD AS SIGN OF MILL EXITING LINER. Printed 10/8/2012 1.31:06PM 4111111X,_'North America-ALASKA- BP • Page 8 of 17 Operation Summa Report Common Well Name:S-32 AFE No Event Type:RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date: 9/14/2012 X3-0129C-C: (2,554,817.00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.:NORDIC 2 Spud Date/Time. 11/1/1990 12.00:OOAM Rig Release. 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 9/8/2012 00:00 - 02:30 2.50 STWHIP P WEXIT MILL WINDOW FROM 10120'MD AT MIDNIGHT TO 10122'MD(MILL 1'OUTSIDE WINDOW AND STRING MILL AT BASE OF WINDOW); FREESPIN=2470 PSI,2700-2750 PSI,NO STALLS,1-2 KLBS DHWOB,2.6 BPM,446 MILL RPM. MW IN/OUT=8.5 PPG, ECD=9.8 PPG, IA/OA=85/350 PSI. LOSSES TO FORMATION AVERAGE 30 BPH DURING MILLING OPERATIONS. ESTIMATED WINDOW DEPTHS: 10113'MD-10121'MD 02:30 - 03:30 1.00 STWHIP P WEXIT MILL NEW FORMATION FROM 10122'MD TO 10131'MD(10'OUTSIDE BOTTOM OF WINDOW);2.6 BPM,2700 PSI,2470 FREESPIN. 03:30 - 05:00 1.50 STWHIP P WEXIT REAM THREE PASSES UP AND DOWN THROUGH WINDOW;2.6 BPM 1 FPM,33 KLBS PICKUP,19 KLSS'SLACKOFF,2650-2750 PSI 05:00 - 05:30 0.50 STWHIP { P WEXIT DRY DRIFT WINDOW AND CONFIRM CLEAN PASS THROUGH;1 FPM. PULL UP INTO WINDOW AND OPEN EDC. FLOW CHECK WELL WELL ON LOSSES. 05:30 - 07:30 2.00 STWHIP P WEXIT CIRCULATE OUT OF HOLE FROM WINDOW AT 10113'MD TO BHA AT 121'MD. FLOW CHECK WELL AT BHA. WELL ON LOSSES. 07:30 - 09:00 1.50 - STWHIP P WEXIT AT SURFACE.GET OFF WELL.UNSTAB COIL, LD BHA MILL GAUGED 3.9"GO/3.80 NO GO STRING REAMER:3.8"GO/3.79"NO GO 09.00 - 10:00 1.00 DRILL P PROD1 MU INTERMEDIATE SECTION BUILD DRILLING BHA.STAB ON WELL INJECTOR AND PRESSURE TEST QTS TO 250 PSI LOW AND 3500 PSI HIGH FOR 5 MINS EACH(PASSING TEST) -4 1/4"REED-HYCALOG BI-CENTER PDC, SER#128690,SRR3611 M-B4-Z -2 7/8"X-TREME HIGH SPEED MOTOR,2.8 BEND -3"COILTRAK TOOLS WITH RESISTIVITY AND DFCVC -BHAOAL=79' 10:00 - 12:00 2.00 DRILL P PROD1 TIH WITH DRILLING ASSEMBLY FROM BHA AT 79'MD TO PREVIOUS DRILLED DEPTH AT 10,131'MD. 12:00 - 12:30 0.50 DRILL P PROD1 LOG GR TIE IN FROM 9920'. SUBTRACT 21' CORRECTION. SPR:1436 PSI AT 1.35 BPM. 12:30 - 13:00 0.50 DRILL P PROD1 CLOSE EDC. RUN IN HOLE THROUGH. WONDOW. SMOOTH. 13:00 - 16:00 3.00 DRILL P PROD1 DRILL AHEAD FROM 10.131'. 2710 PSI FS AT 2.61 BPM IN/2.0 BPM OUT. 100-250 PSI MTR WORK. 2.0-3.0 K#DHWOB. BHP/ECD/TVD:4434 PSI/9.78 PPG/8750' 16:00 - 18:00 2.00 DRILL P PROD1 DRILL AHEAD FROM 10,185'. 2650 PSI FS AT 2.61 BPM IN/2.0 BPM OUT. 2.85K#DHWOB. HIGH LEVELS OF VIBRATION ON MWD. DRILL TO 10200' Printed 10/8/2012 1:31:06PM • North America -ALASKA- BP •Y. , ,�� f" Page 9 of 17 Operation Summa Re•ort Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date: 9/14/2012 X3-0129C-C:(2,554,817.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time. 11/1/1990 12.00:OOAM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 18:00 - 00:00 6.00 DRILL P PROD1 DIRECTIONAL DRILL 4-1/4"BUILD HOLE SECTION FROM 10200'MD TO 10252'MD AT MIDNIGHT(52'IN 6 HRS=9 FPH);SHUBLIK, HIGHSIDE,2.6 BPM,446 BIT RPM,2700 PSI FREESPIN,2900-3100 PSI,3-5 KLBS WOB,8.5 PPG MW IN/OUT,ECD=9.8 PPG. LOSSES TO FORMATION AVERAGE 25-30 BPH. IA/OA= "-165/425 PSI. NO DIRECTIONAL SURVEYS YET. ESTIMATED DLS USING NBI=29 DEG/100' SLOW PUMP RATES AT 10230'MD,8.5 PPG: PUMP-#1. 1604 PSI @ 1 BPM,1275 PSI @ 0.5 BPM PUMP#2: 1527 PSI @ 1 BPM,1245 PSI @ 0.5 BPM 9/9/2012 00:00 - 04:00 4.00 DRILL ; P PROD1 DIRECTIONAL DRILL 4-1/4"BUILD HOLE SFr:TIMN FRAM 10752'MD AT MIDNIGHT TO END OF BUILD SECTION AT 10286'MD(34'IN 4 HRS=9 FPH);SHUBLIK,HIGHSIDE,2.6 BPM, 446 BIT RPM,2700 PSI FREESPIN,2900-3000 PSI,4-5 KLBS WOB,8.5 PPG MW IN/OUT,ECD -=9.8 PPG. LOSSES TO FORMATION AVERAGE 20-25 BPH. IA/OA=225/500 PSI. NO DIRECTIONAL SURVEYS YET DUE TO MAGNETIC INTERFERENCE. 04:00 - 04:30 0.50 DRILL P PROD1 PULL OUT OF HOLE FROM 10286'MD TO WINDOW AT 10113'MD. NO HOLE ISSUES ENCOUNTERED. OPEN EDC AND FLOWCHECK WELL. WELL STATIC. PERFORM KICK WHILE TRIPPING DRILL AND HOLD MR. FOCUS OF DRILL IS ON COMMUNICATIONS AND ACCOUNTING OF PERSONNEL. ALL PERSONNEL ACCOUNTED FOR AND RESPOND CLEARLY/PROPERLY. RESPONSE FOR SHUBLIK GAS SCENARIOS REVIEWED. 04:30 - 06:30 2.00 DRILL P PROD1 PULL OUT OF HOLE FROM 7"WINDOW AT 10113'MD TO BHA AT 79'MD;3 BPM,80-100 FPM. HOLD PJSM NEAR SURFACE. 06:30 - 07:00 0.50 DRILL P PROD1 AT SURFACE. FLOW CHECK. GET OFF WELL. UNSTAB COIL. LD MOTOR AND MILL BIT 1-1-I 07:00 - 07:30 0.50 BOPSUR P PROD1 PERFORM WEEKLY FUNCTION TEST OF BOPS FROM RIG FLOOR CONTROL STATION. 07:30 - 08:30 1.00 DRILL P PROD1 MU 1.2 DEG INTEQ EXTREME MTR. RE RUN HYCALOG 4-1/4"BICENTER. STAB COIL. TEST MWD TOOLS.GET ON WELL. PT QT SUB TO 250 AND 3500 PSI. GOOD TEST. 08:30 - 10:00 1.50 DRILL P PROD1 OPEN EDC. RUN IN HOLE. CIRC AT MIN RATE. 0.54 BPM IN/1.02 BPM OUT. Printed 10/8/2012 1.31:06PM O North America -ALASKA- BP • Operation Summary Report . Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date:9/14/2012 X3-0129C-C: (2,554,817.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release:9/18/2012 Rig Contractor: NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 10:00 - 11:30 1.50 DRILL P PROD1 LOG GR TIE IN FROM 9440'. SUBTRACT 22' CORRECTION. CONTINUE TO LOG IN HOLE. FIND RA TAG AT 10118'. SLOW PUMP RATES AT 10286'MD,8.5 PPG: PUMP#1: 1428 PSI @ 1 BPM,1132 PSI @ 0.5 BPM PUMP#2: 1417 PSI @ 1 BPM,1115 PSI @ 0.5 BPM 11:30 - 15:00 3.50 DRILL P PROD1 DRILL AHEAD FROM 10.286' 2750 PSI FS AT 2.78 BPM IN/2.40 BPM OUT. 200-300 PSI MTR WORK DHWOB:3.97K# BHP/ECD/TVD:4540 PSI/9.86 PPG/8746'. IA/OA/PVT:265 PSI/385 PSI/VARIABLE. 15:00 - 18:00 3.00 DRILL P PROD1 DRILL AHEAD FROM 10,343'. 2790 PSI FS AT 2.77 BPM IN/2.30 BPM OUT. 200-250 PSI MTR WORK. 2-3K#DHWOB. DRILL TO 10375' 18:00 - 20:00 2.00 DRILL P PROD1 DIRECTIONAL DRILL 4-1/4"LATERAL HOLE SECTION FROM 10375'MD TO 10398'MD(23' IN 2 HRS= 12 FPH); SHUBLIK,-90°ROHS,2.7 BPM,213 BIT RPM,2850 PSI FREESPIN, 2900-2950 PSI,5 KLBS DHWOB,8.5 PPG MW IN/OUT, ECD=9.9 PPG. LOSSES TO FORMATION AVERAGE 20-25 BPH. IA/OA= 330/500PSI. CROSS PLANNED FAULT#1 AT 10398'MD. NO EXTRA LOSSES AFTER CROSSING FAULT. SHUBLIK FAULTED INTO TOP OF TSAD(UNCONFORMITY AT VERY TOP OF ZONE 4). 20:00 - 22:30 2.50 DRILL P PROD1 DIRECTIONAL DRILL 4-1/4"LATERAL HOLE SECTION FROM 10398'MD TO 10450'MD(52' IN 2.5 HRS=21 FPH);ZONE 4(TSAD UNCONFORMITY),-90°ROHS,2.7 BPM,213 BIT RPM,2850 PSI FREESPIN,3000-3100 PSI, 4-5 KLBS DHWOB,8.5 PPG MW IN/OUT, ECD= 9.9 PPG. LOSSES TO FORMATION AVERAGE 20-25 BPH. IA/OA=350/550PSI. 22:30 - 23:00 0.50 DRILL P PROD1 PERFORM WIPER TRIP FROM 10450'MD TO 7"LINER WINDOW BOTTOM AT 10121'MD. NO HOLE ISSUES ON UP PASS. ENCOUNTER SIGNS OF HOLE PACKING OFF ON RETURN TRIP IN HOLE. DECISION TO PULL UP INSIDE 7"LINER WINDOW TO CLEAN UP HOLE. 23:00 - 23:30 0.50 DRILL P PROD1 CIRCULATE BOTTOMS UP THROUGH OPEN EDC;3.5 BPM,2900 PSI. 23:30 - 00:00 0.50 DRILL N DPRB 10,113.00 PROD1 UNABLE TO PASS BACK DOWN THROUGH WINDOW. TAG INITIALLY AT 10114'MD WHIPSTOCK TRAY PINCH POINT. UNSUCCESSFULLY ATTEMPT VARIOUS MOTOR ORIENTATIONS AND PUMP RATES (CONTINUED ON NEXT REPORT UNTIL 01:00). SUCCESSIVE TAGS MOVE UP HOLE FROM 10114'MD TO 10109'MD. Printed 10/8/2012 1:31:06PM ` North America -ALASKA- BP " Page 11 of 17 Operation Summary Report Common Well Name:S-32 AFE No Event Type:RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date 9/14/2012 X3-0129C-C: (2,554,817.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 9/10/2012 00:00 - 01:00 1.00 DRILL N DPRB 10,113.00 PROD1 UNABLE TO PASS BACK DOWN THROUGH WINDOW. TAG INITIALLY AT 10114'MD WHIPSTOCK TRAY PINCH POINT. UNSUCCESSFULLY ATTEMPT VARIOUS MOTOR ORIENTATIONS(HIGHSIDE,90°LOHS, 180° 90°ROHS)AND PUMP RATES,0.3-0.75 BPM(CONTINUED ON NEXT REPORT UNTIL 01:00). SUCCESSIVE TAGS MOVE UP HOLE FROM 10114'MD TO 10109'MD. 01:00 - 03:30 2.50 DRILL N DPRB 10,113.00 PROD1 OPEN EDC AND CIRCULATE 2.5 BOTTOMS UP,4.2 BPM,3600 PSI. CIRCULATE 25 BBL HI-VIS SWEEP ROUND TRIP WITH 10-20% INCREASE IN CUTTINGS BACK AT SHAKERS. CLOSE EDC AND RETAG RESTRICTION AT 10108'MD(APPROXIMATE TOP OF • WHIPSTOCK TRAY);0.5 BPM. UNABLE TO MAKE PROGRESS CLEANING OUT WHIPSTOCK TRAY. DECISION TO PULL OUT OF HOLE FOR WINDOW MILLING ASSEMBLY TO CLEANOUT SUSPECTED FILL. RE-OPEN ' EDC AND FLOWCHECK WELL. WELL ON LOSSES. 03:30 - 05:00 1.50 DRILL N DPRB 10,113.00 PROD1 PULL OUT OF HOLE FROM 7"LINER WINDOW AT 10108'MD TO BHA AT 80'MD;60-100 FPH, 3.5 BPM. _ 05:00 - 06:00 1.00 DRILL N DPRB 10,113.00 PROD1 FLOW CHECK WELL AT BHA. WELL ON LOSSES. UNSTAB FROM WELL AND SETBACK INJECTOR. LAYDOWN BHA. GRADE BIT. 2-2-I. SEVERAL CHIPPED _ CUTTERS. 06:00 - 06:30 0.50 DRILL N DPRB 10,113.00 PROD1 CREW CHANGE. DISCUSS CURRENT OPERATIONS. ALSO DISCUSS EQUIPMENT STATUS. MAKE INSIDE AND OUTSIDE ROUNDS. 06:30 - 07:30 1.00 DRILL N DPRB 10,113.00 PROD1 MU INTEQ WINDOW MILLING BHA ON 1.2DEG MOTOR. INCLUDE USED WINDOW MILL AND STRING REAMER FROM ORIGINAL WINDOW MILLING RUN. HOLE REMAINING FULL DURING BHA CHANGE. STAB COIL. TEST TOOLS. GET ON WELL. PT QTS AT 300 AND 3970 PSI. PASSED. 07:30 - 09:30 2.00 DRILL N DPRB 10,113.00 PROD1 OPEN EDC. _RUN IN HOLE. CIRC AT MIN RATE. 09:30 - 10:00 0.50 DRILL N DPRB 10,113.00 PROD1 LOG GR TIE IN FROM 9830' SUBTRACT 21.5' CORRECTION. 10:00 - 11:30 1.50 DRILL N DPRB 10,113.00 PROD1 RIH THROUGH 7"LINER. 1132 PSI AT 0.51 BPM IN/0.46 BPM OUT. TAG FILL AT 10,108' PU. RIH AT 3 FPM. CIRC AT 2490 PSI AT 2.54 BPM IN/2.20 BPM OUT. NOTE 50-70 PSI MTR WORK FOR SEVERAL FEET IN WINDOW. CONTINUE TO CIRC IN HOLE TO 10,131'. NO ADDITIONAL MTR WORK NOTED. POOH CIRCULATING AT FULL RATE ABOVE WINDOW. RIH CIRCULATING TO 10,131'. CIRCULATE WHILE POOH THROUGH 7"AT 2.54 BPM. CONTINUE UP IN TO 4-1/2"TBG TO 9700'. RIH SLOWLY. SHUT DN PUMP. OPEN EDC. Printed 10/8/2012 1.31:06PM •• • Noah America -ALASKA- BP � Page 12 of 17 Operation Summary Report Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date:9/2/2012 End Date: 9/14/2012 X3-0129C-C:(2,554,817 00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase I Description of Operations (hr) -- (ft) 11:30 - 13.15 1.75 DRILL N DPRB 10,113.00 PROD1 CIRCULATE OUT OF HOLE AT 3.4 BPM. SLIGHT LOSSES DOWN HOLE. HOLD PJSM NEAR SURFACE. 13:15 - 14:00 0.75 DRILL N DPRB 10,113.00 PROD1 FLOW CHECK WELL. GET OFF WELL. UNSTAB COIL. LD ALL BHA TOOLS. 14:00 - 14:45 0.75 DRILL N DPRB 10,113.00 PROD1 MU LATERAL BHA WITH RESISTIVITY,2-7/8" XTREM MTR,AND HCC4.125"RE-BUILT `BICENTER. TAB COIL. TEST TOOLS. GET ON WELL. PT QTS TO 290 PSI AND 3950 PSI. PASSED. 14:45 - 16:30 1.75 DRILL N DPRB 10,113.00 PROD1 RUN IN HOLE. CIRC AT MIN RATE. 16:30 - 17:00 0.50 DRILL N DPRB 10,113.00 PROD1 LOG GR TIE IN FROM 9840'. -22' CORRECTION. 17:00 - 18:00 1.00 DRILL N DPRB 10413.00 PROD1 RUN IN HOLE. CLOSE EDC. RUN IN TO OPEN HOLE. SET DOWN AT 10,216'. PICK UP. OVER PULLTO 44K#(33K#NOMINAL UP WT). BACK REAM AT 8 FPM TO 10.135'. CIRCULATE BACK IN HOLE TO 10,450. 2443 PSI AT 2.33 BPM IN/2.37 BPM OUT HOLE CLEAN ON SECOND PASS DOWN. 18:00 - 19:00 1.00 DRILL N DPRB 10,113.00 PRODt COMPLETE ADDITIONAL WIPER TRIP FROM 10450'MD TO WINDOW AT 10113'MD. MINOR SIGNS OF PACKING OFF AROUND 10210'MD ON UP PASS(5 KLBS DRAG,100-200 PSI DIFFERENTIAL, FLUCTUATING RETURNS). NO SIGNS OF TROUBLE ON DOWN PASS. SLOW PUMP RATES AT 10450'MD,8.6 PPG: PUMP#1: 1538 PSI©1 BPM,1208 PSI ©0.5 BPM PUMP#2: 1483 PSI @ 1 BPM,1179 PSI @ 0.5 BPM 19:00 - 00:00 5.00 DRILL P PROD1 OIRECTIONAL DRILL 4-1/8"LATERAL MIL SECTION FROM 10452JMMDI0.10560 AT MIDNIGHT(110' IN 5 HRS=22 FPH),TOP OF ZONE 4 UNCONFORMITY,90°ROHS TO 180° TF,2.8 BPM,221 BIT RPM,2850 PSI FREESPIN,2950-3100 PSI,3-5 KLBS DHWOB, 8.6 PPG MW IN/OUT, ECD=9.9 PPG. LOSSES TO FORMATION AVERAGE 5-10 BPH. IA/OA= 100/75PSI. PUMP ONE 20 BBL HI-VIS SWEEP ROUND TRIP WHILE DRILLING AHEAD AT 10550'MD WITH 20%INCREASE IN CUTTINGS RETURNED OVER SHAKERS. BLEED IA ONCE FROM 500 TO 100 PSI AND OA ONCE FROM 500 TO 75 PSI AT 23:30. 9/11/2012 00:00 - 01:00 1.00 DRILL P PROD1 DIRECTIONAL DRILL 4-1/8"LATERAL HOLE SECTION FROM 10560'MD AT MIDNIGHT TO 10600'MD(40'IN 1 HR=40 FPH);TOP OF ZONE 4 UNCONFORMITY,2.8 BPM,221 BIT RPM,2900 PSI FREESPIN,3000-3200 PSI,3-4 KLBS DHWOB,8.6 PPG MW IN/OUT,ECD=9.9 PPG. LOSSES TO FORMATION AVERAGE<5 BPH. IA/OA=150/125PSI. 01:00 - 03:00 2.00 DRILL P PROD1 PERFORM PLANNED WIPER TRIP FROM 10600'MD TO WINDOW AT 10113'MD. NO HOLE ISSUES. PULL UP INSIDE LINER. OPEN EDC AND JET 197'7"LINER CLEAN AT 4 BPM. Printed 10/8/2012 1:31:06PM 'North America -ALASKA- BP • Page 13 of 17 Operation Summary Report Common Well Name:S-32 AFE No Event Type RE-ENTER-ONSHORE(RON) Start Date:9/2/2012 End Date: 9/14/2012 X3-0129C-C:(2,554,817.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time. 11/1/1990 12.00:OOAM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 03:00 - 05:00 2.00 DRILL P PROD1 DIRECTIONAL DRILL 4-1/8"LATERAL HOS SFGTION FROM 10600'Mr)TO 10750'MD-(150' IN 2 HRS=75 FPH);ZONE 4 PRODUCTIVE SAND,2.8 BPM,221 BIT RPM,3000 PSI FREESPIN,3100-3400 PSI,3-4 KLBS DHWOB, 8.6 PPG MW IN/OUT,ECD=10 PPG. LOSSES TO FORMATION AVERAGE<5 BPH. IA/OA= 350/250PS1. DROP BELOW UPPER ZONE 4 UNCONFORMITY AT 10618'MD INTO 6-7 OHM-M PRODUCTIVE ZONE 4 SAND. INSTANTANEOUS ROPS INCREASE FROM 20-40 FPH TO 100420 FPI-I. _ PUMP ONE 20 BBL HkVIS SWEEP ROUND TRIP WHILE DRILLING AHEAD AT 10725'MD WITH 20%INCREASE IN CUTTINGS RETURNED OVER SHAKERS. 05:00 - 07:00 2.00 DRILL P PROD1 PERFORM PLANNED WIPER TRIP FROM 10750'MD TO WINDOW AT 10113'MD. NO HOLE ISSUES. PULL UP INSIDE LINER,OPEN EDC AND JET 197'7"LINER CLEAN AT 4.2 BPM,3500 PSI. 07:00 - 09:00 2.00 DRILL P PROD1 DRILL AHEAD FROM 10,750'. 264C PSI FS AT 2 78 BPM IN/OUT. 200-300 PSI MTR WORK. IA/OA/PVT.430 PSI/328 PSI/358 BBLS. BHP/ECD/TVD:4654 PSI/10.10 PPG/8872'. 09:00 - 10:30 1.50 DRILL P PROD1 WIPER TRIP TO TBG TAIL. BUILD SECTION SMOOTH. OPEN EDC IN 7". CIRCULATE TO CLEAN SAME. CLOSE EDC. 10:30 - 11:00 0.50 DRILL P PROD1 LOG GR TIE IN FROM 10120'. SUBTRACT 5' CORRECTION. 11:00 - 13:00 2.00 DRILL P PROD1 DRILL TO 10910 FT. NOT GETTING ENOUGH DLS TO SATISFY DIRECTIONAL OBJECTIVES. 13:00 - 15:00 2.00 DRILL P PROD1 POOH. 15:00 - 15:30 0.50 DRILL P PROD1 TAG STRIPPER, FLOWCHECK WELL. L/D BHA. BIT IS 2-1, SOME CHIPPED CUTTERS. 15:30 - 16:00 0.50 DRILL P PROD1 CUT 50 FT OF CT FOR CHROME MANAGEMENT. 16:00 - 18:30 2.50 DRILL P PROD1 INSTALL CT CONNECTOR AND PULL TEST TO 35K INSTALL BHI CABLE HEAD, PRESSURE TEST IS GOOD. 18:30 - 19:30 1.00 BOPSUR P PROD1 PRESSURE TEST NEW BHI DUAL FLAPPER CHECK VALVES TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH(PASS,SEE ATTACHED CHART). Printed 10/8/2012 1:31.06PM " Page 14 of 17 North America-ALASKA- BP Operation Summary Report Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE (RON) Start Date:9/2/2012 End Date: 9/14/2012 X3-0129C-C: (2,554,817.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:OOAM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) •19:30 - 20:30 1.00 DRILL P PROD1 'MAKEUP BHA#7 FOR WELL(4-1/4"LATERAL (ASSEMBLY)AND SCRIBE IN HOLE TO BHA OAL 80'MD. STAB ON WELL WITH INJECTOR. PRESSURE TEST QUICK TEST SUB TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH(PASSING TESTS). -3-3/4"X 4-1/4"HYCALOG SRH3611 M-B4 BI-CENTER BIT,SER#A161943 -BHI 2-7/8"ULTRA LOW SPEED 1.4°BENT MUD MOTOR -3"COILTRAK TOOLS WITH RESISTIVITY 20:30 - 23:00 2.50 DRILL P PROD1 TRIP IN HOLE FROM BHA AT 80'MD TO 7" LINER WINDOW AT 10113'MD;0.35 BPM,100 FPM. SET DOWN AT TOP OF WHIPSTOCK. SUCCESSFULLY PASS THROUGH WINDOW ON 5TH ATTEMPT AT 10°LOHS TF AND AT 40 FPH,0.3 BPM. LOG KINGAK JB MARKER AT 9908'MD FOR GR TIE-IN. APPLY-19'CORRECTION (CAPARED TO-22'CORRECTION ON LAST RUN). 23:00 - 00:00 1.00 DRILL P PROD1 TRIP IN HOLE FROM 7"LINER WINDOW AT 10113'MD TO TAG BOTTOM AT 10900'MD (-10'HIGHER THAN PREVIOUSLY DRILLED TO MD). ONLY ONE TIGHT SPOT(NOTED BELOW). TIGHT SPOTS ENCOUNTERED IN SHUBLIK 10200'MD TO 10250'MD. 60 KLBS PICKUP REQUIRED TO PULL FREE ONCE. CIRCULATED AROUND ONE 20 BBL HI-VIS SWEEP ONCE PAST 10250'MD TROUBLE ZONE WITH NO INCREASE IN CUTTINGS ACROSS SHAKERS. SLOW PUMP RATES AT 10910'MD,8.6 PPG: PUMP#1: 1794 PSI @ 1 BPM,1472 PSI @ 0.5 BPM PUMP#2: 1780 PSI @ 1 BPM,1501 PSI @ 0.5 BPM 9/12/2012 00:00 - 07.30 7.50 DRILL P PROD1 DIRECTIONAL DRILL 4-1/4"LATERAL HOLE SECTION FROM 10910'MD AT MIDNIGHT TO 11050'MD(115' IN 7.5 HRS= 19 FPH);ZONE 4 PRODUCTIVE SAND,2.8 BPM,221 BIT RPM, 3080 PSI FREESPIN,3100-3350 PSI.1-3 KLBS DHWOB,8.6 PPG MW IN/OUT, ECD= 10.1 PPG. LOSSES TO FORMATION AVERAGE<5 BPH. IA/OA=450/300 PSI. PUMP ONE 20 BBL HI-VIS SWEEP ROUND TRIP WHILE DRILLING AHEAD AT 10725'MD WITH 10% INCREASE IN CUTTINGS RETURNED OVER SHAKERS. 05:00-DISPLACE WELL OVER TO NEW 8.5 PPG POWERPRO MUD AND NOTICE INCREASE IN ROP FROM 20-50 FPH,WITH FEWER STICK-SLIP SIGNS. DRILL TO 11050 FT. Printed 10/8/2012 1;31:06PM • 'North America -ALASKA- BP • Page 15 of 17 Operation Summary Re•ort Common Well Name:S-32 AFE No Event Type. RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date: 9/14/2012 X3-0129C-C:(2,554,817.00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.:NORDIC 2 Spud Date/Time: 11/1/1990 12.00:OOAM Rig Release:9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 07:30 - 09:00 1.50 DRILL P PROD1 WIPER TRIP FROM 11050 FT TO WINDOW SLIGHT MOTOR WORK GOING THROUGH SHALES AT 10250-10200 FT. AFTER WIPER TRIP GET SPP ABOUT 50 FT OFF BOTTOM. PUMP#1 0.5 BPM= 1150 PSI,1.0 BPM= 1425 PSI. -PUMP#2 0.5 BPM= 1150 PSI,1.0 BPM= 1420 PSI. 09:00 - 12:45 3.75 DRILL P PROD1 TAG BOTTOM AND DRILL FROM 11050 FT. CONTINUE HOLDING 93 DEG INC FOR NOW. ROP INCREASES AFTER 11120 FT. DRILL TO 11200 FT. 12:45 - 14:00 1.25 DRILL P PROD1 WIPER TRIP FROM 11200 FT TO TUBING TAIL REDUCE PUMP RATE PULLING THROUGH WINDOW. PERFORM JOG ABOVE WHIPSTOCK THEN OPEN EDC. CLEAN 7"TUBING AT 3.5 BPM. 14:00 - 15:00 1.00 DRILL P PROD1 CLOSE EDC AND PASS THOUGH WINDOW. STACK WT 3 TIMES FINALLY GET THROUGH AT 15R 15 FT/MIN. RIH. STACK WT TWICE AT 10175 FT WITH _CORRECT TOOLFACE. PICK UP AND REDUCE PUMP RATE TO 1.3 BPM. 15:00 - 18:00 3.00 DRILL P PROD1 CONTINUE DRILLING FROM 11200 FT. CONTINUE TO HOLD 93 DEG INC. ROP AROUND 40-60 FT/HR. DRILL TO 11300'. 18:00 - 22:30 4.50 DRILL P PROD1 DIRECTIONAL DRILL 4-1/4"LATERAL HOLE SECTION FROM 11300'MD TO 11366'MD(66' IN 4.5 HRS=15 FPH);2.7 BPM,213 BIT RPM, 2515 PSI FREESPIN,2750-3100 PSI,3-5 KLBS DHWOB,8.6 PPG MW IN/OUT,ECD=10.0 PPG. LOSSES TO FORMATION AVERAGE<5 BPH. IA/OA=650/450 PSI. WELLPATH HAS EXITED TOP OF ZONE 4 PRODUCTIVE SAND AND IS IN UPPER ZONE 4 UNCONFORMITY. ATTEMPTING TO DROP ANGLE TO RE-ENTER ZONE 4 SAND. SLOW PUMP RATES AT 11300'MD,8.6 PPG: PUMP#1: 1425 PSI @ 1 BPM,1223 PSI @ 0.5 BPM PUMP#2. 1428 PSI @ 1 BPM,1230 PSI @ 0.5 BPM 22:30 - 00:00 1.50 DRILL P PROD1 COMPLETE PLANNED WIPER TRIP FROM 11366'MD TO 7"LINER WINDOW AT 10113' MD. NO HOLE ISSUES ON UP PASS. ONE MINOR TIGHT SPOT ON DOWNPASS AT 10190'MD. ABLE TO WORK THROUGH AT 40 FPM. LOG WHIPSTOCK RA TAG AND APPLY+10' CORRECTION. Printed 10/8/2012 1:31:06PM North America-ALASKA- BP Page 16 of 17 • Operation Summary Re•ort Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date:9/2/2012 End Date:9/14/2012 X3-0129C-C:(2,554,817.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release:9/18/2012 Rig Contractor: NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code I NPT NPT Depth Phase Description of Operations (hr) (ft) 9/13/2012 00:00 - 06:00 6.00 DRILL P PROD1 DIRECTIONAL DRILL 4-1/4"LATERAL HOLE SECTION FROM 11366'MD AT MIDNIGHT TO 11500'MD(134'IN 6 HRS=22 FPH);2.7 BPM, 213 BIT RPM,2515 PSI FREESPIN,3000-3200 PSI,3-4 KLBS DHWOB,8.6 PPG MW IN/OUT, ECD= 10.1 PPG. LOSSES TO FORMATION AVERAGE<5 BPH. IA/OA=800/600 PSI. 06:00 - 08:15 2.25 DRILL P PROD1 WIPER TRIP FROM 11500 FT TO WINDOW. MOSTLY CLEAN PASS UP,SLIGHT WEIGHT FLUCTUATIONS GOING THROUGH SHALES JUST OUTSIDE WINDOW. PULL THROUGH WINDOW AND PERFORM JOG,THEN OPEN EDC. BLEED IA AND OA EACH TO 100 PSI. 08:15 - 11:00 2.75 DRILL P PROD1 CONTINUE DRILLING FROM 11500 FT. REDUCE INC TO 81 DEG TO GET TO TARGET SANDS FASTER. 2.69/2.66 BPM @ 2600 PSI FREE SPIN. ROP IS 60-90 FT/HR WITH 1K DWOB. DRILL TO 11650 FT. 11:00 - 12:45 1.75 DRILL P PROD1 WIPER TRIP FROM 11650 FT TO WINDOW. CLEAN PASS UP AND DOWN. 12:45 - 21:00 8.25 DRILL P PROD1 DIRECTIONAL DRILL 4-1/4"LATERAL HOLE SECTION FROM 11650'MD TO 11790'MD(140' IN 8.25 HRS=17 FPH); HOLDING 83°INC TO MATCH FORMATION DIP,2.8 BPM,221 BIT RPM,2700 PSI FREESPIN,2900-3200 PSI,1-4 KLBS DHWOB,8.7 PPG MW IN/OUT, ECD= 10.3 PPG. LOSSES TO FORMATION AVERAGE<5 BPH. IA/OA=500/475 PSI. PERIODIC WEIGHT STACKING ISSUES. 21:00 - 23:30 2.50 DRILL P PROD1 COMPLETE PLANNED WIPER TRIP FROM 11790'MD TO 7"LINER WINDOW AT 10113' MD. PULL UP INSIDE WINDOW AND CIRCULATE BOTTOMS UP TO CLEAN UP 7" ✓ LINER WHILE RECIPROCATING UP INSIDE 4-1/2"TUBING TAIL;4.5 BPM,3650 PSI. 34 KLBS PICKUP OFF BOTTOM,16 KLBS SLACKOFF. SEVERAL 5-10 KLB OVERPULLS THROUGH 10650'MD-10550'MD INTERVAL ON UP PASS. NO ISSUES ON DOWN PASS. LOG KINGAK JB MARKER AND APPLY+4' CORRECTION. 23:30 - 00:00 0.50 DRILL P PROD1 DIRECTONAL DRILL 4-1/4"LATERAL HOLE SECTION FROM 11790'MD TO 11795'MD AT MIDNIGHT(DRILLING CONTINUES ON 9/14/12). PERFORM KICK WHILE DRILLING DRILL WITH PROPER RESPONSE FROM ALL CREWMEMBERS. Printed 10/8/2012 1:31:06PM e North America -ALASKA- BP Operation Summary Report Common Well Name:S-32 AFE No Event Type: RE-ENTER-ONSHORE(RON) Start Date: 9/2/2012 End Date: 9/14/2012 X3-0129C-C: (2,554,817.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.:NORDIC 2 Spud Date/Time: 11/1/1990 12.00:OOAM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) _ 9/14/2012 00:00 - 03:00 3.00 DRILL P PROD1 DIRECTIONAL DRILL 4-1/4"LATERAL HOLE SECTION FROM 11795'MD AT MIDNIGHT TO 11840'MD,8991'TVD,WELL TOTAL DEPTH (45'IN 3 HRS=15 FPH);2.71315M,213 BIT RPM, 2700 PSI FREESPIN,2750-2850 PSI,1-3 KLBS DHWOB,8.7 PPG MW IN/OUT,ECD=10.3 PPG. LOSSES TO FORMATION AVERAGE<5 BPH. IA/OA=530/505 PSI. PERIODIC WEIGHT STACKING ISSUES. DURING ROUTINE PICKUP AT 11840'MD, DRILLSTRING WAS DIFFERENTIALLY STUCK IN BHA BELOW OWNHOLE PERFORMANCE SUB(DPS)AND ABOVE HYDRAULIC ORIENTING TOOL(HOT). FULL RETURNS WERE MAINTAINABLE AT 2.7 BPM,2700 PSI. UNSUCCESSFULLY ATTEMPTED TO PICKUP IN INCREMENTS TO 80 KLBS THREE TIMES PRIOR TO SHUTTING DOWN PUMPS. 03:00 - 04:00 1.00 DRILL N DPRB 11,840.00 PROD1 PER COILED TUBING STUCK PIPE PROCEDURE, SHUT DOWN PUMPS TO RELAX HOLE. WELLBORE FLUID LEVEL REMAINED STATIC. WAIT FOR 20 MINS WITH PUMPS -DOWN.ORDER 50 BBLS MINERAL OIL. AFTER 20 MINS,WORK PIPE DOWN AND UP TWICE. PIPE PULLS FREE ON SECOND UP ATTEMPT TO 80 KLBS PICKUP WEIGHT. DECISION WITH WELLSITE GEO TO CALL TD AT 11840'MD. 04:00 - 06:00 2.00 DRILL P PROD1 COMPLETE PLANNED WIPER TRIP FROM WELL TOTAL DEPTH 11840'MD TO 7"LINER WINDOW AT 10113'MD. 34 KLBS PICKUP OFF BOTTOM,16 KLBS SLACKOFF. NO HOLE ISSUES ON UP PASS. LOG WHIPSTOCK RA TAG AND APPLY+9' CORRECTION. RE-TAG BOTTOM AND CORRECT WELL TOTAL DEPTH TO 11848'MD, 8991'TVD. 06:00 - 08:45 2.75 DRILL P PROD1 PULL OUT OF HOLE FROM WELL TOTAL DEPTH AT 11848'MD, LAYING IN CLEAN 8.5 PPG LINER IN OPENHOLE,30 FPM. CONDUCT PJSM FOR LD BHA WHILE TRIPPING. 09:30 - 10:30 1.00 DRILL P PROD1 TAG STRIPPER,FLOWCHECK WELL. FLOW CHECK SHOWS NO FLOW. OPEN RISER. UD BHA. BIT IS 1-1, ONE MISSING CUTTER ON THE SIDE APPEARS TO HAVE BROKEN OFF. END DRILLING EVENT AT 10:30 AM ON 9/14/12. BEGIN COMPLETION EVENT. Printed 10/8/2012 1:3106PM North America-ALASKA- BP Page 1 of B Y Operation Summary ary"Report Common Well Name:S-32 AFE No Event Type:COM-ONSHORE(CON) Start Date:9/14/2012 End Date:9/18/2012 'X3-0129C-C:(1,577,340.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release:9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 9/14/2012 10:30 - 11:30 1.00 CASING P RUNPRD BEGIN COMPLETION EVENT AT 10:30 WITH NORDIC 2 CTD RIG. INSTALL NIGHT CAP,CIRC ACROSS TOP WHILE PREP FOR RUNNING LINER. PJSM THEN PICK UP INJECTOR AND REMOVE BHI CABLE HEAD. PUMP OUT 200 FT OF E-LINE CABLE,THE SPREADSHEET TALLY LISTED 241 FT OF EXCESS CABLE. CUT 10'COIL(NEW COIL LENGTH= 13485', 11:30 - 12:30 1.00 CASING P RUNPRD INSTALL CT CONNECTOR, PULL TEST TO 35K,GOOD. PRESSURE TEST 300/3500 PSI, GOOD. 12:30 - 13:30 1.00 CASING P RUNPRD M/U CT RISER TO PUMP 3/4"DRIFT BALL AROUND. PUT BALL IN REEL, LAUNCH WITH 1000 PSI. NO INDICATION OF BALL ROLLING. PUMP A CT VOLUME AT 3.5 BPM. OPEN CT RISER AND REMOVE NOZZLE, NO BALL. 13:30 - 14:00 0.50 CASING P RUNPRD M/U NOZZLE AND CT RISER. RE-LAUNCH WITH 1500 PSI. BALL ISN'T HEARD. OPEN 1502 CAP ON BALL DROP AND PUSH HOSE DOWN, FIND PIECES OF POLYMER IN THE BALL DROP THAT COULD HAVE HUNG THE BALL UP. RE-LAUNCH, BALL IS HEARD ROLLING. PUMP AROUND AT 3.5 BPM. 14:00 - 16:30 2.50 CASING P RUNPRD OPEN CT RISER AND REMOVE NOZZLE, RECOVER 3/4 BALL. SET INJECTOR ON LEGS. PREP RIG FLOOR FOR RUNNING LINER. PJSM FOR MAKE UP LINER. 16:30 - 23:00 6.50 CASING P RUNPRD M/U LINER AS PER TALLY. DRIFT FIRST 5 CONNECTIONS OF 2-7/8 AND 3-1/4. 23:00 - 00:00 1.00 CEMT P RUNPRD 'MAKEUP 2-3/8"COILED TUBING TO LINER AND STAB ON WELL WITH INJECTOR. PRESSURE TEST QUICK TEST SUB TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH(PASSING TESTS). CONFIRM BHA LENGTH IN C-CAT. BREAK CIRCULATION AT 0.3 BPM,1275 PSI. 9/15/2012 00:00 - 02:15 2.25 CASING P RUNPRD RUN 3-1/2"X 3-1/4"X 2-7/8"PRODUCTION _ LINER ON 2-3/8"COILED TUBING FROM LINER TOTAL LENGTH AT 1990'MD TO 7"LINER WINDOW FLAG AT 10030'MD;60-100 FPM,0.3 BPM,1600 PSI CORRECT DEPTH TO FLAG (-10'). CONTINUE IN HOLE WITH LINER AND TAG BOTTOM AT 11857'MD(<10'VARIATION FROM PLANNED SETTING DEPTH AT 11848' MD). FINAL PICKUP WEIGHT=43 KLBS, SLACKOFF=10 KLBS. Printed 10/8/2012 1:31:32PM North America-ALASKA-BP Page 2 of 8 Operation Summary Report Common Well Name:S-32 AFE No Event Type:COM-ONSHORE(CON) Start Date:9/14/2012 End Date: 9/18/2012 X3-0129C-C. (1,577,340.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.. NORDIC 2 Spud Date/Time 11/1/1990 12.00.00AM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 02:15 - 03:00 0.75 CASING P RUNPRD STACK 10 KLBS WEIGHT DOWN ON LINER AND ESTABLISH CIRCULATION WITH FULL RETURNS AT 2 BPM,2550 PSI. 103-00 - 04:00 1.00 CASING P RUNPRD PUMP 5 BBLS 8.4 PPG KCL DOWN COIL. LAUNCH 5/8"STEEL BALL WITH 1500 PSI. DISPLACE BALL WITH KCL AT 2 BPM. AT 35 BBLS AWAY(70%COIL VOLUME),SLOW "'RATE TO 0.5 BPM. LAND BALL AT 40 BBLS AWAY(80%COIL VOLUME). PRESSURE UP TO 4450 PSI BEHIND BALL TO SHEAR OFF LINER. 04:00 - 04:30 0.50 CASING P RUNPRD PICKUP TO BREAKOVER WEIGHT AT 29 KLBS +3'TO CONFIRM COIL IS RELEASED FROM LINER. NEW PICKUP WEIGHT IS 14 KLBS LESS THAN WITH LINER. STACK 10 KLBS BACK DOWN ON LINER. 04:30 - 07:30 3.00 CASING P RUNPRD DISPLACE WELL FROM 8.7 PPG POWERPRO MUD TO 8.4 PPG 1%KCL. FINAL CIRCULATION PRESSURE AT 1.5 BPM=500 PSI. LOAD PITS WITH KCL AND BUILD 120 BBLS BIOZAN KCL. MOVE IN AND RIG UP SLB _ CEMENTERS. 07:30 - 08:00 0.50 CASING P RUNPRD PJSM WITH SLB CEMENTING CREW AND RIG CREW FOR PUMPING CEMENT. PRESSURE TEST CEMENTING LINES TO 250 PSI LOW AND 6000 PSI HIGH FOR FIVE MIN EACH TO LEAKTIGHT CRITERIA(PASSING TESTS). 08:00 - 08:45 0.75 CASING P RUNPRD BATCH UP 27.9 BBLS 15.83 CLASS G CEMENT. ✓ PUMP 5 BBLS BIOZAN AHEAD WITH RIG PUMP THEN SHUT DOWN. SLB PUMP UNIT PUT 27.9 BBLS CEMENT INTO rµ/ REEL,THEN SHUT DOWN. CLEAN UP LINE GOING BACK TO SLB PUMP UNIT WET CEMENT SAMPLE SENT BACK TO LAB FOR UCA ANALYSIS. 08:45 - 09:15 0.50 CASING P RUNPRD START RIG DISPLACEMENT WITH 120 BBLS BIOZAN SLOW DOWN PUMP WHEN LEADING EDGE OF CEMENT IS AT THE SELRT. ZERO OUT MM WHEN CEMENT EXITS THE SHOE 09:15 - 09:45 0.50 CASING P RUNPRD PICK UP 13 FT THEN SET BACK DOWN 10K. NOW 10 FT HIGHER. BRING PUMP ON SLOWLY TO PUSH PEE WEE DART DOWN. PUMP 2 BBLS PEE WEE DART NOT ENGAGED DISCUSS WITH CTD SUPT AND BTT IN DEADHORSE. DECISION IS MADE TO CONTINUE ON WITH THE JOB. PICK UP AND SIDE EXHAUST 5 BBLS.THEN SET DOWN. PRESSURE UP AND LAUNCH LWP AT 3500 PSI. PUSH IT TO BOTTOM AT 2 BPM, THEN GO TO 1.5 BPM WHEN RETURNS FALL OFF. Printed 10/8/2012 1 31.32PM • North America -ALASKA- BP ! Page 3 of 8 Operation Summary Report Common Well Name:S-32 AFE No Event Type:COM-ONSHORE(CON) Start Date:9/14/2012 End Date: 9/18/2012 X3-0129C-C: (1,577,340.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:OOAM Rig Release:9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3©68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 09:45 - 10:05 0.33 CASING P RUNPRD BUMP PLUG AT 13.9 BBLS(13.7 BBLS CALCULATED)HOLD 1000 PSI OVER CIRC PRESSURE, HOLDING GOOD. OPEN BAKER CHOKE AND CHECK FLOATS, HOLDING. ESTIMATED CEMENT BEHIND PIPE IS 20.6 BBLS,AGAINST 25.8 BBLS PUMPED. CEMENT IN PLACE AT 10:05. TOC ESTIMATED BETWEEN TOL AT 9858'MD AND WINDOW AT 10113'MD BASED ON EXCESS PUMPED AND LOSSES DURING JOB- OPENHOLE EXCESS VOLUME PUMPED= 40%,5.6 BBLS. CEMENT AT 1500 PSI COMPRESSIVE STRENGTH AT 21:00. 10:05 - 10:10 0.08 CASING N DPRB 11,84.8.00 RUNPRD WHILE CHECKING FLOATS,RETURNS FROM WELL ARE NOTICED, SHOULD BE NO RETURNS AT THIS POINT OF THE JOB. WELL FLOWS BACK 1.3 BBLS. SHUT IN WELL AT CHOKE HCR,MAKE NOTIFICATION TO CTD SUPT. LINE UP WELL TO A CLOSED CHOKE TO READ PRESSURES. INITIAL WHP=250 PSI,CT PRESSURE=550 "PSI. f 10:10 - 10:15 0.08 CASING N DPRB 11,848.00 RUNPRD UNSTING CT FROM DEPLOYMENT SLEEVE AND PICK UP 20 FT. WHP=132 PSI,CT PRESSURE=278 PSI. START EXHALE TEST FOR WELLBORE BREATHING. BLEED OFF 0.8 BBLS THEN FLOW STOPS. FINAL WHP=18 PSI,CT PRESSURE=187 PSI. RDMO SLB CEMENTERS. 10:15 - 11:00 0.75 CASING N DPRB 11,848.00 RUNPRD LEAVE WELL OPEN,FLOW CHECK. NO FLOW FOR 40 MIN. 11:00 - 12:30 1.50 CASING N DPRB 11,848.00 RUNPRD START CIRC BOTTOMS UP AT 1 BPM HOLDING 200 PSI WHP. STARTING PVT=340 BBLS. RECIP PIPE ABOVE LINER TOP SLOWLY. STING INTO LINER ONCE TO ENSURE LINER TOP IS CLEAN. 12:30 - 13:10 0.67 CASING N DPRB 11,848.00 RUNPRD OUT DENSITY CLIMBS TO 8.6 PPG,THEN DOWN TO 8.2 PPG. LINE UP TO TAKE RETURNS OUT TO TIGER TANK. CONTINUE PUMP B/U OUT TO TIGER TANK. WHEN RETURNS CLEAN UP,LINE UP THROUGH MGS. 13:10 - 14:10 1.00 CASING N DPRB 11,848.00 RUNPRD LINE UP THROUGH MGS. HOLD 200 PSI WHP INITIALLY THEN OPEN HAND CHOKE. PUMP 2.7 BPM/2 7 BPM FOR AN ADDITIONAL B/U. STARTING PVT=368 BBLS. Printed 10/8/2012 1:31:32PM North America-ALASKA- BP Operation Summary Report Common Well Name:S-32 AFE No Event Type: COM-ONSHORE(CON) Start Date: 9/14/2012 End Date: 9/18/2012 X3-0129C-C: (1,577,340.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3©68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 14:10 - 15:50 1.67 CASING N DPRB 11,848.00 1 RUNPRD AFTER 1.1 B/U STOP AND FLOW CHECK WELL. WELL IS FLOWING SLIGHTLY. CHECK MUD WEIGHT,8.4 PPG OUT OF WELL AND 8.5 PPG IN THE SUCTION PIT. LIKELY U-TUBING. SHUT IN CT, FLOW GOES DOWN TO A DRIP AFTER SOME TIME. DISCUSS PLAN FORWARD WITH WTL,AGREE TO POOH PUMPING 2.6 BPM ON THE WAY OUT. 15:50 - 18:00 2.17 CASING P RUNPRD PULL OUT OF HOLE FROM LINER TOP AT 9858'MD TO BHA AT 140'MD,REPLACING VOIDAGE+0.5 BPM. TRIP SHEET IS EVEN FOR TOTAL TRIP. 18:00 18:30 0.50 CASING P RUNPRD FLOWCHECK WELL FOR 30 MIN PRIOR TO BHA ENTERING STACK. WELL STATIC. HOLD PRE-JOB MEETING FOR LAYING DOWN BHA. 18:30 - 19:30 1.00 CASING P RUNPRD UNSTAB FROM WELL AND SETBACK INJECTOR.RECOVER AND CUTOFF 10' E-LINE. INSPECT AND LAYDOWN LINER RUNNING ASSEMBLY. RECOVER 5/8"BALL FROM SELRT TOOLS WHICH ALL APPEAR TO HAVE FUNCTIONED PROPERLY. CEMENT NOTED ON EXTERIOR OF SELRT TOOLS AND PH-6 JOINTS. 19:30 - 21:00 1.50 BOPSUR P RUNPRD CLOSE SWAB VALVE,MAKEUP NOZZLE ASSEMBLY TO COIL,STAB ON WELL WITH INJECTOR,AND JET BOP STACK CLEAN WITH THREE PASSES. 21:00 - 22:00 1.00 BOPSUR N DPRB 11,848.00 RUNPRD PRESSURE TEST HCR AND INJECTOR PACKOFF TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH(PASSING TESTS. SEE ATTACHED CHART) FOLLOWING WELL SHUT-IN EVENT UNSTAB FROM WELL AND SETBACK INJECTOR ON LEGS RE-OPEN SWAB VALVE. PRESSURE TEST BAKER DOUBLE BACK PRESSURE VALVE SUB FOR CLEANOUT LOGGING RUN TO 250 PSI LOW AND 3500 PSI HIGH FIVE MIN EACH(PASSING TESTS;SEE ATTACHED CHART). 22:00 - 00:00 2.00 EVAL P OTHCMP MAKEUP LOGGING BHA AND RUN IN HOLE FROM SURFACE TO 825'MD AT MIDNIGHT -RE-RUN HCC D331 2.30"MILL -2-1/8"X-TREME STRAIGHT MUD MOTOR -SLB GR/CCUCNL LOGGING TOOLS (MARKER PUP INSTALLED FOR 300' WARNING) -TWO DISCONNECTS AND ONE CIRC SUB -BHA OAL=2301' REVIEW DISPENSATION FOR NON-SEABLE EQUIPMENT. HOLD KICK WHILE TRIPPING DRILL. STAB SAFETY VALVE AND SECURE WELL IN 3 MIN. HOLD MR. Printed 10/8/2012 1:31:32PM • North America -ALASKA- BP • a' Page 5 of 8 Operation Summa Re•ort z .. . Common Well Name:S-32 1 AFE No Event Type:COM-ONSHORE(CON) Start Date: 9/14/2012 End Date:9/18/2012 X3-0129C-C: (1,577,340.00) Project: Prudhoe Bay Site:PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 9/16/2012 00:00 - 03:00 3.00 EVAL P OTHCMP MAKEUP LOGGING BHA AND RUN IN HOLE FROM 825'MD AT MIDNIGHT TO BHA OAL AT 2301'MD. -RE-RUN HCC D331 2.30"MILL -2-1/8"X-TREME STRAIGHT MUD MOTOR -SLB GR/CCUCNL LOGGING TOOLS (MARKER PUP INSTALLED FOR 300' WARNING) -69 JTS 1-1/4"CSH,TWO DISCONNECTS AND ONE CIRC SUB 03:00 - 03:30 0.50 EVAL P OTHCMP MAKEUP 2-3/8"COILED TUBING TO LOGGING/CLEANOUT BHA AND STAB ON WELL WITH INJECTOR. PRESSURE TEST QUICK TEST SUB TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH(PASSING TESTS). 03:30 - 05:30 2.00 EVAL P OTHCMP RUN IN HOLE WITH 2.30"MILL CLEANOUT/LOGGING ASSEMBLY FROM BHA AT 2301',MD TO 9925'MD;0.45 BPM,375 PSI. PRESSURE AT 1.3 BPM=1375 PSI. CONFIRM ABILITY TO ENTER LINER. NO SIGN OF CEMENT ON TRIP IN HOLE. PULL BACK UP HOLE TO LOGGING DEPTH AT 9650'MD. 05:30 - 06:50 1.33 _ EVALP OTHCMP 'LOG DOWN FROM 9650'MD TO TAG DEPTH AT 11825 FT MD;30 FPM,1.3 BPM,1375 PSI. PICK UP AND REPEAT,TAG AT SAME DEPTH WITH MOTOR WORK. 06:50 - 07:40 0.83 EVAL ' P OTHCMP LOG UP 60 FT/MIN LAYING IN PERF PILL. FLAG PIPE AT 9199 FT EOP ON THE WAY OUT. 07:40 - 08:00 0.33 EVAL P OTHCMP LOG UP TO 9624 FT. FLOW CHECK WELL. TRIP SHEET IS EVEN FROM TD TO THIS POINT. FLOW CHECK IS NEGATIVE. 08:00 - 09:30 1.50 EVAL P OTHCMP POOH,PUMP 1.3 BPM ON THE WAY OUT. 09:30 - 10:00 0.50 EVAL P OTHCMP TAG STRIPPER AND FLOWCHECK WELL. PJSM FOR STANDING BACK CSH. FLOW CHECK IS NEGATIVE. 10:00 - 13:00 3.00 EVAL P OTHCMP UD 2 JTS OF PH6 AND STAND BACK 1.25 CSH. CONDUCT KICK DRILL WHILE STANDING BACK CSH. 13:00 - 13:10 0.17 EVAL P OTHCMP STOP PULLING PIPE AT THE MARKER JOINT, 5 STANDS FROM BOTTOM. PJSM WITH THE SLB LOGGER AND RIG CREW. 13:10 - 14:10 1.00 EVAL P OTHCMP PULL REMAINING 5 STDS AND THE LOGGING TOOLS OUT. PROCESS AND ANALYZE LOGGING DATA. FROM POINT FORWARD, NEW LINER SET DEPTH IS 11845'MD. LINER PBTD IS 11808' MD. 14:10 - 15:40 1.50 CASING P RUNPRD PREP FOR LINER LAP TEST AND LOAD PERF � GUNS INTO PIPE SHED. t LINER LAP TEST PASSES LOW PRESSURE, FAILS HIGH PRESSURE TEST. DISCUSS RESULTS WITH WTL,CONTINUE WITH WELL PLAN. Printed 10/8/2012 1:31:32PM • North America-ALASKA- BP 411 Page 6 of 8 Operation Summary Report Common Well Name:S-32 AFE No Event Type: COM-ONSHORE(CON) Start Date:9/14/2012 End Date: 9/18/2012 'X3-0129C-C: (1,577,340.00) Project:Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:OOAM 'Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 15:40 - 16:40 1.00 PERFOB P OTHCMP PREP RIG FLOOR FOR M/U PERF GUNS. PJSM FOR M/U PERF GUNS. 16:40 - 20:30 3.83 PERFOB P OTHCMP M/U 49 PERF GUNS AND 32 JTS 1.25"CSH. CONDUCT KICK DRILL WHILE M/U PERF GUNS. MAKEUP PERFORATING BHA TO COILED TUBING AND STAB ON WELL WITH INJECTOR. PRESSURE TEST QTS TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH (PASSING TESTS). 20:30 - 23:30 3.00 PERFOB P OTHCMP RUN IN HOLE WITH PERFORATING ASSEMBLY FROM BHA AT 2146'MD TO FLAG AT 11347 MD(APPLY-17'CORRECTION. CONTINUE IN HOLE AND TAG PBTD AT 11809.5'MD(CORRECT DEPTH TO LOGGING PBTD AT 11807.6'MD. PICKUP TO 11731.9' MD(1'BELOW BOTTOM PERF DEPTH)AND ESTABLISH BASELINE CIRCUATION RATES AT 0.45 BPM,185 PSI,1.55 BPM,1440 PSI. PICKUP WEIGHT AT DEPTH=34 KLBS, SLACKOFF=18 KLBS. 23:30 - 00:00 0.50 PERFOB P OTHCMP COMPLETE E-FIRE PERFORATING SEQUENCE. FIRE GUNS AT 23:53 WHILE PULLING UP HOLE AT 10 FPM. POSITIVE INDICATIONS OF SHOTS FIRING INCLUDE: (1) • 5 BBL FLUID LOSS AND(2)POSITIVE DETECTION ON SEISMIC SENSOR. PERFORATION INTERVALS(280'NET 46P IN ZONE 4A): 10700'-10750'MD 10770'-10780'MD 11065'-11085'MD 11250'-11300'MD 11700'-11730'MD 9/17/2012 00:00 - 00:30 0.50 PERFOB P • OTHCMP PULL OUT OF HOLE,HOLDING 250 PSI BACKPRESSURE WITH CHOKE,FROM PERF DEPTH AT 11730'MD TO TOP OF LINER AT 9855'MD,40 FPM,1 BPM. TRIP SHEET IS EVEN TO TOP OF LINER AFTER INITIAL 5 BBL LOSS TO PERFS. NO OVERPULLS IN LINER AND NO SIGNS OF SWABBING. 00:30 - 01:00 0.50 PERFOB P OTHCMP FLOWCHECK WELL FOR 30 MINUTES PER PERFORATING RP. WELL IS STATIC. 01:00 - 02:30 1.50 PERFOB P OTHCMP PULL OUT OF HOLE FROM TOP OF LINER AT 9855'MD TO BHA AT 2150'MD;80-90 FPM,NO BACK PRESSURE HELD ON WELL,1.35 BPM 1050 PSI. 02:30 - 03:00 0.50 PERFOB P OTHCMP FLOWCHECK WELL FOR 30 MINUTES PER PERFORATING RP. WELL IS STATIC. 03:00 - 04:00 1.00 PERFOB P OTHCMP UNSTAB FROM WELL AND SET INJECTOR BACK PULL OUT OF HOLE FROM TOP OF BHA AT 2150' MD TO TOP OF PER GUNS AT 1045'MD RACKING BACK 1-1/4"CSH WORKSTRING HOLD KICK WHILE TRIPPING DRILL, SECURE WELL IN 3 15 MIN WITH SAFETY JOINT AND HOLD AAR TO DISCUSS DRILL. Printed 10/8/2012 1:31:32PM s - Aft, North America -ALASKA- BP Page 7 of 8 • O' in m a Report Common Well Name:S-32 AFE No Event Type:COM-ONSHORE(CON) Start Date:9/14/2012 End Date: 9/18/2012 X3-0129C-C: (1,577,340.00) Project:Prudhoe Bay Site:PB S Pad Rig Name/No.:NORDIC 2 Spud Date/Time: 11/1/1990 12.00:OOAM Rig Release: 9/18/2012 Rig Contractor:NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 04:00 - 08:00 4.00 PERFOB P OTHCMP LAYDOWN 49 SPENT PERF GUNS FROM 1045' MD TO SURFACE. GUNS CONFIRMED TO HAVE FIRED. 08:00 - 09:00 1.00 PERFOB P OTHCMP OFFLOAD PERF GUN EQUIPMENT AND SPENT GUNS FROM RIG. 09:00 - 09:30 0.50 WHSUR P POST PJSM WITH LRS AND RIG CREWS FOR PUMPING FREEZE PROTECT. MAKE UP NOZZLE, DBPV,STINGER FOR FREEZE PROTECT. 09:30 - 11:00 1.50 WHSUR P POST MAKE UP CT RISER AND TEST QTS,GOOD. RIH, PUMP 1 BPM. AFTER LRS GETS A GOOD PT,START LOADING CT WITH 45 BBLS DIESEL. LAY IN DIESEL 1.1 FROM 2500 FT. TAKE RETURNS OUT TO FLOWBACK TANK. 11:00 - 12:30 1.50 WHSUR P POST PJSM WITH VALVE SHOP CREW. GREASE TREE VALVES THEN T-BAR IN A BPV (WELL STATIC PRIOR TO SETTING BPV). 12:30 - 14:30 2.00 RIGD P POST PJSM WITH SLB N2 CREW. PURGE REEL WITH 1500 SCFM N2 FOR 15 MIN. ALLOW IT TO BLEED OFF. 14:30 - 18:00 3.50 RIGD P POST :REMOVE CT CONNECTOR. INSTALL CT GRAPPLE FOR PULLING PIPE ACROSS.AND PULL TEST. PULL CT ACROSS PIPE SHED ROOF AND BACK TO REEL. - SECURE IT AT THE REEL WITH THE SHIPPING BAR. 18:00 - 20:00 2.00 RIGD P POST UNSUCCESSFULLY ATTEMPT TO CALIBRATE REEL BRIDGE CRANES. RIG CREW PREPARING TO MOVE RIG. 20:00 - 21:30 1.50 RIGD P POST LOWER 2-3/8"COILED TBG REEL 32364E (580K RUNNING FOOTAGE)DOWN TO TRUCK AND PICKUP BRAND NEW 2-3/8"COILED TBG REEL#32645-E(15850') 21:30 - 22:30 1.00 RIGD P POST ESTABLISH TREE BARRIERS FOR ND BOP USING LEAK TIGHT ISOLATION STANDARDS PER ADWOP 10-36,SECTION 6. 22:30 - 00:00 1.50 RIGD P POST OPEN BOP DOORS ND INSPECT BOP COMPONENTS -CHANGEOUT BLIND RAM BLADE AND TOP SEALS. -NO CEMENT OR LCM NOTED IN STACK. RIG UP HARDLINE IN NEW REEL. 9/18/2012 00:00 - 01:00 1.00 BOPSUR P POST COMPLETE INSPECTION OF BOP COMPONENTS. 01:00 - 04:00 3.00 RIGD P POST PULL PACKING MATERIAL OFF COIL REEL AND RIG DOWN SHIPPING BAR. INSTALL AND PULL TEST GRAPPLE PULL 2-3/8"COIL ACROSS FROM REEL HOUSE TO RIG FLOOR AND SECURE IN INJECTOR. CHANGEOUT INJECTOR PACKOFF. 04:00 - 05:30 1.50 BOPSUR P POST NIPPLE DOWN 7-1/16"BOP STACK. BREAKOFF CROSSOVER SPOOL ON BOTTOM OF STACK IN PREPARTION FOR S-12 TREE SIZE. LIFT BOP STACK AND SECURE FOR RIG MOVE. Printed 10/8/2012 1:31:32PM 41111WNorth America-ALASKA Page O•erat.on Summary Report Common Well Name:S-32 AFE No Event Type:COM-ONSHORE(CON) Start Date:9/14/2012 End Date:9/18/2012 X3-0129C-C: (1,577,340.00) Project: Prudhoe Bay Site: PB S Pad Rig Name/No.: NORDIC 2 Spud Date/Time: 11/1/1990 12:00:00AM Rig Release:9/18/2012 Rig Contractor: NORDIC CALISTA UWI: Active Datum:28.5+37.3 @68.50ft(above Mean Sea Level) Date From-To Hrs Task Code NPT NPT Depth Phase Description of Operations (hr) (ft) 05:30 - 06:30 1.00 WHSUR P POST INSTALL TREE CAP WITH NEW RING GASKET AND PRESSURE TEST AGAINST TOP OF SWAB VALVE(WITH CLOSED SSV AND MASTER)TO 250 PSI LOW AND 3500 PSI HIGH FOR FIVE MIN EACH(PASSING TESTS,SEE ATTACHED CHART). 06:30 - 08:00 1.50 RIGD P POST GENERAL RIG DOWN OPERATIONS IN PREPARATION FOR RIG MOVE. RELEASE NORDIC 2 CTD RIG AND END COMPLETION EVENT AT 08000N 9/18/2012. -ALL TREE AND WELLHEAD VALVES LEFT CLOSED TO PRESSURE GAUGES. -FINAL IA/OA=0/40 PSI TREE/WELLHEAD AND CELLAR CLEAN -WELLWORK TRANSFER PERMIT CLOSED OUT WITH PAD OPERATOR. -WELL HANDOVER COMPLETED WITH WELLS GROUP(NOTE: LINER TOP PACKER MUST BE SET POST RIG) 16.08 DAYS FROM RIG ACCEPT TO RIG RELEASE ORIGINAL PERFORMANCE TARGET=10.56 DAYS ORIGINAL AFE P50 TARGET= 16.29 DAYS Printed 10/8/2012 1:31:32PM S-32A, Well History (Post Rig Sidetrack) Date Summary 09/21/12 T/I/O=Vac/0/0; Conduct PJSM; Opened tree valves to verify tubing pressure. While shutting in SSV it was noted that actuator stem would only move 2-1/4". Valve needs at least 4-1/2"of stem travel to be shut in. Serviced valve with 100%AS grease. Pumped opened and repeated cycling valve 3 times obtaining same movement of 2-1/4"travel of stem. Shut in MV and brought tree pressure up to 500 psi by pumping diesel through tree cap needle valve. Shut in SSV and stem travelled full stroke and there was no obsruction or odd noises noted. Repeated fully opening and closing the SSV three more times to ensure it was cycling smoothly. Bled off pressure above MV and cycled SSV and noted only 2-1/4" movement.Torqued only the THA to MV flange to API specs with#32023 Lube van and equipment calibrated on 9/21/12, no movement noted on nuts. Placed valves in normal position and replaced JIC caps on needle valves. 09/22/12 T/I/O =0/0/0 Well shut in upon arrival. Held PJSM. Verified LTT on TWC and MV. Double block and bleed on production side. Walked down safeout with DSO. Removed all fluids from tree down to closed MV. Removed 4"SSV and replaced with new CIW 4" SSV with Baker actuator.Torqued all flanges to spec. Rigged up lubricator with pulling tool. Tested against TWC to 250/5000 psi. Both tests good. RIH and retrieved TWC at 125"on polished rod.POOH. Closed swab valve and tested tree cap to 2500 psi. Cleaned up area and notified operator. 09/22/12 T/I/O=Vac/0/0 Conducted PJSM; Barriers= SV& MV; P.T. (charted) down on SV to 300 psi/3500 psi (passed); Installed lubricator& P.T. (charted)w/each break to 300 psi/3500 psi (passed); P.T. (charted) down on MV to 300 psi/5000 psi (passed); Pulled 4" CIW"H" BPV#253 @ 110"w/1-1' ext.; Set 4" CIW "H"TWC#279 @ 110"w/1-1' ext.; P.T(charted&downloaded into U-drive TRP folder)TWC/tree to 300 psi/5000 psi (passed). 09/25/12 DRIFT W/2.25"CENT&S. BAILER, STOP DUE TO DEVIATION @ 10174' SLM (SAMPLE OF CEMENT/MUD IN BAILER). 09/26/12 T/I/O 5/1/35 Temp=Sl Assist slickline, MIT-T to 2500 PSI PASSED (load and test) Pumped 3 bbls MEOH & 12 bbls diesel to confirm ability to go down TBG. Pumped 3.65 bbls diesel to test. 1st 15 min TBGP lost 108&2nd 15 min TBGP lost 53 for a total TBGP loss of 161 in 30 min. Bled back—3 bbls. FWHP's=500/2/35 DSO notified SLB still on well upon departure& pulling plug. 1 09/26/12 RAN SLB TANDEM SBHPS AS PER PROGRAM (GOOD DATA). SET 3.70"45 KB LT PKR W/ STINGER ASSEMBLY(OAL=14.83', MIN ID=2.38") IN DEPLOY SLV @ 9854' SLM (9855' MDL SET C LTTP ON TOP OF 45 KB LT PKR©9840' SLM, LRS PERFORMED PASSING MIT-T TO 2500 psi PULL LTTP © 9840' SLM, SET WHIDDON CATCHER SUB @ 9835'SLM. 09/27/12 PULLED ST#1 RK-DGLV @ 9794' MD, ST#3 RK-DGLV @ 7719' MD, ST#4 RK-DLGLV @ 5551'MD, ST#5 RK-DGLV @ 3101' MD. SET ST#5 RK-LGLV© 3101' MD, ST#4 RK-LGLV @ 5551' MD, ST#3 RK-LGLV @ 7719' MD, ST#1 RK-OGLV @ 9798' MD. PULLED 4-1/2"WHIDDON C-SUB FROM 9835' SLM. Page 1 of 1 BAKER HUGHES INTEQ North America - ALASKA - BP Prudhoe Bay PB S Pad S-32 S-32A Survey: MWD Survey Report - Geographic 27 September, 2012 EMI BAKER HUGHES Survey Report-Geographic 0 by INTEQ Company: North America-ALASKA-BP Local Co-ordinate Reference: Well S-32 Project: Prudhoe Bay TVD Reference: S-32 @ 64.53ft(Nabors 18E) Site: PB S Pad MD Reference: S-32 @ 64.53ft(Nabors 18E) Well: S-32 North Reference: True Wellbore: S-32A Survey Calculation Method: Minimum Curvature Design: S-32A Database: EDM.16-ANC Prod-WH24P Project Prudhoe Bay,GPB,PRUDHOE BAY 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 PBS Pad,TR-12-12 Site Position: Northing: 5,980,854.54ft Latitude: 70°21'23.002 N From: Map Easting: 617,919.92ft Longitude: 149°2'32.343 W Position Uncertainty: 0.00 ft Slot Radius: 0.000 in Grid Convergence: 0.90° Well S-32 API No 500292209900 Well Position +N/-S 0.00 ft Northing: 5,979,855.00 ft Latitude: 70°21'12.869 N +E/-W 0.00 ft Easting: 619,867.00 ft Longitude: 149°1'35.894 W Position Uncertainty 0.00 ft Wellhead Elevation: ft Ground Level: 0.00 ft Wellbore S-32A API No 500292209901 Magnetics Model Name Sample Date Declination Dip Angle Field Strength (0) (0) (nT) BGGM2012 9/5/2012 20.68 81.02 57,628 I Design S-32A Audit Notes: Version: Phase: ACTUAL Tie On Depth: 10,099.70 Vertical Section: Depth From(TVD) +N/-S +E/-W Direction (ft) (ft) (ft) (0) 27.23 0.00 0.00 28.99 Survey Program Date: 9/27/2012 From To (ft) (ft) Survey(Wellbore) Tool Name Description 40.00 10,099.70 1 :Schlumberger GCT multishot(S-32) GCT-MS Schlumberger GCT multishot 10,108.50 11,848.00 MWD(S-32A) MWD MWD-Standard 9/27/2012 8:44:53AM Page 2 COMPASS 2003.16 Build 73 BAKER HUGHES Survey Report-Geographic 0()ip INTEQ Company: North America-ALASKA-BP Local Co-ordinate Reference: Well S-32 Project: Prudhoe Bay TVD Reference: S-32 @ 64.53ft(Nabors 18E) Site: PB S Pad MD Reference: S-32 @ 64.53ft(Nabors 18E) Well: S-32 North Reference: True Wellbore: S-32A Survey Calculation Method: Minimum Curvature Design: S-32A Database: EDM.16-ANC Prod-WH24P Survey Measured Vertical Map Map Depth Inclination Azimuth Depth +N/-S +E/-W Northing Easting (ft) (1 (1 (ft) (ft) (ft) (ft) (ft) Latitude Longitude 10,099.70 39.73 42.42 8,810.99 3,529.41 1,809.45 5,983,412.62 621,619.61 70°21'47.578 N 149°0'42.980 W TIP 10,108.50 39.78 42.40 8,817.75 3,533.57 1,813.25 5,983,416.83 621,623.33 70°21'47.619 N 149°0'42.869 W KOP 10,131.70 42.23 42.40 8,835.26 3,544.81 1,823.51 5,983,428.24 621,633.42 70°21'47.729 N 149°0'42.569 W 10,160.55 49.82 42.40 8,855.28 3,560.13 1,837.50 5,983,443.78 621,647.16 70°21'47.880 N 149°0'42.160 W 10,190.07 58.35 42.50 8,872.58 3,577.75 1,853.62 5,983,461.65 621,662.99 70°21'48.053 N 149°0'41.688 W 10,220.04 67.46 42.50 8,886.21 3,597.41 1,871.63 5,983,481.59 621,680.68 70°21'48.246 N 149°0'41.161 W 10,249.94 76.69 42.60 8,895.40 3,618.34 1,890.85 5,983,502.83 621,699.56 70°21'48.452 N 149°0'40.599 W 10,280.02 86.76 42.76 8,899.73 3,640.19 1,911.00 5,983,525.00 621,719.36 70°21'48.667 N 149°0'40.010 W 10,300.12 90.06 44.04 8,900.29 3,654.79 1,924.80 5,983,539.81 621,732.93 70°21'48.811 N 149°0'39.606 W 10,329.88 91.14 47.81 8,899.97 3,675.49 1,946.18 5,983,560.85 621,753.97 70°21'49.014 N 149°0'38.981 W 10,360.04 91.63 51.40 8,899.24 3,695.02 1,969.14 5,983,580.75 621,776.61 70°21'49.206 N 149°0'38.309 W 10,390.08 91.29 55.34 8,898.48 3,712.94 1,993.23 5,983,599.04 621,800.41 70°21'49.382 N 149°0'37.604 W 10,420.74 90.83 60.28 8,897.91 3,729.26 2,019.17 5,983,615.78 621,826.08 70°21'49.543 N 149°0'36.846 W 10,448.60 88.31 63.65 8,898.12 3,742.35 2,043.75 5,983,629.26 621,850.45 70°21'49.671 N 149°0'36.127 W 10,481.92 84.47 67.08 8,900.22 3,756.21 2,073.97 5,983,643.60 621,880.44 70°21'49.808 N 149°0'35.243 W 10,510.07 83.30 69.42 8,903.22 3,766.58 2,099.96 5,983,654.38 621,906.26 70°21'49.910 N 149°0'34.483 W 10,540.22 84.75 73.50 8,906.36 3,776.11 2,128.38 5,983,664.37 621,934.52 70°21'50.003 N 149°0'33.651 W 10,574.34 83.35 78.39 8,909.90 3,784.36 2,161.29 5,983,673.13 621,967.29 70°21'50.084 N 149°0'32.689 W 10,600.57 82.27 81.07 8,913.18 3,788.99 2,186.90 5,983,678.18 621,992.82 70°21'50.130 N 149°0'31.940 W 10,630.53 79.66 81.73 8,917.88 3,793.42 2,216.15 5,983,683.07 622,022.00 70°21'50.173 N 149°0'31.085 W 10,660.63 81.09 80.96 8,922.92 3,797.89 2,245.49 5,983,688.01 622,051.25 70°21'50.217 N 149°0'30.227 W 10,690.62 81.32 77.04 8,927.50 3,803.54 2,274.57 5,983,694.13 622,080.24 70°21'50.273 N 149°0'29.376 W 10,720.34 80.72 74.57 8,932.14 3,810.74 2,303.03 5,983,701.78 622,108.58 70°21'50.343 N 149°0'28.544 W 10,750.06 80.34 71.40 8,937.03 3,819.31 2,331.06 5,983,710.80 622,136.47 70°21'50.428 N 149°0'27.724 W 10,780.22 79.92 69.20 8,942.21 3,829.33 2,359.03 5,983,721.26 622,164.27 70°21'50.526 N 149°0'26.906 W 10,810.59 77.86 67.44 8,948.06 3,840.34 2,386.72 5,983,732.71 622,191.78 70°21'50.634 N 149°0'26.096 W 10,840.82 78.87 65.02 8,954.16 3,852.27 2,413.82 5,983,745.07 622,218.68 70°21'50.751 N 149°0'25.304 W 10,870.29 81.30 62.52 8,959.23 3,865.10 2,439.85 5,983,758.32 622,244.50 70°21'50.878 N 149°0'24.542 W 10,900.44 83.56 60.85 8,963.20 3,879.28 2,466.16 5,983,772.91 622,270.58 70°21'51.017 N 149°0'23.773 W 10,930.36 88.80 58.96 8,965.19 3,894.24 2,491.98 5,983,788.29 622,296.15 70°21'51.164 N 149°0'23.017 W 10,960.38 96.26 56.50 8,963.87 3,910.24 2,517.32 5,983,804.69 622,321.23 70°21'51.321 N 149°0'22.276 W 10,990.34 96.00 53.38 8,960.67 3,927.35 2,541.70 5,983,822.18 622,345.33 70°21'51.489 N 149°0'21.563 W 11,020.26 94.30 49.95 8,957.98 3,945.83 2,565.07 5,983,841.03 622,368.40 70°21'51.671 N 149°0'20.879 W 11,050.42 93.41 45.91 8,955.96 3,965.99 2,587.40 5,983,861.55 622,390.41 70°21'51.869 N 149°0'20.226 W 11,080.46 92.37 42.77 8,954.44 3,987.44 2,608.37 5,983,883.33 622,411.02 70°21'52.080 N 149°0'19.613 W 11,110.20 90.98 37.52 8,953.57 4,010.16 2,627.52 5,983,906.35 622,429.81 70°21'52.304 N 149°0'19.052 W 11,140.52 95.60 32.29 8,951.83 4,034.97 2,644.84 5,983,931.43 622,446.73 70°21'52.547 N 149°0'18.546 W 11,170.30 95.32 28.05 8,948.99 4,060.59 2,659.73 5,983,957.28 622,461.21 70°21'52.799 N 149°0'18.110 W 11,200.42 93.84 23.67 8,946.59 4,087.60 2,672.82 5,983,984.50 622,473.87 70°21'53.065 N 149°0'17.727 W 11,230.38 93.20 19.35 8,944.75 4,115.41 2,683.78 5,984,012.48 622,484.38 70°21'53.338 N 149°0'17.406 W 11,260.43 93.41 14.43 8,943.01 4,144.11 2,692.50 5,984,041.31 622,492.63 70°21'53.621 N 149°0'17.151 W 11,290.26 94.61 9.58 8,940.93 4,173.21 2,698.69 5,984,070.50 622,498.35 70°21'53.907 N 149°0'16.969 W 11,319.54 95.38 5.18 8,938.38 4,202.13 2,702.43 5,984,099.47 622,501.64 70°21'54.191 N 149°0'16.859 W 11,349.22 90.28 3.71 8,936.91 4,231.67 2,704.73 5,984,129.05 622,503.46 70°21'54.482 N 149°0'16.792 W 11,380.33 87.57 2.66 8,937.50 4,262.72 2,706.46 5,984,160.12 622,504.69 70°21'54.787 N 149°0'16.741 W 11,409.14 84.93 2.92 8,939.38 4,291.44 2,707.86 5,984,188.85 622,505.63 70°21'55.070 N 149°0'16.700 W 11,440.35 82.35 0.01 8,942.84 4,322.44 2,708.65 5,984,219.86 622,505.93 70°21'55.374 N 149°0'16.676 W 11,470.67 83.91 354.68 8,946.47 4,352.50 2,707.25 5,984,249.89 622,504.05 70°21'55.670 N 149°0'16.717 W 11,500.54 84.12 349.44 8,949.58 4,381.91 2,703.15 5,984,279.23 622,499.48 70°21'55.959 N 149°0'16.837 W 11,530.87 81.73 346.56 8,953.32 4,411.34 2,696.90 5,984,308.56 622,492.75 70°21'56.249 N 149°0'17.019 W 11,560.92 80.00 343.78 8,958.09 4,440.02 2,689.31 5,984,337.11 622,484.71 70°21'56.531 N 149°0'17.241 W 11,590.79 80.37 338.89 8,963.19 4,467.90 2,679.89 5,984,364.83 622,474.85 70°21'56.805 N 149°0'17.516 W 11,620.31 80.31 333.44 8,968.14 4,494.51 2,668.13 5,984,391.24 622,462.67 70°21'57.067 N 149°0'17.859 W 9/27/2012 8:44:53AM Page 3 COMPASS 2003.16 Build 73 P's BAKER HUGHES Survey Report-Geographic 0 by INTEQ Company: North America-ALASKA-BP Local Co-ordinate Reference: Well S-32 Project: Prudhoe Bay TVD Reference: S-32 @ 64.53ft(Nabors 18E) Site: PB S Pad MD Reference: S-32 @ 64.53ft(Nabors 18E) Well: S-32 North Reference: True Wellbore: S-32A Survey Calculation Method: Minimum Curvature Design: S-32A Database: EDM.16-ANC Prod-WH24P Survey Measured Vertical Map Map Depth Inclination Azimuth Depth +N/-S +El-W Northing Easting (ft) (0) (0) (ft) (ft) (ft) (ft) (ft) Latitude Longitude 11,650.44 86.12 330.31 8,971.70 4,520.87 2,654.03 5,984,417.38 622,448.15 70°21'57.326 N 149°0'18.272 W 11,680.69 86.53 335.72 8,973.64 4,547.77 2,640.34 5,984,444.05 622,434.03 70°21'57.591 N 149°0'18.672 W 11,710.29 85.36 340.86 8,975.74 4,575.19 2,629.42 5,984,471.29 622,422.67 70°21'57.860 N 149°0'18.991 W 11,740.20 86.01 346.90 8,977.99 4,603.83 2,621.15 5,984,499.79 622,413.94 70°21'58.142 N 149°0'19.233 W 11,770.34 85.85 352.50 8,980.13 4,633.39 2,615.77 5,984,529.26 622,408.09 70°21'58.433 N 149°0'19.389 W 11,800.32 84.87 356.24 8,982.56 4,663.13 2,612.84 5,984,558.94 622,404.69 70°21'58.725 N 149°0'19.475 W 11,848.00 84.87 356.24 8,986.82 4,710.51 2,609.73 5,984,606.27 622,400.82 70°21'59.191 N 149°0'19.566 W TD-PRODUCTION LINER 1 9/27/2012 8:44:53AM Page 4 COMPASS 2003.16 Build 73 TREE= 4-1/16"CIM SAFE ME: WELL ANGLE>70 1 099 0'*** ACTUATOR 0718 PJC DRAFT '•r� � CHROME TBG&LNR-DONOTACIDIZE*** NTIAL KB BEV= 64.53' I Li 2800' 36.63' KOP= 3100' 2102' —14-1/2"OTIS SSSV NIP,ID=3.813" Max Angle= a6°@ 10990' 00 Datum MD= 10176' GAS LIFT MANDRELS Datum TV D= 8800'SS ST MD TVD DEV TYPE VLV LATCH PORT DATE 20"CONDUCTOR ? 5 3101 3100 9 CAMCO DOME RK 16 09/27/12 4 5551 5193 39 CAMCO DOME RK 16 09/27/12 13-3/8"CSG,88#,NT-80, D=12.415" --1 2685' Iyl 3 7719 6898 37 CAMCO DOME RK 16 09/27/12 2 9462 8309 36 CAMCO DMY RK r 0 04/19/97 1 9798 8576 39 CAIVCOSO RK 24 09/27/12 Minimum ID = 2.377" @ 9955' I I j 9826' H4-1/2"PARKERSWS NIP,ID=3.813" 3-3/16 X 2-7/8" XQ 9830' —RIGHT HAND RELEASE M 98++33�22'' —19-5/8"X 4-1/2'WV FKR,D=3.99" 981Pi' H4-1/2"KB LNR TOP PKR,ID=2.38" TOP OF TIW 7"LNR 9860' --y 9855' _-3.370 DEPLOY SLV,ID=3.00" 9860' I—{9-5/8"X 7"TM/LNR TOP PKR ASSY 9876' -3-1/2"HES X NEP,ID=2.813" L. ill . 9880' —14-1/2"PARKERSWS ' .ID=3.813" 9901' —4-1/2"PARKERSWN NIP, BEHIND . 4-112"TBG,12.6#,NT13-CR-80 TDB, H 9913' MLLE D TO 3.80"(07/23/12) CT LNR .0152 bpf,U=3.958" 9913' -4-112"W/LIG,ID=3.958" i tie 3-1/2"LNR,9.3#,L-80 STL, .0087 bpf,ID=2.992" H 9955' --- . 9907 --i ELMD TT LOGGED 02/08/92 9-5/8"CSG,47#,NT-80S NSCC,ID.=8.681' — 10099' *� 9955' —I3-1/2"X 3-3/16"XO,ID=2.786" IL. t re 4-1/2'BKR WHIPSTOCK(TAGGED 09/03/12) —{ 10109' i.` At te L 7"LNR,26#,NT13CR-80 NSCC,.0383 bpf,ID=6.2— 10113' 4 Pie1 MILLOUT WINDOW (S-32A) 10113'-10121' PERFORATION SUMMARY REF LOG:SLB MEM GRI CCL/CNL ON 09/15/12 I ANGLE AT TOP F€RF:81"Q 10700' I Nate:Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz SHOT SQZ I 2' 6 10700-10750 0 09/15/12 10994' —13-3/16 X 2-7/8"X0,D=2.377" 2" 6 10770-10790 0 09/15/12 2" 6 11065-11085 0 09/15/12 2" 6 11250-11300 0 09/15/12 2" 6 11470-11580 0 09/15/12I 2" 6 11700-11730 0 09/15/12 I 3-1/4"LNR,6.6#,L-80 Tat,.0079 bpf,D=3.850" —I 1099A I PBTD H 10808' I 2-7/8"LNR,6.5#,13CR-80 STL,.0058 bpf,ID=2.441" — 11845' �.�, DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY IJNT 12/21/90 N18E ORIGINAL COMPLETION WELL: S-32A 09/18/12 NORDIC 2 CTD SIDETRACK(S-32A) PERMT No: 2120820 09/18/12 PJC DRLG DRAFT CORRECTIONS API No: 50-029-22099-01 09/26/12 MSS/PJC SET LTP(09/26/12) SEC 35,T12N,T12E, 1643'FNL&1705'FWL 09/27/12 MSS/PJC GLV CIO(09/27/12) BP Exploration(Alaska) Letter of Transmittal ran Date: ---- - nGV BAKER October 2, 2012 0 C T 12 2012 HUGHES __ AOGCC- To: From: State of Alaska AOGCC Baker Hughes INTEQ 333 W. 7th Ave., Suite 100 795 East 94th Avenue Anchorage, Alaska 99501 Anchorage, Alaska 99515 Bill Michaelson Please find enclosed the directional survey data for the following well(s): C-09BPB 1 C-09B Le 0 C-03CPB 1 C-03C -0 5--T8 C-24BPB1 C-24B l4., 1B-27B -g- L 3 11 07-22A ;2,1 • S-3 : ' : - _ 9,;), 4.' S-32A J 0 S-1 2B A - ( ( ( Enclosed for each well(s): 2 hardcopy prints of directional survey reports 1 compact disk containing electronic survey files Please sign and return one copy of this transmittal form to: BP Exploration (Alaska) Inc. Petrotechnical Data Center, LR2-1 900 E. Benson Blvd. Anchorage, Alaska 99508 to acknowledge receipt of this data. ( 41\ RECEIVED BY: , State of Alaska AOGCC DATE: PG/2 5-32_A_ PM 01 z_062,0 Regg, James B (DOA) From: Sarber, Greg J [SarberJG@BP.com] Sent: Sunday, September 16, 2012 6:17 AM To: Regg, James B (DOA); Kilfoyle, Jeffery A; McMullen, John C; Rossberg, R Steven; Miller, Mike E; Sheffrey, Tom (Fircroft); DOA AOGCC Prudhoe Bay Subject: BOP Usage on Nordic 2, 9-15-2012 Attachments: 2012-09-15 BOPE Usage Report to AOGCC.doc All, On 9-15-2012, BOP's were used to shut in the well on well S-32A. This well was being sidetracked by the Nordic 2 CTD rig. The event was attributed to a wellbore breathing event in the Shublik formation. Details are in the attached report. Please contact me if you have any additional questions. Greg Greg Sarber Operations Superintendent RWO/CTD +1 (907)659-5329(Office-slope) +1 (907)242-8000(Cell Phone) Harmony 2157 Alternate. Rich Burnett 1 Blow Out Preventer Equipment ( BOPE ) Usage Report to the AOGCC The purpose of this document is to ensure timely reporting to the AOGCC of any BOPE use to prevent the flow of fluids from a well. Field Superintendent Name: Greg Sarber Wellsite Leader Name: Tom Kavanagh Contact Number: 659-5329 Contact Number: 659-4393 Traction Number: 2012-IR-4232074 Well Location/Name & Rig Name: PBU S-32A Nordic 2 Rig Permit To Drill (PTD) Number: 2120820 r Date and Time of Incident: 2012-09-15 10:05 Original Scope of Work: Liner cement job on a well drilled with coiled tubing. Operational Description Leading up to Well Control Event: Had 5.2 bbls losses during the cement job. Near the end of the cement job the well was seen to be flowing with the pump off. Well was shut in at the choke HCR and injector packoff as per standing orders. Observed 250 psi wellhead pressure, 0 psi CT pressure. Notifications were made. Bled off 0.8 bbls from the wellhead and flow stops from well. Flow check for 40 min is negative. Circulated a bottoms up and observed "fizzy" mud returns. After bottoms up was circulated, a flow check was performed on the well. There was no flow observed. The cementing BHA was POH with no further signs of flow. BOPE Used and Reason: Choke HCR, CT stripper Is a BOPE Test Required after use ( Yes / No): If no, why? Yes. Slightly gas cut mud returns observed after bottoms up. 24 hour notice required to NS AOGCC Inspectors prior to testing BOPE components. Plan Forward: Pull out of hole, test HCR and Stripper Additional Comments: Pressure on well after cementing operations attributed to wellbore breathing event in the Shublik Formation, with a very slight amount of gas influx during the breathing event. The well has been dead thru the drilling process. The formation equivalent mud weight is -7.2 ppg and the wellbore fluids are 8.4 ppg (KCL brine). Email to AOGCC North Slope Inspectors within 24 hours of the incident: doa.aogcc.prudhoe.bay@alaska.gov Email CC List Well Integrity Team Leader: Ryan Daniel HSE Advisor: Jeff Kilfoyle Engineering Team Leader: Ken Allen, John Egbejimba, John McMullen, Dave Reem Wells Operations Manager: _ Steve Rossberg Wells Intervention Manager: Doug Cismoski Organizational Capability Tom Sheffrey BOPE Usage Report for AOGCC Rev 1 September 1, 2010 '7?-7 Fr 11 r ALA A ' I• �'�-� I SEAN PARNELL, GOVERNOR ALASKA OIL AND GAS 333 W.7th AVENUE,SUITE 100 CONSERVATION COMMISSION ANCHORAGE,ALASKA 99501-3539 PHONE (907)279-1433 FAX (907)276-7542 John McMullen Engineering Team Leader BP Exploration (Alaska), Inc. P.O. Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Prudhoe Bay Oil Pool, PBU S-32A BP Exploration (Alaska), Inc. Permit No: 212-082 Surface Location: 1643' FNL, 1705' FWL, SEC. 35, T12N, R12E, UM Bottomhole Location: 3835' FSL, 4543' FWL, SEC. 26, T12N, R12E, UM Dear Mr. McMullen: 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 Commission reserves the right to withdraw the permit in the event it was erroneously issued. Operations must be conducted in accordance with AS 31.05 and Title 20, Chapter 25 of the Alaska Administrative Code unless the Commission specifically authorizes a variance. Failure to comply with an applicable provision of AS 31.05, Title 20, Chapter 25 of the Alaska Administrative Code, or a Commission order, or the terms and conditions of this permit may result in the revocation or suspension of the permit. Sincerely, Cathy . Foerster Chair 5f DATED this 2 1 day of June, 2012. cc: Department of Fish 85 Game, Habitat Section w/o encl. (via e-mail) Department of Environmental Conservation w/o encl. (via e-mail) STATE OF ALASKA RECEIVED ALASI' SIL AND GAS CONSERVATION COMMI. JN PERMIT TO DRILL JUN 14 2012 20 AAC 25.005 [(�� _ �j la.Type of work: 1b.Proposed Well Class: ®Development Oil 0 Service-Win ®Single Zone ' 1 c.AQf is proposed for: ❑ Drill ®Redrill 0 Stratigraphic Test 0 Development Gas 0 Service-Supply ❑Multiple Zone 0 Coalbed Gas 0 Gas Hydrates ❑ Re-Entry 0 Exploratory 0 Service-WAG 0 Service-Disp 0 Shale Gas 2. Operator Name: 5.Bond: IN Blanket 0 Single Well 11. Well Name and Number: BP Exploration(Alaska) Inc. Bond No. 6194193 - PBU S-32A ' 3. Address: 6. Proposed Depth: 12.Field/Pool(s): P.O. Box 196612,Anchorage,Alaska 99519-6612 MD 12580' ' TVD 8990'ss - Prudhoe Bay/Prudhoe Bay . 4a. Location of Well(Governmental Section): 7. Property Designation(Lease Number): Surface. ADL 028257 , 1643'FNL, 1705'FWL,Sec.35,T12N, R12E, UM . Top of Productive Horizon: 8. Land Use Permit: 13. Approximate Spud Date: 1882'FSL,3514'FWL,Sec.26,T12N, R12E, UM August 15,2012 Total Depth: 9.Acres in Property: 14.Distance to Nearest Property: 3835'FSL,4543'FWL,Sec.26,T12N, R12E, UM 2560 6850' • 4b. Location of Well(State Base Plane Coordinates-NAD 27): 10.KB Elevation above MSL: 64.53' ' feet 15.Distance to Nearest Well Open Surface: x- 619867 ' y-5979855 ' Zone- ASP4 GL Elevation above MSL: 36.63' feet to,Same Pool: 16.Deviated Wells: Kickoff Depth. 10110' feet ' 17.Maximum Anticipated Pressures in psig(see 20 AAC 25.035) & iST-/y Maximum Hole Angle: 90 degrees Downhole: 3402 ' Surface: 2513 • 18. Casing Program: Specifications Top-Setting Depth-Bottom Quantity of Cement,c.f.or sacks Hole Casing Weight Grade Coupling_ Length MD ND MD ND (including stage data) 4-1/8" 3-1/4"x 2-7/8" 6.6#/4.7# L-80/13CR80 TC-II/STL 2720' 9860' 8625' 12580' 8990'ss-136 sx Class'G' (2` Oa) 19. PRESENT WELL CONDITION SUMMARY(To be completed for Redrill and Re-entry Operations) Total Depth MD(ft): Total Depth TVD(ft): Plugs(measured): Effective Depth MD(ft): Effective Depth ND(ft): Junk(measured): 10690' 9259' 10333' 10647' 9227' None Casing Length Size Cement Volume MD ND Conductor/Structural 110' 20" —260 sx Arctic Set(Approx.) 110' 110' Surface 2685' 13-3/8" 3722 cu ft Arctic Set III &II 2685' 2685' Intermediate 10099' 9-5/8" 2078 cu ft Class'G' 10099' 8810' Production Liner 828' 7" 332 cu ft Class'G' 9860'- 10688' 8625'-9258' Perforation Depth MD(ft): 10104'- 10386' Perforation Depth ND(ft): 8814'-9031' 20.Attachments: ❑ Property Plat IS BOP Sketch ®Drilling Program 0 Time vs Depth Plot 0 Shallow Hazard Analysis ® Diverter Sketch 0 Seabed Report ®Drilling Fluid Program ®20 AAC 25.050 Requirements 21. Verbal Approval: Commission Representative: Date: 22. I hereby certify that the foregoing is true and correct. Contact Zach Sayers,564-5790 Printed Name Jo /Ks„ Title Engineering Team Leader Prepared By Name/Number Signatur II Phone 564-4711 Date /1(94 Joe Lastufka,564-4091 Commission Use Only Permit To Drill PI Number: Permit Appr v a See cover letter for Number: zrzve50-029-22099-01-00 W u,I other 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 shales: [[( -Al396p5_ 66 P /e- Sam les Req'd:Other: / P q' 0 Yes No Mud Log Req'd: Et/Yes allo H2S Measures: ['Yes 0 No Directional Survey Req'd: Les ❑No • / / APPROVED BY THE COMMISSION Date 4. -lil - 1 Z , . ,COMMISSIONER Form 10-401 Revised 07/2009 his permit is valid for 24 gt14s fr�Rf itimt-,Af p• oval(20 AAC 25.005(g)) Submit,�/ In Duplicate r , I, ecP i9 ' Iz KI11V-� `v ,/,Y t v To: Alaska Oil & Gas Conservation Commission From: Zach Sayers 4:4)4:4) CTD Engineer Date: June 11, 2012 Re: S-32A Permit to Drill Request Approval is requested for a permit to drill a CTD sidetrack from well S-32. CTD Drill and Complete S-32A program: Rig Start Date: August 15th, 2012 Pre-Rig Work: (scheduled to begin June 25th, 2012) 1. F MIT- IA to 3,000 psi, MIT-OA to 2,000 psi 2. W Cycle LDS; PPPOT- T to 5,000 psi 3. E Mill XN nipple at 9,900' to 3.80" 4. S Dummy WS Drift to deviation or 10,210' MD (40° Inc) 5. E Set 4-1/2" x 7" TT Whipstock at -10,110' MD 6. V PT MV, SV, WV 7. 0 Bleed wellhead, production, flow, and GL lines down to zero and blind flange 8. 0 Remove wellhouse, level pad 3lZ"I• 2''' Rig Work: (scheduled to begin August 15th, 2012) 1. MIRU and test BOPE to 250 psi low and 3,500 psi high. Ps A 2. Mill 3.80" window at 10,110' and 10' of rathole. Swap the well to PowerVis. 7 3. Drill Build: 4.125" OH, 176 (31 deg/100 planned) 4. Drill Lateral: 4.125" OH, 2,294' (12 deg/100 planned) with resistivity • 5. Run 3-1/4" x 2-7/8" liner leaving TOL at 9,860' MD. 6. Pump primary cement leaving TOC at 9,860' MD, 28 bbls of 15.8 ppg liner cmt planned 7. Cleanout liner and run MCNUGR/CCL log. ;i'P 8. Test liner lap to 2,400 psi. 1 , 9. Perforate liner per asset instructions (-1,200') 10. Freeze protect well, set BPV, RDMO Post-Rig Work: 1. Re-install wellhouse, flowline and pull BPV. 2. Set 4-W liner top packer, and test to 2,400 psi (If liner lap test fails) 3. Generic GLV's 4. Test separator Mud Program: • Well kill: 8.4 ppg brine. • Milling/drilling: 8.4 ppg PowerVis for milling window and drilling (480 psi over-balance). Disposal: • All drilling and completion fluids and all other Class II wastes will go to Grind & Inject. - • All Class I wastes will go to Pad 3 for disposal. Hole size: 4.125" Liner Program: • 3-1/4", 6.6#, L-80, TC-II Solid Liner 9,860' MD — 11,000' MD • 2-7/8", 4.7#, 13CR-80, STL Solid Liner 11,000' MD — 12,580' MD • A minimum of 28 bbls of 15.8 ppg cement will be used for liner cementing. (TOC 8,860' MD) • The primary barrier for this operation: a minimum EMW of 8.4 ppg. • A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Well Control: • BOP diagram is attached. • Pipe rams, blind rams and the CT pack off will be pressure tested to 250 psi and to 3,500 psi. • The annular preventer will be tested to 250 psi and 3,500 psi. Directional • See attached directional plan. Maximum planned hole angle is 90°. • Magnetic and inclination surveys will be taken every 30 ft. No gyro will be run. • Distance to nearest property— 6,850'. Logging • MWD directional, Gamma Ray and Resistivity will be run over all of the open hole section. • Cased hole GR/CCL/MCNL logs will be run. • Perforating: • SWS 2", 6 spf, pert guns, 1-1/4" CSH work string, & 2-3/8" PH6 • The primary barrier for this operation: a minimum EMW of 8.4 ppg. • A X-over shall be made up to a safety joint including a TIW valve for all tubulars ran in hole. Anti-Collision Failures • None Hazards • The maximum recorded H2S level on S Pad was 300 ppm on well S-201 on 2/06/2012. Reservoir Pressure S � 7."Z Alq 1--tv • The reservoir pressure on S-32A is expected to be 3,402 psi at 8 ' TVDSS. (736"ppg equivalent). • Maximum expected surface pressure with gas (0.10 psi/ft) to surface is 2,513 psi. • • An EMW of 8.4 ppg for this well will provide 480 psi over-balance to the reservoir._ Zach Sayers CC: Well File CTD Engineer Sondra Stewman/Terrie Hubble ■ W mW `Igo Q= 0W m H z ISI a- m m (in a-1 o o a ce c o ar) .. L cii) ,Q aIC 00 O N a m {. ' ♦ N n t A O L Q , N N N C ti a M M co' 0 Z a: rn W a m®pt= Z m' ��; N 11h1 iiiI.' N co . O Wco 0 v b Di 41 w O. (h0 L.0 O Cn O Fr N0 - (h0 O Z N O0 _ N N N N 0) O) CO O T O- V I Q r a 0 0N..4- N N C N U O co N O` U Ca I ? Y Q. a) N > M LZ > a) .O 0 CD j0 a) C) E co a) .. > `12 > O) N n .O J C CP of hi 7 L • (n F- W ur ur O 3 " C CD rn fa c o `y J J U' a) > d C O 7 O a) O a) .0 'n U 'o g a O m 0 N G O N L J J U� .0 U, w0 y O) R a C (� C m u .a E .C-a 00 ` 0 - iii a, p Baa) w > a E N . : o O '_.O U > m CD 0 L N N N ONi 0 V o V ❑ mO e 0 V O) O �_ N J 2 N O CO CO O O O V ❑ o r- o O o co C rn m CO o N co OD CLC7 CO a) N t Cr CD OC Lc, Q 6-..... 0) o, _s c O, r 0. a) o p co U oa) u7 x o0 CO in cc N CO o a, O A W N r3 L C Ce En -C C 2 O▪ C G L 6C .a C z W fn t N — W o T. till Z W U O O ❑ O Z 5 N_ Y O 4 a) N co as W O O °) m O O a. 1 a7 re CO a y ad a. UZ =N = 1 1 An m cx N O . 0 0 W U ,_ V O O O >; ■ M O 0 U) 0 0 (D 0 0 0 0 0 0 0 0 0) CI W O 0 I- o 0 v 0 0 0 0 0 0 0 0 0) U 1'mg= O o h 0 co v 0 o O 0 0 O 0 c0 lfl > ��0 0) 0) 0) 0) 0) 0) 0) 0) 0) m �� m v 0C) m E. d I 0 Z d M N CO N CO Y') c° O 0 0) a V CO N U) O 0) N 00 0) N R C M M g 0 U M si W O M M 6 V O M 0 13 M co V 6 O n 0) 1� M CO O) M U) CO CL 0) 0) 0) 0) O 0 0 N N N N M M C) () LI-.1 N 0 .... M M M M 0. 0. 0. 0. 0. 7 '7 R V !. CO C0 C a - cu z a 0> o O M O o o O O O 0 O o O O O cl Z Z o O O7 O O O o O 0 o O O o O O J Lc) 7 Q O O O of a- oi a-- C C C ,- a- � to 0 , - c� ch PN) O E co 1 • cp N N C 2 U) �� 2to 1- w IMS Y M c- O N 0 N N O 0) M V M O CD I� CO o N 0) N N O M lD N (O Oi Oi 0 N O Oi m of I� O C N- N M (O d N M I� N M 0) 0) 0 N- O 'U U) .� } cD c0 U) CO CO n n CO CO 0) 0) O O C 0 I: C r '- .- ' r N N N N d .0 I: N N N N N N N N N N N N N N N w co co co co co co co CD c0 c0 CD CD c0 CO O CD 2 i ; O! C .9.2. ai O C Ci .. U co V C 7 O N f0 l° N O ? CO N 7 M V 0) 0) W V L y u V 0 ca r N M I- n W a- 0 0. N N 0) a- 0- C Q d w id - N_ N r n 0) u') ui N cD cD 0 C') l° O w d U N N o N M 0) M M l° lD N- co O O CUa' >, 1p E dt V 0- ) lc) 6c0 c0 00 UO o o U' .0 CU .0 C UM M M M 1- co co co co co co co co co co co co co co co O 0> 0 0 m L 0 is U t V V V lcrn rn o) 0) 0) 0) 0) CD CD CD 0) m 0) 0) 0) J F r2 Z N O U` 70 0 .`:c° U) c° 0 if) U) U) N N N N N U) U) u) m Z U) D C O) c O O 4 0. C E c° co 0) co 0) IO co 0) In Ul co N U) CO O 0 V 3 p cc) CO U) m CO n 0) CO lD 0 N N CO C N L O) O) M N O O O o M co - O h O O O N C N M 0) O co O co 0) 0. 0)CZ 0 (% UD UO UO coCO 0) O) 0 O N N N M C_ _ a- a- e- N N N N N N N N e W `� I- 0 U a O7 co 0) CO C V CO n Cl n M N O CO ? co N 0) co N- co N O CO N N CO M 0) 0) R M M O a0 C h O M V N y N N M V co V cD O V 0 cD CO 0) a E U) ll-) l° U) U) CO CO N.- N n N- I,- n n CO N CO t') c') C') (') Z a rn IL 0 2 x pU c0 0) N- ? O O O O O O O O O co O sr CD M U) O 0) 0) 0) 0) O) O) 0) 0) O 0 0 0 V 0) N N N FV-. V' Q 00 a- M M M M M M M M M M c.-) n N- CO CO CO CO CO CO COCO CO CO COUO co-cn ao ao co- ao ao co- ao co 6m m co-am m n o x o 1 — L co E I- I.. N N 0) 0) CO CO CO CO CO CO CO CO V I- V M M CO CO 0- CO CO N N M N- 0N N N N 4 co ao O O N N M6 M 7 a a v a a V co N- N CO CO n CD CO o a) _ a 2' Q a" y N a. c.i3co E . co o N cu L a) 6 U co 7 0 -- N M M 0) 0) C 0 O O 0 0 0 0 0 CO 0 CO a N- N � lc) N 0 O O O O 0 0 0 N O 0) 0) O) M O O O O O O O O 0) O) Q 0) ON 00 co M M Q co 0) 0) 0) 0) 0) 0) 0) 0) CO CO R v• >, 0 m co J (O 0 lc) O f 0 c 9 4-) cocp 0 v F O. =Q O d 0 L � 0 o NI o N) c to E Z a a co co a T. O O O O 0 o I- O O n O N- O I- 0 n p7 I� 0 0 o O o tD o o (0 o C o CO 0 co O v rn >, of o 0 o m o co 0 0 co o 6o xio m c0.) a Oo U) 0) O M O co O O O O O o co 0 '7 ` o r O N N co �t V In N co co I- N- 0 N Op. v O 0 O a 0 O O O C O O O O O O O O O CO0 C a m w C o • m E •o m m '7, n o U a• ` in 3 3 o v) 2a ■ MO m O m o in m 0 n N- 0 7 0 n O CO o 7 7 n W o n U) CO o 0) CO o U) o O v 0 o n ,- 0 7• m a 1. 1 O O) O m M N0 m n 0 N O n U) M M0 O O) '' `W o 0 o m co co m co m O O O CO CO CO M 0) O m CO iltz0' w e m F — o N Z 0) CO CO N n 0) CO CO N 7 7 N CO 7 CO N- CO CO CO 7 CO a n m O O N 7 N `- CO co U) 7 N N O U) co co N M N m CO O N- 0) U) N m N N O N N O CO Q N m O 0) O O CD 0) O 7 CO n CO n 7 (O n U) U) d 7 7 U) N m CO n N CO O 0) 0 O N N N CO 7 U) 0 ca 7 7 7 7 7 7 7 7 7 7 ? U) (O U) U) U) U) (O U) U) NJ 0 N > ` o Ca N 0O ? 3 a d = CO o o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 C. 0 0 0 N M Z Z 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 _) U Q N N N N N N N N N N N N N N N N N N N N CV m E co. 3 O p u� `"E J o 0 N N 2 W a) co 7 C p 0 rG U) F- 2 W U) 7 7 0) n 7 CO m n n N CO N 0) 0 m m CO n • U) U) 7 co CO N n CO 7 U) 7 0 0 n U) 0) O U) N o of N m 0) U) _ U) Ui U) N CO m m o 4 V d O co U) co co n co O O O O O O 0) 0) O O N U -a O N N CO CO CO co 7 7 7 7 7 7 7 7 co co CO 7 7 C 0 G _ N N N N N N N N N• N N N• N N- N• N N N N N 2 L N N N N N N N N N N N N N N N N N N N N w W U) ' U) U) m U) m 0 co co m m CO m CO U) m CO m m m m W W C W O R6 ra c c m 0 N C N 0) O m (1) O N n O U) 7 N 7 N- O 3- 0) O 7 L U C 2 U N C) m U) 7 7 0) 7 N CO O O n co m y c 9W A co M n O m 7 O N O m 7 n N U) 0) U) 7 OD 0 O Ca N 0 m co U) a) co U) U) N U) U) 0 7 at N 7 N 7 U) 7 7 O O CIp_' T A O n N- n CO CO O O O 3- N N CO co 7 U) co U) co N- CO N L d LC M M M M M M 7 7 7 7 7 7 7 7 7 7 7 7 7 7 L CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO CO m CO m J O o m(p x 0 0) 0) 0) O 0) 0) 0) m 0) 0) 0) O 0) CO 0) 0) 0) o) O F 2 Z U) al Z U) Ui U) Ui U7 U) U) U) U) U) U) U) U) VI- L11- U) U) Ui 111- U] 0 O Q (13 O U) m O U) O O O N- O O CO (0 7 N U) N N O O 7 N U) CO a CO CO CO U) CO CO. CO m m n LO N- W W n m U) CO 0 m O tri CO m Q 0 U) O co 7 O U) U) CO N m N N N- 0) 0 0 0 O O O CO 0) co 7 7 U) U) to U) to co to m U) m U) m m m mm CO_ _ _ C_ _ N N N N N N N N N• N N N• N N- N• N N N N N E W "-- I- 0 - 0 0 CL U) CO CO U) CO 7 O n CO CO N 0) CO CO N O) O) O) CO CO O co O m O N m co n CO co r N M 0) O U) N co V m m 0) N 7 O N 7 O M N m m O) N 0) 6 N co m O n N- m N U) U) O U) U) U) U) N 7 0 7 7 I ) co co co co 0 o .- a N CO CO V V U) m m m n CO O coco U) _ co M cococo- 7 4 4- 7• 7 7 7• 7 4 7• 7 7 4- 4- V d 3 - U) 0) CO n CO O N O N- U) at CO CO N O U) O O U) O U) m CO U) m U) co n 7 U) 0) U) 0 N n 7 7 n CO m O (.1:i n O CO O Ti U) U) U) CO U) U) m O N co co 7 U) U) n CO O O O N N CO 7 7 7 7 N U) CO CO CO CO CO CO CO CO CO O 0 O O O 0) 0) 0) 0) 0) 0 O CO- CO- CO- m m CO- m m CO- CO- CO- CO CO- m- m m CO- CO CO m CO U) m CO N CO CO U) N O N O m 7 O C') 7 O N. M CO O n n O n m O N CO O n U) 0 7 7 CO n N Co UI 7 N Si O m n O O CO O N N 7 N U) U) 7 CO CO N 3- 3- U) CO U) •- U) 7 U) U) .- N co co co co co co co a — m ca N O 7 7 7 N N N N n co N- .-- m O (O N CO CO O CO N N O 7 U) N N- (31 U) 7 7 m N m U) U) U) Q m 7 N O O O N N M M M M M 7 7 n U) co m m CO CO co n n co co CO m co CO co co co co CO CO co co co m U E m E — a < o a Q m L "0 U) N N C O 2 m M M (O Z d 0_ (n U) d o n o n o o n o 0 0 0 0 0 O o o O O o O Z o m o m 0 o m o 0 0 0 0 0 0 0 0 0 0 0 0 a )+ O n O n O O N O O U) O O m O U) O (") O O O] coc m o 7 o O o o N- o o W o C. C) o n o 0 C) CO NND 1)_. m CO O O O O O co- O N CO M7 CO U) CO mn nm O O MQ r 0 • CV CO 4 80to p O N 0 N U a ya C c o E• o m m d SG_ CV o_ O a U) 0 . 460 0 0 (O O M CD 0 U) CON. W o o) o o (O 0 n N- 0 0) U MOM Di ao CD U) c o m o ao ;W6 m co 0) rn ) o o C) 0) CO m MIM 01.) (r m= W co 2:: M F o N z co co L- f CLSI N Ca CD O UiCO 03 n UM CO N N 0) CO CO N: n 0 U) 01- R O V U) CO O_ co CD CD r� CO C 0) 0) O C) W N N _ U) co- U) U) (O U) U) U U) U) CO I H C N O ca N O ? 7 d '1) V m 0 0 0 0 0 0 0 0 0 O o CD M Z Z o 0 0 0 0 0 0 0 0 0 JLCI V a N y- Di Di Di DI Di Di DI DI DI N C _ M C 0) U1 O J o N a) o ❑ • (n H W CCI CO N O teCO (CD Cr CN') N O CO r` CO O) N M co CO N d CO C CO V CO N. C CO 0) U -a O, V C V U) U) U) U) U) U] CD C 0N N N N N N N N N DI- E E L •C N N N N N N N N N N w N N co CD CD CO CO CO (.0 CD CD CD al E O: W c m o m of c_ ei •• U m O C 7 U) N CO C U) CD L C U 2 U • U) N U) U) CO U) V C CO y C O w R co M co N N W O N O w F`yd d U M N N O CO O O O () d T co 0) co 0) O) O O N N M M o: m m a C v - v Vi CD CD CD CD L5 LO- T3T3 C1ce L t 2 :° L co co co co co co co co co CO p > ❑ O 7 N t' V W W 0) 0) W 0) 0) 0) 0) 0) J F r2 2 N ❑ 0 U) U] U) V) U) U) U) V) U) U7 0 0. 0) CO N CO U7 CD CO co 0) N U) CO U) U) CD O N )O CC 0) N CO CD aD O V U) N N 0) CDD n N N. n CO O CO CO O C_ _ N N N N N N N N N N - E 3 W I 0 0 a O U] N CD cil CD M O O N U) CO CO . 0 C CO OD N CO (O ✓ N N O C 0 0 N O co - W O O N CO CO V C O: _ V U) CD U) V) U) U) U) U) CD II CO CL2 CO ? CO co V co (NI fD N M M N CO O) 0 r- co M U) U) CD O N M 0) U) U] V) U) co CD I N- CO CO 0) 0) 0) 0) 0) O) 0) 0) W 0) y 0) ... Oa- COao aD aD m eo ao Co Co O C 7 0 CO 0 V) O U) 0 CO 7 N 0) 0 0 N 0 CO (O D] n CD 0) V N O o 0) N CO M N N- •- ,- N- 0- CO 1 co co co CO coCcoMCO N COC00)) N Q aoai CO N- r- ro v ri ('i v ao co co m co CO co co co co m U• >, U as Do Do C — U < 0Q C O O CO C./ CJa) CV MI O C O Z O_ 0_ VI V1 d O O 0 O O 0 0 0 O O co Oa. >, O CO O O OD O O OD O O N CO) ID > O O • N u-) CO') V V 0O COC O ' N `- r Oi `- r N 1 1:::1 C 0 E - - -C- f N d R U o a m c o O) C N O O w 0 0 0 O) O O 0. co 0 d M . yr... W a ca '�kg= d y m 7 (6n coN co m F = N N N CO O cm O O O O N Z - co J V V V C ¢ a Z 0 d 0 W C z z Z Z (O = (O N- N O V CO c N > co )) O N 4) O N- O) a O a U) Z-,1 V V (6 4) O Y - Z 0 d •. N N N N x m 0 O J 3 Q oN- N m 4/0 ' M () V o (D U) N N 4) ,E O O 000000 O O >N O M 3 C_ O O 000000 O O U) H W M N N V r ,- N N. N N NN O l0 O ,- N O r 0 C co N CO CODi Di N Di Di Di CN- O CO O O CO CD C 4) 4) (L U -Q C o N L w N N 2 O N N Z C o o 000000 o o d 0 N ✓ O oOi 0h o O O O O O o M O O o D M M OO U)6 U 4 (n OOM 4OCO O) (O CO O E 'C 6y C WU Of f�M Vn V co co V co C CO n N M M co- U M UM = - a PC: w ` � 0 i C O coco OO CO (O CO CO CO O 0 0 0 0 0 0 O COa) O Km K m co r (U ri xi U) vi vi Uri (n (n L O LO III .41 o >>> 0 0 7 CU ', Z r J F E z U) 0 `y r) co CO (+i (V Oi ,N C O O. CU Cr M V OO O V CO O) m 4 ri 6 6 m co C V ri V V co r N N V CO CO .0 W C N N N CON N N N N + 0 U O O O N- v N- o O O CL o 7 (n v 0) m (n N I GO (a O O (n N O (a O N V (p N (O O W o N (n O Q) o r...- V W (O V CO V V 0 O (O N- 0 CU Z M (f) N (O (l) M M M (U M W M (JJ cc O) + N O 0- N- a r.- DI N (D N CO Z N O U) n Z A O o0 0 0 0 0 0 O co o Z Z O O (O O O O O O O O N C 0 M O O O O O O O O N (Si N (o M LU co O co ,_ 0 m m N coLo co- M6 coco h 0• 0 . M O 6 O O) O a) a) co'... c0 co O O 0 OOD O OO I O O O O co O ON O 0 O 0 m Zo 00 N = M n N _O t .- N CO C 6 co aU) N d ,_ (00 O CO CO CO CO O CO o ai N (U O Ca L NCO ir Q O O = O O 7- U a.�E (O O N.. O O N O O t.' 43 N 00 (n y O O 0 O 0 4) O J O) r- co C J Q O Qco • m ( . d O O O U >. 0 O 0 0 0 II)0 45 a N O O) L E m m 6- 4a) m o 3 a^ co CO 0 Q 0 f1 C U U U , y N ci O 'o UJ N N no - C 4) 4) 4) 4) 6 0 O E CU M co O) U O) O) O) E Z d CL U) UJ 0 N .5...° «U CU (^)a al En 41 N 4) " N M V U) CO cn Q) CO 4) O .i(fco a� co a O .Ca C.0 C C C C C N N U w N N y O)C C m C Off)d d d d CL Cl 0I 5 15 C C O) E - O CC1 ,� 1hd .. Z E (o ~ NO d N O (0O l0'p d E v a ? L Q ad Q ad Q ad Q as rnCm O)L N N N N♦ N 4) (O M M M M AC 0 F F- W Ul (n (n U b M i N W W NJ m' ®W.J )0 m= d o F. o Z0) 0) 0- 0 a (.) vr w O N N ,- 1.'..) O U CO P_) O Z n D_ a a) z a) J V O Q N CO a) EO 0 co 0 N a) � - a 6 it W au) a c O E.' L w m w E re c a) a o '« C d .. U LO 'O U VC N 0 4O :v N w Ti a U ydtd a > m 23 in t al J F E Z U) 0 0 CL Q) Ct 0) C 121 0 0 I— O 0 O = o U --- CD c CL ) m CO CCI m a) E O -oo m o m O d O c OC) (N � 4 La `D N- CCD O°' O Q CL U I Y W V LO CO n CO CD F- Q Q LO 0) CO N- LO 0 LO 0 0 CO 0) = 0 Ln N N CO LDC) LO ✓ CO 0 COCOO N CO O N C coC) LO r N- N 10 O LC) . . (N O O N N O) 0 CD VCO O N O) 0 O CO O r- O CO CO CO CO O) 0 N- N CO V LO LO 0 CD CD CO CO N- N- CO CO W Lj." N N N N N N N N N N N N N N N N N + R C_ O O U CO CO CO CO CO O O LO O O 0) CO N O) LO N O Ln To V N O) t` co O LC) CO O m N N- co O) 0 7 r- 0 U on V L") V r- C) Ni CO Ni O) O) O O N N4 V O O O N co V V V CD CO .- 0 N. N O LO N CD N 0 N r J U) LO Ln LO CD N. N- N- CO O O) co V CD CO C) O CO V ZCO CO CO CO CO CO C) C) CO' CO- V V V V V V LO Ln N LO + a co CD N. V 0 O O O O O) N- ,- O Cl. CO O) OJ V CO o0 « v CO N co co co O) CD O) CO Ln V O) O R CO LO C) VNOrNVV !)a) CO coLO coCcoCcoC) coCco M LO 0 O L LO CO N- CO ''.E 9.g (` r.- co co. m co co co co CO D) m m CD rn CD T W m y O CO m O O ao CO CO m CD m m m m m LD W 0 O O CD > La U T C• mLO 'p O O O N- N- N. N. r- N- N- N- 0 0 0 O] O O O O O O CON- O O CD 0 0 CD CO 0 CO CO O O O O O O O O O Q O) O O 0 0 O O O r- r- N 0 O O 6 O O O O O . 'O - N < co 3 w O) CO CO CO CO CD V Cr O) N- LO O n CO O) N CO C Ln a O .— ,— N V LO 0 r- CO_ O) CO_ N 0 r C) O N 'Cr u] /� Z d d CO U) d N O O O O O O O O O O .- .- .- .- .- N N N N ' ) co E O it CM O T co CD N O -0 b C `y c N ♦,,,, ay a a ¢ o IN®, p •,-5. d d Wto L O '"�j 0 Q. U) 0 O 0 C VI Mule _ 4z a I 8 itgli Pl . a c,_ oc ag 8 J a i.g 0g $ 1, a o w. 8 a o 1 I 1 0 PA �� ogz)(8)wu$rv(�v�n§s I I I N 1 €~ c U § iii m i ■■■■1 m 7"�Q��Am�o 7 En a ME! 3 y 0,— ■■ x�v"iu°�s��ry}r"i�o�i��ry ��'ieaRir ■■■a.... __. H I ■■■! 38 CI $a R 9 QST 88882o22oor'28ogo R aw Na "g2EAk�r mmeMm N y N Q �= w 8 J g79 ii 0 0 0,0 0, � a Li w � H 'ad,�mwB'�4'28nemRe�F�".nno� I E a I 1 ii iriiiiilli o a 228 1 ha«o,mBeG{8$";R',g',.b,Mii qAniiffillialillgi Illit I 1 Fs A iL. SI eve:M-71 �42PAgl!;e 8 ' 1Pg"2888888 < 88 28a 8gssRaa233p2m2mZ22213I 0 � banal ROS ueay� 3o ti (m/808)iRdaQj !2.IAan-I h W Oseciem Maio •m= a E 1 1 8 t i i is 1 Q y i g 5 B Sly, ! 0 Hill I 13 PHS 1 q Z ( 1 HE!E. c _. RY N r d I g245 8 8 r ‹ ��i] ,off al ? :4 M `ccs o VJ y' q; ^0 0 re p g bpoQ f h 9 4�0 cb.��p00 1 § - N_ m "N - a s1.1 _ vmv N ) 2m72y — $ui....IIIII y m _ R cla0e _ 0�An a w% b a 0 t !,4 1.-4 a tl R ,'; •"! § i i t' It041 &' 0„111Egt (ui/li oci)(+)uuoN/(-)9pnos o I m= N 18 88$1$111$ ONIM c d d a4- ;;;;; A1 0. 3 gsoa$88$$$$$$$$$$$$$$ s � aa!3i3ika €21 3aa.333333i3ae AA ^, :P W:R"ha -x.4455 --;!...><-:,;fla $>ssszs g laa 3, 3 Z'�n 5t$5i9i$@dim.=�R38�$^dAe`o'Be c 000c 3 J,��,Jf 3-5 S�D�S^s Hg6.1A" '' ddddd�ddd�d ddd61dddiA I$ o iiiiiiiila h it o ppppppgggggg ppgg pp###�H__ �aw€A7xs a g drArAddd7lw,, d1%. .",ddddddddddd p Eu/ o WIM Igo J .A ab. 25 ,§R88mww^aww'w^888888888 • £ as o $i o -e o f c // � ---_ - ' 812 A # - -, Ng 'E' imS� \ate\`\\\ C zw - Ili/ 4'4 te \ \--\ \*N\\ -2 to) s4Q\ ,,,N46, - Ill* */***,:-.- ----- 'W \* A - w U 0 0 00 oro > .. FI OWL 4- g ��Ak � _Se. o taN ya � 41117.a��\•--C--___=*. - o 2 0) \ \ to G aa_ om N y -t'' H9 �v _ No Q V rn o C ,\'...'-.,_-,-- ____ - -____-- r a ' TD 41:::11E :*01.* --- _ — ....".! .._N N N 1 0 bp North America - ALASKA - BP Prudhoe Bay PB S Pad S-32 S-32A Plan 8 Travelling Cylinder Report 10 June, 2012 BAKER HUGHES INTEQ I►..,L b p Travelling Cylinder Report BAKER HUGHES roo. INTEQ Company: North America-ALASKA-BP Local Co-ordinate Reference: Well S-32 Project: Prudhoe Bay TVD Reference: Mean Sea Level Reference Site: PBS Pad MD Reference: S-32 @ 64.53ft(Nabors 18E) Site Error: 0.00ft North Reference: True Reference Well: S-32 Survey Calculation Method: Minimum Curvature Well Error: 0.00ft Output errors are at 1.00 sigma Reference Wellbore S-32A Database: EDM.16-ANC Prod-WH24P Reference Design: Plan 8 Offset TVD Reference: Offset Datum Reference Plan 8 Filter type: GLOBAL FILTER APPLIED:All wellpaths within 200'+100/1000 of reference Interpolation Method: MD Interval 25.00ft Error Model: ISCWSA Depth Range: 10,099.70 to 12,580.00ft Scan Method: Tray.Cylinder North Results Limited by: Maximum center-center distance of 1,455.28ft Error Surface: Elliptical Conic Survey Tool Program Date 6/10/2012 From To (ft) (ft) Survey(Wellbore) Tool Name Description 40.00 10,099.70 1 Schlumberger GCT multishot(S-32) GCT-MS Schlumberger GCT multishot 10,099.70 12,580.00 Plan 8(S-32A) MWD MWD-Standard Casing Points — — ---_ —_- Measured Vertical Casing Hole Depth Depth Diameter Diameter (ft) (ft) Name (in) (in) 2,685.00 2,620.31 13 3/8" 13.375 17.500 12,580.00 8,989.96 2 7/8" 2.875 4.125 10,099.00 8,745.92 9 5/8" 9.625 12.250 Summary Reference Offset Centre to No-Go Allowable Measured Measured Centre Distance Deviation Warning Site Name Depth Depth Distance (ft) from Plan Offset Well-Wellbore-Design (ft) (ft) (ft) (ft) PBS Pad J S-109-S-109-S-109 Out of range S-12-S-12-S-12 Out of range S-124-S-124-S-124 Out of range S-14-S-14-S-14 Out of range S-14-S-14A-S-14A Out of range S-15-S-15-S-15 11,925.00 11,960.00 1,051.48 286.70 771.50 Pass-Major Risk S-24-S-24-S-24 10,115.34 10,375.00 1,270.56 211.77 1,074.83 Pass-Major Risk S-32-S-32-S-32 10,149.82 10,150.00 1.92 3.37 -1.45 FAIL-Major Risk S-43_DIMS-S-43-S-43 11,525.00 13,888.80 654.66 295.96 361.22 Pass-Major Risk S-43L1-S-43L1-S-43L1 11,575.00 14,000.00 641.90 287.15 360.94 Pass-Major Risk CC-Min centre to center distance or covergent point,SF-min separation factor,ES-min ellipse separation 6/10/2012 8:27 18PM Page 2 of 10 COMPASS 2003.16 Build 73 TREE= 4-1/16"5MCNV WELLHEAD= FMC SAF, NOTE: ***CHROME TBG&LNR-DO NOT ACTUATOR= OTIS S-32 ACIDIZE*** KB.ELEV= 64.53' 2800' 36.63' KOP= 3100' Max Angle= 41 @ 10567' Datum MD= 10170' 2102' —14-1/2"OTIS SSSV NIP, ID=3.813" Datum TVD= 8800'SS 13-3/8"CSG,68#,NT-80,ID=12.415" — 2685' , GAS LIFT MANDRELS ST MD TVD DEV TYPE VLV LATCH PORT DATE 5 3101 3100 9 9-CR-1M0 DOME RK r 16 12/07/09 Minimum ID = 3.725" @ 9900' 4 5551 5193 39 9-CR-1M0 DOME RK ' 16 12/07/09 4-1/2" PARKER SWN NIPPLE L 3 7719 6898 37 9-CR-1M0 DOME RK ' 16 12/07/09 2 9462 8309 36 9-CR-1M0 DMY RK 0 11/23/90 1 9798 8576 39 9-CR-1M0 SO RK ' 24 12/07/09 ' 9826' —14-1/2"PARKER SWS NIP,ID=3.813" 9830' —RIGHT HAND RELEASE Z X 9832' 1-19-518"X 4-1/2"MV PKR,ID=3.99" TOP OF TNN 7"LNR —{ 9860' I ® I 9880' —14-112"PARKER SWS NIP,ID=3.813" 9900' —4-1/2"PARKER SWN NIP, ID=3.725" 4-1/2"TBG,12.6#,NT-13-CR-80, H 9913' — \ 9913' —14-1/2"W/LEG, ID=3.958" .0152 bpf, ID=3.958" 9902' —I ELMD TT LOGGED 02/08/92 9-5/8"CSG,47#, NT-80S, ID=8.681" — 10099' PERFORATION SUMMARY REF LOG: BHCS ON 11/20/90 ANGLE AT TOP PERF:39 @ 10104' Note:Refer to Production DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 2-1/2" 4 10104-10144 0 05/15/94 10333' —3-3/8"BAKER IBP, 1-3/4"EXT FN-05/18/92 3-3/8" 6 10269-10335 0 02/08/92 3-3/8" 4 10345-10386 0 12/21/90 0 PBTD — 10647' *MOO 000. 7"LNR,26#,NT-13CR-80,.0383 bpf, ID=6.276" —1 10688' 1....10.4 DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 12/21/90 ORIGINAL COMPLETION 12/09/09 GTW/SV GLV C/O(12/07/09) WELL: S-32 09/07/01 RN/TP CORRECTIONS 12/09/09 MBM/SV SET ROCK SCRN(12/08/09) PERMIT No: 1901490 10/26/02 CO/KAK MAX ANGLE CORRECTION 09/21/11 MSS/PJC PULL ROCK SCREEN(09/01/11) API No: 50-029-22099-00 11/19/02 BM/TP WAIVER SAFETY NOTE SEC 35,T12N,T12E, 1643.08'FNL&1704.61'FWL 03/23/03 JMP/KK WAIVER SAFETY NOTE REV. 09/24/05 EZL/TLH WAIVER SFTY NOTE DELETED BP Exploration (Alaska) TREE= /16"5M CMV WELLHEAD= FMC S-3 2A ASAF.CIDIZE*'OTE: ***CHROME TBG& LNR-DO NOT ACTUATOR= OTIS KB.FIB/= 64.53' proposed CTD sidetrack 2800' 36.63' KOP= 3100' Max Angle= 11 @ 10567' Datum k/D= 10170' 2102' H4-1/2"OTIS SSSV NIP,ID=3.813" Datum TVD= 8800'SS O 13-3/8"CSG,68#,NT-80,D=12.415" —r 2685' _ , GAS LIFT MANDRELS ST MD ND DEV TYPE VLV LATCH PORT DATE 5 3101 3100 9 9-CR-1M0 DOME RK ' 16 12/07/09 –4 5551 5193 39 9-CR-1M0 DOME RK r 16 12/07/09 Minimum ID =2.377" @ 10450' I 3 7719 6898 37 9-CR-1M0 DOME RK ' 16 12/07/09 3-3/16" x 2-7/8" XO I 2 9462 8309 36 9-CR-1MO DMY RK 0 11/23/90 1 9798 8576 39 9-CR-1M0 SO RK r 24 12/07/09 I I I 9826' —4-1/2"PARKER SWS NIP,ID=3.813" TSGR = 10,090' MD 9830' —I RIGHT HAND RELEASE R 9832' H9-5/8"X 4-1/2"T W PKR,ID=3.99" TOP OFTM/7"LNR H 9860' Top of 3-1/2"liner and cement at 9,860' 3e 9880' H4-1/2"PARKER SWS NP, D=3.813" II 3-1/2"X Nipple V W1:)9900' H4-1/2"PARKER SN NP,� =3.80" milled out 4-1/2"TBG,12.6#,NT-13-CR-80, H 9913' • ``` 9913' H4-1/2"W/LEG,D=3.958" .0152 bpf,D=3.958" 9902' H H-ND Tr LOGGED 02/08/92 3-1/2"x 3-3/16"XO 9-5/8"CSG,47#,NT-80S,ID=8.681" H 10099' A \ L 2-7/8"TD at 12,580' 4-1/2"x 7"TT whipstock at 10,110' hilikk ' I I-- 40° ---\ 5_32.A PERFORATION SUMMARY 3-3/16"x 2-7/8"XO at 11,000' REF LOG:BRCS ON 11/20/90 ANGLE AT TOP PERF:39 @ 10104' Note:Refer to Ikoduction DB for historical perf data SIZE SPF INTERVAL Opn/Sqz DATE 10333' —13-3/8"BAKER 13P,1-3/4"EXT FN-05/18/92 2-1/2" 4 10104-10144 O 05/15/94 3-3/8" 6 10269-10335 O 02/08/92 3-3/8" 4 10345-10386 O 12/21/90 — PBTD —I 10647' 11111111 111111111111111 7"LNR,26#,NT-13CR-80,.0383 bpf,ID=6.276" —I 10688' 101011.0.1 DATE REV BY COMMENTS DATE REV BY COMMENTS PRUDHOE BAY UNIT 12/21/90_ ORIGINAL COMPLETION 12/09/09 GTW/SV GLV C/O(12/07/09) WELL: S-32A 09/07/01 RN/TP CORRECTIONS 12/09/09 1/13M/SV SET ROCK SCRN(12/08/09) PERMIT No: 1901490 10/26/02 CO/KAK MAX ANGLE CORRECTION 09/21/11 MSS/PJC FULL ROCK SCREEN(09/01/11) AR No: 50-029-22099-00 11/19/02 BMYTP WAIVER SAFETY NOTE 05/24/12 ZJS proposed U I U sidetrack SEC 35,T12N,T12E, 1643.08'FNL&1704.61'FWL 03/23/03 JMP/KK WAIVER SAFETY NOTE REV. 09/24/05 1 EZL/TLH WAIVER SFTY NOTE DELL IEU BP Exploration(Alaska) • e G NMf Y O 0 - i - I I / M . a - I ►41 a rr • w m CO J cn Y an 1 a ° • O U U N O —1 w 3 iU G = .111 m 1!F i U 93 I. '110111' d ,mss 1 g ... U U U 1 vex 1 1 os inn '11111111 ,^ : _ V _ L O QWo U _I m nw1,a1snH S 9 ." Q N N it m 1 11 III L W NI i. f m f K U m J 1•• I I d `m ole 0 v O 1111011 er m r 0 Z f o 0 f m Q 0 r ~ ' in 12 1 LL C J = a U U 2 pe MI I 6:0 W~ JQ U ; s. . III._• a itf G f d1 N U.o n2 o `; •s• U• C a Q UN f LL g,�,'Va ' a Et o c2 2 • Lo Z j •mN rt = Z V 0 0 oq f e ;►tea o 3J • • + W .• M• : U..r.. V m Y " ilbq Et d as • • - ` U U LR11N N et y f Ica U U N V� r`; r�O 2 c f N w�� _Erci U UO i•-1 I ---,de. ..'Q " aN o 0.....4� .. 1 9 h _ N •4C a 0 i '^ rn a o. L . c0 0 o U O U NLL Z U iy m 3.W d mpy 1- = zE aJe v J �¢ � Ii U a _ 3 .V `.12eU C r . CI 0 N 1III Z �` 1- l._ I I -N co ow Emiiiii a 1 ya .... a x = OVERSIZED DOCUMENT INSERT This file contains one or more oversized documents. These materials may be found in the original hard file or check the parent folder to view it in digital format. TRANSMITTAL LETTER CHECKLIST WELL NAME ��(e ` ,z...w.. PTD# 2/9_- - 2,__ Development Service Exploratory Stratigraphic Test Non-Conventional// Well FIELD: /'t��C 1 L.0-C--- POOL: f��'`�6)-� (`j(. ( Check Box for Appropria /Paragraphs to be Included in Transmittal Letter CHECK ADD-ONS WHAT (OPTIONS) TEXT FOR APPROVAL LETTER APPLIES MULTI LATERAL The permit is for a new wellbore segment of existing well (If last two digits in Permit No. ,API No. 50- - - API number are between 60-69) Production should continue to be reported as a function of the original API number stated above. PILOT HOLE 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 name ( PH) and API number (50- - - ) from records, data and logs acquired for well . SPACING The permit is approved subject to full compliance with 20 AAC EXCEPTION 25.055. Approval to produce/inject is contingent upon issuance of a conservation order approving a spacing exception. assumes the liability of any protest to the spacing exception that may occur. DRY DITCH All dry ditch sample sets submitted to the Commission must be in SAMPLE no greater than 30' sample intervals from below the permafrost or from where samples are first caught and 10' sample intervals through target zones. Non-Conventional Please note the following special condition of this permit: Well production or production testing of coal bed methane is not allowed for (name of well) until after (Company Name) has designed and implemented a water well testing program to provide baseline data on water quality and quantity. (Company Name) must contact the Commission to obtain advance approval of such water well testing program. Rev:9/09/2011 To 0) o a) 0- V) N .fo a) 0 O@ — N C Q c .0 0 E a) _N o > L O V W u) CD a0 0m c aa) a T) co E O X -00 7 m a) c CO c 0) 0) 0 L O =a 0 5 a) ai 3 a M d w _ O N o C O a _ o a) 3 co U m = 3 C, 7 a) 7 ° o O a) o m a) (0 0 3 a) c m V) a c m N o W a) J N c0 No - p - uj N t� U) to _o 13 O N O a) (O W2 I- O U a) -0 r...: p O N O m Z CO 0 — O V (raj 13 E a a) D r ' C 3 n @ O 0 CO N C N O Q co as N a) N d i I n .O CO NO W c - N M CV = M m 0 0) o O J y O tV a) O) (� M 3 a) 7 L a) C M a) • a II (n CO y O Q a) a co a) c 3 -6 0 s = m _a a) m c CA C = O M •� U N > CO 7 L C CO _ d ~ a) (p T Vl Q O 0) N O_ C N — N to N w 0) a N if)) E 2 '0 .7.. O CD 3 r - m C o c n — a N a) L. -° a) < N CO __ 0) 01 .Vl a a) O C n a O a) @ — m N N 'y U a) C co co 0 N p ) a, C W Ct T U co (6 C a) "0 n _ U N E CD W 0 a a o U U o n 7 cc)CD o f N to a) -° -a > U a) a) N co 7 N II C 3 a) 7 0 Z — 0 -, c 7o CO° m = co Q N L ° a o -° E co Z ami CL O .. o 0 0 o co US 0 a) m < N d Q co m W Et a0 -.2t 0 co co a E a Z 2 2 I co W n -45 ;