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217-006
David Douglas Hilcorp Alaska, LLC GeoTechnician 3800 Centerpoint Drive, Suite 1400 Anchorage, AK 99503 Tele: (907) 777-8337 E-mail: david.douglas@hilcorp.com Please acknowledge receipt by signing and returning one copy of this transmittal or fax to 907 777-8510. Received By: Date: Date: 01/22/2021 To: Alaska Oil & Gas Conservation Commission Natural Resource Technician 333 W 7th Ave Suite 100 Anchorage, AK 99501 DATA TRANSMITTAL PBU L-118L1 (PTD 217-006) FRAC FOCUS REPORT STAGE 1-3 TREATMENT REPORTS Folder Contents: Received by the AOGCC 01/22/2021 PTD: 2170060 E-Set: 34609 Abby Bell 01/25/2021 Operator Name:2. Development Exploratory Service 5 Permit to Drill Number:217-006 6.50-029-23043-60-00 PRUDHOE BAY, BOREALIS OIL Hilcorp North Slope, LLC 5. Well Name and Number:8. 10.Field/Pools: Well Class Before Work4. Present Well Condition Summary:11. Total Depth: measured feet feet Plugs measured feet feet Effective Depth: measured feet feet Packer measured feet feettrue vertical true vertical 12780 12761 6686 None 12440 None None Casing: Length: Size: MD: TVD: Burst: Collapse: Structural Conductor 78 20" 31 - 109 31 - 109 1490 470 Surface 3265 7-5/8" 30 - 3295 30 - 2622 6890 / 8180 4790 / 7150 Intermediate Production 8703 5-1/2" x 3-1/2" 27 - 8730 27 - 6506 7000 / 10160 4990 / 10540 Perforation Depth: Measured depth: 8726 - 12775 feet True vertical depth:6502 - 6685 feet Tubing (size, grade, measured and true vertical depth)3-1/2" 9.2# L-80 25 - 8481 25 - 6263 Packers and SSSV (type, measured and true vertical depth) No Tubing Packer Liner 4108 2-3/8" 8662 - 12770 6439 - 6686 11200 11780 12. Stimulation or cement squeeze summary: Intervals treated (measured): Oil-Bbl Gas-Mcf Water-Bbl Casing Pressure Tubing Pressure 3371387330125 1420902 1577 550 638 344 Representative Daily Average Production or Injection Data Prior to well operation: Subsequent to operation: 17. I hereby certify that the foregoing is true and correct to the best of my knowledge. Contact Name: Contact Email: Brodie Wages david.wages@hilcorp.com Authorized Name:Stan Golis Authorized Title: Authorized Signature with Date:Contact Phone:(907)564-5006 Treatment descriptions including volumes used and final pressure: 13. Operations Manager Operations Performed1. Abandon Plug Perforations Fracture Stimulate 5 Pull Tubing GSTOR WINJ WAG GINJ SUSP SPLUG 16. Well Status after work:Oil 5 Gas Exploratory Development 5 Stratigraphic 15. Well Class after work: Service WDSPL 14. Attachments: (required per 20 AAC 25.070.25.071, & 25.283) Daily Report of Well Operations Copies of Logs and Surveys Run true vertical measured6686 Sundry Number or N/A if C.O. Exempt: 320-012 No SSSV Installed Junk Packer Printed and Electronic Fracture Stimulation Data 5 5 Operations shutdown Change Approved Program See Attached Senior Pet Engineer:Senior Res. Engineer: STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION REPORT OF SUNDRY WELL OPERATIONS Suspend 5Perforate Other Stimulate Alter Casing Plug for Redrill Perforate New Pool Repair Well Re-enter Susp Well 3.Address: 3800 Centerpoint Dr, Suite 1400, Anchorage, AK 99503 7.Property Designation (Lease Number):ADL 028239 PBU L-118L1 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): Stratigraphic Other: API Number: Form 10-404 Revised 03/2020 Submit Within 30 days of Operations By Samantha Carlisle at 3:42 pm, Jan 22, 2021 Digitally signed by Stan Golis (880) DN: cn=Stan Golis (880), ou=Users Date: 2021.01.22 10:37:53 -09'00' Stan Golis (880) SFD 1/27/2021 8,776 - 12,226 6,549 - 6,676 SFD 1/26/2021 DSR-1/22/21 RBDMS HEW 1/27/2021MGR19FEB2021 ACTIVITY DATE SUMMARY 11/26/2020 ***WELL ONLINE ON ARRIVAL*** (frac) BEGIN RIGGING UP ***WSR CONTINUED ON 11/27/20*** 11/27/2020 ***WSR CONTINUED FROM 11/26/20*** (frac) ATTEMPTED TO SET 3-1/2" XX-PLUG IN X-NIP @ 8,559' MD. (heavy paraffin) LRS PUMPED 80 bbls HOT DIESEL DURING BRUSH & FLUSH. ***WSR CONTINUED ON 11/28/20*** 11/27/2020 T/I/O= 1602/1611/402 TEMP= SI (WELLHEAD OR TREE MAINT) Assist Sline as directed Pumped 2 bbls 60/40 followed by 11 bbls DSL down FL for FP. Pumped 80 bbls of 180* DSL down TBG for brush and flush. Sline incontrol of well upon departure. CV's= OTG Tags hung Pad op notified of well status upon departure. FWHP's= 675/1640/460 11/28/2020 ***WSR CONTINUED FROM 11/27/20*** (frac) SET 3-1/2" XX-PLUG IN X-NIP @ 8,559' MD. DEPLOYED 3-1/2" CATCHER TO XX-PLUG @ 8,559' MD. PULLED INT-ORIFICE FROM ST# 2 @ 7,671' MD. PULLED INT-GLV FROM ST# 3 @ 6,385' MD. PULLED INT-GLV FROM ST# 4 @ 4,788' MD. SET INT-DGLV IN ST# 4 @ 4,788' MD. ***WSR CONTINUED ON 11/29/20*** 11/29/2020 ***WSR CONTINUED FROM 11/28/20*** (frac) SET INT-DGLV IN ST# 3 @ 6,385' MD. SET INT-CIRC VLV IN ST# 2 @ 7671' MD. PULLED EMPTY 3-1/2" CATCHER FROM 8,559' MD. LRS CIRCULATE 100 bbls 2% KCL FOLLOWED BY 65 bbls CRUDE DOWN IA UP TBG. (U-TUBE CRUDE) ATTEMPTED TO PULL INT-CIRC VLV FROM ST# 2 @ 7,671' MD. PULLED CATCHER w/ CIRC VLV. ***WSR CONTINUED ON 11/30/20*** 11/29/2020 T/I/O=1115/1250/375 CircWell / Feeze Protect FLowline (Pre Frac) Pump 5 bbls 60/40, 100 bbls inhibited 2% KCL, & 65 bbls crude down IA taking returns up tbg to flowline. U-tube TxIA for approx 1 hour to freeze protect tbg & IA to 2500'. Freeze protect flowline with 18 bbls neat meth leaving 1500 psi on flowline. FWHPs=80/75/390 11/30/2020 T/I/O=106/9/381 MIT T to 4500 psi / MIT IA to 4500 psi Pump 5 bbls crude down Tbg to test. TP lost 200 psi 1st 15 min & 63 psi 2nd 15 min. Bled Tbg down IA to 2500 psi. Pump 1 bbl crude down IA to test. IAP lost 67 psi 1st 15 min & 33 psi 2nd 15 min. Bled back Tbg & IA to 0 psi total of 5 bbls back. FWHPs=0/0/377 11/30/2020 ***WSR CONTINUED FROM 11/29/20*** (frac) DEPLOYED 3-1/2" CATCHER TO XX-PLUG @ 8,559' MD. SET INT-DGLV IN ST# 2 @ 7,671' MD. LRS OBTAINS PASSING 4,500 psi MIT-T. LRS OBTAINS PASSING 4,500 psi MIT-IA. PULLED 3-1/2" CATCHER FROM 8,559' MD. EQUALIZED & PULLED 3-1/2" XX-PLUG FROM 8,559' MD. DRIFTED TO S/D IN DOGLEG @ 8,903' SLM. ***JOB COMPLETE, WELL LEFT S/I*** 12/2/2020 Annual UT Inspection on Universal Tool (Tree Saver) Daily Report of Well Operations PBU L-118 Daily Report of Well Operations PBU L-118 12/9/2020 CTU#9 1.5" CT. Job Objective:Pre-Frac set CBP and AssPerf Complete Pipe Swap. MIRU CTU. Perform Weekly BOP Test and pump drift ball. Make up GR/CCL logging BHA with 1.75" drift and RIH. ...Continued on 12-10-20...*CP 12/10/2020 CTU #9 - 1.50" Coil. ***Cont. from WSR 12-9-20*** Job Objective: Pre-frac set CBP and AddPerf Log from 10800 to 8600' painting a white tie-in flag at 10420'. POOH. Good data and +17' correction. Make up Baker Magnum 2-3/8" CBP and RIH. RIH to flag make 17' correction for EOP to 10423.60' continue to RIH to 10510' set CBP mid element PT plug to 3000 psi. POOH. Shoot 1st perf interval 10265' to 10286' POOH. FP well and keep hole full while POOH. Rig off the well and stand back in preparation for the frac. Crew travel to CTU #6 to continue operations. ...Continued on WSR 12-11-20...***CP 12/11/2020 T/I/O= 500/0/360. Assist Frac. Hold IA pressure and monitor/bleed OA pressure during frac. Pumped a total of 4 bbls of diesel during the job. Final T/I/O= 1300/0/140. 12/11/2020 T/I/O=SI Assist SLB Frac (FRACTURING) Heat 90 bbls 90* DSL on SLB transport. Assist Frac crew holding IAP during Frac. Job Postponed--Called off for another job 12/11/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-11-20*** Job Objective: Frac Support Standby for Frac. MIRU CTU. ...Continued on WSR 12-12-20... 12/11/2020 ***SLB Frac Crew*** Job Scope: Multi stage Fracture Stimulation Targeting Kuparuk C Sands Stage 1 of 3. Set & Test Tree Saver. Line up well for Frac Treatment. Pump Frac Per pump schedule as follows. Pumped 50 bbl injectivity test with water while holding back pressure on IA, hard shut down. ISIP= 1730 psi, CP= 1090 psi. Formation did not break over as expected. Pumped a second 40 bbl Injectivity test with same results. Review data from both injections. Decision mad to pump 100 bbl data frac with X-Link Gel, Followed by a water flush. During Flush a large pressure drop was observed at constant rate. Surface equipment check out ok. Finished flush and Freeze protected surface lines. Decision made to rig down frac equipment and rig up coil for drift run to verify down hole bridge plug and possible liner top packer integrity. Laydown tree saver, secure Tree and hand over well to Coil #9. ***Job not complete** 12/12/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-11-20*** Job Objective: Frac Support Rig up CTU. Make up 1.75" JSN drift BHA and RIH. Tie-in at the flag and tag CBP at 10501' MD. POOH repaimt yellow flag at 9488.6'. MU Read logging tools RIH. Complete caliper start spinner runs. Log from 10480' up across liner top while pumping at 1.0 bpm. Good data, CBP is holding with no definite flow into the LTP, no LTP damage or buckled tubing on the caliper. Test 1.50" safety joints for upcoming wellwork. Begin rigging back CTU for Frac. ...Continued on WSR 12-13-20... Daily Report of Well Operations PBU L-118 12/13/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-12-20*** Job Objective: Frac Support Rig back CTU and standby for Frac. MIRU CTU. Make up FP BHA with 1.80" DJN and RIH. Jet Ice from tree and FP well to 500'. ...Continued on WSR 12-14-20..... 12/13/2020 T/I/0= 1300/0/150. LRS Unit 72 Assist Frac (FRACTURING). Fill SWS transport with 65 bbls of 90* F diesel. Hold IA pressure and monitor OA pressure as directed. Pumped a total of 5 bbls diesel into the IA. Bled back 4.5 bbls to Final T/I/0= SI/535/150. 12/13/2020 ***SLB Frac Crew*** Job Scope: Fracture Treatment Targeting Kuparuk C Sands Stage 1 of 3. Pumped 30.5 bbl injectivity test, 13.5 BBL XL Check, performed a hard shut down. ISIP= 1800 psi, CP= 1175 psi Pad Stage 1, 125 bbl of Pad, 50 bbl Scour 0.5 PPA, 125 bbl Pad, 125 bbls @ 1 PPA, 50 bbls @ 2 PPA, 50 bbls @ 3 PPA, 120 bbls @ 4 PPA, 50 bbls at 5 PPA 38 bbls @ 6 PPA, 50 bbls @ 7 PPA, 7.2 bbls @ 8 PPA, 30 bbls @ 8 PPA Carbo bond, 51 bbls @ 9 PPA Carbo bond. 14 bbls @ 10 pps Carbo bond. - 89,335 lbs of 16/20 C-Lite Propant pumped. Screened out with 8 PPA at perfs. 63,990# of 16/20 Carbolite behind pipe. 25,345# of 16/20 Carbolite in TBG. Unable to pump in to well with clean gel. Flush surface lines and hand over to Coiled Tubing. Job in progress... 12/14/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-13-20*** Job Objective: Frac Support Make up 1.75" BDJSN and RIH performing reverse FCO. Cleaned out to 9800' POOH layed in freeze protect. Make up GR/CCL logging BHA and RIH. Tag high and 9513' and clean down to 9762'. Log from 9760 up to 8500' painting a white/green tie- in flag at 9600'. POOH. Ice plug in coil at surface. Lay down logging BHA and confirm +7' correction. Make up 2.0" BDJSN and attempt to thaw coil. Well injectivity is reducing, pump FP cap and RIH to thaw coil with BHT. ...Continued on WSR 12-15-20... 12/15/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-14-20*** Job Objective: Frac support RIH to thaw coil using BHT. Thawed coil POOH freeze protect coil and well. MU new MHA RIH with CBP set at 9550' top of plug. PT plug to 3000 psi. POOH. Make up Perf gun run #2 with 20' of 1.56" Prospector perf guns, 6 spf. RIH and tie-in to top of CBP. Perforate 9470-9490' (adjusted per OE). PUH and paint white/red tie in flag with corr. EOP of 8774.97'. POOH keeping hole full with diesel for FP. ...Continued on WSR 12-16-20...***CP 12/16/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-15-20*** Job Objective: Frac Support POOH with perf gun while keeping hole full. FP well with Diesel. Rig back CTU for Frac. Complete weekly BOP test. ...Continued on WSR 12-17-20...***CP Daily Report of Well Operations PBU L-118 12/17/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-16-20*** Job Objective: Frac Support Rig down CTU after BOP test. Change packoffs/chain insp. Trim 30' of pipe (tie-in flag now 8744.97' corr. EOP). Standby for Frac. MIRU after frac finished. Make up 1.75" BDJSN reverse FCO BHA and RIH, Circulate out gel while RIH. ...Continued on WSR 12-18-20...***CP 12/17/2020 LRS unit 46 assist Frac (FRACTURING) Fill SWS transport with 90 bbls of 90* DSL. Hold pressure on the IA. Monitor the OA and bleed as needed. 12/17/2020 ***SLB Frac Crew*** Job Scope: Fracture Treatment Targeting Kuparuk C Sands Stage 2 of 3. Pumped 53 bbl injectivity test. Performed a hard shut down. ISIP= 2025 psi. CP= Not applicable for this stage. Pump Pad Stage 1. 125 bbl Pad, 50 bbl Scour 0.5 PPA, 125 bbl Pad, 50 bbls @ 1 PPA, 50 bbls @ 2 PPA, 100 bbls @ 3 PPA, 100 bbls @ 4 PPA, 100 bbls @ 5 PPA, 75 bbls @ 6 PPA, 45 bbls @ 6 PPA, 55 bbl flush w, YF128ST cross-link gel, 34 bbl flush freeze protection with diesel. Wellbore has 22.5 bbls diesel, 55 bbls cross-link gel. Leaving 2 bbls of cross-linked gel with 6 PPA 16/20 Proppant, Pull Universal Isolation Tool from well. Hand over well to Coiled Tubing. ***Stage 2 of 3 Complete*** 12/18/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-17-20*** Job Objective: Frac Support Perform FCO down to 9000' MD. POOH. Make up 2-3/8" Baker CBP and RIH. Set top of plug at 8900'. Lay in FP from 4700' to surface. MU/RIH with 20' x 1.56" Prospector BH charge gun. Perforate 8776-8796'. Confirm static WHP of 590 psi and injectivity of 0.4 bp at 830 psi and 2.5 bpm at 1475 psi. FP well with Diesel while POOH pumping pipe displacement. Rig back CTU for the Frac. ...Continued on WSR 12-19-20...***CP 12/19/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-18-20*** Job Objective: Frac Support Standby for Frac. ...Job in Progress... 12/19/2020 ***SLB Frac Crew*** Job Scope: Fracture Treatment Targeting Kuparuk C Sands. Stage 3 of 3. RU and deploy Tree Saver. Pumped 125 bbls injectivity test. Perfromed a hard shut down. ISIP=1843 psi. CP= Not applicable for this stage. Pump 125 bbl Pad, 50 bbls Scour 0.5 PPA, 150 bbl Pad, 50 bbls @ 1 PPA, 50 bbls @ 2 PPA, 100 bbls @ 3 PPA, 100 bbls @ 4 PPA, 100 bbls @ 5 PPA, 75 bbls @ 6 PPA, 50 bbls Carbo Bond @ 6 PPA, Call flush w/ YF128ST 41 bbls cross-link gel. freeze protection with 30 bbls of diesel. Wellbore has 20 bbls diesel. 41 bbls of cross-link gel. Leaving 5 bbls of cross-linked gel with 8 PPA 16/20 Carbo Bond Proppant in liner. Pull Universal Isolation Tool from well. Hand well over to Coiled Tubing. ***Stage 3 of 3 Complete*** 12/19/2020 LRS unit 46 assist Frac.(FRACTURING) Filled SWS transport with 70 bbls of 90* DSL. Hold pressure on the IA as instructed with 2 bbls of diesel. Monitor and bleed the OA as needed. Final T/I/O= 1650/200/240. Daily Report of Well Operations PBU L-118 12/20/2020 CTU #9 1.50" CT .109" WT Job Scope: FCO of Carbo Bond Proppant, mill three CBP's and push to top of fish. Found sand top at ~8450' ctmd cleaned down to CBP #1 and tagged at 8800' ctmd, milled through and continued working it down through proppant and landed on top of CBP #2 @ 9550' ctmd. Worked on getting CBP #1 broken up and started milling CBP #2 fillanly started moving down to 9606' ctmd and started having problems with stalls and choke issues. Both sides of choke got washed out and we could not hold back pressure. POOH and chased gel to surface. 7800' from surface choke plugged off with parts and pieces from CBP Opened by pass and got returns back. TBG freeze protected from 2600' to surface. ...Job in continued on 12/21/2020... 12/21/2020 CTU #9 1.50" CT .109" WT Job Scope: FCO of Carbo Bond Proppant, Mill CBP #3 and push to top of fish. Attempt. Had circlation issues through BHA and froze tip of CT. Cut 137' of coil and regained circulation and freeze protected coil reel and all sufface lines were flushed. Choke was leaking on at weep hole at packing on needle seat. Shut down and get issues addressed before continuing operations. ...Job in progress... 12/22/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-21-20*** Job Objective: Frac Support. FCO and Mill CBPs Make up 1-11/16" motor and 1.70" 3-bladed mill with Tempress Hydropull, RIH. FCO and mill CBP #3 Set at 10501 MD. Begin pushing CBP to bottom. Hard milling encountered at ~11775' CTMD mith multiple stalls and reduced overall ROP to <2 fpm. Potential for scale or other damage/debris. Continue milling ahead. ...Continued on WSR 12-23-20...***CP 12/23/2020 CTU #9 - 1.50" Coil ***Cont. from WSR 12-22-20*** Job Objective: Frac Support, Mill CBP and FCO Continue with hard milling and average ROP of ~1 fpm and push CBP down to 11892' CTMD. Potential for scale or other tubular debris/obstructions. Forced to POOH before target depth of 12240' reached due to pump issues. FP well. ...Complete.... 12/24/2020 LRS Well Test Unit 6. Frac Flowback. Begin WSR 12/24/20, SB for Scheduling, Perfom Unit Move, Jocky Equipment to Location, RU FB Tank. Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 12/25/20 12/25/2020 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 12/24/20. Resume SB for Scheduling, Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 12/26/20 12/26/2020 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 12/25/20. Continue SB for Scheduling, Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 12/27/20 12/26/2020 ***WELL S/I UPON ARRIVAL***(gas lift) RAN 2.80" GAUGE RING TO LTP @ 8654' MD SET 3 1/2 WHIDDON CATCHER @ 8654' MD PULLED 1" DUMMY BTM-INT FROM STA # 2 @ 7671' MD PULLED 1" DUMMY BTM-INT FROM STA #3 @ 6385' MD PULLED 1" DUMMY BTM-INT FROM STA #4 @ 4788' MD SET 1" BTM-INT DOME(16/64" 1755PSI) IN STA # 4 @ 4788' MD. ***JOB CONTINUED ON 12/27/2020*** 12/27/2020 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 12/26/20. Continue SB for Scheduling, Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 12/28/20 Daily Report of Well Operations PBU L-118 12/27/2020 ***JOB CONTINUED FROM 12/26/20*** SET 1" BTM-INT (20/64" TRO 1880PSI) IN STA # 3 @ 6385' MD SET 1" BTM-INT S/O (22/64") IN STA # 2 @ 7671' MD. BAILED FROM 8630' SLM TO 8647' SLM.(cement/sand) ***JOB CONTINUED ON 12/28/20*** 12/28/2020 ***JOB CONTINUED FROM 12/27/20*** BAILED TO 3 1/2" WHIDDON CATCHER @ 8644' SLM. PULLED 3 1/2" WHIDDON CATCHER FROM 8644' SLM. TUBING/IA COMMUNICATION. TAPPED ON STA # 2 @ 7671' MD AND GAINED TUBING INTEGRITY. ***WELL LEFT S/I UPON DEPARTURE*** (job complete) 12/28/2020 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 12/27/20. Continue SB for Scheduling, End SB, Begin Rig Up, Continue Rig Up. Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 12/29/20 12/29/2020 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 12/28/20. Compete Rig Up, PT, POP Well, Initiate GL, Continue Flowback/ Drawdown. Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 12/30/20 12/30/2020 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 12/29/20. Continue Flowback/ Drawdown. Continue Slo-Bean Up. Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 12/31/20 12/31/2020 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 12/30/20. Continue Flowback/ Drawdown. Continue Slo-Bean Up. Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 01/01/21 1/1/2021 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 12/31/20. Continue Flowback/ Drawdown. Continue Slo-Bean Up. Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 01/02/21 1/2/2021 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 01/01/21. Continue Flowback/ Drawdown. Continue Slo-Bean Up. Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 01/03/21 1/2/2021 T/I/O = 500/1550/460. Temp = 91*. IA FL (Well testers). AL open @ casing valve. IA FL @ 7671' (#2, S/O). Hardline rigged up from TBG to tanks & #L-250. SV = O. WV = C. SSV, MV = O. IA, OA = OTG. 1/3/2021 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 01/02/21. Continue Flowback/ Drawdown. Continue Slo-Bean Up, Achieved FOC, Perform Purge, Begin 8 Hr Test. Inlet Well L-118, Outlet Well L-250. Job in Progress, Continued on WSR 01/04/21 1/4/2021 LRS Well Test Unit 6. Frac Flowback. Continued from WSR 01/03/21. Complete 8 Hr Test, RDMO. Inlet Well L-118, Outlet Well L-250. Job Complete/ End WSR Schlumberger-Private Pressure (All Zones) Initial Wellhead Pressure (psi) 345 Surface Shut in Pressure(psi) 1,175 Injection Surface ISIP (psi) 1,800 Final Surface ISIP (psi) Screen Out Max Surface Pressure (psi) 8,157 Total Proppant Pumped (lbs)* 89,335 Estimated Closure Pressure (psi) - Total Proppant in Formation (lbs) 63,990 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbls) 867.9 Total YF128ST Past Wellhead (bbls) 732.1 Total WF128 Past Wellhead (bbls) 13.5 Total Neat Water Past Wellhead (bbls) 30.5 Total Freeze Protect Pumped (bbls) 1.8 Total Freeze Protect Past Wellhead (bbls) 1.8 Total 16/20 CarboBond Lite Pumped (lbs.) 26,175 Total CarboLite Pumped (lbs.) 63,160 Total Chemical Additives Invoiced Past WH Invoiced Past WH J580 (lbs) 1011 894 J532 (gal) 85 85 L071 (gal) 67 67 L065 (gal) 30 30 F103 (gal) 30 30 J134 (lbs) 4 0 J475 (lbs) 165 165 M275 (lbs) 15 12 J218 (lbs) 0 0 S123 (gal) 21 21 Schlumberger-Private 11:59:32 12:05:22 12:11:12 12:17:02 12:22:52 Time - hh:mm:ss 0 5000 10000 Tr. Press - psi0 2 4 6 8 10 12 14 16 18 20 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 18 20 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 1: Pressure Test © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-13-2020 Schlumberger-Private 12:50:07 12:58:27 13:06:47 13:15:07 13:23:27 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 Tr. Press - psi0 5 10 15 20 Slurry Rate - bbl/min-2 0 2 4 6 8 10 12 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 1: Injection © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-13-2020 Schlumberger-Private 13:14:52 13:35:42 13:56:32 14:17:22 14:38:12 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 Tr. Press - psi0 2 4 6 8 10 12 14 16 18 20 22 24 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 16 18 20 22 24 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 1: Main Treatment © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-13-2020 Schlumberger-Private Schlumberger-Private Schlumberger-Private Schlumberger-Private 12:49:02 12:54:02 12:59:02 13:04:02 13:09:02 Time - hh:mm:ss 0 2 4 6 8 10 12 14 16 18 20 Slurry Rate - bbl/min0 2 4 6 8 10 Liquid Additives - gal/mgal0 2 4 6 8 10 12 14 16 18 20 J218, J475 CONC - lb/mgalSLUR_RATE CFLD_RATE J532_CONC S123_CONC F103_CONC L071_CONC L065 CONC J218_CONC J475_CONC Stage 1: Injection Additives © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 Stage 1 12-13-2020 Schlumberger-Private 13:17:01 13:37:51 13:58:41 14:19:31 14:40:21 Time - hh:mm:ss 0 2 4 6 8 10 12 14 16 18 20 Slurry Rate - bbl/min0 1 2 3 4 5 6 7 8 9 10 Liquid Additives - gal/mgal0 2 4 6 8 10 12 14 16 18 20 J218, J475 CONC - lb/mgalSLUR_RATE CFLD_RATE J532_CONC S123_CONC F103_CONC L071_CONC L065 CONC J218_CONC J475_CONC Stage 1: Additives © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 Stage 1 12-13-2020 Schlumberger-Private Pressure (All Zones) Initial Wellhead Pressure (psi) 725 Surface Shut in Pressure(psi) 1,575 Injection Surface ISIP (psi) 2,025 Final Surface ISIP (psi) 2,170 Max Surface Pressure (psi) 6,385 Total Proppant Pumped (lbs)* 75,420 Estimated Closure Pressure (psi) - Total Proppant in Formation (lbs) 73,590 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbls) 962.1 Total YF128ST Past Wellhead (bbls) 800.3 Total WF128 Past Wellhead (bbls) 11.3 Total Neat Water Past Wellhead (bbls) 40.7 Total Freeze Protect Pumped (bbls) 34.3 Total Freeze Protect Past Wellhead (bbls) 24.3 Total 16/20 CarboBond Lite Pumped (lbs.) 13,615 Total CarboLite Pumped (lbs.) 61,805 Total Chemical Additives Invoiced Past WH Invoiced Past WH J580 (lbs) 1082 952 J532 (gal) 80 80 L071 (gal) 67 67 L065 (gal) 32 32 F103 (gal) 30 30 J134 (lbs) 4 0 J475 (lbs) 220 220 M275 (lbs) 18 15 J218 (lbs) 11 11 S123 (gal) 17 17 Schlumberger-Private 10:24:20 10:31:00 10:37:40 10:44:20 10:51:00 Time - hh:mm:ss 0 2000 4000 6000 8000 10000 Tr. Press - psi0 2 4 6 8 10 12 14 16 18 20 22 24 Slurry Rate - bbl/min0 2 4 6 8 10 12 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 2: Pressure Test © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-17-2020 Schlumberger-Private 10:51:53 11:00:13 11:08:33 11:16:53 11:25:13 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 Tr. Press - psi0 2 4 6 8 10 12 14 16 18 20 22 24 Slurry Rate - bbl/min0 2 4 6 8 10 12 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 2: Injection © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-17-2020 Schlumberger-Private 11:19:03 11:39:53 12:00:43 12:21:33 12:42:23 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 7000 Tr. Press - psi0 2 4 6 8 10 12 14 16 18 20 22 24 Slurry Rate - bbl/min0 2 4 6 8 10 12 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 2: Main Treatment © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-17-2020 Schlumberger-Private Schlumberger-Private Schlumberger-Private Schlumberger-Private 11:19:03 11:39:53 12:00:43 12:21:33 12:42:23 Time - hh:mm:ss 0 5 10 15 20 25 Slurry Rate - bbl/min0 2 4 6 8 10 12 Liquid Additives - gal/mgal0 2 4 6 8 10 12 J218, J475 CONC - lb/mgalSLUR_RATE CFLD_RATE J532_CONC S123_CONC F103_CONC L071_CONC L065 CONC J218_CONC J475_CONC Stage 2: Injection Additives © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-17-2020 Schlumberger-Private Pressure (All Zones) Initial Wellhead Pressure (psi) 700 Surface Shut in Pressure(psi) 1,534 Injection Surface ISIP (psi) 1,845 Final Surface ISIP (psi) 1,735 Max Surface Pressure (psi) 5,157 Total Proppant Pumped (lbs)* 95,805 Estimated Closure Pressure (psi) - Total Proppant in Formation (lbs) 94,253 Treatment Totals (All Zones As Per FracCAT) Total Slurry Pumped (Water+Adds+Proppant) (bbls) 1041.9 Total YF128ST Past Wellhead (bbls) 829.4 Total WF128 Past Wellhead (bbls) 41.5 Total Neat Water Past Wellhead (bbls) 44.5 Total Freeze Protect Pumped (bbls) 38.6 Total Freeze Protect Past Wellhead (bbls) 28.6 Total 16/20 CarboBond Lite Pumped (lbs.) 66,735 Total CarboLite Pumped (lbs.) 29,070 Total Chemical Additives Invoiced Past WH Invoiced Past WH J580 (lbs) 1061 1038 J532 (gal) 96 96 L071 (gal) 78 78 L065 (gal) 37 37 F103 (gal) 39 39 J134 (lbs) 1 0 J475 (lbs) 210 210 M275 (lbs) 30 15 J218 (lbs) 11 11 S123 (gal) 23 23 Schlumberger-Private 14:09:25 14:15:15 14:21:05 14:26:55 14:32:45 Time - hh:mm:ss 0 2000 4000 6000 8000 10000 Tr. Press - psi0 5 10 15 20 25 Slurry Rate - bbl/min0 5 10 15 20 25 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 3: Pressure Test © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-19-2020 Schlumberger-Private 14:30:35 14:36:25 14:42:15 14:48:05 14:53:55 Time - hh:mm:ss -3000 -2000 -1000 0 1000 2000 3000 4000 5000 6000 7000 Tr. Press - psi0 5 10 15 20 Slurry Rate - bbl/min0 5 10 15 20 25 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 3: Injection Test © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-19-2020 Schlumberger-Private 14:52:14 14:54:19 14:56:24 14:58:29 15:00:34 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 Tr. Press - psi0 5 10 15 20 25 Slurry Rate - bbl/min0 5 10 15 20 25 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con FracCAT Crash Stage 3: Main Treatment © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-19-2020 Schlumberger-Private 15:15:02 15:31:42 15:48:22 16:05:02 16:21:42 Time - hh:mm:ss 0 1000 2000 3000 4000 5000 6000 Tr. Press - psi0 5 10 15 20 25 Slurry Rate - bbl/min0 2 4 6 8 10 12 14 Prop Con - PPATr. Press BHP Annulus Press Slurry Rate Prop Con BH Prop Con Stage 3: Main Treatment © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 12-19-2020 Schlumberger-Private Schlumberger-Private Schlumberger-Private Schlumberger-Private 15:15:02 15:31:42 15:48:22 16:05:02 16:21:42 Time - hh:mm:ss 0 5 10 15 20 25 Slurry Rate - bbl/min0 1 2 3 4 5 6 7 8 9 10 Liquid Additives - gal/mgal0 2 4 6 8 10 12 14 16 18 20 J218, J475 CONC - lb/mgalSLUR_RATE CFLD_RATE J532_CONC S123_CONC F103_CONC L071_CONC L065 CONC J218_CONC J475_CONC Stage 3: Injection Additives © Schlumberger 1994-2016 Hilcorp North Slope LLC L-118L1 Stage 1 12-19-2020 Hydraulic Fracturing Fluid Product Component Information DisclosureHydraulic Fracturing Fluid Composition:Job Start Date:12/11/2020Job End Date:12/19/2020State:AlaskaCounty:Beechey PointAPI Number:50-029-23043-60-00Operator Name:Hilcorp Alaska, LLCWell Name and Number:L-118ALatitude:70.35060448Longitude:-149.32498103Datum:NAD27Federal Well:NOIndian Well:NOTrue Vertical Depth:6,686Total Base Water Volume (gal):117,343Total Base Non Water Volume:0Trade NameSupplierPurposeIngredientsChemicalAbstractServiceNumber(CAS #)MaximumIngredientConcentrationin Additive (% by mass)**MaximumIngredientConcentrationin HF Fluid (% by mass)**CommentsFluidSchlumbergerSurfactant , Breaker J475, Crosslinker, Gel J580, Scale Inhibitor, Clay Control Agent, Bactericide,Activator , B511 Disclosure,Propping Agent, Breaker J218 Water (Including Mix Water Supplied by Client)*7732-18-578.54698Ceramic materials and wares, chemicals66402-68-496.9514820.79902Guar gum9000-30-01.227460.263332-hydroxy-N,N,N-trimethylethanaminiumchloride67-48-10.601850.129122-Butenedioic acid, (Z)-, polymer with sodium 2-propene-1-sulfonate68715-83-30.270080.057941, 2, 3 - Propanetriol56-81-50.208990.04483Phenolic resin9003-35-40.192910.04139Diammoniumperoxodisulphate7727-54-00.192530.04130Sodium tetraborate decahydrate1303-96-40.170650.03661PROPAN-2-OL67-63-00.137800.02956Ethylene glycol107-21-10.080000.01716Alcohols, c11-15-secondary, ethoxylated68131-40-80.076070.016322-Propenoic acid, polymer with sodium phosphinate129898-01-70.074830.016052-butoxyethanol111-76-20.061730.01324Ethoxylated C11 Alcohol34398-01-10.056700.01216Vinylidenechloride/methylacrylatecopolymer25038-72-60.039960.00857Potassium hydroxide1310-58-30.038580.00828Ethoxylated Alcohol68131-39-50.030770.00660Sodium chloride7647-14-50.015110.00324Diatomaceous earth, calcined91053-39-30.012330.00264Calcium Chloride10043-52-40.007640.00164Undecanol112-42-50.004940.00106Items above are Trade Names with the exception of Base Water . Items below are the individual ingredients. * 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%*** If you are calculating a percentage of total ingredients do not add the water volume below the green line to the water volume above the green lineNote: 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)Non-crystalline silica (impurity)7631-86-90.003080.00066Magnesium nitrate10377-60-30.002470.000535-chloro-2-methyl-4-isothiazolin-3-one and 2-methyl-4-isothiazolin-3-one55965-84-90.001480.00032Magnesium chloride7786-30-30.001230.00026Magnesium silicate hydrate (talc)14807-96-60.001220.000262,2''-oxydiethanol(impurity)111-46-60.000810.00017poly(tetrafluoroethylene)9002-84-00.000520.00011Sodium hydroxide (impurity)1310-73-20.000400.00009Potassium chloride (impurity)7447-40-70.000240.00005Quartz, Crystalline silica14808-60-70.000250.00005Cristobalite14464-46-10.000250.00005Acetic acid, potassium salt127-08-20.000190.00004Acetic acid (impurity)64-19-70.000030.00001 12/02/20 THE STATE °fALASKA GOVERNOR MIKE DUNLEAVY Bryan McLellan Senior Intervention and Integrity Engineer BP Exploration (Alaska), Inc. PO Box 196612 Anchorage, AK 99519-6612 Re: Prudhoe Bay Field, Borealis Oil Pool, PBU L -118L1 Permit to Drill Number: 217-006 Sundry Number: 320-012 Dear Mr. McLellan: Alaska Oil and Gas Conservation Commission 333 West Seventh Avenue Anchorage, Alaska 99501-3572 Main: 907.279.1433 Fax: 907.276.7542 www.aogcc.alaska.gov Enclosed is the approved application for the sundry approval relating to the above referenced well. Please note the conditions of approval set out in the enclosed form. As provided in AS 31.05.080, within 20 days after written notice of this decision, or such further time as the AOGCC grants for good cause shown, a person affected by it may file with the AOGCC an application for reconsideration. A request for reconsideration is considered timely if it is received by 4:30 PM on the 23rd day following the date of this letter, or the next working day if the 23rd day falls on a holiday or weekend. Sincerely- -IliDATED this N day of January, 2020. RBDMS 6/ JAN 2 4 2920 STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APPLICATION FOR SUNDRY APPROVALS 20 AAC 25.280 kv¢.0 1. Type of Request: Abandon ❑ Plug Perforations ❑ FractureStimulate 0 ^ Repair Well ❑ Operations shut�down r❑ Suspend ❑ Perforate 0 • Other Stimulate ❑ Pull Tubing 11ChangeA0Y Plug for Redrill ❑ Perforate New Pool ❑ Re-enter Susp Well ❑ Alter Casing ❑ Other ❑ 2. Operator Name: BP Exploration (Alaska), Inc Current Well Class: Exploratory ❑ Development 0 5. Permit to Drill Number: 217-OOfi3. Address: P.O. Box 196612 Anchorage, AKJ4. 99519-6512 Stratigraphic ❑ Service ❑ 6. API Number: 50-029-23043-60-00 7. If perforating: CO 341H What Regulation or Conservation Order governs well spacing in this pool? 8. Well Name and Number: Will planned perforations require a spacing exception? Yes ❑ No 0 PBU L-118LI 9. Property Designation (Lease Number): 10. Field/Pools: ADL 028239 ' PRUDHOE BAY, BOREALIS OIL 11. PRESENT WELL CONDITION SUMMARY Total Depth MD (ft): Total Depth TVD(ft): Effective Depth MD: Effective Depth TVD: MPSP (psi): Plugs (MD): Junk (MD): 12780 6686 12761 6686 None 12440 Casing Length - Size MD TVD Burst Collapse Structural Conductor 78 20" 31-109 31-109 1490 470 Surface 3265 7-5/8" 30-3295 30-2622 6890/8180 4790 / 7150 Intermediate Production 8703 5-1/2" x 3-1/2" 27-8730 27-6506 7000/10160 4990/10540 Liner 4108 2-3/8" 8662-12770 6439-6686 11200 11780 Perforation Depth MD (ft): Perforation Depth TVD (ft): Tubing Size: Tubing Grade: T ubing MD (ft): 11215 - 12755 6625 - 6685 3-1 /2" 9.2# L-80 25-8481 Packers and SSSV Type: No Tbg Packer Packers and SSSV MD (ft) and TVD (ft): No Tbg Packer No SSSV Installed No SSSV Installed 12. Attachments: Proposal Summary 0 Wellbore Schematic 0 13. Well Class after proposed work: Detailed Operations Program ❑ BOP Sketch ❑ Exploratory ❑ Stratigraphic ❑ Development 0 Service ❑ 14. Estimated Date for Commencing Operations: January 22, 2020 15. Well Status after proposed work: Oil 2 WINJ ❑ WDSPL ❑ Suspended ❑ 16. Verbal Approval: Date: GAS ❑ WAG ❑ GSTOR ❑ SPLUG ❑ Commission Representative: GINJ ❑ Op Shutdown ❑ Abandoned ❑ 17. 1 hereby certify that the foregoing is true and the procedure approved herein will not Contact Name: McLellan, Bryan J be deviated from without prior written approval. Contact Email: Bryan.McLellanQbp.com Authorized Name: McLellan, Bryan J Contact Phone: +1 9075644145 Authorized Title: Senior Intervention & Integrity Engineer Authorized Signature: Date: COMMISSION USE ONLY Conditions of approval: Notify Commission so that a representative may witness Sundry Number: Plug Integrity ❑ BOP Test ❑ Mechanical Integrity Test C7 Location Clearance ❑ Other: iBDMSW AN 2 4 2020 Post Initial Injection MIT Req'd? Yes 11No0 Spacing Extion Required? V No ld Subsequent Form Required. / 0 -+� yQ y APPROVEDBYTHE �JP Approved by: • COMMISSIONER COMMISSION Date: I V c.ow ►i k�zd,-�ej Form 10-403 Revised 04/2017 ORIGINAL V� 112-(1,-o Approved application is valid for 12 months from the date of approval. t.& Submit Form and Attachments in Duplicate STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION AFFIDAVIT OF NOTICE OF OPERATIONS /I Before me, the undersigned authority, on this day personally appeared r an MC LF llaed who being duly sworn states: 1. My name is Bryan McLellan. I am 18 years of age or older and I have personal knowledge of the facts stated in this affidavit. 2. I am employed as an Engineer by BP Exploration (Alaska) Inc. (`BPXA") and I am familiar with the Application for Sundry Approvals to stimulate the L-I18A Well (the "Well") by hydraulic fracturing as defined in 20 AAC 25.283(m). 3. Pursuant to 20 AAC 25.283(1), BPXA prepared a Notice of Operations regarding the Well, a true copy of which is attached to this Affidavit as Attachment 1 ("Notice of Operations"). 4. On January7th, 2020, the Notice of Operations was sent to all owners, landowners, surface owners and operators within a one-half mile radius of the current or proposed wellbore trajectory of the Well. The Notice of Operations included: a. A statement that upon request a complete copy of the Application for Sundry Approvals is available from BPXA; b. BPXA's contact information. Signed this 7th day of January, 2020. (Signature) STATE OF ALASKA THIRD JUDICIAL DISTRICT Subscribed and sworn to or affirmed before me at on day of ZA IJ 4 A i ,20_2,6 /1 Alaska E bicblicordheim ssion Expires: 3 2p-Zo the '% rb— McLellan, Br e,i ` 4-,e, From: AK, Prudhoe Bay Unit Secretary Sent: Tuesday, January 7, 2020 12:28 PM To: dnr.notifications@alaska.gov Cc: Buckbee, Rachel A; McLellan, Bryan J; Vance, Bridger Subject: Notice of Hydraulic Fracturing of PBU Well L-1181-1 Hello, This is the notification of a hydraulic fracture stimulation planned for Well L-1181-1. Planned start date is January 2020. . History/Objectives L-1181_1 is a 2018 slimhole CTD sidetrack in the Kuparuk Borealis field sidetracked to access undrained oil in the northwest periphery of L -Pad. The 2-3/8" liner was completed with ball drop frac sleeves near the toe of the well. A 3 - stage frac was conducted post rig which delivered lower-than-expected rate. s L-1181_1 POP'd on 6/4/18 at a higher than expected WC and lower than expected fluid rate. The latest well tests were only -200 bfpd with the well hydrating off due to low fluid rate. The likely cause of L -1181-1's poor performance is due to lack of quality and/or presence in the C4 sands near the toe. C4 rock quality degrades considerably to the Northwest. The model indicates that there is presence of reservoir quality C4 sand at the toe of the L-1181-1, albeit thinning and degrading. A multi -stage frac will be conducted in the mid-section and heel of the well, closer to where there is evidence of the C4 sand being logged and better rock quality. The heel frac will be close to the original motherbore, which had an impressive post -frac rate and was still producing -100 bopd at the time the CT sidetrack was drilled. BOREALIS LINK WELL: L-118 L1 PERMIT No: 217.0% API No: 50-029-23043-017, 60 SEC 34, T12N, R11 E, 2551' FSL & 3773' FEL OP Exploration (Alaska) A full copy of the application submitted to the AOGCC is available by contacting Bryan McLellan at 907-564-4145, Bryan. McLellan@bp.com. Thank you, Bridger Vance Commercial Analyst BP Exploration, Alaska 907.564.4235 3anuary 9, 2020 L-118BL3 Fracture Stimulation Intervention Engineer Bryan McLellan (907) 564-4145 (work), (907) 250-9193 (mobile) Objective Perform a plug and pert three stage fracture stimulation on the coil sidetrack to increase well's PI and off -take. Procedural Steps Slickline with Fullbore Assist 1. Set a retrievable bridge plug in the tubing 2. Pull DGLV from Station #2 and set a circulation valve 3. Circulate well with inhibited seawater and leave a 2500' freeze protect in the tubing and inner annulus 4. Pull circulation valve and set a DGLV S. MIT -T to 4500 psi with 0 psi on IA 6. MIT -IA to 4500 psi with 2500 psi on tubing 7. Pull retrievable bridge plug from tubing and drift to deviation Special Projects with Coil/Fullbore Assist 8. Rig up tree -saver for fracturing operations 9. Execute three fracture stimulation with the following pressure limits: Maximum Anticipated Treating Pressure: 6000 psi Maximum Allowable Treating Pressure: 7300 psi Stagger Pump Kickouts Between: 6570 psi and 6935 psi (90% to 95% of MATP) Global Kickout: 6935 psi (95% of MATP) IA Pop-off Set Pressure: 4100 psi (<95% of 4500 psi MIT -IA) IA Minimum Hold Pressure: 3900 psi Treating Line Test Pressure: 8300 psi Maximum Anticipated Rate: 20 bpm OA Pressure: Monitor and maintain open to atmosphere 10. Between frac stages, coil will FCO and perforate Paoe 1 of 2 Coiled Tubing 11. Perform a fill cleanout to TD of the well post stimulation Slickline 12. Install a generic GLV design Well Testers 13. Flow well back post stimulation through test separator to ensure solids are at a manageable level for facilities to handle and conduct a post frac well test Paoe 2 of 2 Date: January 8th, 2019 Subject: L -118L1 Fracture Stimulation From: Bryan McLellan — Wells Engineer, Alaska e: mclellbi(&bp.com o: 907.564.4145 c: 907.250.9193 David Wages— Wells Engineer, Alaska e: David.Waaes(c)bp.com 0:907.564.5669 c: 713.380.9836 To: AOGCC Attached is BP's proposal and supporting documentation to perform a fracture stimulation on well L-1181_1 in the Kuparuk reservoir of the Prudhoe Bay Unit. Well L-1181_1 is a coiled tubing drilling sidetrack that was drilled March 2018. The well is an undulating lateral (^'4000') through the Kuparuk C sands. It was initially completed with a cementless 2-3/8" liner with three ball drop frac sleeves installed. The initial fracs were performed through the 3 frac sleeves in June 2018, however the post -frac rates were below expectation. Perforations were added to connect with fracs that may have initiated a distance away from the frac sleeves, but no change in production was observed and a CT milling BHA was stuck in the second frac sleeve. Currently the well has difficulty remaining online due to low rates and hydrate formation in the tubing. BP is applying for a 3 -stage, plug & perforate fracture stimulation to access Kuparuk C -sand oil reserves toward the heel of the well and to re -connect with the frac in the L-118 motherbore. Please direct questions or comments to Bryan McLellan or David Wages. Section 1— Affidavit of Notification (20 AAC 25.283, a, 1): All owners, landowners, surface owners and operators within % mile radius of the current wellbore trajectory have been provided a notice of operations on 01/07/2020: ConocoPhillips ExxonMobil Chevron Department of Natural Resources Section 2 — Plat Identifying Wells (20 AAC 25.283, a, 2): Plat s� -L-02A. -o2P ryry� C.. L z�L3p8? v 2 92 •2 3 ooh y N N 1_ � � ��.. -2f17C3 -.410 2� w i 25OL2 2 V )B 4-114 !19 v,1 L' 210PB5 l2 2Di L -114A 4i ' C106 L-04 L-102 L214A -L-214.05- - - R-fAS._ 1,1 L-2041_3. loA L-2041,2 L,03. N r 6s, L -p1-4 �? 'L--50 - �(1 LSOPBl N s v N 1,500 0 1,500 Feet by L-1181_1 Plat Landowners • L-118LI Fracs L-1181_1 - Wells within 1/2 mile of L-1181_1 7 L-1181.1 Production Interval 1/2 Mile Buffer :3L-11 8LI 1/2 Mile Buffer BP Leases Data Sources: Wells, Units, Coastline maintained by Bl Cartography. MAP 1 rigute .: rmL snowing weir tocauon tmgnogncea to real and an wells that penetrate within one-half mile of the current wellbore trajectory and fracturing interval (brown & orange outline). The list of wells with classification and status is in the table below. Well Name Well Classification Well Status IGNIKSIKUM11 Exploratory Abandoned L-01 Development Abandoned L -01A Development Oil Producer Gas Lift L-02 L -02A L-02APB1 L -02B L-02PB1 L-03 L -03A L-03APB1 L-04 L-100 L-101 L-102 L-102PB1 L-102PB2 L-103 L-104 L-105 L-106 L-107 L-108 L-109 L-110 L-111 L-112 L-114 L -114A L-115 L-116 L-117 L-118 L-119 L-120 L-121 L -121A L-122 L-123 L-123PB1 Development Development Development Development Development Development Development Development Service Development Development Development Development Development Service Development Service Development Development Service Service Development Service Development Development Development Service Development Service Development Service Development Development Development Development Service Development Abandoned Abandoned Plugged Back For Redrill Oil Producer Shut -In Plugged Back For Redrill Oil Producer Shut -In Suspended Plugged Back For Redrill Water Injector Injecting Oil Producer Gas Lift Oil Producer Gas Lift Oil Producer Gas Lift Plugged Back For Redrill Plugged Back For Redrill Water Injector Injecting Oil Producer Gas Lift Water Injector Injecting Oil Producer Shut -In Oil Producer Gas Lift Miscible Injector Shut -In Water Injector Injecting Oil Producer Shut -In Water Injector Injecting Oil Producer Shut -In Abandoned Oil Producer Shut -In Water Injector Injecting Oil Producer Gas Lift Water injector injecting Oil Producer Shut -In Water Injector Injecting Oil Producer Gas Lift Abandoned Oil Producer5hut-In Oil Producer Gas Lift Miscible Injector Shut -In Plugged Back For Redrill Well Well Classification Name L-201 Development L-2011_1 Development L- Development 201LlPB1 L-2011_2 Development L-2011_3 Development L- Development 2011-3/3131 L-201PB1 Development L-201PB2 Development L-202 Development L -202L1 Development L-2021_2 Development L-2021_3 Development L-203 Development L -203L1 Development L-2031_2 Development L-2031-2-01 Development L-2031_3 Development L- Development 2036PB1 L- Development 203L3PB2 L-2031_4 Development L-204 Development L -204L1 Development L-2041_2 Development L-2041_3 Development L-2041_4 Development L-205 Development L -205L1 Development L-2051_2 Development L-2051_3 Development L-2051_4 Development L-2051_5 Development L-205PB3 Development L-210 Service L-210PB1 Service L-211 Service L-211PB1 Service L-212 Service L-212PB1 Service L-212PB2 Service L-213 Service Well Status Oil Producer Gas Lift Oil Well Plugged Back For Redrill Oil Well Oil Well Plugged Back For Redrill Plugged Back For Redrill Plugged Back For Redrill Oil Producer Gas Lift Oil Producer Gas Lift Oil Producer Flowing Oil Producer Flowing Oil Producer Shut -In Oil Well Oil Well Oil Well Oil Well Plugged Back For Redrill Plugged Back For Redrill Oil Well Oil Producer Shut -In Oil Producer Gas Lift Oil Producer Gas Lift Oil Producer Gas Lift Oil Producer Gas Lift Oil Producer Shut -In Oil Well Oil Well Oil Well Oil Well Oil Well Plugged Back For Redrill Water Injector Shut -In Plugged Back For Redrill Water Injector Shut -In Plugged Back For Redrill Water Injector Shut -In Plugged Back For Redrill Plugged Back For Redrill Water Injector Injecting Well Name Well Classification Well Status Well Well Classification Well Status Name L-124 Development Oil Producer Gas Lift L-214 Service Abandoned L-124PB1 Development Plugged Back For Redrill L-214A Service Water Injector Injecting L-124PB2 Development Plugged Back For Redrill L-215 Service Water Injector Shut-In L-200 Development Oil Producer Shut-In L-216 Service Water injector Injecting L-20OL1 Development Oil Well L-217 Service Miscible Injector Shut-In L-2001_2 Development Oil Well - L-218 Service Water Injector Shut-In L-219 Service Water Injector Shut-In L-2501_2 Development Oil Producer Gas Lift L-220 Service Water Injector Shut-In L-250PB1 Development Plugged Back For Redrill L-221 Service Water Injector Shut-In L-50* Development Oil Producer Shut-In L-222 Service Water Injector Injecting L-50PB1 Development Plugged Back For Redrill L-223 Service Miscible Injector Shut-In NWEI-01 Exploratory Abandoned L-250 Development Oil Producer Gas Lift V-04 Development Oil Producer Gas Lift L-250L1 Development Oil Producer Gas Lift Sections 3-4 — Exemption for Freshwater Aquifers (20 AAC 25.283, a, 3-4): Well L -118L1 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 BP exemption from 20 AAC 25.283, a, 3-4 which require identification of freshwater aquifers and establishing a plan for basewater sampling. Sections 5-6 — Detailed Casing and Cement Information (20 AAC 25.283, a, 5-6A): The parent bore of L-1181_1 (L-118) was spudded 03/22/2003. A 9-7/8" hole was drilled to 3310' MD where 7-5/8", 29.7#, L-80 / 5-95, BTC / NSCC casing was run (casing shoe at 3295' MD, 2622' TVD) and cemented in place with 293 bbls of Permafrost L lead cement slurry (10.7 ppg) and 41 bbls of 15.8 ppg Premium Class G tail cement. During cement displacement, approximately 50 bbis of good cement were seen back J to surface. The 7-5/8" casing was successfully pressure tested to 3500 psi for 30 minutes. Float collar, shoe and 20' of new formation were drilled out with a 6-3/4" bit to 3330' MD where a leak off test (LOT) was performed with 9.7 ppg mud (675 psi surface pressure, 2642' TVD, 14.6 ppg EMW). A 6-3/4" production hole was drilled from 3330' to 8980' MD where a combination of 3-1/2", 9.2#, L-80, IBT / EUE / NSCT/ TC -II / BTC x 5-1/2", 15.5#, L-80, BTC casing was run (casing shoe at 8969' MD, 6743' TVD) and cemented in place. The casing was cemented with 62 bbls of 12.5 ppg SilicaLite lead cement and 24 bbls of 15.8 ppg Class G premium < cement. No losses were noted during cementing and plug bumped on calculated volume. Pressure was bled off the casing and floats held. The completion assembly consisting of 3-1/2", 9.34, L-80 IBT tubing was run to 8481' MD. Corrosion inhibited seawater was reverse circulated into the IA and tubing was stabbed —15' into the polished bore receptacle at 8469' MD (6251' TVD). Pressure tested tubing and 3-1/2" production liner to 4000 psi for 30 minutes. On 12/31/2017 coiled tubing performed a cement packer repair where 6 bbis of 15.8 ppg cement were circulated into the IA leaving estimated top of cement at 7950' MD (5748' TVD). L -118L1 kicked -off in the existing parent bore perfs and was directionally drilled to 12,780' MD (6686' TVD) undulating through the Kuparuk sands. An uncemented 2-3/8", 4.7#, L-80, TH511 liner was run consisting of three ball drop frac sleeves. Since this is a coiled tubing drilling sidetrack, the existing production tubing is being utilized for production. Section 7 — Pressure Testing (20 AAC 25.283, a, 7): Table 1—Tubing and Productinn racing Prnca,ro Tactina Tubing Pressure Date (psi) Production Casing Pressure (psi) Differential Pressure (psi) TBD 4500 0 4500 TBD 2500 4500 1 2000 T I ne tubing will be pressure tested to 4500 psi differential which is greater than 110% max differential during stimulation per 20 AAC 25.283, b. 6500 psi (max tbg pressure) — 3100 psi (IA casing pressure) = 3400 psi (differential while stimulating) 3400 psi (differential) x 1.1 = 3740 psi (110% max differential pressure while stimulating) Section 8—Accurate Pressure Ratings of Tubulars and Schematic (20 AAC 25.283, a, 8): Wellbore Schematic PROPOSED L -I18 PERES Li Minimum ID=1.3T5" @ 12753' 60�� 2-318" NS FRAC SLEEVE EST TCC N fA (12!31117) —7950- 15- 1 f2 950' 5•.112" CSG, 15.5#, L-80. ID=4 950' 846W 512"%3-tfY fSG %D,D=3.000' —�. PW.iiy:7HIS{Pi(.I yxgW ND I DEPTH I SEAT SZ. I ACRAL SIZEOIC 01/01103 OAQKK ORIDMAL COMPLETKM! DATE ' 3 117461 1.680' 1 2515 C 03/311101 2 22411 1.563' 1 2 -SS' C I 03131118 1 127531 1.438" 1 2-518- C 0313 118 PEFFORATION SUM.4ARY F*FLOG SIASV6XNd DN{NJ0312=3 ANGLEATTOPPERF, 10 -@8n6 - Note: Refer ro RaduC80B tib ter hY1p'iCal pert data SIZE SEF INTERVAL OpNSryz DATE L-115 -6EF PG 2 FOR PEW SL4WRY- L-115 Li ( PBTo� H- a , SAFETY NOTES: WELL ANGLE 2 70'@ 8095'. MAX DL&{S2• =88501 .._ 1 1DKR LOC SEAL ASSY, ID = 3.00' 25" YN U= D=225" M R -LOUT WINDOW (L-118 Lt) 8730' - 8736' 11745'—2-X8'NSFRACSLV.0=1.7r Ft5H' 8OT MLt NG — 12240' FISH( -101 aela) POTD 12761' 2-318' LM R.6 7#. L-80 HYD511 12770" 0039 bpf. D = 1.485' DATE REV BY COMMENTS DATE GASLIFT' MANDRELS 01/01103 OAQKK ORIDMAL COMPLETKM! 8&19118 ST e MD _ TWO -DEV TYPE VC LATCH PORT DATE 4 4783 350251 KSG2 DOME NT 16 11!15119 ! 3 5390 05 44 51 "Q! 2 DOME NT 16 11n5n9 2 7671 _ 5485 23 KSG2 SO Ni' 20 11115n9 1 8381 1STA 31&8 14 KBC-2 -DMY M 0 1119MI # 1 = DMY HAS S'AFLL PACKNG & 6 COVERED BY CEMENT .._ 1 1DKR LOC SEAL ASSY, ID = 3.00' 25" YN U= D=225" M R -LOUT WINDOW (L-118 Lt) 8730' - 8736' 11745'—2-X8'NSFRACSLV.0=1.7r Ft5H' 8OT MLt NG — 12240' FISH( -101 aela) POTD 12761' 2-318' LM R.6 7#. L-80 HYD511 12770" 0039 bpf. D = 1.485' DATE REV BY COMMENTS DATE ''REVBY COMMENTS 01/01103 OAQKK ORIDMAL COMPLETKM! 8&19118 G,IBUMD GLV 070(0&15118) 040119 N.CDR2 CTD ML SIDETRACK 415 Li fm"o BCIJMO MRL rnAC SLEEVE&LEFT FISHOH O4N4/18 .DOJ DRLG HO CORRFCTONS 0315'18 RGAID =0.L FRAC SLEEVE BADPF.RFS 04A1118 JUAAD FHA_L _ODE. APPROVAL 8514118 CJNJM0 OLV C!O 05115!1& --- 1628119 N+ MI GLV C,1�(11M 19) 0514118 RCBIJMD T TP WRTSA & R NP (051018) Figure 2.1—Proposed wellbore schematic for well L-1181.3, page 1. 1.7 L-118 Li -- BOREALG UNIT — WELL: LA 18 Li PERMIT Np: 2171108 APINO'50-029-23043-00,00 1 BP E-Pk4rahn fA,Oaaa) TRff= 3-11$514 aw Y'h1LFCAD• FAG' ACRYtTOR- BAKERC Im. B_EV == zaa IS E LEM . _ -........-70N 2-578' C KGP- — 9W V Arvgle= 10t-09331' 2-518" C O�t1anT%p� _. 56W'SS PROPOSED PERFS Minimum ID =1,375" @ 12755' 2-318" NS FRAC SLEEVE 11 -VA" FRAC PnPT Al PPVP4 it0 OEP�TF1 SEAT SZ. ACTWL SIZE Q+C OATE 3 19748 9.688' 2-578' C 0313V18 2 12241 1.563• 2-518" C 01MV18 1 17753 1.438• 2.5f8' C 03+31x16 PERFORATION SUMMARY REFLOG SWSVISIONO-NONO3r9W3 ANGLE AT TOP PERF: 10° @ 8726' L- • • 8 M�$:4Y*1'@ 85«Ea70"x$$96'. L1 Figure 3.2—Proposed wellbore schematic for well L-11817, page 2, showing proposed perforation depths. iL1 BOREALIS UNR WELL: L-118 Li PEB1AIr Ne: 217406 API Na: 50-029-23043-00.60 BP Ervlurallon (Alaska) L.118 2.17X 6 6726.5776 j O 04117A)3 L-116 0 1.55' 6 8776-8807 O f 1.5W 0 9510 9542 O f 1 0 10344.1npQg O 156" 6 11215-11247 0 0140f19 196' 6 11669-11733 O 03r"9 156' 6 11763 -11827 O 03119!19. 156' 6 12162-12194 O 03f19119.. I,W 6 12194-12226 O 03118119 L- • • 8 M�$:4Y*1'@ 85«Ea70"x$$96'. L1 Figure 3.2—Proposed wellbore schematic for well L-11817, page 2, showing proposed perforation depths. iL1 BOREALIS UNR WELL: L-118 Li PEB1AIr Ne: 217406 API Na: 50-029-23043-00.60 BP Ervlurallon (Alaska) Table 2—Tubular Ratings Size/Name Weight Grade Connection ID Burst, psi Collapse, psi 7-5/8" Surface Casing 29.7# L-80 BTC / NSCC 6.875" 6890/8180 4790/7150 5-1/2" Production Casing 15.5# L-80 BTC -M 4.950" 7000 4990 3-1/2" Production Liner 9.2# L-80 IBT/ NSCT/ ELIE / BTC / TC -11 2.992" 10,160 10,540 2-3/8" Production Liner 4.7# L-80 HYD511 1.995" 11,200 11,780 3-1/2" Production Tubing 9.2# L-80 IBT 2.992' 10,160 10,540 Wellhead Wellhead: FMC manufactured wellhead, rated to 5,000 psi. • Tubing head adaptor: 11" 5,000 psi x 3-1/8" 5,000 psi • Tubing Spool: 11" 5,000 psi w/2-1/16" side outlets • Casing Spool: 11" 5,000 psi w/ 2-1/16" side outlet Tree: Cameron 3-1/8" 5,000 psi Tree -saver Top connection is 3" 1502 hammer union which will be crossed over to 4" 1002 to connect to the treating iron. Bottom connection is 7-1/16" The tree -saver is rated to 10,000 psi. Figure 4—Diagram of tree -saver to be used during fracture stimulation. Section 9 - Geological Frac Information (20 AAC 25.283, a, 9): Table 3 -Geological Information Formation MD Top MD Bottom TVDss Top TVDss Bottom TVD Thickness Frac Grad Lithological Desc. Top HRZ (parent) 8373 8578 6081 6280 199 -0.83 . Shale Top Kalubik (parent) 8578 8724 6280 6424 144 -0.83 . Shale TKUPC4(parent) 8724 8732 6424 6431 7 0.55 SS KOP 8730.0 - 6429 - - - SS TKOE 8732 8740 6431 6439 j 8 0.55 SS TKOD 8740 8757 6439 6456 16 0.55 SS TKC3C 8757 8779 6456 6476 20 0.55 SS TKO B 8779 8802 6476 6494 19 0.55 SS TKC3A 8802 8811 6494 6501 7 0.55 SS TKC2E 8811 8819 6501 6507 6 0.55 SS TKC2D 8819 8828 6507 6513 6 0.55 SS TKC2C 8828 8837 6513 6519 6 0.55 SS TKC213 8837 8844 6519 6523 4 - SS TKC2A 8844 8854 6523 6528 6 - SS TKC1C 8854 8871 6528 6537 8 0.55 SS TKC113 8871 8899 6537 6548 11 0.55 SS TKC1A 8899 - 6548 - - 0.55 SS Invert 8950 6556 - SS Invert TKC1A 9021 - 6549 - - 0.55 SS InvertTKC1B 9089 9021 6538 6549 11 0.55 SS InvertTKC1C 9131 9089 6530 6538 8 0.55 SS InvertTKC2A 9155 9131 6526 6530 4 0.55 SS InvertTKC2B 9188 9155 6521 6526 6 0.55 SS InvertTKC2C 9231 9188 6513 6521 8 0.55 SS Invert TKC2D 9260 9231 6508 6513 5 0.55 55 InvertTKC2E 9293 9260 6502 6508 6 0.55 SS InvertTKC3A 9324 9293 6496 6502 6 0.55 SS Invert TKC38 9420 9324 6481 6496 15 0.55 SS Invert TKC3C 9990 9420 6487 6481 6 0.55 SS Revert TKC3C 11478 - 6565 - - 0.55 SS TD 12780 - 6609 - - - SS Top B Silts (Parent) - - 6559 6721 162 0.7 r Silts Top A Interval (Projected) - 6721 6814 93 0.72 ' Silts Top Miluveach (Projected) - 6814 - 980 -0.84 Shale Within the reservoir section, formation tops were picked from GR logs and cuttings while drilling L-1181-1. The upper confining zone (HRZ) and top Kuparuk were determined from the parent wellbore logs and cuttings. Top of the lower confining Miluveach shale was projected from isopach maps of the area and thickness was determined from offset wells. J Sections 10-11— Location of Wells, Mechanical Information and Faults (20 AAC 25.283, a, 10-11): Area of Review N I 1 2 3 J Qj� 1,500 0 1500 • L -I 8L1 Fra¢ Data Sources: Feet L MUP Rats Wtlls, Unib. Coastline "inUnenby BRA L Ubu Frac Nat Lague Cartography. byL-11mi Y L-1181_1—"'als�vlmn ,a mlemL.IlaLl 1KG FaUI Pdygms - PI[liz: Fault QnB�y51$ L -„8L r RWUNon l nrerva 1_1 1.111¢ Eutta' MAP 1 =Llml0 v2 Mlle Berta BP Leases — Figure 5—Plat showing Area of Review (brown outline) of wells and faults transecting the confining zones within one-half mile of L-1381_1 wellbore trajectory (red line). The main stress orientation is (-N-S). 9 ti m Q) L Q) v Q) E O N Q O G Q) E u ml VI Y � (NO • C � aci 3 v E m bCO u c N Y 0 a Y V Q N � 0 O. U C O u ~ p Y 0 O O a c Y c -o -0 O O ro U a O) E L L L v o 0 E o 0 to —° 0 E v Y v m Dto N ? c c7 v E `N bo OU N N U C m L 3 u " u v u 0 3 b a 3 Y L aL-. c Q p Y bO O . OW 3 a a O. L u v m a u w u a �n N Qj N Y m c m a L Y 0 O Y a 3 O Y NO n � a c C v 3 m 3 = E E 0 c a °' " v O `° a E 3 3 v c E a O ro vi O Y E a v 3 v SO m a m a 3 I c c bco a 0 Ln aj N tw L U N C y c u u v c a 3 v u U i N a c O ubn C U C X N .N bO C L H Qj ou cL h u iq E w U W YCL u M N a O n vm co c C U OJ O ry N L 3 Y L Y Y b 0 0 3 b4 cl m u s a u a u o y ~ E N v _ L Q m + N m o n bo o 3 0 E o v a n v o L N C O E L 0 3 0 aE o 3� 0 L O VL u L X N u m V1 v O. N C 0 t O v a 3 w d CO bm m m bm O U bm ar a .` C C (U u L O1 a Ea 0 H L n N Y bO O 14 0 0 L in C �n P•1 I— N J N J JLp d J ti m Q) L Q) v Q) E O N Q O G Q) E u ml BP'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 %2 mile radius of the production and confining zone trajectory for L-1181-1. 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-16ppg. Thickness and fracture pressure for the confining layer is discussed in Section 9. No faults were crossed when the L -118L1 was drilled. Losses were taken from start and were assumed to be losses to the parent wellbore (that was frac'ed). Total losses were 2318 bbls. Fault #1-5 intersect the production interval and confining zone within the %, mile radius. Their displacements, sense of throw and zone in which they terminate upwards in are given below. Faults THROW Upward Fault Termination Zone Fault #1 200' (DTE) Ugnu Fault #2 40' (DTW) Colville Fault #3 10' (DTE) Colville Fault #4 80-150' (DTE) Schrader Bluff Fault#5 100-120'(DTN) Colville I he location of Frac #3 of the production hole is in the near vertical section of the heel of the well. The fracture is planned to be initiated at 8775' MD. It is planned to re-establish connection with the original parent frac in the heel of the well. The location of Frac #2 of the production hole was drilled -5 degrees to the maximum horizontal stress which will result in a transverse fracture. The fracture is planned to be initiated at 9510' MD. The location of Frac #1 of the production hole was drilled -5 degrees to the maximum horizontal stress which will result in a transverse fracture. The fracture is planned to be initiated at 10260' MD. Standoff values from the midpoint of planned perforations/frac points in the wellbore to mapped nearby wells are shown in Table 4. Table 4—Standoff Values. Frac #3 8775' MD Fault 2 376' Frac #3 8775' MD Fault 1 533' Frac #2 9510' MD Fault 2 685' Frac #2 9510' MD Fault 1 651' Frac #1 10260' MD Fault 2 778' Frac #1 10260' MD Fault 1 793' Section 12 — Hydraulic Fracture Program (20 AAC 25.283, a, 12): Fracture Stimulation Pump Schedule Chemical Disclosure Client &PExpioratlon Aa:Ya Onestim, Well: L4Y661 Basir4Field: Prudhoe Bay Aurora scats Alaska County,Marinh: North Slope Bw qh ca. D'udosum Type: Pre -:bb Well Completed: 7=2020 Date Prepared: 1,.66.20202:33 PM 8epvrlD: PPT -64850 - F303 ~ Sufacean<' • • 0-9 Gal f 1000 Gal 108.0 Gal 1213 Bmakert23i OS Lb,13000 Gat 55.4 Lb 1475 Breaker 0.9 Lb; 8000 Gal 550.0 Lb ism Gelling. Sr errt 26.5 Liaj1000G:I _ 3.023.0 Lb MIX Cma:fnkerl 2.4 G21j1000Ga1 2700 Gal YF32S Fle L-WF123 134.072 Gal s Sale I.Nydor 0.9 Gal ±1000 Gal _ I 100A Gal LO71 Cla Corwol _ rt 1.9 Gal T 1000 Gal 216.0 Gal M002 Addidae 0.9 Lb (II000 Gal 106.0 Lb M275 Bactv'amde 0.5 La 11000 G-{ 50.0 ib 5323 Aai.• or 0.5 Gal j I000 Gal +- 60tQ Gal 5522-100 Pmpmrg APP 216.001.0 La 5526-56M EM&A 40M •.cried mncentntions 124,574.4 Lb '1,. ran�niAmrl._ .w+`. wn.vo[ .:m -...e. eie.n..mum YF..m.ndailmn. wuors.xW+dsrare - UCater [tndudirs Ma Water Suuulied try f .TMW -73 } 66402454 Cvamic material and Wares. dremk-lL ^' 26 % 9080-30-0 Guar burn .1'a 67'•=&I ,_ i-irpdmxy-N,N,N'•trimethykanarn:niym. drlaride 1319-33-1�- Uleaim .0.i 107-21-1 Edntere Gl a1 0.1 767-0-04 DIaR m6nlnm: LueidoulPhaye dD.1 jj 63{53-0 n�-ol c 01 129696-0I-7 2- oic add, ! mer o4".n odium ahmMt. QI U131 -M-8 Alcohols, dl-f5-secondar •, etha lated . 01 % I11 -76d 2-hretml`ethanW �ql gl 34348.01-1 fdaae dated Cii A+whd c 0Y 51 3303-964 Serum Tetnbon[7eoh dram x0.91 % 131473.2 Sodi:um.h dreride i uri.- <Q.08 % 2303&-72.6 4'ih lidene c6lorSdy'neeth, la late ce •mer .:0.03 65131-345 Ptha.; dam Alcohol •:0.01 76:7-14-5 Sodium &Ioride 11417-3 but -2- .di.m acid ,_0_01 91053-39-3 Ciatomaceau: earth, calcined ,:O -M 10013-523 Calcurn Chloride <0.01 % 312-42-5 Undecarml .:9.01 % 7631.36+1 No :ranine dtim fwn or' .:0.001 10377-60-3 Ma ea um nitrite ,. q,g01 % 14607-96-6 141a neo urn Arcam h.-dnte.�lc .0.001% 26172-553 5-ch7vro-'c-me' I-2h-isathi8olo1-3-orae tO.Opj 95 7786-343 Rta rium chkxride .:0.001 313366 2,2'-0 ' thanol 'im u' ' x0.001 % 595555-152 Diutan s0.001 % 125001-67-0 O+utan ran c 0.001 % 9002-840 vel eSraQueroeth nel x4.003 % 2682-203 2-metksi4dhvothiaaoF3rone .00001 4 744750-7 Pam:aium cWmride im - i x_0.0001 % 14808-50-7 tluarL•„C saltine silica -0.0000 140.63-06-1 CM: Obalite ,:0.0001 % ?27' -Z _ Acetec xid, pnGsiumsaR -®AIOM-4 63-19-7 Acetic........ 0.0701 % r' O irn�imn X4'0. LYetl b/8P'syi4rotYm AluAv t.i Armn'ssra�. Pace.1,•' 2 Anticipated Treating Pressures Table 5—Anticipated Pressures Maximum Anticipated Treating Pressure: 6000 psi Maximum Allowable Treating Pressure: 7300 psi Pump Kickouts Between: 6570 psi and 6935 psi (90% to 95% of MATP) Global Kickout: 6935 psi (95% of MATP) IA Pop-off Set Pressure: 4100 psi (<95% of 4500 psi MIT -IA) IA Minimum Hold Pressure: 3900 psi Treating Line Test Pressure: 8300 psi Maximum Anticipated Rate: 20 bpm Sand Requirement: 213,000 lbs 16/20 Carbo Lite 122,000 lbs 16/20 CarboBond Lite Minimum Water Requirements: 1 3400 bbls (pump schedule: 3000 bbls) CA Pressure: I Monitor and maintain open to atmosphere There are three overpressure devices that protect the surface equipment and wellbore from an overpressure event. 1) Each individual frac pump has an electronic kickout that will shift the pumps into neutral as soon as the set pressure is reached. 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 CIA pressure will be monitored in the frac van. Frac Dimensions: Frac. Top Perf Location (ftMD) Base Perf (ftMD) Top Perf (ftTVDSS) Base Perf (ftTVDSS) Depth Top C Sands (ftTVDSS) Depth Base C Sands (ftTVDSS) Frac Half - Frac Height Length (ft TVD) (ft) #1 10,260 10,292 -6,485 -6,485 -6424 -6560 136 "200 #2 9,510 9,542 -6,476 -6,477 -6447 -6583 136 —200 #3 8,775 8,807 -6,474 -6,505 -6479 -6618 139 —200 The above values were calculated using modeling software. Maximum Anticipated Treating Pressure: 6000 psi Surface pressure is calculated based on a closure pressure of —0.55 psi/ft or 3600 psi. Closure pressure plus anticipated net pressure to be built and friction pressure minus hydrostatic results in a surface pressure of 6000 psi at the time of flush. 3600 psi (closure) + 500 psi (net) + 6390 psi (friction) - 4485 psi (hydrostatic) = 6000 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 —0.83 psi/ft limiting fracture height to the thickness of the C -sands. 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. 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E: N I� WN T� b •« �C N j C vi J (,J J m 0 GGo D C n r N � cn � N F, 00 00W r N v Z O n N T -4 V A O rt O � N O'Q = D 3 -O .L n• Z O G W O N O n O �- �'' fD N n V rr STATE OF ALASKA ALASKA OIL AND GAS CONSERVATION COMMISSION APR O 9 REPORT OF SUNDRY WELL OPERATIONS 2019 1. Operations Performed Abandon ❑ Plug Perforations ❑ Fracture Stimulate ❑ Pull Tubing ❑ OperabonAQ C C❑ Suspend ❑ Perforate ® Other Stimulate ❑ Alter Casing ❑ Change Approved Program ❑ Plug for Reddll ❑ Perforate New Pool ❑ Repair Well ❑ Re-enter Susp Well ❑ Other. ❑ 2. Operator Name: BP Exploration (Alaska), Inc 4. Well Class Before Work Development ® Stratigraphic ❑ Exploratory ❑ Service [18. 5. Permit to Drill Number. 217-006 3. Address: P.O. Box 196612 Anchorage, AK 99519-6612 API Number: 50-029-23043-60-00 7. Property Designation (Lease Number): ADL 028239 8. Well Name and Number: PBU L-118Li 9. Logs (List logs and submit electronic and printed data per 20AAC25.071): 10. Field/Pools: PRUDHOE BAY, BOREALIS OIL 11. Present Well Condition Summary: Exploratory ❑ Development m Service ❑ Stratigraphic ❑ 16. Well Status after work: Oil ® Gas ❑ WDSPL ❑ Copies of Logs and Surveys Run ❑ Printed and Electronic Fracture Stimulation Data ❑ Total Depth: measured 12780 feet Plugs measured None feet WA true vertical 6686 feet Junk measured None feet 1.7 Contact Phone: +1 907 564 4864 Effective Depth: measured 12761 feet Packer measured No Tbg Packer feet true vertical 6686 feet Packer true vertical No Tbg Packer feet Casing: Length: Size: MD: TVD: Burst: Collapse: Structural Conductor 78 20" 31-109 31-109 1490 470 Surface 3265 7-5/8" 30-3295 30-2622 6890/8180 4790/5120 Intermediate Production 8703 5-1/2" x 3-1/2" 27-8730 27-6506 7000 / 10160 4990/10530 Liner 4108 2-3/8" 8662-12770 6439-6686 11200 11780 Perforation Depth: Measured depth: 11215 -12753 feet True vertical depth: 6625-6685 feet Tubing (size, grade, measured and true vertical depth) 3-1/2" 9.29 L-80 25-8481 25-6262 Packers and SSSV (type, measured and No Tbg Packer true vertical depth) No SSSV Installed 12. Stimulation or cement squeeze summary: Intervals treated (measured): Treatment descriptions including volumes used and final pressure. 13. Representative Daily Average Production or Injection Data Oil -Bbl Gas-Mcf Water -Bbl Casing Pressure Tubing Pressure Prior to well operation: Lateral Subsequent to operation: Lateral 14. Attachments: (re u,red per 20 nm 25070,25 rat s 25283) 15. Well Class after work Daily Report of Well Operations 0 Exploratory ❑ Development m Service ❑ Stratigraphic ❑ 16. Well Status after work: Oil ® Gas ❑ WDSPL ❑ Copies of Logs and Surveys Run ❑ Printed and Electronic Fracture Stimulation Data ❑ GSTOR ❑ WINJ ❑ WAG ❑ GINJ ❑ SUSP ❑ SPLUG ❑ 17. 1 hereby certify that the foregoing is true and correct to the best of my knowledge. Sundry Number or N/A if C.O. Exempt: WA Authorized Name: Youngmun, Alex Contact Name: Youngmun, Alen Authorized Title: Kupawk 3 Schrader Bluff PE Contact Email: younakQBP.wm /� Authorized Signature: A�evt VWlf1 m— Date: 4 its/ 1.7 Contact Phone: +1 907 564 4864 Form 1Q404 Revised 042017 ` �/ ' REIDMS1•" APRp 10 2019 6vbmll Original Only Daily Report of Well Operations PBU L -118L1 Ar`TI\/ITVn ATC CI IMMCRY Coil Unit #8 -- 1.75" Coil. Job Objective: Mill, Fish, & Perf MIRU. MU and RIH with Baker milling BHA and 1.77" mill. 3/16/2019 ***Continue on 3/17/2019 WSR*** Coil Unit #8 -- 1.75" Coil. Job Objective: Mill, Fish, & Part RIH with Baker milling BHA and 1.77" mill. Tag frac sleeve at 11,750' and mill through. Dry drift through frac sleeve with 1.77" mill and tag top of fish at 12,234'. Pump power visc pill and chase to surface. Rih w/ Baker fishing BHA. Tag in heel of well at 8912'. Pooh. LD tools. Pick up 1.75' JSN. Cleanout to top of fish w/ get pill to 12223'. Pump a final 15 bbl gel sweep and chase ooh at 70%. Rih w/ Baker fishing BHA. Tag at 8,943', work past and latch fish at 12,234'. Unable to free fish with bi-directional hip tripper; release from fish. POOH 3/17/2019 '*'Continued on 3/18/2019 WSR*** Coil Unit #8 -- 1.75" Coil. Job Objective: Mill / Fish / Perforate Unable to recover Fish. Pump off w/ G -spear and pooh. Pull heavy through doglegs at —8900. LD fishing bha. Trim 100' of pipe. Consult with APE and decide to forego fishing and go into perforating. MU & RIH w/ HES GR/CCL & 1.75" JSN. Tag top of Fish at 12223'. Log up from compression to 8300'. Flag coil at 12150'. Pooh. LD logging tools. Correction of +16' with tie-in log. MU and RIH with 1.56" x 32' HES Perfecta Gun #1. Perforate interval 12,194' 12,226'. POOH 3/18/2019 'Continued on 3/19/19 WSR*** Coil Unit #8 -- 1.75" Coil. Job Objective: Mill / Fish / Perforate Lay down gun #1. Shots fired, ball recovered. MU & RIH with HES TCP Perfecta 1.56" x 32' gun #2. Perforate interval 12,162'- 12,194'. Pooh. LD gun. Shots fired, ball recovered. RIH w/ 1.56' x 32' HES Perfecta pert gun #3. Tag Fish, correct depth. Perforate interval 11795' - 11827'. Pooh. LD gun. Shots fired, ball recovered. RIH w/ 1.56'x 32' HES Perfecta perf gun #4. Tag Fish, correct depth. Perforate interval 11763' - 11795'. Pooh. Shots fired, ball recovered. Change Pack -offs. Leak on inner gate valve of P -sub during PT, replace. 3/19/2019 "'Continued on 3/20/19'** Coil Unit #8 -- 1.75" Coil. Job Objective: Mill / Fish / Perforate MU & RIH with HES Perfecta1.56" x 32' gun #5. Tag fish for depth correction. Perforate interval 11,701'- 11,733'. POOH. LD gun. Shots fired, ball recovered. MU & RIH w/ 1.5 x 32' HE Perfecta perf gun #6. Tag in perf debris at 11800'. Uanble to get to flag depth. Notify APE. Get approval to shoot last two guns using CTM. Perforate interval 11669'- 11701'. Flag coil. Pooh. LD Perfecta rf gun V. Stop flag, gun. Shots fired, ball recovered. MU & RIH w/ 1.56'x 32' HES Pe Pe correct depth. Perforate interval 11215'- 11247f. Pooh. LD gun. Shots fired. Ball recovered. Freeze protect well 0500 w/w/ 60/40 meoh. RDMOL. Travel to yard for Planned Maintenance. 3/20/2019 ***Job Complete*** TREE= 31/8"5MCIW WELLHEAD= FMC ACTUATOR= BAKER KB. ELEV = 76.9 FIEF ELEV = 76.9' BF. S -EV = 49.79' KOP= 300' Max Angle= 101"@9331' TW 12252' Datum ND= 6600'SS SG, 29.7#, L -80/S-95, ID = 6.875" F -L 3295' Minimum ID =1.375" @ 12753' 23/8" NS FRAC SLEEVE L-1 18 SAFETY MAX DLS:49.2 TES .@ 8850'WELL ANGLE> 70` 8895'. L1 13-1/2" HES X NP. U = 2.813- 1 GAS LFT MANDRELS ST MD TVD DEV TYPE 11 VLV LATCH PORT 0147E 4 4788 3502 51 KBG-2 DOMtE M 16 06/15/18 3 6385 4496 51 KBG2 SO M 22 06/15/18 2 7671 5486 23 KBG-2 DM' M 0 05/15/18 1 8381 6166 14 KBG-2 '0MY M 0 11/29/11 SIA # 1 = LMY YWS SWILL PALY ING & rS W V tHtV BY LAMZ V I t, L-80-0087 bpf, D = 2.992-I 8462' ACTUALSEE 8462' BKR LOC SEAL ASSY, D = 3.00" CSG, 15.5#, L-80, D = 4.950' 8469' 2-S18" LF gggg• TOP OF BKR PBR, D = 4.00" 2 8489' 2-518' 8481' BTM OF 31/2" BKR SEAL ASSY, D = 3.00" X 3112' CSG XO, D = 3.000" 12753 1.438" 2-518" C 03/31/18 850W 3-1/2" HES X NP, D = 2.813" TOL 2-3/8" FRAC PORT SLEEVES NO DEPTH SEAT SZ. ACTUALSEE G/C DATE 3 11748 1.688" 2-S18" C 03/31/18 2 12241 1.563" 2-518' C 03/31/18 1 12753 1.438" 2-518" C 03/31/18 PERFORATION StINTMRY REF LOG: SVVS VISION D -N ON 0329/03 ANGLE AT TOP PERF: 100@8726' Note: Refer to Production DB for historical perf data SIZE I SPF I INTERVAL I Opn/Sgz DATE L-118 -SEE PG 2 FOR PERF SUMrMRY- L-118 L1 L-118 8564' X NP ELMD LOGGED ON 11/17/ 8654' 31/2" WFD WEEPAK LELTPw D = 225" (05/16118) SEAL BORE, D= 2.25- 1D 8694' H20' PUPJT W / RA TAG I MILLOUT WINDOW (L-118 L7) 8730' - 8735' l 11748' -2-3/8" NS FRAC SLV, D = 1.77" FRAC SLV, D = 1.500' 12753' 2-318"FRAC SU DD FISH: BOT MLLING — 12240' FISH (10/09118) .0039 bot. D = 1.995" DATE REV BY COMMENTS DATE REV BY COMMENTS 04101103 DACIM ORIGINAL COMPLETION 06/19/18 GJB/JND GLV CIO (06/15/18) 04/01118 N-CDR2 CTD ML SIDETRACK(L-118 Lt) 10/15/18 BG/JMD MILL FRAC SLEVE&LEFT FISHID 04/04/18 JMD DRLG HO CORRECTIONS 03/25/19 BG/JMD MILL FRAC SLEEVE&ADPERFS 04/11/18 JUJMD FINAL ODEAPPROVAL 0524/18 CJNJMD GLV CIO (05/15/18) 0624/18 RCB/JMD LTPw/PTSA&RNP(05/16/18) 1 H 12770' L-118 L1 BORE -ALIS LINT WELL: L-118 L1 PEP W No: 217-006 API No: 50-029-2304300, 60 T12K 1111 E, 2551' FSL & 3773' FEL BP Exploration (Alaska) Tuff= 3-1/8"5M CNV WELLHEAD= FMC ACTUATOR= BAKER KB. E.EV = 76.9' REP ffEV = 76.9' BF. B_B/ = 49.79' KOP= 300' Max Angle= 101°@9331' Dalum M)= 1225T Datum ND= 6600'SS Minimum ID =1.375" @ 12753' 2-3/8" NS FRAC SLEEVE 2-3/8" FRAC PORT SLEEVES NO DffTH SEAT SZ. ACTUAL SIZE O/C DATE 3 11748 1.688" 2-5/8" C I 8726-8776 2 12241 1.563' 2-5/8" C 103/31/18 03/31/18 1 12753 1.438" 2-5/8" C 03/31/18 PERFORATTON SLMul4RY REF LOG SWS VISION D -N ON 03/29/03 ANGLE AT TOP PERF: 10-@8726' Note: Refer to Production DB for historical perf data SIZE I SFS= INTERVAL I Opn/Sgz I DATE DACIKK ORIGINAL COMPLETION 06/19/18 L-118 04/01/18 2-1/2.1 6 I 8726-8776 I O 104/17/03 JM0 DRLG HO CORRECTIONS 03/25/19 L-118 L1 04111/18 1.56' 6 11215 - 11247 1 O 03/20/19 1.56' 6 11669-11733 O 03/20/19 1.56' 6 11763-11827 O 03/19/19 1.56' 6 12162-12194 O 03/19/19 1.56" 6 12194-12226 O 03/18/19 L-1 18 SAFETY NOTS: WELL A MAX DLS:49E2 @ 8850'NGLE> 700 @ 8895'. L1 L-118 DATE REV BY COMMENTS DATE REV BY COM ENM 04101/03 DACIKK ORIGINAL COMPLETION 06/19/18 GJB/JM) GLV GO (06/15/18) 04/01/18 N-CDR2 CTDML SIDETRACK(L-118 L7) 10/15/18 BG/JM) MLLFRACSLfft/E&LEFTFISHDH 04/04718 JM0 DRLG HO CORRECTIONS 03/25/19 BGUMD MLLFRACSLEFVE&ADPE2FS 04111/18 JUJMD FINAL Off APPROVAL 05/24/18 CJWJM) GLVC/O(05/15/18) 05Q4/18 RCB/JND LTPw/PTSA&RNP(05/16/18) L1 BOREALIS LINT WaL: L-118 L1 PEW No: 217-006 AR No: 50-029-23043-00, 60 SEC 34, T12K R11 E, 2551' FSL & 3773' FE. BP Exploration (Alaska)
